HomeMy WebLinkAboutHawaiian Electric - Hawaii Powered Integrated Grid Plan (2023) 1 Integrated Grid Planning Report
CONTENTS
Integrated
Grid Plan
A pathway to a clean energy future
May 2023
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ACKNOWLEDGMENTS
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ACKNOWLEDGMENTS
Acknowledgments
Hawaiian Electric is grateful for the collective time, efforts and insights of the many people involved in Integrated Grid Planning. We would like to thank our customers and communities, as well as the Stakeholder Council, Technical Advisory Panel, Working Groups and Public Utilities Commission for their invaluable perspectives and partnership.
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ACKNOWLEDGMENTS
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CONTENTS
Contents
1 Executive Summary ................................................................................................................................................................... 1 1.1 Customers Are at the Heart of the Energy Transformation .......................................................................................................................... 2 1.2 Our Commitment to Customers .............................................................................................................................................................................. 3 1.2.1 Climate Change Action Plan .......................................................................................................................................................................... 3 1.2.2 Hawai‘i Powered ................................................................................................................................................................................................. 3 1.2.3 Ensuring an Equitable Energy Transformation ...................................................................................................................................... 4 1.3 Renewable Energy and Reliability Risks Today .................................................................................................................................................. 5 1.3.1 Our Current Renewable Energy Portfolio ................................................................................................................................................ 5 1.3.2 Immediate Action to Meet Goals and Maintain Reliability .............................................................................................................. 6 1.4 Overview of Integrated Grid Planning ................................................................................................................................................................... 7 1.4.1 Engaging Communities and Stakeholders .............................................................................................................................................. 8 1.4.2 Key Considerations ............................................................................................................................................................................................ 8 1.4.3 Guiding Principles .............................................................................................................................................................................................. 9 1.4.4 Energy Planning on Moloka‘i and Lāna‘i ................................................................................................................................................ 10 1.5 Action Plan at a Glance .............................................................................................................................................................................................. 11 1.5.1 Key Findings and Recommendations ...................................................................................................................................................... 11 1.5.2 Action Plan for a Clean Energy Future .................................................................................................................................................... 12 1.5.3 Timeline of Renewable Energy Procurement ....................................................................................................................................... 15 1.6 Moving beyond Planning into Action .................................................................................................................................................................. 17 2 Action Plan ................................................................................................................................................................................18 2.1 Key Findings and Recommendations ................................................................................................................................................................... 18 2.1.1 Stabilize Utility Rates and Advance Energy Equity ............................................................................................................................. 19 2.1.2 Grow the Marketplace for Customer-scale and Large-scale Renewable Generation ......................................................... 20 2.1.3 Create a Modern and Resilient Grid ......................................................................................................................................................... 22 2.1.4 Secure Reliability through Diverse Energy Sources and Technologies ..................................................................................... 23 2.2 Timeline and Renewable Portfolios ...................................................................................................................................................................... 25 2.2.1 O‘ahu by 2035 ................................................................................................................................................................................................... 26 2.2.2 Hawai‘i Island by 2035 ................................................................................................................................................................................... 27 2.2.3 Maui by 2035 ..................................................................................................................................................................................................... 27 2.2.4 Lānaʻi by 2035 .................................................................................................................................................................................................... 28 2.2.5 Molokaʻi by 2035 .............................................................................................................................................................................................. 28 2.3 External Actions and Policies for Successful Implementation ................................................................................................................... 29 2.4 Potential Risks and Challenges ............................................................................................................................................................................... 30 2.5 Our Response to Comments on the Draft Integrated Grid Plan .............................................................................................................. 30 2.6 Next Steps ....................................................................................................................................................................................................................... 37 2.6.1 Public Utilities Commission Requests ..................................................................................................................................................... 37 3 Introduction ..............................................................................................................................................................................38 3.1 Climate Change Action Plan .................................................................................................................................................................................... 39 3.2 Hawai‘i Powered ........................................................................................................................................................................................................... 40 3.3 Overview of Integrated Grid Planning ................................................................................................................................................................. 40 3.4 Key Considerations ...................................................................................................................................................................................................... 42 3.5 Pathways to 100% Renewable Energy ................................................................................................................................................................. 43 3.6 Renewable Energy Planning Principles ............................................................................................................................................................... 44 4 Community and Stakeholder Engagement ..........................................................................................................................46 4.1 Engagement Approach and Stakeholder Groups ........................................................................................................................................... 46 4.1.1 Stakeholder Council ........................................................................................................................................................................................ 47 4.1.2 Technical Advisory Panel .............................................................................................................................................................................. 48 4.1.3 Working Groups ............................................................................................................................................................................................... 48 4.1.4 Public ..................................................................................................................................................................................................................... 49 4.2 Public Engagement Tools and Strategies ........................................................................................................................................................... 50
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4.2.1 Integrated Grid Planning Website, Document Library and Email ................................................................................................ 50 4.2.2 Public Open Houses ........................................................................................................................................................................................ 51 4.2.3 Hawai‘i Powered Public Participation Site ............................................................................................................................................. 53 4.2.4 Inputs and Assumptions Data Dashboard ............................................................................................................................................. 55 4.2.5 Student and Youth Engagement ............................................................................................................................................................... 55 4.2.6 Local Events and Community Conversations ....................................................................................................................................... 56 5 Today’s Planning Environment ..............................................................................................................................................66 5.1 Hawaiʻi Energy Policy .................................................................................................................................................................................................. 66 5.2 Federal Policies .............................................................................................................................................................................................................. 68 5.2.1 Bipartisan Infrastructure Law and Inflation Reduction Act ............................................................................................................. 68 5.3 Interrelated Dockets .................................................................................................................................................................................................... 69 6 Data Collection .........................................................................................................................................................................72 6.1 Load Forecast Methodology and Data ................................................................................................................................................................ 72 6.2 Distributed Energy Resources Forecasts ............................................................................................................................................................. 73 6.2.1 High and Low Bookend Sensitivities ........................................................................................................................................................ 75 6.3 Advanced Rate Design Impacts .............................................................................................................................................................................. 76 6.4 Electrification of Buildings and Energy Efficiency ........................................................................................................................................... 77 6.4.1 High and Low Bookend Sensitivities ........................................................................................................................................................ 77 6.4.2 Energy Efficiency Supply Curve Bundles ................................................................................................................................................ 78 6.5 Electrification of Transportation ............................................................................................................................................................................. 80 6.5.1 Light-Duty Electric Vehicles ......................................................................................................................................................................... 80 6.5.2 Electric Buses ..................................................................................................................................................................................................... 81 6.5.3 High and Low Bookend Sensitivities ........................................................................................................................................................ 81 6.5.4 Managed Electric Vehicle Charging ......................................................................................................................................................... 82 6.6 Sales Forecasts ............................................................................................................................................................................................................... 83 6.7 Peak Forecasts ............................................................................................................................................................................................................... 84 6.8 Scenarios and Sensitivities ........................................................................................................................................................................................ 87 6.9 New Resource Supply Options ............................................................................................................................................................................... 89 6.9.1 Resource Cost Projections ............................................................................................................................................................................ 89 6.9.2 Assessment of Wind and Photovoltaic Technical Potential ........................................................................................................... 92 6.9.3 Solar and Wind Potential Assumption .................................................................................................................................................... 93 6.9.4 Renewable Energy Zones ............................................................................................................................................................................. 94 6.9.5 Emerging Technologies In Development .............................................................................................................................................. 94 7 Resilience Planning ............................................................................................................................................................... 100 7.1 Resilience Strategy and Approach ..................................................................................................................................................................... 100 7.2 Identification and Prioritization of System Threats ..................................................................................................................................... 104 7.3 Development of Performance Targets and Rigorous Decision-Making Methods......................................................................... 104 7.3.1 Establish Target Level of Resilience ....................................................................................................................................................... 104 7.3.2 Develop Decision-Making Methods ..................................................................................................................................................... 105 7.3.3 Stakeholder Engagement .......................................................................................................................................................................... 106 7.4 System Hardening ..................................................................................................................................................................................................... 106 7.4.1 Initial Climate Adaptation Transmission and Distribution Resilience Program .................................................................. 107 7.4.2 Future System Hardening .......................................................................................................................................................................... 108 7.4.3 Resilience Standards Development ....................................................................................................................................................... 108 7.5 Residual Risk Mitigation ......................................................................................................................................................................................... 108 7.5.1 ETIPP Microgrid Opportunity Map ........................................................................................................................................................ 109 7.5.2 Resilience Value Quantification Methods ........................................................................................................................................... 109 7.6 Grid Modernization Dependency ....................................................................................................................................................................... 109 7.7 Resilience Working Group ..................................................................................................................................................................................... 112 8 Grid Needs Assessment ........................................................................................................................................................ 114 8.1 Overview of Grid Needs .......................................................................................................................................................................................... 115 8.1.1 Capacity Expansion ...................................................................................................................................................................................... 116 8.1.2 Probabilistic Resource Adequacy ........................................................................................................................................................... 117 8.1.3 Grid Operations ............................................................................................................................................................................................. 118
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8.1.4 Transmission and System Security Needs .......................................................................................................................................... 118 8.1.5 Distribution Needs ....................................................................................................................................................................................... 119 8.1.6 Grid Modernization ...................................................................................................................................................................................... 123 8.1.7 System Protection Roadmap.................................................................................................................................................................... 123 8.1.8 Preferred Plan Development .................................................................................................................................................................... 124 8.2 Oʻahu .............................................................................................................................................................................................................................. 127 8.2.1 Capacity Expansion Scenarios.................................................................................................................................................................. 127 8.2.2 Resource Adequacy...................................................................................................................................................................................... 131 8.2.3 Grid Operations ............................................................................................................................................................................................. 135 8.2.4 Transmission and System Security Needs .......................................................................................................................................... 139 8.2.5 Distribution Needs ....................................................................................................................................................................................... 149 8.2.6 Preferred Plan ................................................................................................................................................................................................. 151 8.3 Hawaiʻi Island .............................................................................................................................................................................................................. 158 8.3.1 Capacity Expansion Scenarios.................................................................................................................................................................. 158 8.3.2 Resource Adequacy...................................................................................................................................................................................... 160 8.3.3 Grid Operations ............................................................................................................................................................................................. 161 8.3.4 Transmission and System Security Needs .......................................................................................................................................... 165 8.3.5 Distribution Needs ....................................................................................................................................................................................... 168 8.3.6 Preferred Plan ................................................................................................................................................................................................. 169 8.4 Maui ................................................................................................................................................................................................................................ 172 8.4.1 Capacity Expansion Scenarios.................................................................................................................................................................. 172 8.4.2 Resource Adequacy...................................................................................................................................................................................... 174 8.4.3 Grid Operations ............................................................................................................................................................................................. 176 8.4.4 Transmission and System Security Needs .......................................................................................................................................... 179 8.4.5 Distribution Needs ....................................................................................................................................................................................... 185 8.4.6 Preferred Plan ................................................................................................................................................................................................. 186 8.5 Molokaʻi ......................................................................................................................................................................................................................... 189 8.5.1 Capacity Expansion Scenarios.................................................................................................................................................................. 189 8.5.2 Resource Adequacy...................................................................................................................................................................................... 191 8.5.3 Grid Operations ............................................................................................................................................................................................. 192 8.5.4 System Security Needs ............................................................................................................................................................................... 195 8.5.5 Distribution Needs ....................................................................................................................................................................................... 196 8.5.6 Preferred Plan ................................................................................................................................................................................................. 197 8.6 Lānaʻi ............................................................................................................................................................................................................................... 199 8.6.1 Capacity Expansion Scenarios.................................................................................................................................................................. 199 8.6.2 Resource Adequacy...................................................................................................................................................................................... 201 8.6.3 Grid Operations ............................................................................................................................................................................................. 202 8.6.4 System Security Needs ............................................................................................................................................................................... 205 8.6.5 Distribution Needs ....................................................................................................................................................................................... 205 8.6.6 Preferred Plan ................................................................................................................................................................................................. 206 9 Customer Impacts ................................................................................................................................................................. 210 9.1 Financial and Bill Analysis ...................................................................................................................................................................................... 210 9.1.1 Revenue Requirements............................................................................................................................................................................... 210 9.1.2 Capital Expenditures .................................................................................................................................................................................... 211 9.1.3 Residential Customer Bill and Rate Impacts ...................................................................................................................................... 211 9.2 Oʻahu Financial Impacts .......................................................................................................................................................................................... 212 9.2.1 Revenue Requirements............................................................................................................................................................................... 212 9.2.2 Capital Expenditure Projections .............................................................................................................................................................. 213 9.2.3 Residential Customer Bill and Rate Impacts ...................................................................................................................................... 213 9.3 Hawai‘i Island Financial Impacts .......................................................................................................................................................................... 215 9.3.1 Revenue Requirements............................................................................................................................................................................... 215 9.3.2 Residential Customer Bill and Rate Impacts ...................................................................................................................................... 216 9.4 Maui County Financial Impacts............................................................................................................................................................................ 217 9.4.1 Revenue Requirements............................................................................................................................................................................... 218
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9.4.2 Residential Customer Bill and Rate Impacts ...................................................................................................................................... 219 9.5 Emissions and Environmental............................................................................................................................................................................... 223 9.5.1 Greenhouse Gas Emissions ....................................................................................................................................................................... 223 9.5.2 Emissions Reductions due to Electrification of Transportation ................................................................................................. 225 10 Energy Equity ......................................................................................................................................................................... 228 10.1 Equity Definitions ...................................................................................................................................................................................................... 228 10.2 LMI Programs .............................................................................................................................................................................................................. 228 10.3 Affordability and Energy Burden ......................................................................................................................................................................... 229 10.4 Community Benefits Package for Grid-Scale Projects ............................................................................................................................... 230 10.5 Renewable Energy Zone Development in Collaboration with Communities ................................................................................... 231 10.5.1 Oʻahu .................................................................................................................................................................................................................. 232 10.5.2 Maui .................................................................................................................................................................................................................... 233 10.5.3 Hawaiʻi ............................................................................................................................................................................................................... 233 10.6 Energy Transitions Initiative Partnership Project .......................................................................................................................................... 234 11 Growing the Energy Marketplace ....................................................................................................................................... 238 11.1 Customer Energy Resource Programs .............................................................................................................................................................. 238 11.1.1 Pricing Mechanisms ..................................................................................................................................................................................... 238 11.1.2 Customer Programs Valuation ................................................................................................................................................................ 240 11.1.3 Energy Efficiency as a Resource .............................................................................................................................................................. 247 11.2 Procurement Plan ...................................................................................................................................................................................................... 250 11.2.1 Process............................................................................................................................................................................................................... 250 11.2.2 Large-scale Competitive Procurements .............................................................................................................................................. 251 11.2.3 Long-term RFP ............................................................................................................................................................................................... 251 11.2.4 Bid Evaluation ................................................................................................................................................................................................. 252 11.2.5 NWA Competitive Procurement ............................................................................................................................................................. 253 11.2.6 Grid Services Competitive Procurement ............................................................................................................................................. 253 11.2.7 Revised Portfolio ........................................................................................................................................................................................... 254 12 Securing Generation Reliability and Assessing Risks ....................................................................................................... 256 12.1 Deactivation of Fossil Fuel–Based Generators .............................................................................................................................................. 257 12.2 Growth in Electric Vehicles .................................................................................................................................................................................... 262 12.3 Generation Reliability Risk Assessment............................................................................................................................................................ 263 12.3.1 Oʻahu .................................................................................................................................................................................................................. 263 12.3.2 Hawaiʻi Island .................................................................................................................................................................................................. 272 12.3.3 Maui .................................................................................................................................................................................................................... 281 12.3.4 Molokaʻi ............................................................................................................................................................................................................ 288 12.3.5 Lānaʻi .................................................................................................................................................................................................................. 294 13 Appendices ............................................................................................................................................................................ 300 Appendix A: Stakeholder Feedback and Public Input ............................................................................................................................................ A-1 Appendix B: Forecasts, Assumptions and Modeling Methods............................................................................................................................ B-1 Appendix C: Data Tables ..................................................................................................................................................................................................... C-1 Appendix D: System Security Study .............................................................................................................................................................................. D-1 Appendix E: Location-Based Distribution Grid Needs ........................................................................................................................................... E-1 Appendix F: NWA Opportunity Evaluation Methodology ................................................................................................................................... F-1 Appendix G: Revised Framework for Competitive Bidding ................................................................................................................................. G-1 Appendix H: Comments on Draft Integrated Grid Plan Report ......................................................................................................................... H-1
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ABBREVIATIONS
Abbreviations
Abbreviation Definition 2018$MM millions of 2018 dollars
AC alternating current
ADMS advanced distribution management system
AEG Applied Energy Group
AFOLU agriculture, forestry and other land use
AMI advanced metering infrastructure
ARA Annual Revenue Adjustment
ARD advanced rate design ATB annual technology baseline
BAU business as usual BESS battery energy storage system
C&S codes and standards CBRE community-based renewable energy
CCUS carbon capture, utilization and storage
CO2 carbon dioxide
CO2e carbon dioxide equivalent
DC direct current
DER distributed energy resources
DOE U.S. Department of Energy
DRC Designing Resilience Communities: A Consequence-Based Approach for Grid Investment
eBus electric bus
ECRC Energy Cost Recovery Clause
EE energy efficiency
EGS enhanced geothermal system
EIA U.S. Energy Information Administration EOI Expression of Interest
EoT electrification of transportation EPRM Extraordinary Project Recovery Mechanism
ETIPP Energy Transitions Initiative Partnership Project EUE expected unserved energy
EV electric vehicle GHG greenhouse gas
GMLC Grid Modernization Laboratory Consortium
GWh gigawatt-hour(s)
HEP Hamakua Energy Partners
HGGRC Hawaiʻi Groundwater and Geothermal Resource Center
HNEI Hawaiʻi Natural Energy Institute
HRS Hawaiʻi Revised Statutes
ICE Interruption Cost Estimator
IECC International Energy Conservation Code
IEEE Institute of Electrical and Electronics Engineers
IIJA Infrastructure Investment and Jobs Act
IPP independent power producer
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ABBREVIATIONS
Abbreviation Definition IPPU industrial processes and product use
IT information technology ITC Income Tax Credit
kg kilogram(s) km kilometer(s)
km2 square kilometer(s)
kV kilovolt(s)
kW kilowatt(s)
kWh kilowatt-hour(s)
LBNL Lawrence Berkeley National Laboratory
LDV light-duty vehicle
LiDAR light detection and ranging
LMI low to moderate income
LOLE loss of load expectation
LOLEv loss of load events
LOLH loss of load hours
MT metric ton(s) MVA megavolt-ampere(s)
MVAR megavolt-ampere(s) reactive MW megawatt(s)
MWh megawatt-hour(s) N/A not applicable
NESC National Electric Safety Code NIST National Institute of Standards and Technology
NOSC Network Operations and Security Center
NPV net present value
NREL National Renewable Energy Laboratory
NWA non-wires alternative
O&M operations and maintenance
OT operational technology
OTEC ocean thermal energy conversion
PGV Puna Geothermal Venture
PNNL Pacific Northwest National Laboratory
POET Power Outage Economics Tool
PPA power purchase agreement
PPAC Purchased Power Adjustment Clause PUC (Hawaiʻi) Public Utilities Commission
PV photovoltaic RBA Revenue Balancing Account
RDG renewable dispatchable generation ReNCAT Resilient Node Cluster Analysis Tool
Report Performance Metrics to Evaluate Utility Resilience Investments REZ renewable energy zone
RFP request for proposals
RPS renewable portfolio standards
SAIDI System Average Interruption Duration Index
SAIFI System Average Interruption Frequency Index
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ABBREVIATIONS
Abbreviation Definition SANDIA Sandia National Laboratory
SLH Session Laws of Hawaiʻi SLR-XA sea-level rise exposure area
SMR steam methane reforming STATCOM STATic synchronous COMpensator
State State of Hawaiʻi
STEM science, technology, engineering and mathematics
TAP Technical Advisory Panel
T&D transmission and distribution
TOU time of use
VAR voltage-ampere reactive
WIND Wind Integration National Dataset
ZEV zero-emissions vehicle
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GLOSSARY
Glossary
Term Definition
Battery energy storage A form of chemical storage that is able to store energy for use at another time. For example, a battery energy storage system can charge using solar energy during the day and discharge that energy for use at night.
Decarbonization To reduce, offset or eliminate all carbon-producing sources contributing to climate change. Decarbonization is a comprehensive approach to climate resilience that considers all sources of carbon emissions, including electricity generation, transportation, shipping, waste management, agriculture, manufacturing and land management. Distributed energy resources Refers to a behind-the-meter technology or device that can alter a customer’s energy use. These technologies include rooftop solar, battery storage, electric vehicles, controllable devices (i.e., grid-interactive water heaters) and energy efficiency. However, in this report it most often refers to rooftop solar and/or battery energy storage located behind a customer’s meter.
Energy efficiency Reducing the overall amount of electricity consumed. It also means improving buildings and appliances to use less energy. Reducing energy use and flattening peaks helps to stabilize customer bills, reduce the risk of outages and decarbonize Hawai‘i.
Firm generation Refers to a synchronous machine-based technology that is available at any time under system operator dispatch for as long as needed, except during periods of outage and deration, and is not energy limited or weather dependent.
Flexible generation Power plants that can start up, ramp up and down quickly and efficiently, and run at low output levels.
Grid needs The specific grid services (including but not limited to capacity, energy and ancillary services) identified through analysis, including transmission and distribution system needs.
Harden In the context of this report, generally refers to installation of grid infrastructure equipment designed and built to be more resistant to severe events.
Hybrid solar A solar system (typically referred to in the large-scale context) that uses photovoltaic technology and is paired with battery energy storage, with a typical duration of 4 hours. Microgrid A microgrid generates, distributes and regulates the supply of electricity to customers on a smaller, local scale compared to traditional, centralized grids. Microgrids are a group of interconnected loads and distributed energy resources within clearly defined boundaries. It is normally interconnected to the grid and can disconnect from the grid during emergencies. They are best suited to areas near critical infrastructure (such as hospitals and emergency response centers), have access to renewable energy resources, and are prone to prolonged outages during weather events.
Net present value The value of a future dollar amount that accounts for the time value of money.
Photovoltaic Commonly known as solar panels, this technology generates power by absorbing energy from sunlight and converting it into electrical energy.
RESOLVE A resource investment model developed by E3 that identifies optimal long-term generation investments in an electric system, subject to reliability, technical and policy constraints.
Resource adequacy The ability of the electric system to supply the aggregate electrical demand and energy requirements of the end-use customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.
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1 – EXECUTIVE SUMMARY
1 Executive Summary
Hawaiian Electric and our customers are rapidly transforming the ways we generate, transmit
and use electricity. Together, we are creating a resilient clean energy grid powered by resources
from Hawai‘i, for Hawai‘i. By 2045, our energy system will use 100% renewable resources and
produce net-zero carbon emissions, meaning whatever small amount of emissions we emit
will be captured or offset. Our work to modernize and decarbonize the grid has never been
more urgent as the effects of climate change escalate and existing electrical facilities and
infrastructure age. The world is watching as we innovate to scale up clean energy on islands with
abundant resources but no option to import renewables from neighbors.
We envision a clean energy future where
customers have more choices, more reliable
power and more stable rates. By 2045, clean
energy will be there when we need it: behind every light we turn on, each meal we share and all the ways we get around. Electric cars and buses will get us where we need to go, with a backbone of vehicle chargers at the workplace and community centers. At home and at work, energy-efficient appliances and equipment will electrify our daily lives.
This clean energy transformation will advance
social equity and benefit all customers and
communities. Enhanced grid capacity will support
growth in residential and commercial development, empowering a statewide expansion in affordable housing. In places with new energy facilities, host communities will thrive with benefit packages from developers.
The future grid will look unlike any before, with customers playing a vital role in generating and storing energy. Customer-scale generation and battery storage in customers’ homes and communities will seamlessly connect to large-
scale generation through a modernized
transmission system, providing a consistent
stream of energy that can adapt to fluctuations in
use. Sourcing energy from a diverse array of local, renewable resources will fortify Hawai‘i against global swings in oil prices, stabilizing utility costs for customers.
How can we bring this vision to life?
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1 – EXECUTIVE SUMMARY
It is possible to live out this vision if we work together and act now.
Hawaiian Electric is pleased to present the
Integrated Grid Plan: a pathway to a clean
energy future. The Integrated Grid Plan proposes
actionable steps to decarbonize the electric grid
on the State of Hawaiʻi’s (State’s) timeline, with a
flexible framework that can adapt to future
technologies.
The Integrated Grid Plan is the culmination of more than 5 years of partnership with stakeholders and community members across the islands. Together, we forecasted future energy needs and identified strategies to meet Hawai‘i’s growing energy demand with 100% renewable resources. Hawaiian Electric is grateful for the collective time, efforts and insights of the many people involved in Integrated Grid Planning, and we look forward to continued collaboration with
customers, community members and stakeholders
as we move beyond planning into
implementation.
This report shares our action plan and summaries of the technical analyses and community engagement. It also underscores the urgency of action needed to achieve this future. We hope the findings help drive or supplement other action plans beyond Hawaiian Electric. The Integrated Grid Plan shows that every industry and individual will need to play a role in decarbonizing Hawai’i’s economy. This plan can help customers, organizations and agencies understand the scope
of the challenge and their role in meeting it. It’s
everyone’s kuleana to create a sustainable future
for Hawai’i.
The Integrated Grid Plan is an important starting
point for focusing efforts and measuring progress.
Now, it’s time to take collective action to create a Hawaiʻi Powered future where everyone will thrive.
1.1 Customers Are at the
Heart of the Energy
Transformation
Again and again throughout the planning process,
we heard that affordability and reliability are of top concern and interest to our customers, echoing the comments in multiple customer surveys and focus groups conducted for the company.
It is imperative that our future grid delivers on
this fundamental need for pricing and power
that people can count on.
The Integrated Grid Plan balances our
commitment to clean energy with our
commitment to stabilizing rates and improving
reliability for customers.
The Integrated Grid Plan also shows that
customer and community participation is essential to decarbonizing Hawai‘i’s economy. Our analysis reveals that we cannot meet projected demands on the grid without customers and communities generating and storing energy and practicing greater energy efficiency (EE). Read more about the role of customers in Section 1.5.2.
Meaningful and sustained engagement with customers, communities and stakeholders has been central to Integrated Grid Planning, and it
STATE OF HAWAI‘I’S
ENERGY EFFICIENCY GOAL:
Reduce the state’s total electricity
consumption across all islands by 4,300
gigawatt-hours by 2030. To put this in
perspective: 4,300 gigawatt-hours is enough energy to power more than 700,000 homes.
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1 – EXECUTIVE SUMMARY
will be instrumental in moving beyond planning into action. Since planning began in 2018, we have worked to foster partnerships with communities that we are a part of and serve by sharing transparent information and listening,
learning and incorporating their feedback. We are
grateful for the involvement of thousands of
community members throughout the planning
process, and we appreciate the opportunities we
have had to collaborate on potential solutions.
See Section 4 for more information about outreach activities and how we have incorporated public input.
1.2 Our Commitment to
Customers
At Hawaiian Electric, customers are at the heart of
our work today and our vision for the future. We are deeply rooted in our communities, and we strive to serve the energy needs of each person in Hawai‘i with purpose, compassion, empathy and aloha for our fellow humans and our natural environment. We are committed to empowering our customers and communities with affordable and reliable clean energy, and providing innovative energy leadership for Hawai‘i.
1.2.1 Climate Change Action Plan
Decarbonizing the electric grid is ultimately about service: caring for our customers and the environment by creating a more prosperous and sustainable Hawai‘i. To that end, Hawaiian Electric announced a bold Climate Change Action Plan in 2021. Our Climate Change Action Plan sets the ambitious goal of reducing electricity-sector greenhouse gas (GHG) emissions in 2030 by 70% compared to 2005 levels and reaching net-zero
carbon emissions by 2045.
This commitment by Hawaiian Electric represents a significant down payment on the economy-wide reduction Hawai‘i will have to achieve to align with nationwide and global GHG reduction goals.
Statewide decarbonization will require
collaboration across sectors, with transportation,
agriculture and other industries working to reduce
and offset emissions.
1.2.2 Hawai‘i Powered
A key strategy to reaching net-zero emissions is generating 100% of our energy from renewable resources. In 2015, Hawai‘i became the first state in the nation to direct its utilities to generate 100% of their electricity from renewable energy
sources by 2045. Hawaiian Electric is dedicated to
partnering with customers, communities and
other stakeholders to reach this energy goal.
DECARBONIZE:
To reduce, offset, or eliminate all
carbon-producing sources contributing to climate change. Decarbonization is a comprehensive approach to climate resilience that considers all sources of carbon emissions, including electricity generation, transportation, shipping, waste management, agriculture, manufacturing, and land management.
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1 – EXECUTIVE SUMMARY
We call our vision for using 100% renewable resources “Hawai‘i Powered.” Clean energy for Hawai‘i, by Hawai‘i:
■ Supports our Climate Change Action Plan and the State’s decarbonization goals
■ Achieves energy independence
■ Expands energy choices for customers and
helps stabilize rates
1.2.3 Ensuring an Equitable
Energy Transformation
We are committed to creating an equitable energy
future. As the cost of living in Hawai‘i continues to
rise, we must make electricity affordable and
ensure that we ease the burden of the renewable
transition on customers with low to moderate income (LMI). We must also ensure that
communities that bear the burden of hosting energy infrastructure, both in the past and future, receive benefits.
The Hawaiʻi Public Utilities Commission (PUC) recently opened a proceeding to investigate energy equity in response to legislative resolutions. The areas for exploration include:
■ High energy rates in Hawai‘i
■ High percentage of people with low and moderate income
■ High energy burden
■ Lack of universal access to renewable energy
initiatives
■ Need for utility payment assistance
■ Historical siting of fossil-fuel infrastructure
■ Land constraints
■ Regulatory process burdens
The benefits and burdens of the transformation to a clean energy grid must be equitably shared. All customers stand to benefit if everyone is able to afford electricity and participate in the transition.
See Section 10 for more information about our ongoing efforts to address energy inequities and offer solutions for the future.
We use the following definitions from the Public Utility Commission to guide planning for energy equity:
Equity refers to achieved results where advantages and disadvantages are not
distributed on the basis of social
identities. Strategies that produce
equity must be targeted to address the
unequal needs, conditions, and
positions of people and communities
that are created by institutional and structural barriers.
Energy equity refers to the goal of achieving equity in both the social and economic participation in the energy system, while also remediating social, economic, and health burdens on those historically harmed by the energy system.
People with low to moderate income
are those whose income is at or below
150% of the Hawai‘i federal poverty
limit.
Energy burden is the percentage of a
household's income spent to cover energy costs.
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1 – EXECUTIVE SUMMARY
1.3 Renewable Energy and
Reliability Risks Today
Hawaiian Electric has the privilege of serving as Hawai‘i’s largest electric utility. We serve 95% of Hawai‘i’s 1.4 million residents on the islands of Hawai‘i, O‘ahu, Maui, Lānaʻi and Molokaʻi, each with separate grids. Since 2010, we have nearly tripled the amount of renewable energy we generate, due in large part to the contributions of our customers. We are proud of the progress we have made, but we still have a long way to go.
1.3.1 Our Current Renewable
Energy Portfolio
Today, approximately 32% of our total energy generation comes from renewables. Our renewable energy comes from many local sources with wide-ranging technologies, and each island has a unique composition of clean energy generation. Figure 1-1 shows the 2022 composition of clean energy generation on Hawai‘i Island, O‘ahu and Maui County, and the consolidated proportions across all three. Additional information on the generation by
resource type and county can be found in the
annual Renewable Portfolio Standard Status Report.
Figure 1-1. Renewable energy portfolios, 2022
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1.3.2 Immediate Action to Meet
Goals and Maintain
Reliability
Creating a resilient, clean energy grid has never been more urgent as the effects of climate change escalate, existing energy infrastructure ages and our timelines shrink. Customers are at risk of
experiencing increasingly frequent outages unless
we take immediate action to address threats to
reliability.
We must act now to bolster the reliability of our electric grid and prevent significant economic and social disruption for customers. Investing in renewable energy generation and updates to transmission infrastructure is an opportunity to
address these risks. See Sections 7 and 12 for
more information about investments and actions
to reduce risks to electrical infrastructure.
We must move swiftly to:
Fortify the grid against extreme weather.
Extreme weather hazards are projected to increase in frequency, intensity, and
duration because of climate change. Failure to prepare for such events could result in power interruptions, damage to electricity infrastructure, significant
economic disruption, and disruption to critical government and private-sector services. Reliability is a matter of safety and state and national security, as our critical infrastructure—like hospitals, communication systems, and emergency
services—depends on electricity.
Meet growing energy demands.
Existing fossil fuel–based generators on Hawaiʻi Island, Maui, and Oʻahu are 55 to 75 years old. These facilities were never designed to keep up with today’s
dynamic grid, which far outpace the needs of decades past and continue to grow. We anticipate that the demand for electricity will dramatically increase in the coming years, as other sectors reduce their carbon emissions, and as customers
and businesses use more electricity for their transportation, work, and homes. We’re in urgent need of more generation capacity to meet this demand.
Cut carbon emissions by 70% in 7 years.
2030 is just around the corner. We need to rapidly develop energy projects and
the necessary infrastructure across the islands to meet our Climate Change Action Plan goal of cutting emissions by 70% (compared to 2005 levels). This will take efficient and effective coordination with communities, policymakers,
stakeholders, and developers to bring renewables online as we deactivate fossil fuel–based generators. Simply put: there's no time to waste.
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1.4 Overview of Integrated
Grid Planning
Integrated Grid Planning brought many people together to determine how to create a resilient and reliable grid that will meet future energy needs, stabilize costs for customers and use 100% renewable resources. Hawaiian Electric began the planning process in 2018. Figure 1-2 displays the steps of Integrated Grid Planning.
Figure 1-2. High-level steps of Integrated Grid Planning
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1.4.1 Engaging Communities and
Stakeholders
We engaged four main stakeholder groups throughout the planning process:
The four Integrated Grid Planning stakeholder
groups were not working alone—many others have been and continue to be involved in creating a clean energy future. These groups include policymakers, regulators, developers and community organizations.
1.4.2 Key Considerations
Stakeholders helped us prioritize and connect five
key considerations that shape our planning for a
clean energy future:
■ Time. How much time will it take to deliver
new energy facilities, and how can we stay on track with our timeline goals?
■ Affordability. How much will it cost to build and operate? What will resources cost in the future? How will costs affect customer bills?
■ Land use. Where is there available land? How does this affect other land use priorities?
■ Community impacts. How will new facilities affect surrounding communities, jobs and
the environment? How can the benefits of
the transition to clean energy be equitably
shared?
■ Resilience and reliability. How can we plan
for current and future energy needs? Needs
evolve based on the number of electric vehicles (EVs), number of private and community-based solar projects, emerging technologies and industries and preparation for extreme events.
Understanding energy needs of today and tomorrow required many technical analyses and input from stakeholders and community
members. Together, we forecasted future energy needs and identified opportunities to meet growing demands.
See Sections 6 and 8 for information about the
data and models we used to forecast grid needs.
See Section 4 for an overview of outreach
strategies and community input we received about potential future energy projects and key considerations.
The four main stakeholder groups:
Stakeholder Council. This group consisted of representatives from cities, counties, each island, the State, partner agencies, and developers. It helped align our planning with interests across the islands.
Working Groups. These specialized groups served in an advisory capacity and were focused on topics like social
and economic resilience, transmission
planning, and the sourcing and
evaluation of contractors.
Technical Advisory Panel. This group
consisted of experts in energy
technologies and engineering who provided an independent source of peer assessment.
The public, including customers and community members across the islands.
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1.4.3 Guiding Principles
The following principles guided our technical
analyses and community conversations as we
moved through Integrated Grid Planning.
Renewable energy is the first option. We are pursuing cost-effective renewable resource
opportunities that reduce carbon emissions and stabilize customer bills. Getting off imported
fossil fuels removes Hawai‘i from the volatility of world energy markets and gives future generations
a tremendous advantage. It can also create a clean energy research and development industry for
our state.
The energy transformation must include everyone. Electricity is essential. Our plans, as well as public policy, should ensure access to affordable electricity, with special consideration given to LMI households. Meaningful community participation must be a key element of renewable project planning.
The lights have to stay on. Reliability and resilience of service and quality of power are vital for our economy, national security and critical infrastructure. Our customers expect it, deserve it and pay for it. Our plans must maintain or enhance the resilience of our isolated island grids by relying on a mix of resources and technologies.
Today’s decisions must be open to tomorrow’s breakthroughs. Our plans keep the door open
to developments in the rapidly evolving energy space. We must be able to easily accept new,
emerging and breakthrough technologies that are cost-effective and efficient when they become
commercially viable.
The power grid needs to be modernized. Energy distribution is rapidly moving to the digital age.
We are reinventing our grid to facilitate a decarbonized energy portfolio and to enable technologies such as demand response, dynamic pricing, aggregation and electrification of transportation (EoT).
Our plans must address climate change. Our Climate Change Action Plan set a goal to reduce carbon emissions from power generation by 70% by 2030 compared with 2005 levels. Our resilience strategy aims to minimize the impacts of climate change—rising sea levels, coastal erosion, increased temperatures and extreme weather events—on the energy system.
There’s no perfect choice. No single energy source or technology can achieve our clean energy goals. Every choice has an impact, whether it’s physical or financial. While we can mitigate those impacts, attaining our clean energy goals has major implications for our land and natural resources, our economy and our communities. We seek to make the best choices by engaging with community members, regulators, policymakers and other stakeholders.
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1.4.4 Energy Planning on
Moloka‘i and Lāna‘i
We tailored our planning and community engagement strategies to each island, recognizing that they have unique energy needs and opportunities. Planning for a clean energy future on Lāna‘i and Moloka‘i was particularly distinct for the following reasons.
1.4.4.1 Lāna‘i
Much of our grid planning work on Lānaʻi
happened in collaboration with the majority
landowner on the island. The Hawaiian Electric
team announced its selection of a developer to
build and maintain the island’s largest renewable
energy project and the first to offer the shared
solar program on the island. We completed contract negotiations with DG Development & Acquisition, LLC. However, we have not finalized the contract as the majority landowner, Pūlama Lānaʻi notified Hawaiian Electric of its intent to design and construct microgrids to supply the energy demands of the resorts on Lānaʻi, which would significantly impact the electric load and the size of the solar project.
1.4.4.2 Moloka‘i
Moloka‘i is preparing a Moloka‘i Community Energy Resilience Action Plan: an independent,
island-wide, community-led and expert-informed
collaborative planning process to increase
renewable energy on the island. The Moloka‘i
Clean Energy Hui by Sustʻāinable Moloka‘i is
coordinating the action plan. Hawaiian Electric is
providing technical support to the Moloka‘i Clean Energy Hui in its planning process to develop a portfolio of clean energy projects to achieve 100% renewable energy for the island that is feasible, respectful of Moloka‘i's culture and environment, and strongly supported by the community.
Learn more at sustainablemolokai.org/renewable-energy/molokai-cerap.
Hawaiian Electric and Ho‘āhu Energy Cooperative Moloka‘i are moving ahead with the State’s first two community-owned and ‑designed solar plus
battery projects. These projects could meet more
than 20% of Moloka‘i’s energy needs and serve an
estimated 1,500 households on the island. The
Ho‘āhu Community-Based Renewable Energy
(CBRE) projects, Pālā‘au Solar and Kualapu‘u Solar, will be the first on the island to offer the shared solar program to help lower the electric bills of customers on Moloka‘i who are unable to install privately owned rooftop solar.
After the completion of a competitive bidding evaluation process, which accounted for the cost of the projects as well as non-price factors including community outreach, Ho‘āhu and Hawaiian Electric entered into negotiations. Once
negotiations of the 20-year contracts are finalized,
Hawaiian Electric and Ho‘āhu will submit the two
applications for approval by the PUC.
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1.5 Action Plan at a Glance
Meeting the energy needs of our customers up to and beyond 2045 requires an Integrated Grid Plan based on a short-term action plan and a long-term strategy. First, the Integrated Grid Plan requires us to take immediate action within the next 5 years to achieve our 2030 goals and set a path toward 2045 decarbonization. The proposed
5-year action plan identifies the next foundational
steps toward meeting our decarbonization,
affordability and reliability goals for customers.
Second, the Integrated Grid Plan also provides the
flexibility we need over the long term to realize the benefits of technological advances, respond to changing customer and community needs and adapt to evolving environmental conditions.
The following is an overview of the Integrated Grid Plan key findings and recommended actions for the short term. See Section 2 for details.
1.5.1 Key Findings and
Recommendations
The Integrated Grid Plan points to four high-level actions we must take within the next 5 years to reach statewide decarbonization goals and future energy needs:
The following is an overview of these actions. See Section 2 for details.
Stabilize utility rates and advance energy equity
Grow the marketplace for customer-scale and large-scale renewables
Create a modern and resilient grid
Secure reliability through diverse energy sources and technologies
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1.5.2 Action Plan for a Clean
Energy Future
Stabilize rates and advance
energy equity
While utility rates may rise during the near-term
transition to clean energy, they will be lower and
less volatile than if we continue to rely on fossil fuels. Our projections show that customer bills may remain relatively flat over the long term, despite growing demands for electricity, integration of renewables and investments to modernize and strengthen the grid. The addition of customer-scale and large-scale renewable energy is expected to stabilize rates and insulate all customers from volatile fossil-fuel markets. Additionally, the electrification of transportation may drive benefits for all customers by putting
downward pressure on rates. Increased
electrification of transportation enables the cost of
grid investments to be spread over more kilowatt-
hours (kWh), reducing per-unit customer costs and introducing opportunities to provide grid services. See Section 9 for more information about impacts to customer bills and the environment.
We are committed to an equitable energy
transition that addresses the total energy
burden on low- and moderate-income customers.
To that end, the Integrated Grid Plan may help to
inform the Energy Equity proceeding that aims to
examine forms of relief for LMI customers. Our
projections show that the transition to clean
energy may reduce the overall energy burden for the typical residential customer on each island through 2050, compared to today's energy burden. See Section 10.3 for more information about affordability and the energy burden.
Grow the marketplace for
customer-scale and large-scale
renewables
We will need a marketplace for both customer-scale and large-scale renewables to achieve 100% clean energy by 2045. To grow the market for large-scale projects that also benefit host communities, we propose routine cyclical procurements with public input and community benefit packages from developers.
We also propose customer programs and options with incentives to increase customer participation
in rooftop solar, energy storage, vehicle charging
and energy efficiency. Customer participation and
early community outreach are instrumental to
electrifying and decarbonizing the state’s economy.
Customer-scale generation is also an opportunity
to promote energy equity by continuing to develop programs that expand access to a wider range of customers. Programs like shared solar (CBRE) are essential for all customers to benefit from generating renewable energy, not only those who own their homes and rooftop solar systems. See Section 11 for more information about customer programs and large-scale procurements.
Customer participation also includes energy
efficiency. Residential and commercial customers
must adopt energy conservation measures to
meet the State’s 2030 and 2045 decarbonization
goals. By 2030, we will need more than 3,400
gigawatt-hours (GWh) of energy efficiency
measures implemented in homes and businesses on Hawai‘i Island, Maui, O‘ahu, Lānaʻi and Moloka‘i to reduce carbon emissions.
With customer participation in energy efficiency, generation and storage, the Integrated Grid Plan will benefit the environment by reducing carbon emissions by up to 75% by 2030, relative to 2005 levels. However, achieving net zero will depend on technology advancements.
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We forecast that energy generation and storage
by customers and communities can provide
enough electricity to power the transition to
electric vehicles, and it will also reduce the
amount of land needed for large-scale
renewables.
Create a modern and
resilient grid
Renewable generation is just one piece of the
energy transformation puzzle. We will also need a modern, resilient system of transmission and distribution (T&D) for customers to power their electric vehicles, connect rooftop solar systems and large-scale renewable generation hubs, support the expansion of affordable housing and fortify the grid against extreme weather events. This will require investment in distribution, transmission and grid hardening.
The State’s economic and policy goals include
developing new housing and commercial
development to expand our economy while
addressing equity. These homes and businesses
will be electrified with clean energy, increasing net
demand on the grid. To support this effort, we estimate that over the next 10 years, up to $59.4 million of distribution upgrades and $1.33 billion in renewable energy zone (REZ) enablement and transmission network upgrades are needed.
We will be actively pursuing the opportunity to
partner with our customers to shape energy use.
Secure reliability through diverse
energy sources and technologies
A diverse grid is a reliable grid. We propose investing in many different resources at various scales, including large-scale renewable and firm generation to replace aging fossil fuel–based generators. A fleet of large-scale renewable and firm generation will ensure that we have a source of stable, consistent power on standby to supplement smaller-scale generation on customers’ homes and communities, as well as weather-dependent resources like solar and wind.
The sooner we modernize the generation
portfolio with the right types of resources, the
sooner we can retire or deactivate our older
fossil-fuel plants.
LARGE-SCALE RENEWABLE GENERATION:
Large-scale generation facilities and transmission infrastructure produce and carry a large volume of energy. This includes wind
turbines and solar and battery energy storage facilities, as well as electric substations, poles and wires.
FIRM GENERATION:
Firm generation provides a steady, reliable flow of energy because it uses resources that
are not weather-dependent. Examples of firm generation are geothermal, waste-to-energy, and green hydrogen.
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1.5.3 Timeline of Renewable
Energy Procurement
The Integrated Grid Plan outlines the amount of energy generation we will need to procure to meet statewide decarbonization goals. Figure 1-3 displays a high-level timeline of adding renewable generation capacity, retiring fossil fuel–based generation and reducing carbon emissions. Though development of REZs and distribution upgrades is not highlighted in the timeline, it is a key enabler of the integrated grid. Figure 1-4
shows our Integrated Grid Plan’s renewable
energy portfolio. This portfolio and timeline reflect
the Preferred Plan Base scenario detailed in this
report.
Figure 1-3. Proposed timeline of adding renewable resources, retiring or deactivating fossil fuel–based generation and reducing carbon emissions
HYBRID SOLAR:
A solar system (typically referred to in
the large-scale context) that uses photovoltaic (PV) technology and is paired with battery energy storage, with a typical duration of 4 hours.
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Figure 1-4. Consolidated RPS from today through 2045
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1.6 Moving beyond Planning
into Action
Energy planning does not exist in isolation—it’s interconnected with many other aspects of life and public policies. It is therefore imperative that any long-term plans for Hawai‘i’s energy future
balance multiple State policy objectives, including
affordable housing, food sustainability, land use
and economic development. Effectively
implementing the Integrated Grid Plan will
depend on:
■ Enhanced energy policies and alignment with other State policy objectives
■ Coordination of regulatory, county and State processes
■ Stakeholder and community outreach,
engagement and partnership
■ Actions outside of and beyond Hawaiian
Electric
None of us can implement the Integrated Grid Plan alone. It will take continued collaboration of customers, communities, utilities, counties, the State and other industries to meet decarbonization goals and live out a resilient clean energy future.
The longevity of our beloved islands for future generations depends on our ability to come together, get creative and get to work creating a more sustainable Hawai‘i.
The time for action is now.
Why is rooftop solar not enough?
We need a mix of customer-scale and large-scale renewable generation to supply enough
power to meet future energy demands. As much as we value rooftop solar, it is not enough
on its own to power the whole grid.
■ A diverse power system is resilient. Generating electricity from a diverse portfolio of resources benefits our overall energy resilience and customer bills. Diversifying our energy generation to include customer-scale and community resources and large-scale renewables (including sources beyond solar) keeps us from depending on any one source for our electricity. This helps us bounce back faster from disasters and shields us from fluctuating costs of resources. For customers, this means reduced risk of outages and more stable utility bills.
■ We need customer-scale and large-scale resources to meet Hawai‘i’s energy needs. As much as we value rooftop solar and distributed storage, they are not enough on their own to power the whole grid. This is especially true in a clean, electrified future. For example, to replace just one fossil-fuel generator on O‘ahu, we estimate needing new wind and solar resources with a collective footprint 29 times the size of
Aloha Stadium. Customer adoption of rooftop solar is not projected to reach the level and reliability to
meet all customers’ electricity needs. New, large-scale renewable resources will be a significant part of a
Hawaii Powered future.
■ Clean energy must be affordable and equitable for all customers. Electricity affordability is a critical
factor to achieve Hawai‘i’s decarbonization goals. This requires careful consideration of energy equity and the cost-effectiveness of our collective customer, community and large-scale renewable resources and storage options. Each of these resource and storage options have benefits and challenges that need to be assessed. No single renewable technology solution addresses all of Hawai‘i’s needs. We need to develop a diversified renewable portfolio that is affordable, equitable, and reliable for all customers.
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2 Action Plan
Our action plan focuses on efficient strategies to swiftly decarbonize the electric grid and
manage risks to affordability, resilience and reliability. We find that cutting carbon emissions
by 70% by 2030 is possible through an “all of the above” approach that seeks to expand
customer participation and large-scale generation and infrastructure. Establishing a
competitive energy marketplace for both customer-scale and large-scale renewables
underpins our ability to create an affordable transition. This will take a statewide effort that
involves government, communities and industry partners. We also describe conditions and
policies that we need to successfully meet statewide decarbonization goals, and we
recommend next steps to move beyond planning into implementation.
2.1 Key Findings and Recommendations
The Integrated Grid Plan points to four high-level actions we must take within the next 5 years to decarbonize the grid while ensuring reliable power and stable rates for customers:
Stabilize utility rates and advance energy equity
Grow the marketplace for customer-scale and large-scale renewables
Create a modern and resilient grid
Secure reliability through diverse energy sources and technologies
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2.1.1 Stabilize Utility Rates and Advance Energy Equity
It is imperative that our future grid delivers on the fundamental need for pricing and power that people can
count on. While utility rates may rise during the near-term transition to clean energy, they will be lower than
if we continue to rely on fossil fuels. We are committed to an equitable energy transition that benefits all
customers and communities. To stabilize rates and advance energy equity, we will need to:
Pursue the least costly pathway, which
maximizes solar, wind and energy storage. We can stabilize rates and mitigate uncertainties in volatile fossil-fuel pricing by acquiring solar, wind and energy storage through fixed-price contracts.
These contracts will provide predictable rates for
20 years or more.
Provide at least $3,000 per megawatt in community benefits packages per year to host communities of large-scale projects. It’s essential
that all communities benefit from the transition to clean energy. We propose that developers of new renewable generation provide at least $3,000 per megawatt (MW) per year in community benefits packages to the communities that bear the burden of those energy projects and infrastructure. By 2035, our plan calls for up to 1,640 MW of new renewable resources across our service territories.
Keep rates lower than the status quo of fossil-
fuel reliance. While utility rates may rise during the near-term transition to clean energy, they will be lower and less volatile than if we continue to rely on fossil fuels. Our projections show that customer bills may remain relatively flat over the long term, despite growing demands for electricity, integration of renewables and investments to modernize and strengthen the grid. The addition of customer-scale and large-scale renewable energy is expected to stabilize rates and insulate all customers from volatile fossil-fuel markets. Additionally, the electrification of transportation may drive benefits for all customers by putting downward pressure on
rates. Increased electrification of transportation enables the cost of grid investments to be spread
over more kilowatt-hours (kWh), reducing per-unit
customer costs and introducing opportunities to provide grid services. See Section 9 for more information about impacts to customer bills and the environment.
Examine forms of relief for LMI customers. We are committed to an equitable energy transition that addresses the total energy burden on LMI customers. Our projections show that the transition to clean energy may reduce the overall energy
burden for the typical residential customer on each island through 2050, compared to today's energy burden. See Section 10.3 for more information about affordability and the energy burden.
Pursue federal funding to expand customer access to renewable technologies and reduce the cost of grid modernization. We must expand access to available federal incentives for customer technologies such as energy efficiency.
We currently have grant applications pending with the U.S. Department of Energy (DOE) to gain funding to offset costs to implement our Climate Adaptation Transmission and Distribution Resilience program to harden grid infrastructure and for Phase 2 of our grid modernization program.
Actions we can take within the next 5 years to stabilize rates:
Use competitive procurements to the extent possible for all types of renewable generation as a means to attract lowest pricing possible for customers
Pursue federal funding with up to 50% match for climate adaptation program and Phase 2 grid modernization
Work with stakeholders to address affordability through the Energy Equity docket
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2.1.2 Grow the Marketplace for Customer-scale and Large-scale
Renewable Generation
We will need a lot more renewable energy to electrify Hawaiʻi's economy and transportation system by 2045. As we retire fossil fuel–based generation, that volume of energy will come from two primary sources: customer-scale renewable generation and large-scale renewable generation. We must support customers in adopting energy conservation measures, installing rooftop solar and battery storage, and we must also rapidly develop large-scale generation facilities. To grow a thriving, competitive marketplace for these two types of generation, we will need:
Greater customer participation in energy generation and storage. Customer adoption of
private rooftop solar and energy storage is needed
to meet the State of Hawaiʻi’s (State’s) 2030 and
2045 decarbonization goals. By 2030, we will need
more than 125,000 residential and commercial
private rooftop solar and energy storage systems
(1,186 MW) across our service territories. These customer resources, along with energy efficiency will help to offset the energy and capacity needed to power electrification of light-duty vehicles (LDVs), reducing land requirements for large-scale resources.
Customer-scale generation is also an opportunity to promote energy equity by continuing to develop programs that expand access to a wider
range of customers. Programs like shared solar
(CBRE) are essential for all customers to benefit
from generating renewable energy, not only those
who own their homes and rooftop solar systems.
See Section 11 for more information about
customer programs and large-scale procurements.
Widespread adoption of energy efficiency. Residential and commercial customers must adopt energy conservation measures to meet the State’s 2030 and 2045 decarbonization goals. By 2030, we will need more than 3,400 gigawatt-hours (GWh) of energy efficiency measures implemented in homes and businesses across the islands to reduce carbon emissions. With customer
participation in energy efficiency, generation and
storage, the Integrated Grid Plan will benefit the
environment by reducing carbon emissions by 75% by 2030 relative to 2005 levels.
Rapid development of low-cost renewables
and transmission. The near-term path toward
70% greenhouse gas (GHG) reduction by 2030
requires wind, solar and energy storage enabled
by transmission facilities as a relatively low-cost
way to scale up renewable energy and displace
fossil fuels. On O‘ahu alone, we will need nearly 3,000 MW of large-scale solar generation by 2050, built on 19,300 acres of land. Developing renewables and transmission will require community support and streamlined regulatory reviews, permitting and execution.
Actions we can take to begin increasing customer participation:
Implement new distributed energy resources (DER) programs to use deployed advanced metering infrastructure (AMI): Smart DER Tariff and bring-your-own-device options, targeting 1,186 MW of private rooftop solar capacity by 2030
Implement community-based renewable energy projects for low- and moderate-income customers and the Tranche 1 procurement
Implement advanced rate designs and conduct time-of-use (TOU) study to use deployed AMI
Procure energy efficiency and other grid services to meet grid needs and reduce supply-side requirements
Review lessons learned from the Phase 2 Tranche 1 community-based renewable energy procurement, and propose changes, if necessary, for a more robust program
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However, if land for renewable projects is more limited in the future, we will need to consider higher-cost alternatives. If low-cost renewables are not available in sufficient quantities in the Land-Constrained scenario, higher-cost
alternatives such as increased use of biofuels
will need to be considered to meet
decarbonization goals.
Actions we can take to start developing low-cost renewables and transmission:
Update key assumptions based on current market conditions (i.e., fuel forecasts) during and following the Stage 3 request for proposals (RFP)
Complete Stage 3 procurement and work with stakeholders to execute the projects that are selected
Complete Land Request for Information to identify potential sites for large-scale renewable generation and development of REZs in concert with communities
Issue an additional competitive procurement for renewable dispatchable generation after Stage 3 and determine market for long lead renewable resources (i.e., offshore wind and other technologies to achieve commercial operations by 2035) and REZs for each island
Continue finding solutions to improve the interconnection process, including working with State and county agencies
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2.1.3 Create a Modern and Resilient Grid
Renewable generation is just one piece of the energy transformation puzzle. We will also need a modern
system of transmission and distribution for customers to power their electric vehicles, connect rooftop solar
systems and large-scale renewable generation hubs, support the expansion of affordable housing and fortify
the grid against extreme weather events. To create a resilient grid with enough capacity to meet the State’s
policy goals, we will need:
Investment of $59.4 million in distribution upgrades over the next 10 years. The State’s economic and policy goals include developing new housing and commercial development to expand our economy while addressing equity. These homes and businesses will be electrified with clean energy, increasing net demand on the grid. To support this effort, we estimate that over the next 10 years, $59.4 million in distribution investments may be needed. However, we will be actively pursuing the opportunity to partner with our customers to shape energy use and their solar/storage resources to potentially reduce/defer some of the investment needed.
Investment of $1.33 billion through 2035 to expand or create new transmission interconnection points between renewable projects. The transmission system remains the backbone of the grid. Creating hubs and enabling transmission facilities for large-scale projects will streamline interconnection and provide access to untapped renewable potential and growth in electrified loads. By 2030, investments are needed to create renewable energy zones (REZs) that connect generation hubs through a modern system of transmission and distribution. Beyond 2030, major transmission expansion is needed on
O‘ahu, Hawai‘i Island and Maui to reach areas with untapped renewable potential and to increase the capacity for electrification of transportation.
Initial investment of $190 million to improve the resilience of the transmission and distribution grid. Resilience grid investments are needed to prepare the grid to withstand natural disasters and support deploying microgrids; for example, hardening critical transmission lines, highway crossings and critical poles on
distribution circuits serving vital community infrastructure. These “least-regrets” investments align with the top stakeholder-identified threats: hurricanes, floods and extreme wind events.
Near-term actions to upgrade the distribution system:
Issue expressions of interest for qualified distribution non-wires alternatives opportunities
Prepare extraordinary project recovery mechanism requests to implement distribution upgrades needed to support electrification and expansion of private rooftop solar hosting capacity, and other requests to support expanded distribution capacity for new housing and commercial developments
Near-term actions to develop REZs:
Continue community engagement to determine feasibility of developing REZs
Create a transmission siting and routing process in collaboration with communities, State, county, landowners, and project developers
Near-term actions to improve grid resilience:
Pending Public Utilities Commission approval, implement and execute a 5-year, $190 million climate adaptation program to harden our grid and implement other resilience measures
Develop resilience modeling and performance target levels of resilience to inform future hardening and other resilience investments
Leverage an energy transition initiative partnership program and Resilience Working Group to identify other microgrid opportunities
Execute North Kohala microgrid and RFP, apply lessons learned, and pursue additional microgrid opportunities to enhance community resilience
Complete rollout of AMI and obtain approval of phase 2 grid modernization to enhance system reliability and resilience
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2.1.4 Secure Reliability through Diverse Energy Sources and Technologies
A diverse grid is a reliable grid—we must invest in a diverse array of resources to provide power that
customers can count on through rain or shine. Modern firm generation is a critical component of a diverse
grid. It will replace fossil fuel–based generation and provide a source of stable, consistent power on standby
to supplement weather-dependent resources and “fill in the gaps” at times when solar and wind are not
sufficient. Creating a reliable clean energy grid will require:
Developing renewable firm generation that is modern and flexible. It is not possible to ensure a consistent, reliable flow of electricity if the entire grid is powered by weather-dependent, energy-limited resources. Investing in firm generation that is flexible, with the ability to quickly start and ramp up, will enable a reliable source of power when conditions are not optimal for solar or wind generation. It will also address vulnerabilities with
today’s system, where aging thermal units still supply most of our energy.
Rapidly deploying renewable firm generation is
also a solution for managing the deactivation of
fossil fuel–based generation. The sooner we transition to modern, flexible firm generation and a critical mass of solar, wind and storage resources, the sooner we can deactivate and retire fossil fuel–based generation.
In particular, the O‘ahu and Maui systems will not be reliable if we do not procure replacement firm generation prior to retirement of existing firm generators.
Adoption of emerging technologies. Shifting to a highly dynamic, decentralized grid will come with risks and uncertainties. It will require investments that we may not be able to identify today, and it will rely on advancements in current technologies. We anticipate that the system of tomorrow will operate on a much faster time scale than today, requiring resources that can act quickly to stabilize the grid. We will need a critical
mass of hybrid solar, wind and/or standalone
energy storage plants with grid-forming capability
to replace fossil fuel–based generation. By adding
many variable, inverter-based resources in various
locations, new challenges may arise in ensuring the security of the system.
Current functionality of rooftop solar and energy storage systems poses a risk to system stability. However, these risks may be mitigated through additions in large-scale renewable resources with grid-forming capability, improved performance of customer rooftop solar and energy storage systems (including legacy systems) and technological advancements in operational technologies that actively manage the grid.
We must also continue to remain flexible and
adaptable as new technologies develop;
particularly, those that use less land and are not
weather-dependent, adding crucial diversity to our resource portfolio.
We are monitoring the following emerging technologies that can provide firm generation, and that may have potential for inclusion in our grid planning:
Near-term actions to secure reliability:
Continue to monitor the condition of an aging generation fleet and prepare contingency plans as necessary; manage prudent and essential capital investments in generating units that could potentially be retired or deactivated in the near future, balanced with ensuring short-term reliability
Acquire new firm generation and solar, wind and energy storage projects through the Stage 3 procurement to facilitate deactivation and retirement of existing fossil-fuel generation through 2035
Complete a resource adequacy study to review reliability planning methods and renewable resource accreditation methodologies
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■ Generating renewable electrical energy using hydrogen produced from renewable energy sources (renewable hydrogen)
■ Emerging technologies to increase the production output of different
biomass/biofuel production pathways and
decrease the costs
■ Enhanced geothermal systems (EGSs) to
produce electricity from locations with favorable thermal conditions and insufficient
hydrological reservoirs or recharge rates
■ Generating electricity using ocean thermal energy conversion (OTEC) generating plants
See Section 6.9.5 for more information about these emerging technologies.
Near-term actions to adopt emerging technologies:
Continue to require grid-forming technology for inverter-based resources, including for large-scale standalone wind and solar when technology is commercially available
Continue to monitor and evaluate the performance of new solar and storage projects, including continued assessment of system security risks as more renewable systems are brought online
Continue to monitor and invest in advanced technologies to operate the high inverter-based grids and seek new grid technologies to improve the reliability of the grid
Implement IEEE 2800-2022 in future large-scale inverter-based resource projects
Continue engagement with the DER industry to improve inverter performance to address system security concerns
Continue evaluating advanced equipment for providing system stability (e.g., grid-forming STATCOM)
Develop interconnection standards for grid interface of electric vehicles to get ahead of potential system security risks seen today with rooftop solar systems
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2.2 Timeline and Renewable
Portfolios
The Integrated Grid Plan outlines the amount of renewable resources we will need to procure to meet statewide decarbonization goals. Figure 2-1 displays a high-level timeline of adding renewable resources, retiring fossil fuel–based generation
and reducing carbon emissions. Though development of REZs and distribution upgrades is not highlighted in the timeline, it is a key enabler of the Integrated Grid Plan. This portfolio and timeline reflect the Preferred Plans—the lowest-
cost plan across all five islands we serve, that also
considers resource adequacy, system security and
other grid needs.
Figure 2-1. Proposed timeline of adding renewable resources, retiring or deactivating fossil fuel–based generation and reducing carbon emissions
The following is an overview of our plan and the
resources we seek to obtain between now and
2035 for each island.
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2.2.1 O‘ahu by 2035
■ 1,067 MW/2,186 GWh of solar and energy
storage or onshore wind
■ 400 MW/2,114 GWh of offshore wind
■ 240 MW/379 GWh of private rooftop solar
■ 1,209 GWh of energy efficiency
■ 180 MW of Phase 2 community solar (CBRE)
14 MW LMI and Phase 2 projects have already been selected (CBRE)
Figure 2-2 presents a preferred plan generation
mix for Oʻahu (Base).
Figure 2-3 presents a preferred plan generation
mix for Oʻahu (Land-Constrained)
Figure 2-2. Preferred plan generation mix: Oʻahu (Base)
Figure 2-3. Preferred plan generation mix: Oʻahu (Land-Constrained)
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2.2.2 Hawai‘i Island by 2035
■ 51 MW/209 GWh of solar and energy storage or wind
■ 58 MW/85 GWh of private rooftop solar
■ 218 GWh of energy efficiency
■ 33 MW of Phase 2 community solar (CBRE)
15 MW LMI and Phase 2 projects have already been selected (CBRE)
Figure 2-4 presents a preferred plan generation mix for Hawaiʻi Island (Base).
Figure 2-4. Preferred plan generation mix: Hawaiʻi Island (Base)
2.2.3 Maui by 2035
■ 103 MW/211 GWh of solar and energy storage or wind
■ 62 MW/100 GWh of private rooftop solar
■ 206 GWh of energy efficiency
■ 33 MW of Phase 2 community solar (CBRE)
8 MW LMI projects have already been
selected (CBRE)
Figure 2-5 presents a preferred plan generation mix for Maui (Base).
Figure 2-5. Preferred plan generation mix: Maui (Base)
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2.2.4 Lānaʻi by 2035
■ 5.5 MW/5.7 GWh of solar and energy
storage or wind
■ 17.5 MW/35.8 GWh of community solar (Lānaʻi CBRE request for proposals [RFP])
17.5 MW have already been selected (CBRE)
■ 0.6 MW/1.0 GWh of private rooftop solar
■ 1.2 GWh of energy efficiency
Figure 2-6 presents a preferred plan generation mix for Lānaʻi (Base).
Figure 2-6. Preferred plan generation mix: Lānaʻi (Base)
2.2.5 Molokaʻi by 2035
Moloka‘i is preparing a Moloka‘i Community Energy Resilience Action Plan: an independent,
island-wide, community-led and expert-informed
collaborative planning process to increase
renewable energy on the island. The Moloka‘i
Clean Energy Hui by Sustʻāinable Moloka‘i is
coordinating the action plan. Hawaiian Electric is
providing technical support to the Moloka‘i Clean Energy Hui in its planning process to develop a portfolio of clean energy projects to achieve 100% renewable energy for the island that is feasible, respectful of Moloka‘i's culture and environment, and strongly supported by the community.
Figure 2-7 presents a preferred plan generation mix for Molokaʻi (Base). This is subject to change based on the ongoing planning process on
Molokaʻi. Hawaiian Electric will continue to work
with the Moloka‘i Clean Energy Hui to align our
planning efforts.
■ 13.8 MW/24.1 GWh of solar and energy
storage or wind
■ 1.0 MW/1.7 GWh of private rooftop solar
■ 1.2 GWh of energy efficiency
■ 2.75 MW of Phase 2 community solar (CBRE)
2.45 MW have already been selected to the final award group (CBRE)
Figure 2-7. Preferred plan generation mix: Molokaʻi (Base)
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2.3 External Actions and
Policies for Successful
Implementation
Decarbonizing the electric grid by 2045 will
depend on many conditions, actions and policies beyond Hawaiian Electric. External conditions and actions that will support successful implementation include:
Economic Conditions and Actions Easing of supply-chain and inflationary pressures.
Federal funding (e.g., bipartisan infrastructure bill and Inflation Reduction Act) for incentives that remove barriers to customer adoption of EE measures and electric vehicles.
Federal funding to offset the cost of renewable energy projects and transmission and distribution resilience investments.
Customer and Community Actions
Robust customer and community participation in energy efficiency, generation and storage.
Customer and community engagement in and acceptance of energy plans and projects.
Resource and Technological Conditions Better-than-expected performance of large-scale solar, battery storage and distributed energy resources, especially during transient or contingency events.
Policies and Regulatory Conditions Policies that accelerate stock turnover of less efficient appliances, equipment and combustion vehicles and changes to building codes and standards that encourage zero-emissions appliances and equipment.
Policies that promote affordability and equity.
Efficient regulatory action and decision making.
Land use policies that promote renewable energy development, including other land being made available (e.g., private land, federal lands, etc.)
Policies that remove barriers to siting and permitting large-scale renewable projects and transmission infrastructure. For example, a separate process or entity that coordinates or has the authority to approve a variety of permits needed to execute a renewable project.
Flexibility in air permitting and mandates to manage reliability and transitions to renewable resource replacements. Policies that provide incentives to communities and residents to host renewable projects and transmission infrastructure.
Policies that provide developers and landowners incentives to develop renewable projects in certain locations. Policies that support a technical workforce pipeline to continue the work needed to accelerate the transition and transition fossil fuel–related jobs to clean energy jobs.
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2.4 Potential Risks and
Challenges
Successful implementation of the Integrated Grid Plan will depend on our own ability to lead, take swift action and collaborate with partners and communities. It is also contingent on actions and conditions external to Hawaiian Electric. Many risks and potential challenges could delay progress toward State decarbonization goals. The primary threat to progress is the status quo and policy inaction to the above-listed
recommendations. We have also experienced the
acute risks to implementation and execution of
renewable projects over the past couple of years
because of persistent supply-chain and
inflationary pressures (or economic recession) that
make customer technologies and large-scale projects unaffordable for customers or that adversely impact the cost of equipment, materials and labor.
In Section 12 we also analyze generation reliability risks and mitigation strategies, including potential load growth from electrification, as we seek to remove fossil fuel–based generation from our daily operations as soon as practicable.
2.5 Our Response to
Comments on the Draft
Integrated Grid Plan
On March 31, 2023, we filed the draft Integrated
Grid Plan with the Hawaiʻi Public Utilities Commission (PUC) and invited public comments through April 21, 2023. We received just over 300 comments from community members, PUC staff, the Technical Advisory Panel (TAP) and members of the Stakeholder Council (see Section 4.1 for information about the TAP and Stakeholder Council).
We appreciate the thoughtful comments from PUC staff, stakeholders and the public, and we have used this feedback to develop eight
clarifications, listed below. We also addressed
comments by adding or clarifying material
throughout the Integrated Grid Plan. See
Appendix H for a record of all comments received and our responses, including notes indicating where we have amended the Integrated Grid Plan.
1. Providing a practical pathway to
decarbonizing the electric grid
Public comments reflect concerns with the
achievability of our plans because of land use and
preservation of our natural environment. In
developing the Integrated Grid Plan, it was clear
that every choice has an impact, whether it’s physical or financial. While we can mitigate those
impacts, attaining our clean energy goals has major implications for our land and natural resources, economy and communities. We sought to make the best choices by engaging with community members, regulators, policymakers and other stakeholders. These groups helped us examine the tradeoffs and options to achieve our goals and uphold our obligation to put forward pathways and plans that comply with State policy.
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The actions we outline in the Integrated Grid Plan are the lowest-cost solutions to decarbonize the power grid by 2045 while also maintaining reliable power, stabilizing pricing for customers and advancing energy equity. While our proposed
timeline to add and activate renewables by 2030 is
ambitious, it would constitute a significant
contribution toward the State’s goal of reducing
greenhouse gases by 50% across the entire state
economy and our commitment to reducing
emissions by 70% in the electricity sector. Moving swiftly to add renewables is also an essential step to retire more fossil fuel–based generation while maintaining reliable power for customers.
Available land and community support are key factors in unlocking renewable potential. The Land-Constrained scenario provides a pathway to meet grid needs and carbon goals if less land is available for energy projects than our preferred plan
assumes. As described below, we also evaluated
the possibility that offshore wind cannot be
developed, as we acknowledge that many
community members have concerns about its
environmental impact. It will take continued
collaboration among Hawaiian Electric, customers, communities, counties, the State, the federal government and other industries to meet decarbonization goals and live out a more sustainable future. A decarbonized grid is achievable if we work together and act now.
2. Investing in a diverse portfolio of renewable resources, including other
technologies than wind and solar
Investing in many different resources at various scales, including renewable firm generation, is key to phasing out aging fossil fuel–based generators while maintaining reliable power. Firm generation—such as geothermal and biofuel—will ensure that we have a source of stable, consistent power to supplement smaller-scale renewable
generation on customers’ homes and in communities, as well as weather-dependent resources like wind and solar. We also propose ongoing community engagement to continue to assess the viability of other technologies.
Nuclear fission, which can generate carbon-free
power, is a promising technology that other states
are assessing for safety and suitability to their
grids. Article XI, Section 8, of the Hawai‘i State
Constitution prohibits nuclear fission power generation without prior approval by the legislature. Accordingly, nuclear fission generation is not currently included in our plans.
However, we are monitoring other energy developments and emerging technologies that can provide or fuel firm generation and have potential for inclusion in our grid planning. These include:
■ Generating renewable electrical energy using
hydrogen produced from renewable energy
sources (renewable hydrogen)
■ Emerging technologies to increase the
production output of different
biomass/biofuel production pathways and decrease the costs
■ EGSs to produce electricity from locations with favorable thermal conditions and insufficient hydrological reservoirs or recharge rates
■ Generating electricity using OTEC generating plants
For further details, we have added Section 6.9.5 to discuss these emerging technologies.
3. Considering offshore wind as a potential part of a diverse grid
We understand that community members have concerns about offshore wind and its environmental impacts. Our proposed timeline
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currently adds 400 MW of offshore wind by 2035 because a study conducted by the National Renewable Energy Laboratory (NREL) shows that it is a low-cost, technically feasible and high-quality renewable resource in Hawai‘i. We have included
offshore wind as a potential solution for meeting
forecasted energy demands and growing a
diverse portfolio of renewables, while also
minimizing impacts to communities and working
within onshore land constraints. Any proposed
offshore projects would be required to undergo extensive environmental reviews, with multiple opportunities for public input and a thorough analysis of onshore and offshore impacts.
We also recognize that each community has a distinct character and each highly values its cultural, natural and other resources. We continue to update our community engagement and cultural resource preservation practices and
requirements using community feedback. We
heard from community members who wanted
Hawaiian Electric and developers we work with to
improve transparency and community
engagement from the start of the energy project
development process. We also believe that early and frequent engagement will help improve the success of renewable projects and help us collectively achieve our state’s renewable energy and carbon neutrality goals.
4. Stabilizing and managing costs for customers
We understand that energy costs are top of mind
for customers and there are concerns that electric
rates may rise in the coming years to enable the transition to a decarbonized economy. However, customer bills will be more stable and our projections show that bills may be lower in the long term compared against a future in which we continue to rely on fossil fuels. Fossil-fuel pricing is inherently volatile and it is impacted by
unpredictable global events and conditions. Renewable energy contracts are generally more stable and predictable because they have fixed prices and escalations over their multi-decade terms. We currently have more than 500 MW of
low-cost renewable projects in the pipeline that
we expect to come online over the next few years.
These renewables are expected to cost less than
the current cost of oil and help stabilize rates.
We also are committed to expanding customer access to renewable technologies. We are working with the PUC and other stakeholders to develop new rooftop solar, battery storage and energy efficiency programs that will provide incentives to help make customer resources more affordable. For example, later this year we’ll be piloting a Shift and Save Program that enables customers to save money by shifting energy use away from the high-demand evening and overnight hours that are at a higher electric rate.
Additionally, we are seeking federal funding that
could greatly reduce the cost of grid modernization
and resilience initiatives. We currently have grant
applications pending with DOE to gain funding to offset costs to implement our Climate Adaptation, Transmission and Distribution Resilience program to harden grid infrastructure and for Phase 2 of our grid modernization program. We are appreciative of the PUC’s, Consumer Advocate’s and other stakeholders’ support for these funding requests.
5. Minimizing and recycling waste from clean energy equipment
Public comments expressed concern about what
will happen to waste from clean energy infrastructure, including solar panels once they reach the end of their life cycle. This is an important topic and one with respect to which others have essential responsibilities as well. Hawaiian Electric addresses this concern to the
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extent allowed through contract and land agreement terms.
Because the vast majority of solar and other utility-scale renewable energy systems are owned and operated by independent power producers
(IPPs), removal and disposal of these clean energy
materials for utility-scale projects is largely
addressed under Hawaiian Electric’s power
purchase agreements (PPAs) with IPPs as well as
the lease or other governing land rights agreement between IPPs and third-party landowners. For IPP projects sited on land owned by a third party, our PPAs require that the IPP, upon termination of the PPA, and at Hawaiian Electric’s request, restore the land to the condition prior to construction of interconnection facilities. For IPP projects sited on land owned by Hawaiian Electric, our lease or other land rights agreement with the IPP require the IPP to remove and
dispose of clean energy materials at Hawaiian
Electric’s request upon the termination or
expiration of the PPA. Hawaiian Electric is not a
party to land rights agreements between IPPs and
third-party landowners, so we cannot directly
dictate or enforce the terms of those agreements. However, such agreements typically require IPPs to remove and dispose of all clean energy materials and restore the land to its preexisting condition upon expiration or termination of the agreement.
Hawaiian Electric also lacks authority to impose disposal requirements for materials used for private residential and commercial clean energy
systems, such as photovoltaics (PV). However, the
state legislature is considering waste and disposal
of clean energy materials. In 2021, Governor Ige
signed into law Act 92, which directed the Hawai‘i
1 See full report at https://www.hnei.hawaii.edu/wp-content/uploads/2023-HNEI-Act92-Final-Report-Clean-Energy-Products-Waste-Management.pdf
Natural Energy Institute, in consultation with the Department of Health, to conduct a comprehensive study to determine best practices for disposal, recycling or secondary use of clean energy products in the state.
The December 2022 study1 found that a total of
225,000 tons of PV-related clean energy materials
have been installed in Hawai‘i through 2021,
which accounts for 8.8% of all municipal solid
waste. The study also concluded that responsible parties for management, collection, disposal and recycling currently lack adequate capacity and preparation to process these materials. The report recommended the following actions:
1. Ensure and enforce waste generator responsibility, where those responsible for generating the waste arrange for and bear the cost of transport and treatment at off-island disposal/recycling centers. In
practice, at the residential and commercial
scales, property owners would contract PV
installers or contractors to remove and
arrange for the off-island transport of their
PV modules to landfill disposal or industrial recycling. At the utility scale, the IPP would be expected to manage the disassembly and transport costs.
2. Pursue and manage “extended producer responsibility” where possible, which assigns responsibility for the end-of-life management of PV modules, electronic items to the manufacturer, reseller or installer.
3. Implement an advanced disposal fee
program, where fees are collected at the
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time of purchase to cover the cost of disposal of materials.
One example the State may be able to look to is Washington. In 2017, the Washington Legislature passed Senate Bill 5939 to promote a sustainable,
local renewable energy industry through
modifying tax incentives. One portion of the bill
created Revised Code of Washington (RCW)
Chapter 70A.510.010 (Photovoltaic Module Stewardship and Takeback Program), which
requires manufacturers of solar panels to provide the public a convenient and environmentally sound way to recycle all modules purchased after July 1, 2017. This program is slated to begin in July 2025.2
6. Serving public interest
Public comments expressed concern that future
energy projects may not serve the public interest
and asked how Hawaiian Electric plans to engage
impacted communities and integrate their input,
especially in rural, residential or agricultural areas. We believe that listening to, learning from and respecting impacted community values and perspectives is essential to the collective success of our clean energy plans. We will communicate with community members early, often and transparently to develop projects that serve the public interest and are respectful of and informed by community values and needs. Throughout the development of the Integrated Grid Plan, we worked to engage customers and communities
that might be most impacted by the transition to
clean energy, including those in rural areas where
many of the proposed renewable projects are
located.
2 More information about the program can be found at https://nwsolar.com/blog/recycling-solar-panels-in-washington/
During community meetings we attended in rural areas, we heard from people who said they prefer face-to-face interaction and appreciate materials they could take home and read later, as local internet access is often limited. We will continue
working to meet community members where they
are, provide accessible information in both
physical and digital formats, foster meaningful
dialog and use community feedback to shape
project outcomes. Starting with our most recent
procurement in 2023, we also require that developers provide and implement community engagement plans, with benefit packages for host communities and multiple opportunities for the public to share input.
The Integrated Grid Plan is an important starting point for focusing efforts of many stakeholders and measuring our collective progress toward our goals. We hope that the Integrated Grid Plan
provides a useful frame of reference for the many
interrelated and ongoing energy dockets,
applications and future proceedings. We’ll
continue communicating with customers,
communities, regulators and other stakeholders,
striving to reach agreement among all parties, or at least shared understanding about the basis for inputs, assumptions and the future direction of grid development.
Integrated Grid Planning is a vital process to enable the PUC to perform its responsibility to ensure that our plans and projects serve the public interest. The Integrated Grid Plan highlights concrete, near-term steps to mitigate and adapt
the energy system to climate change, which is
crucial for public safety, economic security and
statewide sustainability. We have requested
approval from the PUC to implement strategies
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for hardening grid infrastructure (as outlined in Section 7) and execute our Climate Change Action Plan (described in Section 1.2.1). These efforts will help the state make substantial progress toward meeting the requirements of State agencies under
Hawaiʻi Revised Statutes (HRS) § 225P-5.3 The
Integrated Grid Plan seeks to achieve the State
policy goals of HRS § 225P-5 by reaching at least a
50% GHG reduction by 2030 and net zero by 2045
compared to 2005 levels through reducing
dependence on fossil fuels. With respect to GHG emissions and the PUC’s obligations under HRS § 269-6, we provide the environmental analysis in Section 9.5, which will be supplemented by environmental analyses for individual projects.
We will continue to provide multiple opportunities for communities and stakeholders to share input as we move into implementation of the Integrated Grid Plan, including issuing competitive
procurements, developing projects and seeking
approval for individual projects. We will also
continue to partner with the PUC to ensure
alignment with HRS § 269-6 and § 225P-5.
7. Developing renewable energy zones
The development of REZs is critical to the execution of this Integrated Grid Plan. We are working on identifying areas of land that blend technical, community and market considerations to site large-scale renewable energy generation. Building transmission to support this development is key to enabling large amounts of renewable
capacity onto the system, and establishing REZs
guides our buildout of the transmission system.
We expect that under full, economy-wide
decarbonization other sectors will require
3 HRS § 225P-5 does not apply directly to Hawaiian Electric.
substantially more renewable generation. We must continue to keep all options on the table.
In the coming months, customers and communities can expect opportunities to share their thoughts on the development of REZs and
we intend to share additional information from
our recent request for information to landowners
willing to allow for renewable project
development. We want to understand community
members’ perspective on opportunities and challenges for local energy projects. In our initial REZ map outreach campaign in early 2023, we received public comments that pointed to areas where communities would not support projects. We are currently reviewing these comments and technical analyses to refine the REZ maps. Our goal is to locate projects in areas with community support, willing landowners and technical feasibility.
8. Responding to the Technical Advisory
Panel review
The TAP did not identify any Integrated Grid Plan fatal flaws and it recommends urgent action to begin implementing the plan. See Appendix H for a record of the TAP’s comments on the draft Integrated Grid Plan. We appreciate the time and efforts the TAP invested to provide suggestions and recommendations to improve our analyses
throughout this process, which is reflected in its
comments. We clarify many of the TAP’s
comments provided in Appendix H, and address
items of immediate concern.
The TAP provided the following summary of its
review and feedback:
Overall, the [Integrated Grid Plan] report presents an enormous effort by [Hawaiian
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Electric] and its stakeholders to plan out how to reach very ambitious and timely renewable energy goals. Many aspects of the report reflect past TAP feedback that has been used to improve the analysis; some of those
improvements are noted in this feedback
document. The report describes a long-term
plan to achieve 100% renewable energy as well
as concrete near-term actions to meet interim
renewable goals. The long-term plan and near-
term actions appear reasonable. In the places where the TAP would suggest improvements or clarifications, those are noted here in colored text. As is to be expected from an integrated grid plan, the analysis described in the report makes various assumptions; those assumptions in
general appear reasonable. Similarly, the
analysis uses modeling methods designed to
find an optimal solution; those methods are
generally reasonable, well vetted, and are
aligned with best practices. Where the TAP has
concerns, sees risks, or would suggest improvements or clarifications, that is noted in this document in colored text with the most urgent items shown in red. We agree on the need for urgent action and generally encourage [Hawaiian Electric] to continue the various efforts underway and to begin implementing the plan described in this report, notwithstanding any specific TAP
comments to the contrary. At the same time, it
will certainly be possible to improve the plan
going forward as new information is gained,
modeling methods improve, and technology
evolves. Therefore, the plan should remain flexible to allow for future adjustments, as the report notes. For example, a near-term opportunity to evaluate assumptions will come with the Stage 3 RFP bids, which will provide
valuable information on resource availability, pricing, and other details.
Additional Changes and Clarifications
The preceding and following chapters include
clarifications we made in response to comments
we received on the draft Integrated Grid Plan. In
the executive summary and action plan above, we made the following updates in response to comments:
■ Emphasized the importance of improving energy efficiency in homes and businesses to reach decarbonization goals (see Sections 1.1 and 1.5.2)
■ Elaborated on the role of new and emerging technologies in mitigating risks and meeting
future grid needs (see Section 2.1.4)
■ Expanded the discussion of technical
solutions critical to system reliability (see
Section 2.1.4)
In Appendix H, we provide a response to each of
the comments we received, with references to amended sections.
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2.6 Next Steps
As we move beyond planning, we are turning our focus to creating an energy marketplace, building upon our efforts to date in acquiring clean energy solutions through competitive procurement for large-scale resource and community-based energy projects, grid services purchase agreements and customer DER programs.
To create a viable energy marketplace, we will
need to routinely conduct procurements and
adjust program and pricing mechanisms, in a
similar but more efficient manner to the
procurement activities since 2017. To meet our 70% GHG reduction goal by 2030, we will need to increase customer participation in energy efficiency, generation and storage and issue up to two additional competitive procurements. Figure 2-8 shows our proposed near-term actions.
Figure 2-8. Proposed near-term actions, 2023–2035
2.6.1 Public Utilities Commission Requests
To move from planning into implementation, we ask that the PUC:
Approve the Integrated Grid Plan to serve as a foundational guiding strategy for Hawaiian
Electric and stakeholders, including in interrelated and ongoing energy dockets,
applications and future proceedings Open a new docket for competitive bidding related to grid-scale resources, non-wires alternatives, and grid services as described in this report, pursuant to the revised competitive bidding framework previously approved for use in the Integrated Grid Plan
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3 Introduction
At Hawaiian Electric, customers are at the heart of our work today and our vision for the
future. We are deeply rooted in our communities, and we strive to serve the energy needs of
each person in Hawai‘i with purpose, compassion, empathy and aloha for our fellow humans
and our natural environment. We are committed to empowering our customers and
communities with affordable and reliable clean energy, and providing innovative energy
leadership for Hawai‘i.
Hawaiian Electric has the privilege of serving as
Hawai‘i’s largest electric utility. We serve 95% of
Hawai‘i’s 1.4 million residents on the islands of
Hawai‘i, O‘ahu, Maui, Lānaʻi and Molokaʻi, each
with separate grids. Since 2010, we have nearly tripled the amount of renewable energy we
generate, in large part due to the contributions of
our customers. Figure 3-1 shows our renewable
energy portfolio from 2011 through 2022.
Customer-sited solar currently accounts for most
of our renewable energy generation.
Figure 3-1. Hawaiian Electric renewable energy portfolio, 2011–2022
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Together with stakeholders, customers and communities, we have made significant progress toward our decarbonization goals. Among the accomplishments:
■ 35% of single-family homes have rooftop
solar and 4,408 new residential rooftop solar
systems.
■ Total solar capacity, primarily from
customers with rooftop solar, has grown to
more than 1,118 MW.
■ 91% of new rooftop solar is being installed with battery energy storage.
■ GHG emissions have been reduced by 22% compared to 2005.
■ We have expanded customer energy options with innovative programs like Battery Bonus and shared solar.
■ Installation of public EV charging infrastructure has expanded to 31 chargers
at the end of 2022 with plans to have a total
of 36 chargers by year end 2023.
■ Advanced meters have been deployed to
more than 40% of customers on Oʻahu,
Hawaiʻi Island and Maui.
■ Two stages of competitive procurement for renewable dispatchable generation (RDG) have been executed (referred to as Stage 1 and Stage 2), with the first two large-scale solar plus battery energy storage projects in operation: Mililani 1 Solar, a 39 MW/156 megawatt-hour (MWh) battery and Waiawa Solar, a 36 MW/144 MWh battery. Additional projects are in the pipeline and expected to
reach commercial operations over the next
couple of years.
■ A third stage (Stage 3) of competitive
procurement for renewable dispatchable
generation has been issued and firm generation is currently in progress.
We are proud of the progress we have made, but we still have a long way to go.
3.1 Climate Change Action
Plan
The 2021 international summit on climate change made clear that the actions we take this decade will determine whether humanity can slow or stop the warming of the planet. To do our part in cutting global emissions, Hawaiian Electric announced a bold Climate Change Action Plan in 2021.
Our Climate Change Action Plan sets the ambitious goal of reducing electric-sector GHG
emissions in 2030 by as much as 70% compared
to 2005 levels. It also sets the goal of reaching
net-zero carbon emissions by 2045, meaning
whatever small amount of emissions we produce
will be captured or offset. Figure 3-2 illustrates the
Climate Change Action Plan goals.
Figure 3-2. Hawaiian Electric’s Climate Change Action Plan carbon emission goals
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3 – INTRODUCTION
This commitment by Hawaiian Electric represents a significant down payment on the economy-wide reduction that Hawai‘i will have to achieve to align with nationwide and global GHG reduction goals. Statewide decarbonization will require
collaboration across sectors, with transportation,
agriculture and other industries working to reduce
and offset emissions.
3.2 Hawai‘i Powered
A key strategy to reach net-zero emissions is
generating 100% of our energy from renewable
resources. In 2015, Hawai‘i became the first state
in the nation to direct its utilities to generate 100% of their electricity from renewable energy sources by 2045. Hawaiian Electric is dedicated to partnering with customers, communities and other stakeholders to reach this energy goal.
We call our vision for using 100% renewable resources “Hawai‘i Powered.” Clean energy for Hawai‘i, by Hawai‘i:
■ Supports our Climate Change Action Plan and the State’s decarbonization goals
■ Achieves energy independence
■ Expands energy choices for customers and
helps stabilize rates
3.3 Overview of Integrated
Grid Planning
Integrated Grid Planning brought many people
together to determine how to create a resilient
and reliable grid that will meet future energy
needs, stabilize costs for customers and use 100%
renewable resources. Hawaiian Electric began the
planning process in 2018.
Powering a safe, secure, reliable and resilient grid with Hawaiʻi's natural resources, whether on a small scale with individual customers, or through large-scale renewable energy providers, will
require thoughtful and coordinated energy system planning in partnership with local communities and stakeholders alike. Additionally, the electric grid of tomorrow will look dramatically different from the electric grid of the past, as it will need to
efficiently handle complex tasks not originally
imagined. With a renewed focus on
comprehensive energy planning, we believe that
customers will benefit from a process that will
identify the best options to affordably move
Hawai'i toward a reliable, resilient clean energy future with minimal risk. The Integrated Grid Plan is rooted in customer and stakeholder input. We endeavor to create customer value by:
■ Harmonizing resource, transmission and distribution planning processes
■ Evaluating the collective identified system needs
■ Coordinating solutions that provide the best
value on a consolidated basis
This approach appraises the total needs of the
system and considers all alternatives from
customers, independent providers and the utility.
It led us to identify solutions that are the lowest
cost and/or best fit to create a more resilient, reliable and sustainable grid that can meet the needs of Hawaiʻi’s residents and businesses.
Integrated Grid Planning diverged from traditional energy planning practices. It streamlined traditionally disparate planning and procurement activities into a unified process. For instance, our planning framework establishes a marketplace for grid solutions that is integrated into the
optimization and decision-making process,
increasing opportunities for developers and
customers to provide energy and grid services.
Throughout the planning process, we maintained
transparency through active stakeholder, customer and community engagement. See
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3 – INTRODUCTION
Section 4 for details about our communication and outreach approach.
As illustrated in Figure 3-3, Integrated Grid Planning consisted of four high-level steps:
■ Data collection. We developed forecasts
and input assumptions to drive the planning
and procurement process.
■ Plan definition. We identified resource,
transmission and distribution needs to
establish an optimal portfolio of solutions to meet grid needs, policy goals and system reliability standards. This includes a near-term action plan and directional, long-term pathways to meet policy goals.
■ Growing a clean energy marketplace. We seek to identify resource, transmission and distribution solutions and grow the energy marketplace through multiple sourcing mechanisms: procurements, pricing and
programs.
■ Plan refinement. We evaluated and
optimized the resource, transmission and
distribution solutions to identify proposed
solutions for review (i.e., investments, third-
party contract, programs and pricing proposals) for review by the PUC.
Figure 3-3. High-level steps of Integrated Grid Planning
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3.4 Key Considerations
The core challenge of Integrated Grid Planning was to create a clean energy grid that balanced the key considerations of time, affordability, land use, community, and resilience and reliability, as shown here.
Together with stakeholder groups and community members, we worked to prioritize, balance and connect the key considerations. Figure 3-4 displays the ranking of key considerations by community members who voted on their priorities
online and at events on Hawai‘i Island, Maui and
O‘ahu in 2022.
Figure 3-4. Key considerations ranked by community members (voting online and in person)
Throughout Integrated Grid Planning, we focused
on the two considerations that we repeatedly heard were of top concern and interest to
community members: affordability and reliability/resilience. This report provides the most affordable and reliable pathways to decarbonize our electric system.
Time
How long will it take to come online?
Affordability
What will it cost to design, build, and maintain?
Land use
What is the footprint? How does this affect other land use priorities?
Community
How will it affect neighbors, jobs, and the environment?
Resilience and reliability
Will it hold up to a natural disaster and can it bounce back? How will it meet future energy demands
based on electric vehicles, solar projects,
population, and other factors?
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3.5 Pathways to 100%
Renewable Energy
We evaluated five pathways (Table 3-1) to achieving 100% renewable energy over a planning horizon to year 2050. On O‘ahu we evaluated an additional pathway called “Land-Constrained” to represent the possibility that there would be insufficient land to site large-scale renewable energy projects. The objective of each pathway is to best serve our customers’ future needs and preferences, while allowing flexibility to adapt to
the inevitable uncertainties ahead, including
changes in customer preferences and conditions.
This planning approach is customer-centric, as it
defines the residual needs of the grid after
accounting for customer resources. In developing
these possible pathways, we took into account:
■ Island-specific conditions
■ State policies as described in Section 5
■ Customer trends and adoption rates of new technologies
■ How future State or federal policies may
impact customer choices
■ Design and implementation of potential
REZs
The following is an overview of the five pathways
that we developed in collaboration with
stakeholders along with additional scenarios to test key forecast assumptions. A summary of the pathways and modeling scenarios, their purpose and associated forecast assumptions is provided in Section 6.8. See Section 8 for details on these pathways per island.
Table 3-1. Pathways to 100% renewable energy
Pathway Overview Base Customers continue to adopt technologies (private rooftop solar, energy storage, electric vehicles and energy efficiency) based on current projected market conditions and customer trends. EV owners manage their charging and mostly charge during the day when solar resources are abundant, and electricity is cheapest. At this time, we believe this pathway is the most probable trajectory.
Low Load Customer adoption of technologies continues at a much higher pace than expected, such as energy efficiency and private rooftop solar, but EV adoption remains slow. In this future, the electricity demand we must serve is much lower than in all other pathways and fewer large-scale resources will be needed to achieve 100% renewable energy.
Faster customer technology adoption
Customer adoption of all technologies, private rooftop solar and electric vehicles; energy efficiency is higher and accelerated compared to the market forecasts and EV owners manage to charge their vehicles during the day when solar is abundant. In this future, the electricity demand is higher than the Base electricity demand pathway but lower than the High electricity demand pathway. High Load Customer adoption of technologies continues at a much slower pace than expected; however, EV adoption accelerates because of aggressive State or federal policies, but owners charge their vehicles when the grid is most stressed (i.e., unmanaged EV charging). In this future, the electricity demand we must serve is much higher than in all other pathways and more large-scale resources will be needed to achieve 100% renewable energy.
Land-constrained This pathway recognizes the possibility on O‘ahu that insufficient land may be available to develop large-scale resources or to produce local biofuels needed to achieve 100% renewable energy, while balancing other State goals of affordable housing and food sustainability. This pathway helps us understand the impact of limited land availability for future solar, onshore wind and biomass development. In this pathway customer adoption is the same as the Base pathway where customers adopt technologies based on current market and customer trends.
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3.6 Renewable Energy
Planning Principles
The following principles guided our technical analyses and community conversations as we moved through Integrated Grid Planning:
■ Renewable energy is the first option. We are pursuing cost-effective renewable resource opportunities that reduce carbon emissions and stabilize customer bills. Getting off imported fossil fuels removes Hawai‘i from the volatility of world energy
markets and gives future generations a
tremendous advantage. It can also create a
clean energy research and development
industry for our state.
■ The energy transformation must include
everyone. Electricity is essential. Our plans, as well as public policy, should ensure access to affordable electricity, with special consideration given to LMI households. Meaningful community participation must be a key element of renewable project planning.
■ The lights have to stay on. Reliability and resilience of service and quality of power are
vital for our economy, national security and
critical infrastructure. Our customers expect
it, deserve it and pay for it. Our plans must
maintain or enhance the resilience of our
isolated island grids by relying on a mix of
resources and technologies.
■ Today’s decisions must be open to tomorrow’s breakthroughs. Our plans keep the door open to developments in the rapidly evolving energy space. We must be
able to easily accept new, emerging and
breakthrough technologies that are cost-
effective and efficient when they become
commercially viable.
■ The power grid needs to be modernized.
Energy distribution is rapidly moving to the digital age. We are reinventing our grid to facilitate a decarbonized energy portfolio and to enable technologies such as demand response, dynamic pricing, aggregation and electrification of transportation.
■ Our plans must address climate change. Our Climate Change Action Plan set a goal
to reduce carbon emissions from power
generation 70% by 2030 compared with
2005 levels. Our resilience strategy aims to
minimize the impacts of climate change—
rising sea levels, coastal erosion, increased
temperatures and extreme weather events—on the energy system.
■ There’s no perfect choice. No single energy source or technology can achieve our clean energy goals. Every choice has an impact, whether it’s physical or financial. While we can mitigate those impacts, attaining our clean energy goals has major implications for our land and natural resources, our economy and our communities. We seek to
make the best choices by engaging with
community members, regulators,
policymakers and other stakeholders.
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4 Community and
Stakeholder
Engagement
Meaningful and sustained community and stakeholder engagement is at the heart of
Integrated Grid Planning. It has been instrumental in aligning our planning with statewide
priorities and moving Hawai‘i toward a more equitable clean energy future. Since planning
began in 2018, we have worked to foster partnerships with communities that we are a part
of and serve by sharing transparent information and listening, learning and implementing
their feedback into the Integrated Grid Plan.
We are grateful for the involvement of thousands of community members throughout the
planning process, and we appreciate the opportunities we have had to collaborate on
potential solutions.
In this section, we summarize outreach and engagement with community members and stakeholders, what we heard, and how we implemented the feedback we received. See Appendix A for copies of materials from stakeholder and community engagement.
4.1 Engagement Approach
and Stakeholder Groups
We followed an engagement framework for consistent and frequent communication with community members and stakeholders to gather input and share information throughout the planning process. Figure 4-1 illustrates this
framework, with the reciprocal flow of information
and feedback between Hawaiian Electric and our
primary stakeholder groups.
Figure 4-1. Stakeholder engagement framework
We engaged four main groups in planning for a clean energy grid: the Stakeholder Council, the TAP, Working Groups and the public.
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4.1.1 Stakeholder Council
This group helped to ensure that our planning
aligned with interests across the islands. It
consisted of one representative from the following
customer and stakeholder interests:
■ City/county and/or community representative (one from each island/county)
■ Consumer advocate
■ Demand response
■ Energy efficiency
■ Energy storage
■ Environmental advocate
■ Hawai‘i PUC
■ IPPs (utility-scale resources)
■ Large commercial and industrial customers
■ Small solar developers
■ State of Hawai‘i Energy Office
■ Sustainability advocate (local)
■ TAP Chair
■ U.S. Department of Defense
Beginning in fall 2018, we hosted virtual and in-
person Stakeholder Council meetings aligned with
planning milestones and updates. Figure 4-2
shows Stakeholder Councilmembers and Hawaiian
Electric team members at an in-person
Stakeholder Council meeting in December 2022.
See Appendix A for presentations and notes from Stakeholder Council meetings.
Figure 4-2. Stakeholder Council meeting, December 2022
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4.1.2 Technical Advisory Panel
This group provided an independent source of
peer assessment for the technological and
engineering considerations of planning for a
Hawai‘i Powered future. Panel members came
from internationally recognized utilities, market operators and research organizations with engineering expertise in resource, transmission and distribution planning for large-scale and distributed renewable resources. Their review and recommendations on the technical analyses we performed greatly enhanced the quality of our work, and were relied upon by stakeholders to ensure that our analysis was sound and consistent with leading industry practices.
The TAP met on an approximately monthly basis,
aligned with planning milestones and updates.
See Appendix A for presentations and notes from
TAP meetings.
4.1.3 Working Groups
On an as-needed basis, we formed specialized groups of experts who addressed specific topics in an advisory-only capacity. The Working Groups included:
■ Forecast Assumptions Working Group:
Supported development of forecast
assumptions and sensitivities for Integrated
Grid Plan models. This group concluded in
March 2021 when we issued the draft March 2021 Inputs and Assumptions Update.
Further updates to the forecast assumptions were discussed in the Stakeholder Technical Working Group.
■ Resilience Working Group: Supported the development of resilience planning criteria for Hawai‘i's energy system including resource, transmission and distribution in relation to potential community and
economic impacts. This group concluded
with the issuance of the Resilience Working Group Report in June 2020. It is expected to resume as we continue our resilience planning discussions in 2023.
■ Distribution Planning and Grid Services
Working Group: Supported enhancements
to the methods and tools for distribution
planning and the integration with resource
and transmission planning. This working group concluded with the issuance of the
Distribution Planning Methodology and Non-Wires Opportunity Evaluation Methodology in June 2020.
■ Market Working Group: Comprised four interrelated subgroups to support development of the sourcing and evaluation steps in the planning process:
Standardized Contract Working Group:
Developed standardized contracts and
service agreements, beginning with the grid
services purchase agreement and our model
renewable dispatchable generation power
purchase agreement (PPA) and model firm
PPA. This group concluded with the review of the model Grid Services Purchase Agreement in March 2019.
Grid Services Working Group: Identified and defined additional energy, capacity, ancillary and non-wires services. This group concluded with the completion of the soft launch request for proposal for non-wires alternatives (NWAs) in May 2020.
Solution Evaluation and Optimization
Working Group: Focused on the methods
for evaluating and optimizing multiple
solutions for multiple grid services. This
group concluded in March 2021 when we
issued the draft March 2021 Grid Needs Assessment and Solution Evaluation Methodology. Further updates to the planning methodology were discussed in the Stakeholder Technical Working Group.
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Competitive Procurement Working Group: Proposed changes to the PUC’s Framework for Competitive Bidding to reduce barriers to market participation and enable alignment with the Integrated Grid
Plan. This working group concluded in
February 2021 upon filing of the revised
competitive bidding framework that will be
used during the solution sourcing phase of
the process.
■ Stakeholder Technical Working Group: Formed in June 2021 by combining the Forecast Assumptions, Distribution Planning, Solution Evaluation and Optimization, and Grid Services Working Groups. The Stakeholder Technical Working Group provided and continues to provide input on technical issues and helped increase
transparency in the planning process.
Consolidating the original Working Group
structure streamlined planning efforts by
focusing stakeholder time and efforts,
providing opportunities for stakeholder
presentations and allowing for robust and comprehensive discussion and collaboration on technical topics.
Working Groups met on an as-needed basis throughout the planning process. See Appendix A for presentations and notes from Working Group meetings.
4.1.4 Public
The public consists of customers and community
members across the islands we serve.
We viewed the public as an active and essential
partner in Integrated Grid Planning, and we
committed to equitable, inclusive and
transparent community engagement each step
of the way.
We actualized this commitment by:
■ Providing accessible and inclusive opportunities to engage. This included offering multiple ways to engage (both online and in person).
■ Prioritizing outreach to underserved and
potentially most impacted communities,
including people who live in rural areas and
people closest to places where new energy
facilities may be located. We listened to
community members’ experiences, priorities
and vision for a clean energy future, and we used their feedback to shape planning outcomes.
■ Being accountable to feedback we have received by reviewing and considering public feedback as part of planning decisions, including where to locate new energy facilities.
In the following section, we describe the actions
we took to engage the public throughout
Integrated Grid Planning.
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4.2 Public Engagement Tools
and Strategies
We used an array of outreach tools and strategies to meet community members where they were, both online and in person. We tailored our strategies to each island, recognizing that they have unique needs, conditions and opportunities for decarbonization and public participation.
Most of the Integrated Grid Planning process took place over the course of the COVID-19 pandemic, with community engagement opportunities
beginning in March 2020. Public health and safety
were our top priority, and we worked to align our
outreach with all local, State and federal
guidelines for pandemic safety practices. This
included extending the duration of opportunities
to share input through virtual/online formats.
4.2.1 Integrated Grid Planning
Website, Document Library
and Email
In 2019, we launched the Integrated Grid Planning website (hawaiianelectric.com/clean-energy-hawaii/integrated-grid-planning) to share information on planning progress and engagement activities. We also created a project email address (IGP@hawaiianelectric.com), which we maintained and managed throughout the
planning process to gather and share information.
Community members joined the email list by
signing up at public meetings or through the
Integrated Grid Planning website.
We updated the website on an ongoing basis
throughout the planning process. This included maintaining a document library with copies of technical analyses, reports filed with the PUC, and copies of stakeholder and community presentations and meeting notes. As the planning process evolved, the growing volume of project
documents prompted a need for improved library organization. In March 2022, the PUC requested that we improve the clarity and navigability of the library, with a more consistent system for document descriptions, dates, titles and categories.
We responded to this request by adding new
search functions and category tags, as well as
consistency in document titling and captioning.
We posted notifications about the updated library on the project website homepage and Hawai‘i Powered participation site. (See Section 4.2.3, below, for information about the participation site and e-newsletter.) Figure 4-3 displays a screenshot of the updated document library.
Figure 4-3. Updated document library on the Integrated Grid Planning project website
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4.2.2 Public Open Houses
Before the COVID-19 pandemic, in early March
2020, we began our initial campaign of public
outreach and engagement, hosting in-person
open houses and an online open house. The
online open house was built to be interactive and
featured informational graphics, links to additional resources and an embedded survey tool. A total of 1,260 people visited the online open house, and 161 attended the in-person open houses. The engagement goal of this outreach campaign was to connect with the public, provide a general overview of Integrated Grid Planning, and gather input on what is most and least important to
consider as part of the planning process. Topics included:
■ Grid modernization
■ Grid-scale renewables
■ Rooftop renewable energy
■ Community-based renewable energy (CBRE)
■ Electrification of transportation
■ Resilience
■ Careers at Hawaiian Electric
We invited the public to the open houses by sharing a press release with local media outlets, emailing all Integrated Grid Planning subscribers and posting advertisements to social media. We also produced a livestreamed social media
segment publicizing the open houses and
introducing the Hawaiian Electric team and
information boards. Additionally, we provided the
Stakeholder Council a communications “toolkit”
with fliers and messaging for councilmembers to
share with their organizations and communities.
A total of 161 participants joined us at four in-person open houses: two on Hawai‘i Island and one each on O‘ahu and Maui. Table 4-1 displays the locations and number of participants at each meeting.
Table 4-1. In-person Participation in March 2020 Public Open Houses
Event Information Participants
3/3/2020 Kealakehe High School, Kailua-Kona, Hawaiʻi
17
3/5/2020 Hilo High School, Hilo, Hawaiʻi 52
3/10/2020 Hawai‘i Pacific University, Honolulu, Oʻahu
61
3/12/2020
Hawaiian Electric, Kahului, Maui
31
Total number of in-person participants 161
At each open house, participants visited stations with information boards and then attended a panel discussion. Figure 4-4 shows community
members speaking with Hawaiian Electric team
members near informational boards. The panel
included community members, representatives
from energy organizations and Hawaiian Electric
team members.
See Appendix A for a list of the panelists and copies of open-house materials, including informational boards and handouts. During the panel sessions, participants submitted 127 comments and questions ranging from the role of transportation in energy goals, resilience and domestic security, renewable and energy-efficient programs, connections with smaller communities, and community solar program and energy cost calculations.
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Figure 4-4. Community members and the Hawaiian
Electric team connect at public open houses, March 2020
Each panel session was filmed and broadcasted by local community television networks, allowing those unable to join the opportunity to watch at their convenience. Hawaiian Electric also posted recordings of the panel sessions to the Integrated Grid Planning website after the events. See
Appendix A for a list of the local television networks that broadcasted the open houses, as well as a record of the total views for each video recording posted to the website.
We hosted a virtual open house in tandem with
the in-person open houses that shared the same
information boards and an online version of the
community survey. Virtual open-house
participants could also leave a comment or email
the project team. More than 1,260 people visited the virtual open house between March 2 and 30, 2020, with peak participation on March 9 and 10.
After the open houses, we consolidated comments from in-person and virtual participants and posted summaries of what we heard to the Integrated Grid Planning website. See Appendix A for copies of the summaries. Key themes included:
■ Energy reliability and affordability were of
top concern to participants.
■ Participants expressed interest in personally
helping to increase use of renewable energy
and reduce greenhouse gases. Participants
supported the effort to reduce greenhouse
gases by owning and/or driving electric vehicles, switching to solar and using energy-efficient appliances. Many expressed interest in having rooftop solar installed, or already had solar installed or were waiting for installation. Participants were interested but looking for more information on advanced meter installation and battery storage installation.
■ Very little interest was expressed in using
transit or carpooling to reduce emissions,
and participants expressed the least interest
in exploring new technologies to provide
more information and control over energy
uses.
This input helped to inform future pathways where we evaluated futures with high adoption of
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electric vehicles, different levels of rooftop solar adoption, and described the distribution system investments needed to ensure that all customers who want rooftop solar can easily interconnect their system to the grid. We also assessed the
reliability of the system to ensure that we have the
right type of resources to continue reliable service
to customers. See Sections 8 and 12 for details
about future pathways and reliability analyses.
Pivoting to an online meeting format during the pandemic, Molokaʻi and Lānaʻi virtual community meetings (live presentation with facilitated question-and-answer session) were held in summer 2020 attended by a total of 31 attendees. The meetings were also recorded and posted online for viewing with thousands of views (Molokaʻi had 4,293 views and Lānaʻi had 3,569 views).
4.2.3 Hawai‘i Powered Public
Participation Site
In March 2022, we launched an online public participation site at hawaiipowered.com. The purpose of this site was to provide a dynamic hub for community engagement, with content that helped humanize the planning effort, convey
technical concepts in plain language, and offer
multiple opportunities to get involved. The
participation site paired with the Integrated Grid
Planning project website, where community
members could explore the document library and
learn more about the technical planning process.
We chose the campaign name, “Hawai‘i Powered,” to convey pride, collective action and shared responsibility in planning for a future grid powered entirely by local renewable resources. This name helped us lead with less technical language than “integrated grid planning” in communications with the public and celebrate finding local solutions for renewable, resilient energy in partnership with many people—within and outside of Hawaiian Electric.
The Hawai‘i Powered participation site provided:
■ An overview of Integrated Grid Planning goals and commitment to community engagement, with multimedia features including a welcome video.
■ Learning modules, such as interactive charts,
that depict how much renewable energy
comes from various local sources with wide-
ranging technologies.
■ A community survey about energy priorities
and a real-time data visualization of the results collected from online and in-person events.
■ Information about recent and upcoming Integrated Grid Planning activities on each island.
■ Short forms for people to request a presentation for their community groups, contact the project team and sign up for
email updates. As of February 2023, we
received a total of six requests for
presentations and 22 messages through the
“contact us” feature.
■ A blog called Plugged In, with monthly posts about Integrated Grid Planning milestones, features on customers and Hawaiian Electric team members, and “deeper dives” on technical subjects. See Table 4-2 for a list of blog posts and their purposes. Copies of these posts are provided in Appendix A.
■ Monthly Hawai‘i Powered e-newsletters sharing Integrated Grid Planning updates
and blog post links with all project
subscribers. We included statements
encouraging readers to share each
newsletter with their family and friends. The
newsletter gained subscribers with each
edition, presumably as recipients shared the email with their networks.
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Table 4-2. Hawai‘i Powered Blog Posts, March 2022 to February 2023
Purpose Blog Post Titles, Publication Dates and Synopses Provide transparent updates on Integrated Grid Planning
Announcing Hawaii Powered 3/11/2022 Learn how Hawaiian Electric is moving toward a sustainable future and how you can get involved.
Shared Solar 101 3/11/2022
Explore how solar power generation goes beyond private rooftop solar panels.
Humanize Hawaiian Electric Aloha from Hawaiian Electric! 4/18/2022 Meet Colton Ching, who leads Hawaiian Electric's efforts to power the grid with 100% renewables by 2045.
Demystify technical topics What You Need to Know: 2021-2022 Sustainability Report
4/19/2022 See how much power Hawaiʻi is cleanly generating, how communities are getting involved in a green future, and more!
Non-wires alternatives 5/31/2022 Learn about the benefits of NWAs and how they fit into our clean energy future. Inputs and Assumptions: What does the data really mean? 9/6/2022 Learn about the data and modeling that goes into planning for enough renewable energy to power our future grid.
Distributed Energy Resources: A diverse grid is a strong grid
7/6/2022
Learn how diversifying energy generation is necessary to a clean energy future.
Promote community-driven clean energy initiatives and community engagement efforts
Molokai residents receive kits to help save energy at home 7/5/2022 Read about the Molokaʻi residents who picked up energy saving kits from Hawaiʻi Energy, the County of Maui Department of Water Supply and Hawaiian Electric.
Building Resilience in North Kohala: A collaborative approach to strengthen our communities
8/1/2022
Read more about this community's collaborative approach to energy resilience.
Encourage behavior changes and participation in clean energy planning
Energy Efficiency: The power to change is in our hands 6/1/2022 Get pro tips on how to be your most energy efficient. Electrification of Transportation: Driving toward a renewable future 8/2/2022 Check out our EV toolkit and how we're preparing for more electric transportation.
Renewable Energy Zone (REZ) Maps: You know your community best
11/28/2022
We need your help identifying potential project locations.
a. Hawaiian Electric published the Energy Efficiency, Distributed Energy Resources and Electrification of Transportation blog posts in advance of launching the inputs and assumptions data dashboard (see information about the dashboard below). These three posts built on one another and provided foundations to help people understand the inputs and assumptions used in modeling. We provided links to these blog posts on the inputs and assumptions data dashboard for readers to reference.
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From March 2022 to March 2023, the Hawai‘i Powered participation site received 2,928 total visits from 1,765 unique visitors.
4.2.4 Inputs and Assumptions
Data Dashboard
In September 2022, we launched a complementary site to Hawai‘i Powered to share information about the data and models we use to predict how much clean energy we’ll need to meet future customer demand. This site, called the
inputs and assumptions data dashboard
(hawaiipowered.com/iadashboard), provided
interactive learning modules and graphs tied to
the data sets we used to model future energy
scenarios.
Our intent was to help make this highly technical
process more accessible by explaining and visually conveying what scenario planning is, what it involves and why it matters. See Figure 4-5 for a screenshot of the data dashboard homepage.
See Appendix A for more screenshots of the dashboard.
Figure 4-5. Screenshot of the inputs and assumptions data dashboard
To promote the inputs and assumptions data dashboard, we published a blog post, sent an e-newsletter to all subscribers, added a banner notification at the top of the Hawai‘i Powered participation site and posted the welcome video
to Hawaiian Electric’s social media. We also
presented it at a Stakeholder Council meeting and
encouraged council members to share it with their
networks. The data dashboard received 624 visits
from 339 unique visitors from September 2022 to
March 2023.
4.2.5 Student and Youth
Engagement
We believe it is essential to involve young people
in planning for a clean energy future, as they will
be its inheritors and stewards.
To that end, we developed a Hawai‘i Powered activity book in 2022, with energy exercises, power-up puzzles, creative coloring and more for learners of all ages. We distributed this activity book at community events on Hawai‘i Island, O‘ahu and Maui. Parents and teachers could also
download the activity book at hawaiipowered.com.
Figure 4-6 shows pages from the activity book.
See Appendix A for a copy of the full activity
book.
Young people shared their input in ranking the importance of key considerations for the Integrated Grid Plan. See Section 4.2.6 for an overview of the local events and community conversations including the ranking activity.
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Figure 4-6. Cover and pages from the Hawai‘i Powered activity book
4.2.6 Local Events and
Community Conversations
We conducted our second campaign of community outreach from July 2022 through
February 2023. Our goals with this round of outreach were to:
■ Tailor our strategies to each island,
recognizing that they have unique needs,
conditions and opportunities for
decarbonization and public participation
■ Connect with community members, listen to and document their ideas, and help answer questions about clean energy planning
■ Raise awareness about Integrated Grid Planning and Hawai‘i’s decarbonization goals
■ Gather public input on potential future REZs
■ Understand how community members prioritize Integrated Grid Planning key considerations
We participated in local events and hosted
community conversations, which were small-
group, in-person or virtual events to share
information and discuss Hawai‘i’s energy future.
Community conversations typically included handouts or display boards with Integrated Grid
Planning information, presentations by members of the Hawaiian Electric team, and time for open discussion. Benefits of participating in local events and hosting community conversations included:
■ Supporting other local initiatives for clean energy and sustainability outside of Hawaiian Electric. These events included local fairs and festivals, where we staffed booths to reach a broader audience and
raise awareness about Integrated Grid
Planning and Hawai‘i’s decarbonization
goals.
■ Focusing our outreach to communities who
might be most impacted by energy projects.
■ Improving accessibility to our Integrated Grid Planning team by offering more opportunities to connect in more communities, at more places and at more times.
To share information about upcoming opportunities to connect with the Hawaiian Electric team and share input, we maintained an
updated list of events per each island on the Hawaiʻi Powered website.
We had the opportunity to connect with
community members at 26 events on Hawai‘i
Island, Maui and O‘ahu in 2022 and early 2023.
The following is a summary of the events we
attended or hosted on each of the islands.
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4.2.6.1 Hawai‘i Island
We connected with community members at 16 events on Hawai‘i Island in 2022:
■ He Ala Pono Electric Vehicle and Sustainability Fair in Hilo
■ Rotary Club of Kona Mauka in Kona
■ Kiwanis Club of East Hawai‘i in Hilo
■ AstroDay in Kona
■ Girls Scouts STEM Fest in Waikoloa
■ Vibrant Hawai‘i’s Resilience Hub Makahiki
and Community Resilience Fair in Puna
■ Vibrant Hawai‘i’s North Hawai‘i Resilience
Fair in Waimea
■ Focus group sessions with Sustainable Energy Hawaiʻi and County of Hawai‘i mayor's cabinet (two separate events)
■ Holualoa Elementary School second-grade class
■ Vibrant Hawai‘i’s South Hilo Resilience Fair in Hilo
■ Hawai‘i Island Realtors in Hilo
■ Vibrant Hawai‘i’s Ka‘ū Makahiki in Ka‘ū
■ County of Hawai‘i Senior Lecture Series in Hilo
■ Vibrant Hawai‘i’s North Hilo Resilience Fair in
Laupahoehoe
■ Hamakua Community Development Plan Action Committee in Honoka‘a
We also introduced the Hawai‘i Powered website at virtual and in-person community meetings in early 2022, prior to the launch of the REZ maps. These events were:
■ March to May 2022: County of Hawai‘i Community Informational Sessions (10 in-person, island-wide events)
■ Hawai‘i Leeward Planning Conference (virtual)
■ Waimea Community Association (virtual)
Figure 4-7 shows community members and Hawaiian Electric staff connecting at public events across Hawai‘i Island, 2022.
Figure 4-7. Participants at engagement events across Hawai‘i Island
Top to bottom, left to right: Hawaiian Electric staff discussing REZs at the 2022 He Ala Pono Electric Vehicle and Sustainability Fair. Girl Scouts with Hawaiian Electric Activity Books at Girl Scouts in STEM event. Community members learning about REZs at Kiwanis Club of East Hawai‘i meeting. Community member commenting on REZs at Vibrant Hawai‘i event in Puna. Kids with Hawaiian
Electric activity books at Vibrant Hawai‘i in Puna.
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4.2.6.2 Maui
We connected with community members at nine events on Maui in 2022. Figure 4-8 shows community members sharing their priorities for Integrated Grid Planning key considerations at a Hawaiian Electric booth at Maui Arbor Day. Hawaiian Electric team members shared information about the key considerations, and
visitors voted on their top priorities using poker
chips. We tallied the number of chips at the end
of the event, and included the count in our
summary of public feedback. See Appendix A for a summary of the ranking of key considerations.
Figure 4-8. Community members use poker chips to vote on the most important grid planning considerations at a Maui Arbor Day event, 2022
We also hosted eight community conversations with 44 representatives of various organizations and interests, including:
■ Government officials
■ Cultural practitioners
■ Community stakeholders/members
■ Conservation and environmental advocates
and organization representatives
■ Businesses
■ Agricultural leaders
At these conversations, we shared information about our planning efforts and sought a wide range of perspectives from our Maui community.
4.2.6.3 O‘ahu
From October through December 2022, we held six community conversations across O‘ahu for people to join in person or online. We sent notices about the upcoming conversations to elected officials, neighborhood boards and energy-related groups and organizations. We also sent a news release to various media outlets and promotional
news stories ran in the Star Advertiser and Pacific
Business News.
Each community conversation included an open
house (in-person only) followed by a hybrid
community workshop (in-person and via Zoom).
The workshops were also livestreamed and recorded by ʻŌlelo Community Media. A total of 105 community members joined us in person.
We collected input about the REZ maps and priorities for O‘ahu energy facilities and services, including microgrids. Figure 4-9 shows community members and the Hawaiian Electric team at the O‘ahu community workshops. See Appendix A for a record of all comments received and a summary of what we heard.
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Figure 4-9. Community conversations about microgrids on O‘ahu, fall 2022
O‘ahu microgrid planning was an outcome of
Hawaiian Electric’s involvement in DOE's Energy
Transitions Initiative Partnership Project (ETIPP) to
improve energy resilience and combat climate change. As part of this partnership, Hawaiian Electric helped identify areas on O‘ahu that are optimal for developing microgrids to build a more resilient electric grid. See Section 10.6 for more information on ETIPP.
MICROGRID:
A microgrid generates, distributes, and
regulates the supply of electricity to
customers on a smaller, local scale
compared to traditional, centralized
grids. Microgrids are a group of
interconnected loads and distributed
energy resources within clearly defined boundaries. They are normally interconnected to the grid and can disconnect from the grid during emergencies. They are best suited to areas near critical infrastructure (such as hospitals and emergency response centers), have access to renewable
energy resources, and are prone to
prolonged outages during weather
events.
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We also launched an online interactive map and survey at hawaiipowered.com/etipp about potential locations for future microgrids on O‘ahu. The online map and survey helped the public and planners alike consider the technical and
practical viability of microgrid development.
Figure 4-10 presents a screenshot of the online
microgrid survey.
Figure 4-10. Screenshot of the O‘ahu microgrids online
map and survey
We approached community outreach differently on Lānaʻi and Moloka‘i, recognizing the unique needs and conditions of energy planning on those islands.
4.2.6.4 Lānaʻi
Much of our grid planning work on Lānaʻi happened in collaboration with the majority landowner on the island. The Hawaiian Electric
team announced its selection of a developer to
build and maintain the largest renewable energy
project and the first to offer the shared solar
program on the island. We have completed contract negotiations with DG Development & Acquisition, LLC; however, we have not finalized the contract as the majority landowner, Pūlama Lānaʻi, notified Hawaiian Electric of its intent to design and construct microgrids to supply the energy demands of the resorts on Lānaʻi.
4.2.6.5 Moloka‘i
Moloka‘i is preparing a Moloka‘i Community Energy Resilience Action Plan: an independent, island-wide, community-led and expert-informed collaborative planning process to increase
renewable energy on the island. The Moloka‘i
Clean Energy Hui by Sustʻāinable Moloka‘i is
coordinating the action plan. Hawaiian Electric is
providing technical support to the Moloka‘i Clean
Energy Hui in its planning process to develop a
portfolio of clean energy projects to achieve 100% renewable energy for the island that is feasible, respectful of Moloka‘i's culture and environment, and strongly supported by the community. Learn more at sustainablemolokai.org/renewable-energy/molokai-cerap.
At all community events and talk stories across the islands (as described above), we focused on gathering public input about two topics:
Integrated Grid Planning key considerations and the concept of REZs.
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4.2.6.6 Key Planning Considerations
We organized Integrated Grid Planning key considerations into five categories: time, affordability, land use, community and resilience/reliability. We asked community members to help us understand which
considerations are most important to them by ranking their priorities. Figure 4-11 displays the consolidated ranking of key considerations by the people who voted on their priorities at events on Hawai‘i Island, Maui and O‘ahu, as well as online at hawaiipowered.com/powerup.
Figure 4-11. Key considerations ranked by community members (voting online and in person)
The ranking activity showed that affordability and reliability are top priorities for many community members. This feedback was consistent with what we heard from community members in our initial phase of public outreach in 2020. This key takeaway informed our Integrated Grid Plan by reaffirming our dedication to finding clean energy solutions that also stabilize customer rates and ensure reliable power that people can count on.
4.2.6.7 Renewable Energy Zones
A core part of the Integrated Grid Planning
process was identifying potential future locations
for renewable generation facilities and
transmission and distribution infrastructure to
power the grid with 100% clean energy. Hawaiian
Electric partnered with NREL to estimate the
potential for large-scale solar, wind and
distributed rooftop solar developed based on available land, potential capacity and potential electricity generation for sites across the five islands. This included data about:
■ Wind and sun coverage
■ Steepness of slopes
■ Financial costs
■ Access to the site and proximity to existing
transmission corridors and grid connections
■ Land use and zoning
We identified potential areas called renewable
energy zones to complete a high-level analysis of
the transmission requirements needed to support
the interconnection of each zone to our electric grid.
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We shared information about REZs with the public online and at the in-person events described
above. We invited the public to help us understand the potential impacts, land use opportunities and community needs and interests within each REZ on Hawai‘i Island, Maui and O‘ahu. Together, public input and technical
studies help inform a round of competitive
procurements to be issued in 2023. We will further
use the input and data to find synergies between
commercial and community interests to refine our
grid plans and future competitive procurements in
2024 and beyond.
We launched interactive renewable energy maps at hawaiipowered.com/rez to gather public input. See Figure 4-12 for a screenshot of the interactive map website.
Figure 4-12. Screenshot of the REZ interactive maps
On this site, community members could learn about the development of the potential REZs and add their input by placing pins with comments on the maps, representing areas of opportunities and
RENEWABLE ENERGY ZONES:
A renewable energy zone (REZ) is an area that has suitable technical conditions for clean energy generation projects. These projects include cost-effective connections to the existing grid and additional transmission infrastructure required to connect renewable energy generation to
customers. A REZ will enable efficient
interconnection of clean energy projects
that may include solar, wind, and
battery energy storage (among other resources), expanding grid capacity.
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challenges. Examples of opportunities and challenges are:
■ Opportunities: Which areas could be successful sites for future energy projects?
Available land/property
Access to existing energy grid
Vacant building/property
Co-location possibilities
■ Challenges: Which areas would be most
challenging?
Steep terrain
Sensitive species
Cultural sensitivities
New or planned construction
Recreation
Agriculture
The REZs input period was open from September 2022 to February 2023. Participants could view
other pins and comments on the maps, and the
record of comments remained available online
once the input period closed.
We conducted a media campaign from January 17
to February 12, 2023, called “Power Up,” to promote the REZ website and public input opportunity. The campaign involved placing ads on Instagram and Facebook, sending emails to all stakeholders on the project email list, leveraging Hawaiian Electric’s customer communication email system, and publishing a blog post and e-newsletter.
Power Up received 6,334 visits from 5,385 unique visitors, primarily on mobile devices. The campaign was extremely successful, resulting in a lot of visitors, extended time spent on the page (just under 2 minutes), and more than 500 comments.
Figure 4-13 depicts a Power Up Facebook ad.
Viewers could click the ad to visit the REZ maps
and share their input. See Appendix A for
additional copies of the social media ads and information about their reach, as well as copies of the email to stakeholders and e-newsletter to all project subscribers.
Figure 4-13. Social media ad to promote the opportunity to provide input on the REZs
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We also took the REZ maps on the road, soliciting in-person feedback at the public events detailed above, including local fairs and festivals and community workshops. At these events, we asked participants to place dots on the maps,
representing areas of opportunities (green dots) and challenges (yellow dots). Figure 4-14 displays the sticker-dot activity from Maui community workshops in fall 2022.
Figure 4-14. Participants at Maui community workshops, fall 2022, placed stickers representing opportunities and challenges within REZs
We received more than 500 comments on the
online and in-person maps. We sorted comments into categories that correspond to key considerations in Integrated Grid Planning: time, affordability, community, land use and resilience and reliability. See Appendix A for a record of all public comments posted to the REZ interactive maps.
We will consider the comments we received as we
work with communities and developers to identify opportunities for future renewable energy projects. See Section 10 for additional discussion on public input as it relates to energy equity.
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5 Today’s Planning
Environment
Since we began the Integrated Grid Planning process in 2018, global and local environmental
factors have significantly changed. During 2020, we saw dramatic decreases in electricity
usage impacting the operations of our system; in 2022, we started to see recovery to pre-
pandemic levels.
Inflation and tight supply chains have plagued progress on renewable energy projects and access
to foundational grid equipment. This has caused
upwards of 30% increased cost for solar and
battery energy storage equipment and short
supply of skilled labor. Oil prices spiked in part
because of the Russia-Ukraine conflict, resulting in
an increase of electricity rates.
Customers continue to affirm through our public
engagement that reliability and affordability are
most important to them. Intertwined are energy
justice and equity issues as certain customers are
being left behind, creating a clean energy divide.
Our grid planning is guided by laws and policies enacted by the Hawaiʻi State legislature, along
with the multitude of interrelated proceedings
before the PUC. Hawaiʻi continues to lead the
nation in climate and environmental policies,
particularly in the electricity sector. Overarching
State policies that guide our grid planning include
100% renewable energy by 2045 and statewide GHG reductions of 50% by 2030 and net negative by 2045 compared to 2005 levels.
5.1 Hawaiʻi Energy Policy
In 2008, a memorandum of understanding
between the State of Hawaiʻi and DOE launched
the Hawaii Clean Energy Initiative, which laid out
the foundational elements to achieving Hawaiʻi’s clean energy future. It envisioned that 60% to 70% of future energy needs would be provided by renewable energy, including energy efficiency. Then, in 2014, a re-commitment to the Hawaii Clean Energy Initiative blazed the pathway for the nation’s first ever 100% renewable portfolio standards (RPS) by 2045. The memorandum of understanding between Hawaiʻi and DOE set forth several key goals:
■ To define the structural transformation that
will need to occur to transition Hawaiʻi to a
clean energy–dominated economy
■ To demonstrate and foster innovation in the
use of clean energy technologies, financing methodologies and enabling policies designed to accelerate social, economic and political acceptance of a clean energy–dominated economy
■ To create opportunity at all levels of society that ensures widespread distribution of the
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benefits resulting from the transition to a clean, sustainable energy state
■ To establish an “open source” learning model for others seeking to achieve similar goals
■ To build the workforce with crosscutting
skills to enable and support a clean energy
economy
Table 5-1 summarizes the key energy policies enacted by the legislature over the past 15 years, which has led to significant progress in shaping Hawaiʻi’s sustainable energy future. The sum of these policies are considered in our planning as described in this report.
Table 5-1. Key State Policies and Legislation That Drive Energy Planning
Sector State Policy Electricity
Clean electricity standard
Performance incentives
Act 155 (SLH 2009) set an RPS target of 25% by 2020 and 40% by 2030. Act 97 (SLH 2015) modified the RPS to 70% by 2040 and 100% by 2045. Act 5 (SLH 2018) initiated the performance-based regulation proceeding, to establish performance incentives and penalties to accomplish State policy goals (e.g., accelerated RPS achievement).
Climate
Statewide decarbonization
Climate emergency
Act 234 (SLH 2007) declared that by 1/1/2020 the State of Hawaiʻi shall reduce statewide GHG emissions to levels at or below the best estimations and updates of the inventory of GHG emissions estimates for 1990. Act 109 (SLH 2011) requires the PUC to explicitly consider, quantitatively or qualitatively, reliance on fossil-fuel and GHG emissions when determining the reasonableness of costs of utility system capital improvements and operations. Act 15 (SLH 2018) set a target to sequester more atmospheric carbon and greenhouse gases than the state produces no later than 2045, which was furthered in 2022 by Act 238 to set a target to reduce statewide emissions by 50% by 2030 compared to 2005 levels. Act 23 (SLH 2020) ceased coal burning for electricity operations by 12/31/2022. This led to the closure of the AES coal plant in September 2022. Senate Concurrent Resolution 44 (2021) declaring a climate emergency and requesting statewide collaboration toward an immediate just transition to restore a safe climate.
On-road transportation
Light-duty zero-emissions vehicles (ZEVs)
Act 74 (SLH 2021) Plan and coordinate vehicle acquisition to meet the following clean ground transportation goals: (1) 100% of passenger vehicles in the State’s fleet shall be ZEVs by 12/31/2030 and (2) 100% of light-duty vehicles in the State’s fleet shall be ZEVs by 12/31/2035.
Buildings
Building electrification
Building codes/appliance standards
EE programs
DER resources
Act 99 (SLH 2015) set a goal for the University of Hawaiʻi to achieve net-zero energy usage by 2035. Act 176 (SLH 2016) set a goal for the Hawaiʻi Department of Education to achieve net-zero energy usage by 2035.
Act 204 (SLH 2008) required a solar water heater for all new single-family dwellings. State Building Code Council establishing statewide adoption of 2018 International Energy Conservation Code (IECC) for residential and commercial buildings.
Act 141 (SLH 2019) established minimum appliance efficiency standards. Act 155 (SLH 2009) established an EE portfolio standard of 4,300 GWh statewide reduction by 2030. Act 100 (SLH 2015) established a CBRE program.
Resilience
Microgrids
2018 Act 200 (SLH 2019) encouraged the development of the microgrid services, which led to PUC approval of Hawaiian Electric Rule 30.
Equity
Energy equity
Senate Concurrent Resolution 48 (2022) requested the PUC to consider efforts to mitigate high energy burdens for LMI customers and integrate energy equity across its work.
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Each county in Hawaiʻi also has or is in the process of developing sustainability plans in alignment with State policy. For example, the City and County of Honolulu will transition its vehicle and bus fleet to electric as required by Ordinance 20-
47. The Department of Transportation Services
now has 17 electric buses (eBuses) in service and
has installed bus charging equipment to kick-start
TheBus transition to 100% electric. It has also
stated a goal of 45% reduction in targeted GHG
emissions by 2025 relative to 2015.
5.2 Federal Policies
At the federal level, the Biden Administration has set forth the following climate goals, which are consistent with State policies:
■ Reducing U.S. GHG emissions 50%–52% below 2005 levels in 2030
■ Reaching 100% carbon pollution–free electricity by 2035
■ Achieving a net-zero emissions economy by 2050
■ Delivering 40% of the benefits from federal
investments in climate and clean energy to
disadvantaged communities
The U.S. Department of Defense is our largest
customer, and all branches of the military are
represented in our service territory, highlighting the importance of a reliable and resilient electric system in support of the national defense and the Indo-Pacific region. The U.S. Army, Navy and Marines have set forth climate strategies. The Army Climate Strategy seeks to achieve 50% reduction in Army net GHG pollution by 2030 compared to 2005 levels; attain net-zero emissions by 2050; install a microgrid on every installation by 2035; provide 100% carbon
pollution–free electricity for Army installations by
2030; and electrify light-duty, non-tactical and
tactical vehicles. Similarly, the Department of Navy
Climate Action 2030 plan seeks to reduce greenhouse gases by 65% by 2030 from 2008 levels, provide 100% carbon pollution–free electricity by 2030, with half locally supplied, and acquire 100% zero-emissions vehicles (ZEVs) by 2035.
5.2.1 Bipartisan Infrastructure
Law and Inflation Reduction
Act
In 2022, the U.S. Congress enacted two bills in
support of the Biden Administration’s goals that will significantly impact the nation’s clean energy
transition. We along with the State are aggressively pursuing federal funding to ease the financial burden of the clean energy transition on Hawaiʻi’s residents.
Collectively, the Infrastructure Investment and Jobs Act (IIJA) and Inflation Reduction Act represent a fleeting opportunity for the State and our customers and communities to obtain federal funding to advance sustainability and resilience
goals. We have identified a portfolio of projects
that have the highest impact and chance for
success to receive IIJA funding—grid resilience,
grid flexibility and modernization, electrification of
transportation and middle mile broadband.
Our pending middle mile broadband application is awaiting award notice, which could come with up to a 69% federal match in funding. In December 2022, we submitted two concept papers to DOE for the grid resilience and grid flexibility and modernization topic areas. We currently have grant applications pending with DOE to gain funding to offset costs to implement our Climate Adaptation, Transmission and
Distribution Resilience program to harden grid
infrastructure and for Phase 2 of our grid
modernization program.
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The Inflation Reduction Act also provides investment tax credits for standalone storage, which could benefit the Waena and Keahole battery energy storage projects that were selected through the Stage 2 competitive procurement. We
do not expect the tax credits from the Inflation
Reduction Act to materially affect the outcome of
the grid needs assessment (Section 8). The cost
projections (Section 6.9.1) for hybrid solar and
wind were already the lowest-cost resource option
available to the model. We will gain further insight into the Inflation Reduction Act impacts as we evaluate prospective projects through the Stage 3 RFP.
Outside of the modeling process, we recognize the importance of the Inflation Reduction Act to reducing cost to customers, including leveraging any potential tax credit “adders” based on other factors like Indigenous communities. We will
continue to pursue available federal funding to
reduce the costs of any Hawaiian Electric–owned
projects.
5.3 Interrelated Dockets
Integrated Grid Planning and Performance-Based
Regulation proceedings are foundational to
implementing State energy policy and achieving
its goals. In combination, these two proceedings shape how we will continue to serve Hawaiʻi with clean, affordable and reliable energy.
A multitude of ongoing proceedings are currently before the PUC, in collaboration with Hawaiʻi energy stakeholders, intended to carry out the legislature’s policies. The Integrated Grid Plan is foundational to these interrelated proceedings because it sets forth a well vetted common set of assumptions and lays out future pathways as we move toward our decarbonization goals. Having
PUC-approved Integrated Grid Plan and priorities
set under Performance-Based Regulation (along
with a stable financial structure for the utility)
allows other dockets to advance more efficiently by reducing protracted discussions on forward-looking assumptions and resource plans. The Integrated Grid Plan sets the direction to implement other initiatives and programs.
Throughout this report we note where other
dockets are intertwined with the Integrated Grid
Plan. The Stakeholder Council discussed the
importance of maintaining the interrelationship of
the following dockets.
Performance-Based Regulation (Docket 2018-0088). A docket to reform Hawai‘i’s regulatory framework through regulatory mechanisms focused on utility performance and alignment with public policy goals.
Performance-Based Regulation and the Integrated Grid Plan build upon one another, including but not limited to performance incentives for RPS achievement, interconnection of rooftop solar and
large-scale resources, fossil-fuel cost risk sharing,
generation reliability and Extraordinary Project
Recovery Mechanism (EPRM) to enable needed
investments to transition the grid we need.
Priorities outlined in Performance-Based
Regulation are areas that the Integrated Grid Plan seeks to address and may also drive future adjustments to Performance-Based Regulation such that the execution of our near- and long-term plans are aligned with Performance-Based Regulation priorities that ultimately accomplish our decarbonization goals.
Community-Based Renewable Energy Program (Docket 2015-0389). A docket to create a
market-based framework that enables renewable
energy opportunities for customers who are
unable to have on-site distributed generation.
CBRE resources acquired through CBRE Phase 1
and assumptions to fulfill the Phase 2 program capacity are part of the planned resources in our plans. The CBRE resources in our plans play an
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important role in providing essential grid services under a renewable dispatchable PPA while simultaneously expanding customer access to renewable energy for those without a roof to install solar, LMI customers or renters.
Competitive Bidding Process to Acquire
Dispatchable and Renewable Generation
(Docket 2017-0352). A repository docket for RFP,
PPAs and other documents related to the
procurement of large-scale renewable resources and grid services.
Since the power supply improvement plans in December 2016 we have issued procurements for large-scale renewable dispatchable generation through three stages of procurements, known as Stages 1, 2 and 3. Through Stages 1 and 2, solar paired with battery energy storage and standalone energy storage have been the lowest-cost technologies awarded contracts. Many of
these projects have been plagued by supply-chain
and other issues caused by the pandemic. A Stage
3 procurement is currently in progress to procure
additional renewable energy and also seeks firm
renewable generation to enable retirement of existing fossil fuel–based generators. The Stage 3 renewable energy targets are a part of the planned resources in our analysis.
Microgrid Services Tariff (Docket 2018-0163). A docket to establish a greater structure around microgrid interconnection(s) and the value of services provided by microgrids through a microgrid services tariff.
Through this proceeding, we worked with stakeholders to develop a microgrid services tariff
that enables communities to build microgrids for
added resilience. Enhancements to enable more
participation in microgrids are expected to
continue in Phase 2 of the proceeding. However, in parallel we have worked with the Resilience Working Group and the Energy Transition
Initiative Partnership Project to identify and prioritize critical and vulnerable customers. As discussed in Section 7, microgrids are part of our tools to enhance grid resilience.
Electrification of Transportation Roadmap
(Docket 2018-0135). A docket to evaluate the
state of EV technology and the EV market in
Hawai‘i and Hawaiian Electric’s near- and long-
term priorities for electrifying the transportation
sector.
As part of the Integrated Grid Planning forecasts and assumptions we have developed EV adoption forecasts with managed charging load usage to determine the benefits of workplace and daytime charging. We also describe the potential distribution infrastructure needed to integrate electrification onto our grids. See Sections 8 and 11.
Distributed Energy Resource Policies (Docket 2019-0323). A docket to investigate technical,
economic and policy issues associated with
distributed energy resources and further develop
a portfolio of broader DER customer options.
As discussed in Section 6, we have incorporated
future DER programs and time-of-use (TOU) rates, including managed EV charging, as part of our forecasted electric load.
An important component of our resource portfolio to date and into the future are customer resources, including private rooftop solar, battery energy storage, electric vehicles and energy efficiency. These customer technologies are prominently discussed throughout this report.
Investigation of Energy Equity (Docket 2022-
0250). A docket to investigate energy equity to
further State policy goals, improve energy
affordability, reduce energy burdens for
vulnerable customers and ensure that the benefits
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of the renewable energy transition are equitably distributed, among other things.
We are keen on addressing energy equity, as discussed in Section 10, as we strive to make the transition to our decarbonized future as equitable
as possible. In our engagement with customers,
we have heard firsthand from communities burdened by hosting energy infrastructure and projects. We have also heard from customers that affordability is their highest consideration.
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6 Data Collection
In the data collection phase of the process we engaged with numerous Working Groups
made up of industry leaders, economists and engineers along with our Stakeholder Council
and Technical Advisory Panel to collect data to forecast how customers will choose to
consume and produce energy in the future. This includes evaluating the propensity for
customers to adopt new technologies like private rooftop solar, battery energy storage,
electric vehicles and energy-efficient appliances, among other key inputs and assumptions.
These forecasts allow us to develop scenarios and
pathways to understand how energy needs will
change over a range of possible futures. For
example, we will use a high and low adoption rate
of customer technologies to determine the lowest-cost way to deliver renewable energy to
customers.
We aim to create the grid as a platform to support both active and passive customers of the grid—for those who desire traditional electric service or for those who want greater control over their energy use. The choices customers make in adopting technologies and the ways they choose to use electricity influence how many large-scale projects we must pursue. We used these forecasts in our
analysis to lay out pathways for a grid that works for all.
See Appendix B for more details on the forecasts,
assumptions and methodologies used as part of
the Data Collection phase and overall planning process.
6.1 Load Forecast
Methodology and Data
The customer load forecast is a key assumption
for the planning models that provide the energy
requirements and peak demands that must be
served by the grid through the planning horizon.
Based on the recommendation of the TAP we
developed a High Load and Low Load projection
(i.e., bookend sensitivities) to test how the cost and portfolio of resources would change for a
range of peak demand and load profiles. These bookend sensitivities are influential in supporting planning analysis that are robust to changes in future load assumptions. Assumptions to the Base forecasts need to be considered holistically because policy, technology and economic condition changes often cause offsetting effects. Rather than attempting to holistically revise the
Base forecasts between planning cycles, the
scenarios and sensitivities described in Section 6.8
provide a range of forecasts to plan for
uncertainties in adoption of customer
technologies, which ultimately drive the amount
of electricity we forecast our customers will consume.
We developed forecasts for each of the five islands and began with the development of the energy forecast (i.e., sales forecast) by rate class (residential, small, medium and large commercial and street lighting) and by layer (underlying load forecast and adjusting layers: energy efficiency,
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distributed energy resources, electrification of transportation and time-of-use rate load shift).
The underlying load forecast is driven primarily by the economy, weather, electricity price and known adjustments to large customer loads and is
informed by historical data, structural changes4
and historical and future disruptions. The impacts
of energy efficiency, distributed energy resources,
primarily private rooftop solar with and without
storage (i.e., batteries), and electrification of transportation (light-duty electric vehicles and electric buses, collectively “EoT”) were layered onto the underlying sales outlook to develop the electric sales forecast at the customer level. Load shifting in response to time-of-use rates was also included as a forecast layer. Because we assumed a net-zero load shift (i.e., load reductions during the peak period are offset by load increases during other periods), there is impact to the peak
forecasts, but no impact to the sales forecasts. The
March 2022 Inputs and Assumptions Report
provides additional descriptions of the load
forecast assumptions and methodologies.
The modeling process to identify grid needs relies on a set of forecast assumptions to define what we believe the future system could look like. Many of these assumptions have been developed by the forecast assumptions, the solution evaluation and optimization, and the Stakeholder Technical Working Groups.
4 Structural changes include the addition of new resort loads or new air conditioning loads that have a persistent impact on the forecast.
5 See Hawaiian Electric's DER Program Track Final Proposal filed on May 3, 2021, in Docket 2019-0323, Instituting a Proceeding
6.2 Distributed Energy
Resources Forecasts
The DER forecast layer, mainly private rooftop solar and battery energy storage systems (BESSs), includes new additions of rooftop solar capacity by island, rate class and program, and projected sales impact from these additions. We used current/near-term pending and approved DER applications and the long-term economic payback of customers installing a private rooftop solar system to develop the forecast.
At the time forecasts were developed, advanced
rate designs (ARDs) and long-term DER programs
were in the process of being finalized. We
assumed that the future customer solar programs
compensate for export that is aligned with system
needs and allow for controllability during system emergencies. The export compensation and tariff structure for future customer solar programs were based on the Standard DER Tariff for all islands that we proposed in the DER docket5. On January 25, 2022, the PUC issued Order 38196 establishing the framework for the Smart DER Tariff6. While export compensation, incentives and tariff structure for the Smart DER Tariff are awaiting
final PUC approval, anecdotal conversations with
industry experts, customer application and permit
data show that customers are choosing to use
battery storage to shift their generation to offset
their own load rather than exporting to the grid
during the daytime.
to Investigate Distributed Energy Resource Policies pertaining to the Hawaiian Electric Companies.
6 6 See Order 38196 issued on January 25, 2022, in Docket 2019-0323, Instituting a Proceeding to Investigate Distributed Energy Resource Policies pertaining to the Hawaiian Electric Companies.
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In addition, for O‘ahu and Maui, we incorporated the current Battery Bonus program7, and assumed new DER-provided grid services (i.e., bring-your-own-device programs) as part of a long-term DER program. Consistent with the Battery Bonus
program, incentives would be paid based on
performance and commitment of the customer
resource. We assumed customers participating in
Battery Bonus export at the battery system’s rated
capacity (kilowatts [kW]) (if energy is available) for
a 2-hour duration during the evening peak window each day. Future retrofits for net energy metering customers assumed both an addition of a battery system, 5 kW/13.5 kWh, and an increase in PV capacity, 5 kW8. The described methodology
and forecast sensitivities appropriately capture the PUC-approved Battery Bonus program targeting 50 MW on O‘ahu and 15 MW on Maui.
NREL 2021 Annual Technology Baseline (ATB) forecasts PV and BESS costs to continue to decline
and with the rollout of a broad opt-out time-of-
use rate, we assumed that most future systems
under the future Smart DER Tariff will be paired
with storage. Furthermore, the rollout of a broad
opt-out time-of-use rate would increase the incentive to pair future systems with storage.
Table 6-1 and Table 6-2 summarize the private rooftop solar and energy storage forecasts by island used in the Base scenario.
Table 6-1. Forecasted Cumulative Distributed PV Capacity (kW)
Year O‘ahu Hawai‘i Island Maui Molokaʻi Lānaʻi Consolidated kW A B C D E F =A + B + C + D +E 2025 723,234 138,801 158,260 3,200 1,050 1,024,545 2030 830,974 164,392 185,501 3,696 1,356 1,185,919
2040 993,411 209,179 227,968 4,476 1,888 1,436,922 2045 1,053,934 227,449 242,917 4,768 2,085 1,531,153
2050 1,104,843 243,258 255,327 4,952 2,266 1,610,646
Table 6-2. Forecasted Cumulative Distributed BESS Capacity (kWh)
Year O‘ahu Hawai‘i Island Maui Molokaʻi Lānaʻi Consolidated kWh A B C D E F =A + B + C + D +E 2025 317,754 84,230 128,263 1,348 515 532,110
2030 493,412 126,316 179,030 2,308 875 801,941
2040 756,521 196,611 254,943 3,976 1,550 1,213,601
2045 848,456 224,301 282,258 4,588 1,829 1,361,432
2050 923,096 247,272 303,603 5,068 2,072 1,481,111
7 See Order 37816 issued on June 8, 2021, in Docket 2019-0323, Instituting a Proceeding to Investigate Distributed Energy Resource Policies pertaining to the Hawaiian Electric Companies.
8 Order 37816 permits existing PV customers to add up to 5 kW of additional PV generation capacity.
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6.2.1 High and Low Bookend
Sensitivities
High and low DER adoption rates were developed to capture uncertainties associated with the base assumptions. Under these sensitivities, we modified assumptions to the addressable market, incentive structure and technology costs.
Under the High DER sensitivity, we assumed an extension of the federal investment tax credit through 2032, with residential investment tax
credits ending and commercial investment tax credits settling at 10% in 2033. These assumptions
closely align to the final provisions under the
Inflation Reduction Act, signed into law on August
16, 2022. The long-term upfront incentives for a
future grid services program on all islands were also increased to $500/kW for the high DER forecast.
NREL 2021 ATB Advanced Scenario cost curves for residential and commercial PV and battery systems were selected for the High DER sensitivity forecast. The ATB Advanced Scenario assumes a rapid advancement in technology innovation and
manufacturing at levels above and beyond the
current market, resulting in lower projected costs
compared to the ATB Moderate Scenario.
The Low DER sensitivity (compared to the Base)
assumes a smaller addressable market, no long-term export program and no additional incentives for distributed energy resources.
The No State Income Tax Credit (ITC) sensitivity was modeled assuming a 0% State ITC starting in 2022, resulting in lower DER uptake compared to the Base forecast. In both sensitivities, DER system costs and tax credit assumptions were updated similarly to the current Base scenario. Figure 6-1 illustrates the revised DER forecasts for O‘ahu.
Figure 6-1. O‘ahu DER bookend sensitivities
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6.3 Advanced Rate Design
Impacts
The advanced rate design discussed in the DER docket includes the implementation of default time-of-use rates, with an option to return to the prior rate schedule, applicable also to all new DER customers. Consistent with advanced rate design, each customer that adopts private rooftop solar and energy storage and/or electric vehicles under managed charging scenarios is effectively shaping their consumption aligned with a time-of-use rate.
For example, DER customers would charge their
energy storage system with rooftop solar during
the day and discharge the energy in the evening.
This load shifting is captured in the forecasted battery energy storage profiles. Because these kinds of DER customers are already assumed to be shifting their load in a manner consistent with that encouraged by proposed time-of-use rates,
minimal to no additional load shift would be
expected in response to time-of-use rates for
these customers. The managed charging forecast
profiles for EV customers reflect customers
charging electric vehicles during the day in
response to time-of use rates.
We evaluated time-of-use load shifting impact for non-DER and non-EV customers. Table 6-3 was used to develop time-of-use load shift scenarios for residential customers.
Table 6-3. Summary of Assumptions Used to Develop Residential TOU Load Shift Sensitivities
Input Low Base High Rates Hawaiian Electric Final ARD Proposal Hawaiian Electric Final ARD Proposal DER Parties Final ARD Proposal
Residential customer pool All non-DER residential customers = residential forecast minus High DER Sch-R forecast
All non-DER residential customers = residential forecast minus Base DER Sch-R forecast
All non-DER residential customers = residential forecast minus Base DER Sch-R forecast AMI rollout 100% by 2025, straight line from current deployment to 2025
100% by 2025, straight line from current deployment to 2025
100% by 2025, straight line from current deployment to 2025
TOU rollout Default rate for AMI meters ramps up from 2022 to 2026 Default rate for AMI meters ramps up from 2022 to 2026 Default rate for AMI meters ramps up from 2022 to 2026
Load shift method Net-zero load shift Net-zero load shift Net-zero load shift
TOU opt-out rate (%) 25% 10% 10%
Price elasticity -0.045 -0.070 -0.070
On October 31, 2022, the PUC issued Decision and Order 38680 under Docket 2019-0323, establishing a framework for the determination of the new time-of-use rates. Under the order, the PUC directed the new time-of-use energy charge to have a price ratio of 1:2:3 for the daytime, overnight and evening peak periods. While the
PUC’s order came after the establishment of the
forecast we assumed a 1:2:3 ratio in the time-of-
use High sensitivity forecast. We will also conduct
a study on the customers assigned to the time-of-
use rates pilot to understand the impacts and effectiveness of the rate design. We will consider how to incorporate findings from the study into future Integrated Grid Planning cycles. For this cycle, we believe that the High and Low bookend scenario reflects significant load shaping and generally captures unanticipated impacts of rate
design changes or behavioral changes for
customers who do not have an electric vehicle or
rooftop solar and energy storage.
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The uncertainty of these and other future changes in customer trends are what the High and Low bookends are intended to capture such that any changes that may occur, that impact the net demand, would fall within the bookends.
6.4 Electrification of
Buildings and Energy
Efficiency
The EE layer is based on projections from the July 2020 State of Hawaii Market Potential Study prepared by Applied Energy Group (AEG) and sponsored by the Hawai‘i PUC.9 The market potential study considered customer segmentation, technologies and measures, building codes and appliance standards as well as
progress toward achieving the Energy Efficiency
Portfolio Standards. The study included technical,
economic and achievable EE potentials. AEG
reclassified certain market segments to different customer classes to align with how we forecast sales.
6.4.1 High and Low Bookend
Sensitivities
An achievable business-as-usual (BAU) EE
potential forecast by island and sector covering
9See https://puc.hawaii.gov/wp-content/uploads/2021/02/Hawaii-2020-Market-Potential-Study-Final-Report.pdf
the years 2020 through 2045 was provided in February 2020 to use as our Base forecast. The business-as-usual potential forecast represented savings from realistic customer adoption of EE measures through future interventions that were
similar in nature to existing interventions. In
addition to the business-as-usual forecast, AEG
provided a codes and standards (C&S) forecast
and an Achievable: High forecast. The Achievable:
High potential forecast assumed higher levels of
savings and participation through expanded programs, new codes and standards and market transformation.
The additional EE potentials provided by AEG allowed for the creation of various forecast sensitivities. As a result, we developed three different sensitivities, Low, High and Freeze. Table 6-4 and Figure 6-2 summarize the EE sensitivities and their forecasted annual sales (GWh).
Table 6-4. Energy Efficiency Bookend Sensitivities
Low Base High Freeze
BAU (Reduced by 25%)+ C&S
BAU + C&S Achievable: High + C&S
Forecasted BAU capacity fixed at 2021 Base forecast + C&S
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Figure 6-2. O‘ahu energy efficiency annual sales forecast impact sensitivities
6.4.2 Energy Efficiency Supply
Curve Bundles
EE supply curve bundles were developed to
determine the optimal amount of EE measures compared to the assumed forecasted energy efficiency using the results of the market potential study that AEG performed on behalf of the PUC. These supply curves were used in the EE supply curve sensitivity discussed in Section 11.1.3.
6.4.2.1 Energy Efficiency Supply Curve
Development Methodology
The supply curves were developed to treat energy efficiency as an available resource to be selected based on its cost and value. This required creating a new level of EE potential, referred to as “achievable technical,” before applying any screens for cost-effectiveness.
Peak Impacts
Each EE measure has an island-specific load shape, which was created during the potential study process. By taking the annual savings calculated from the market potential study and distributing it across this shape, impacts in each hour of the year can be calculated for each measure shape. The relative “peakiness” of each measure was considered by comparing its impacts during peak hours to a flat shape. Peak impacts refer to
impacts on the average weekday evening peak
hour (between 6 and 8 p.m.) and are calculated as
the average impacts during such hours.
Figure 6-3 shows the average impacts of all
measures within each classification using Oʻahu as an example, based on cumulative potential in 2030. As expected, peak-focused measure impacts are strongly concentrated in the weekday evening hours, whereas “other” measure impacts are much flatter.
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Figure 6-3. Averaged weekday impacts by measure classification, cumulative in 2030 (peak vs. other, Oʻahu)
6.4.2.2 Analysis Results
Figure 6-4 shows the incremental energy savings
potential for each bundle over the forecast period. The sharp increase in savings in 2025 coincides
with an increase in commercial linear lighting installations because of equipment turnover in the potential study modeling. These annual savings values do not include reinstallation of measures that were previously incentivized and may have expired. While these measures will need to be reacquired in later years, they will not increase the
total cumulative potential, so those reacquisition
savings are excluded from this perspective.
There could be marginal additional savings at the time of reacquisition, such as if technology standards have improved in the intervening years; however, such savings would be difficult to quantify directly using the outputs of the market potential study. The modeled potential without reacquisitions is a conservative estimate to avoid overstating potential.
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Figure 6-4. Incremental annual energy savings potential (achievable technical) by measure bundle (all islands
combined)
The peak bundles are dominated by the cooling end use. The Peak A bundle, which includes the most cost-effective measures from the potential study, gets 77% of its savings from the cooling end use. The “Other” bundles are made up mainly
of water heating, lighting and appliance measures,
which tend to have flatter or even morning-
focused shapes.
6.5 Electrification of
Transportation
The EoT layer consists of impacts from the charging of light-duty electric vehicles (i.e.,
privately or fleet-owned passenger vehicles) and
electric buses. A medium- and heavy-duty EV
10 Medium-duty trucks (Classes 4–6) range from 14,001 to 26,000 pounds, and their uses include parcel, linen, and snack-food delivery as well as utility service or “bucket” trucks for telecom and electricity services. Heavy-duty trucks (Classes 7 and 8) weigh more than 26,000 pounds, and include long-haul, regional freight delivery, and drayage trucks (which transfer containers from ports to warehouses). See Hawaiian Electric’s Electrification of Transportation Strategic Roadmap, 2018.
forecast has been identified for inclusion for the next Integrated Grid Planning cycle.10
6.5.1 Light-Duty Electric Vehicles
The light-duty EV forecast was based on an
adoption model developed by Integral Analytics, Inc. as described in Appendix E of the EoT
Roadmap11 to arrive at EV saturations of total light-duty vehicles by year for each island. Historical data for LDV registrations were provided by the State Department of Business, Economic Development, and Tourism and reported at the county level. The development of the EV forecast used the EV saturation by island to arrive at the number of light-duty electric vehicles.12 Although
11 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/electrification_of_transportation/201803_eot_roadmap.pdf
12 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/forecast_assumptions/PUC-HECO-IR-1_att_8_electric_vehicles.xlsx
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EV saturations were not specifically consistent with carbon neutrality in Hawaiʻi by 2045, they are consistent with county goals for converting their fleets to 100% zero-emissions vehicles by 2035.
6.5.2 Electric Buses
The eBus forecast was based on discussions with several bus operators throughout Honolulu, Hawaiʻi and Maui Counties. Route information and schedules for weekdays, weekends and holidays were used to estimate the miles traveled for each bus operator. For each island, the total sales impact for each bus operator was applied to the rate schedule on which each bus operator was serviced.
6.5.3 High and Low Bookend
Sensitivities
Three additional light-duty EV forecast sensitivities (Low, High and Freeze) were developed using varying adoption saturation curves. At the June 17, 2021, Stakeholder Technical Working Group meeting, Blue Planet presented its suggested
sensitivity representing a policy of 100% zero-
13 See Transcending Oil Report by Rhodium Group available at: https://rhg.com/wp-
emissions vehicles by 2045 in the Faster Technology Adoption scenario, a change from the previously presented high saturation curve. Following that meeting, we developed a high customer adoption forecast based on the
Transcending Oil Report prepared by the
Rhodium Group in 2018. The Transcending Oil
Report study considered vehicle scrappage rates
and the transition rate of vehicle sales to fully
electric. The study estimated that all vehicle sales
by 2030 would need to be electric to reach 100% EV stock by 2045.13 A freeze sensitivity was also developed, assuming no new additional electric vehicles above the Base forecast after 2021. Table 6-5 and Figure 6-5 summarize the light-duty EV sensitivities and their forecasted annual sales (GWh).
Table 6-5. Electric Vehicle Forecast Sensitivities
Low Base High Freeze
Low adoption saturation
Market forecast 100% of ZEV by 2045
Forecasted EV counts fixed at 2021 Base forecast
content/uploads/2018/04/rhodium_transcendingoil_final_report_4-18-2018-final.pdf
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Figure 6-5. O‘ahu EV annual sales forecast sensitivities
6.5.4 Managed Electric Vehicle
Charging
The managed EV charging profile considers EV driver response to time-of-use rates that were proposed for each island in the EV pilot programs in Docket 2020-0152. A linear optimization was
used to model drivers who shift their usage to the
daytime to reduce their electricity bill as much as
possible, while still retaining enough state of
charge to meet their underlying driving profiles.
The underlying trip data are the same so the managed and unmanaged charging have the
same annual loads. The average managed EV charging profile for select years is provided for Oʻahu in Figure 6-6.
Figure 6-6. Average managed EV charging profile for Oʻahu
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6.6 Sales Forecasts
Once all the layers are developed for each island, they are added together to arrive at the sales forecast at the customer level by island as shown in Table 6-6 through Table 6-10.
Table 6-6. O‘ahu Sales Forecast
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles Customer Level Sales Forecast GWh A B C D E = A + B + C + D 2025 9,456 (1,255) (1,887) 92 6,407 2030 10,133 (1,415) (2,307) 221 6,632
2040 11,110 (1,642) (2,917) 789 7,341 2045 11,499 (1,707) (3,142) 1,366 8,016
2050 11,905 (1,756) (3,332) 1,964 8,781
Table 6-7. Hawai‘i Island Sales Forecast
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles Customer Level Sales Forecast GWh A B C D E = A + B + C + D 2025 1,471 (228) (268) 10 986
2030 1,535 (263) (345) 39 967
2040 1,634 (325) (461) 172 1,020
2045 1,670 (346) (501) 288 1,110 2050 1,708 (364) (535) 435 1,244
Table 6-8. Maui Sales Forecast
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles Customer Level Sales Forecast GWh A B C D E = A + B + C + D 2025 1,474 (271) (300) 14 917
2030 1,572 (312) (371) 56 945
2040 1,726 (374) (473) 255 1,134
2045 1,787 (390) (505) 357 1,248
2050 1,852 (403) (529) 443 1,363
Table 6-9. Molokaʻi Sales Forecast
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles Customer Level Sales Forecast GWh A B C D E = A + B + C + D 2025 36.0 (5.8) (3.1) 0.1 27.2 2030 36.4 (6.5) (3.6) 0.3 26.6
2040 37.8 (7.7) (4.2) 1.1 27.0 2045 38.3 (8.0) (4.5) 2.1 27.9
2050 38.9 (8.2) (4.7) 3.2 29.3
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Table 6-10. Lānaʻi Sales Forecast
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles Customer Level Sales Forecast GWh A B C D E = A + B + C + D 2025 40.8 (1.7) (1.6) 0.1 37.6
2030 42.2 (2.1) (2.0) 0.2 38.2
2040 44.1 (2.9) (2.8) 0.7 39.1
2045 44.7 (3.2) (3.0) 1.3 39.8
2050 45.6 (3.4) (3.3) 1.9 40.8
As part of future Integrated Grid Planning cycles,
we will consider full economy-wide
decarbonization scenarios and their impact on electric sales. This Integrated Grid Planning cycle focused mostly on the decarbonization of buildings, light-duty electric vehicles and bus segments of the economy. We expect significantly higher electric loads under aggressive electrification scenarios.
6.7 Peak Forecasts
Once the sales forecast is developed by layer (underlying load, rooftop solar and energy storage, energy efficiency and electric vehicles and buses) for each island, we convert it from a monthly sales forecast into a load forecast at the
system level for each hour over the entire forecast
horizon. The method converting sales to an hourly
load forecast is shown in Figure 6-7. Hourly
shapes from class load studies for each rate class
or the total system load excluding the impact
from solar are used to derive the underlying
system load forecast shape. Hourly regression
models are evaluated to look for relationships
with explanatory variables (weather, month, day of the week, holidays) to accommodate change in the underlying shapes over time for each rate class or total system load. The hourly regression models are used to simulate shapes for the underlying forecast based on the forecast assumptions over the entire horizon. The forecasted energy for the underlying and each adjusting layer is placed under its respective future load shape then converted from the
customer level to system level using a loss factor14
as presented in the July 17, 201915 and March 9,
202016 Forecast Assumptions Working Group
meetings. The result is an hourly net system load for the entire forecast period. The annual peak forecast is the highest value in each year.
Table 6-11 through Table 6-15 show peak forecasts by island.
14 The net-to-system factor used to convert customer sales to system level load is calculated as equal to 1/(1-loss factor) and include company use. The loss factors are included below: Oʻahu: 4.43%; Hawaiʻi: 6.76%; Maui: 5.17%; Lānaʻi: 4.39%; Molokaʻi: 9.07%
15 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/workin
g_groups/forecast_assumptions/20190717_wg_fa_meeting_presentation_materials.pdf
16 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/forecast_assumptions/20200309_wg_fa_meeting_presentation_materials.pdf
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Figure 6-7. Process for converting sales forecast into an hourly demand load forecast
Table 6-11. O‘ahu Peak Forecast (MW)
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles TOU Peak Forecast
MW A B C D E F = A + B + C + D + E 2025 1,579 (60) (339) 16 (3) 1,193
2030 1,642 (95) (402) 39 (5) 1,179
2040 1,736 (87) (454) 145 (4) 1,335
2045 1,702 (43) (452) 286 (4) 1,490
2050 1,721 (51) (477) 473 (4) 1,661
Table 6-12. Hawai‘i Island Peak Forecast (MW)
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles TOU Peak Forecast
MW A B C D E F = A + B + C + D + E 2025 229.5 (10.0) (42.6) 2.1 (1.3) 177.6
2030 236.8 (12.5) (55.5) 8.7 (1.5) 176.0 2040 249.9 (10.8) (84.2) 39.6 (2.2) 192.3
2045 247.2 (3.4) (85.3) 64.5 (1.9) 221.2 2050 256.5 (3.8) (99.6) 99.3 (2.1) 250.3
Table 6-13. Maui Peak Forecast (MW)
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles TOU Peak Forecast
MW A B C D E F = A + B + C + D + F 2025 245.5 (18.0) (47.3) 3.4 (0.8) 182.7
2030 260.0 (29.2) (58.1) 12.5 (1.2) 184.1
2040 240.1 (3.9) (64.6) 64.5 (0.9) 235.2
2045 254.2 (4.1) (67.7) 79.0 (0.9) 260.4
2050 259.1 (16.8) (71.2) 112.7 (1.1) 282.8
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Table 6-14. Molokaʻi Peak Forecast (MW)
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles TOU Peak Forecast
MW A B C D E F = A + B + C + D + E 2025 5.8 (0.1) (0.1) 0.0 (0.0) 5.6
2030 5.7 (0.1) (0.1) 0.1 (0.0) 5.5
2040 6.1 (0.2) (0.2) 0.2 (0.0) 5.9
2045 6.3 (0.3) (0.2) 0.5 (0.0) 6.3
2050 6.5 (0.3) (0.2) 0.8 (0.0) 6.7
Table 6-15. Lānaʻi Peak Forecast (MW)
Year Underlying Distributed Energy Resources (PV and BESS) Energy Efficiency Electric Vehicles TOU Peak Forecast
MW A B C D E F = A + B + C + D + E 2025 6.5 (0.0) (0.1) 0.0 (0.0) 6.3
2030 6.8 (0.1) (0.2) 0.0 (0.0) 6.5
2040 7.2 (0.1) (0.3) 0.1 (0.0) 6.9
2045 7.3 (0.2) (0.4) 0.3 (0.0) 7.0
2050 7.5 (0.2) (0.4) 0.4 (0.0) 7.3
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6.8 Scenarios and Sensitivities
In collaboration with stakeholders, as documented in the March 2022 Inputs and Assumptions Report, we developed several scenarios to identify a range of potential grid needs. The scenarios test whether given uncertain futures the resource mix and direction of the lowest-cost portfolio would change. Table 6-16 describes the various scenarios we analyzed and presented in this report.
Table 6-16. List of Modeling Scenarios and Associated Forecast Assumptions
Modeling Scenario Purpose DER Forecast EV Forecast EE Forecast Non-DER/EV TOU Forecast EV Load Shape Fuel Price Forecast Resource Potential
Base Reference scenario. Base Base Base Base Managed EV charging Base NREL Alt-1
Land-Constrained Understand the impact of limited availability of land for future solar, onshore wind and biomass development. Base Base Base Base Managed EV charging Base Land-Constrained Resource Potential
High Load Understand the impact of customer adoption of technologies for DER, EVs, EE and TOU rates that lead to higher loads.
Low High Low Low Unmanaged EV charging
Base NREL Alt-1
Low Load Understand the impact of customer adoption of technologies for DER, EVs, EE and TOU rates that leads to lower loads.
High Low High High Managed EV charging Base NREL Alt-1
Faster Technology Adoption
Understand the impact of faster customer adoption of DER, EV and EE. High High High High Managed EV charging Base NREL Alt-1
Unmanaged Electric Vehicles
Understand the value of managed EV charging relative to unmanaged. Base Base Base Base Unmanaged EV charging
Base NREL Alt-1
DER Freeze Understand the value of the distributed PV and BESS uptake in the Base forecast. Informative for program design and solution sourcing.
DER Freeze Base Base Base Managed EV charging Base NREL Alt-1
Electric Vehicle Freeze Understand the value of the electric vehicle’s uptake in the Base forecast. Informative for program design and solution sourcing.
Base EV Freeze Base Base Managed EV charging Base NREL Alt-1
High Fuel Retirement Optimization
Understand the impact of higher fuel prices on the resource plan while allowing existing firm unit to be retired by the model.
Base Base Base Base Managed EV charging EIA High Fuel Price NREL Alt-1
Energy Efficiency Resource
Understand the value of energy efficiency as a resource. Informative for program design and solution sourcing. Base Base EE Freeze + EE Supply Curves
Base Managed EV charging Base NREL Alt-1
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Figure 6-8 and Figure 6-9 illustrate the total sales forecast and peak load of the various scenarios, respectively.
Figure 6-8. Oʻahu customer-level sales forecast sensitivities
Figure 6-9. Oʻahu peak load forecast sensitivities
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6.9 New Resource Supply
Options
New resources are made available to the model based on commercially ready technologies today, with a focus on technologies that can be acquired within the next 10 years as part of the solution sourcing process. This does not mean that future technologies are not within our long-term plans. Consistent with our renewable energy principles, we strive to make decisions today that do not crowd out future technologies. As future
technologies mature those will be considered in
future Integrated Grid Plans. This section
describes the resource cost projections for the
resources made available to the model and the
renewable energy potential for solar and wind on
each island.
6.9.1 Resource Cost Projections
Resource cost assumptions were based on publicly available data sets, as shown in Table 6-17.
17 U.S. Department of Energy, 2017 Distributed Wind Market Report, https://www.energy.gov/eere/wind/downloads/2017-distributed-wind-market-report
18 U.S. Department of Energy, 2018 Distributed Wind Market Report, https://www.energy.gov/eere/wind/downloads/2018-distributed-wind-market-report
19 U.S. Department of Energy, 2020 Grid Energy Storage Technologies Cost and Performance Assessment, https://www.energy.gov/energy-storage-grand-challenge/downloads/2020-grid-energy-storage-technology-cost-and-performance#:~:text=Pacific%20Northwest%20National%20Laboratory%E2%80%99s%202020%20Grid%20Energy%20Storage,down%20different%20cost%20categories%20of%20energy%20storage%20systems.
Table 6-17. Resource Cost Data Sources
Data Source Resources DOE Distributed wind 17,18
Pumped storage hydro19
NREL 20 Large-scale solar Distributed solar Onshore wind Geothermal Biomass Large-scale storage Distributed storage Combustion turbine Combined cycle Synchronous condenser
Offshore wind21
U.S. Energy Information Administration (EIA) 22
Waste-to-energy
Hawaiian Electric23 Internal-combustion engine
Resource cost assumptions began with a base technology capital cost that was adjusted for:
■ Future technology trends through the planning period
■ Location-specific capital and operations and maintenance cost adjustments for Hawai‘i using data from the U.S. Energy Information
Administration (EIA) and RSMeans
■ Applicable federal and State tax incentives
20 National Renewable Energy Laboratory 2021 Annual Technology Baseline, 2021 ATB Data, https://atb.nrel.gov/electricity/2021/data
21 National Renewable Energy Laboratory Bureau of Ocean Energy Management, Cost Modeling for Floating Wind Energy Technology Offshore Oʻahu, Hawaii, https://www.boem.gov/sites/default/files/documents/regions/pacific-ocs-region/environmental-analysis/HI%20Cost%20Study%20Fact%20Sheet.pdf
22 U.S. Energy Information Administration, Cost and Performance Characteristics of New Generating Technologies, Annual Energy Outlook 2019.
23 Internal-combustion engine costs are based on the Schofield Generating Station provided in Docket 2017-0213, in response to the Consumer Advocate’s information request 19.
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Figure 6-10 summarizes the resource forecasts in nominal dollars. The resource cost forecasts from 2020–2050 can be found in the March 2022 Inputs and Assumptions Report.
In the near term, there are price declines after
accounting for the investment tax credit schedules
for the federal and State investment tax credits.
Over the longer term, after the tax credit
schedules ramp down and are held constant, the
resources costs generally increase over time. As noted in the NREL ATB, all technologies include electrical infrastructure and interconnection costs for internal and control connections and on-site electrical equipment (e.g., switchyard, power
electronics and transmission substation upgrades).24 Similarly, all technologies also include site costs for access roads, buildings for operation and maintenance, fencing, land acquisition and site preparation in the capital
expenditures as well as land lease payments in the
fixed costs for operations and maintenance.25
Although the ATB does not discretely break out
the percentage of the capital costs or operations and maintenance costs associated with either of
these items, their inclusion is consistent with the adjustment made for recent solar, wind, geothermal and hybrid solar projects as actual project pricing would have accounted for interconnection and land costs.
Figure 6-10. Nominal capital costs for candidate resources in $/kW
A comparison of the levelized cost of energy (cents/kWh) for solar and wind resources is shown below in Figure 6-11.
24 See https://atb.nrel.gov/electricity/2021/definitions#capitalexpenditures
25 Ibid.
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Figure 6-11. Levelized cost of energy for select Integrated Grid Plan candidate resources in cents/kWh
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6.9.2 Assessment of Wind and
Photovoltaic Technical
Potential
The developable potential for wind and solar was based on the resource potential study conducted by NREL. Based on stakeholder feedback, NREL
revised its study to include additional scenarios
described in the July 2021 Assessment of Wind and
Photovoltaic Technical Potential Report.
6.9.2.1 Private Rooftop Solar
The potential study quantifies the technical
potential of solar systems deployed on existing
suitable roof areas in our service territory.
Technical potential is a metric that quantifies the maximum generation available from a technology for a given area and does not consider economic, market viability or other technical constraints (e.g., hosting capacity, system stability, etc.). The analysis relies upon light detection and ranging (LiDAR) data. The model will consider LiDAR point clouds, buildings, solar resource from the National Solar Radiation Database, parcels and tree canopy. The system configurations can also be considered
such as fixed roof, losses, tilt, azimuth, panel type,
module efficiency, inverter efficiency and direct
current (DC):alternating current (AC) ratio. The
results of the analysis are provided in Table 6-18.
Table 6-18. Rooftop Solar Technical Potential Study Results
Island Developable Plane Areas (Acres)
Capacity (MW) Generation (GWh) Capacity Factor (%)
Oʻahu 4,934 3,934 6,369 21.23
Hawaiʻi 3,845 2,163 4,856 19.42
Maui 1,425 1,113 1,858 21.05
Lānaʻi 88 44 112 21.20
Molokaʻi 93 45 112 20.05
Figure 6-12 shows the locations of the Oʻahu rooftop potential. The majority of the potential
rooftop locations are in the urban core and
populated areas. The technical potential may be
needed in later years under the O‘ahu Land-Constrained scenario.
Figure 6-12. Technical potential rooftop solar capacity on O‘ahu
6.9.2.2 Large-scale Wind and Solar
NREL used its Renewable Energy Potential Model (reV) to assess the potential for solar and wind
energy deployment. The solar and wind resource
data sets will be sourced from the National Solar
Radiation Database and the Hawaiʻi Wind
Integration National Dataset (WIND) toolkit. The
solar radiation database has a temporal interval of 30 minutes and nominal spatial resolution of 4 kilometers (km). The WIND toolkit has an hourly temporal interval with a nominal spatial resolution of 2 km. The model will consider land exclusions such as slope, constructed structures, protected areas and land cover. System configurations can also be considered in the model such as axis tracking, losses, tilt, panel type, inverter efficiency and DC:AC ratio.
Based on stakeholder feedback the study allowed
for solar development on land with up to 15% and
30% slope, among other changes to inputs. Table
6-19, below, shows the large-scale solar potential
by island.
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Table 6-19. Summarized Installable Capacity in MW for Large-scale 1-axis Tracking Solar Systems up to 30% Slope Land; Input Assumptions Based on Ulupono Input
Island Large-Scale PV Potential Land Use (Acres)
O‘ahu 3,810 24,711
Moloka‘i 10,411 67,708
Maui 13,687 88,960
Lāna‘i 9,691 63,013
Hawai‘i 76,179 495,456
The large-scale solar potential excludes the
following types of land:
■ Federal lands, including U.S. Department of
Defense lands
■ State parks and golf courses
■ Wetlands
■ Lava flow zones, Flood Zone A and tsunami evacuation zones
■ Urban zones
■ Important agricultural land
■ Soil ratings of Class A and 90% of Class B and C land
■ Road and building setbacks were included
Based on stakeholder feedback the study
provided for wind energy potential without
limitation for windspeed. Table 6-20 shows the
large-scale wind potential by island.
Table 6-20. Summarized Installable Capacity in MW for Large-scale Wind Systems up to 20% Slope Land; Input Assumptions Based on Ulupono Input
Island Wind-Alt-1 (No Wind Speed Threshold)
Land Use (Acres)
O‘ahu 256 21,004
Moloka‘i 515 42,503 Maui 767 63,260
Lāna‘i 509 42,009
Hawai‘i 5,037 414,898
The lands excluded from the potential study are the same as solar, except that land greater than 20% slope was excluded and Class A, B and C soil ratings were included; however, important agricultural lands were still excluded.
6.9.3 Solar and Wind Potential
Assumption
The large-scale solar and wind potential assumption garnered much discussion among stakeholders, with varying perspectives on what can realistically be built because of land use and community concerns.
On the developable resource potential for
onshore large-scale solar and wind, stakeholders
noted that federal contracting rules would require
that the U.S. Department of Defense seek the
highest and best use for properties under its
control, in addition to deciding whether that land
would be made available for renewable energy development. Because of this circumstance, it would be difficult to make a blanket assumption that all U.S. Department of Defense lands are available to develop. Further, stakeholders raised concerns on the ease of developing projects at slopes higher than 10% because of the additional effort and cost involved. However, other stakeholders thought that solar on higher slopes could be developed, up to 30%, with some
additional cost adder because some projects have
already been developed on steeper slopes.
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Taking into consideration the various viewpoints, we used the Alt-1 scenario for wind (no wind speed threshold) and solar potential for various scenarios from the July 2021 Assessment of Wind and Photovoltaic Technical Potential Report as shown in the tables above.
It is worth noting that there is substantial overlap
between areas with solar resource potential and
wind resource potential. And the same system
infrastructure can be used to interconnect both wind and solar resources and transfer the renewable energy to the other locations of the system.
We also recognize the realities of solar and wind development in the state. To that end, the “Land-Constrained” scenario reflects the possibility of future limited land availability for solar and wind development and provide a meaningful bookend of analysis that incorporates stakeholder feedback
to assume that a lower amount of land is available for project development.
6.9.4 Renewable Energy Zones
Prime locations for grid-scale development, flat land with rich solar and wind resources adjacent to existing transmission, have been developed through the Stage 1 and Stage 2 procurements. In addition to location, transmission capacity is becoming a limiting factor. The current
transmission system was not designed for large
generator interconnections at various locations,
but rather one that supports bulk generation
resources supplying power to load centers.
Creating REZs will enable efficient
interconnections to the transmission system to
new areas that are prime for development but either is far from existing transmission infrastructure or requires robust transmission upgrades to accommodate the interconnection of generating resources. REZ upgrades are
composed of two types: (1) transmission network expansion costs, which are the transmission upgrades not associated with a particular REZ but are required to support the flow of energy within the transmission system, and (2) REZ enablement
costs, which are the costs of new or upgraded
transmission lines and new or expanded
substations required to connect the transmission
hub of each REZ group to the nearest
transmission substation. Further details on the
REZs can be found in the Hawaiian Electric Transmission Renewable Energy Zone Study as part of the September 2022 GNA Methodology Report.
Section 8 discusses the REZ enablement and transmission expansion infrastructure and costs needed for each island.
6.9.5 Emerging Technologies In
Development
The data collection phase of the Integrated Grid Planning process involves engagement with several Working Groups along with our Stakeholder Council and TAP. The phase includes incorporating new resource supply options into
the planning model that are considered
commercially ready and capable of being acquired within the next 10 years.
Through public comment and our community
engagement efforts, we received inquiries about
other technologies that could potentially use less
land than solar and wind projects and provide for a more diverse portfolio of resources. Hawaiian Electric monitors resource supply–related options and technologies that are not currently considered within the Integrated Grid Planning process to support our long-term planning efforts. Our plan is flexible and adaptable to incorporate future technologies that may emerge as viable in Hawai’i. Such resources include different fuel types used in electricity generation and emerging
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technologies that may increase the efficiency of fuel production or electricity generation and thereby decrease resource cost projections. One continuously growing area of significance in our long-term planning considerations is exploring
options to provide firm generating capacity from
renewable electrical energy.26 We are committed
to ensuring that sufficient system reliability is
maintained as we continue to decrease our use of
fossil fuel–powered generation and incorporate
increasing amounts of intermittently available wind and solar generation. We are currently monitoring energy developments and emerging technologies that can provide or fuel firm generation and have potential for inclusion in our future grid plans. These include:
■ Generating renewable electrical energy using hydrogen produced from renewable energy sources (“renewable hydrogen”)
■ Emerging technologies to increase the
production output of different
biomass/biofuel production pathways and
decrease the costs
■ EGSs to produce electricity from locations
with favorable thermal conditions and insufficient hydrological reservoirs or recharge rates
■ Generating electricity using OTEC generating plants
While nuclear power, including emerging small modular reactor technology, presents a promising zero-emission energy source, it is currently not
eligible as a renewable energy source under State
26 HRS §269-91 defines “renewable electrical energy” as electrical energy generated using renewable energy as the source and defines “renewable energy” as meaning energy generated or produced using the following sources: wind; the sun; falling water; biogas, including landfill and sewage-based digester gas; geothermal, ocean water, current, and waves, including ocean thermal energy conversion; biomass, including biomass crops, agricultural and animal residues and wastes, and municipal
law, and Article XI, Section 8 of the Hawai‘i‘s State Constitution prohibits nuclear fission power generation without prior approval by the legislature (by a two-thirds vote). Accordingly, nuclear fission generation is not currently included in our plans.
Hydrogen
We recognize that renewable hydrogen (referred
to as “green” hydrogen) can potentially be used to
help meet our RPS requirements. Additionally,
depending on the GHG and carbon-based
emissions from the pathway used to produce the
renewable hydrogen, it is a potential option to help achieve Hawaiʻi’s zero-emissions clean energy target27 and our Climate Change Action Plan.
The market for renewable hydrogen is still quite nascent. Hydrogen is currently produced primarily via steam methane reforming (SMR), which is a GHG-intensive process unless capital cost–intensive carbon capture, utilization and storage
(CCUS) technologies are incorporated. Either
technologies that generate hydrogen along
pathways that are less carbon-intensive are still
developing, or the full process of producing the
hydrogen and using it for utility-based
applications where hydrogen could play a role (e.g., storage) have not been demonstrated to be deployable at scale or be cost-competitive with other technologies. A significant part of the scalability and cost-related challenges for hydrogen arise from the substantial upfront capital expenditures required to expand
solid waste and other solid waste; biofuels; and hydrogen produced from renewable energy sources.
27 HRS §225P-5 defines a zero-emissions clean economy target of sequestering more atmospheric carbon and GHGs than emitted within the state as quickly as practicable, but no later than 2045.
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capabilities for producing renewable hydrogen and developing the infrastructure needed to establish hydrogen delivery and storage capabilities. To help coordinate a pathway to cost-effectively producing hydrogen, DOE is focused
on developing technologies that can produce
hydrogen at $2 per kilogram (kg) by 2025 and
$1/kg by 2030 via net-zero-carbon pathways. The
pathways are summarized below together with
their additional challenges.
Fossil Fuel
■ Coal gasification with CCUS
■ SMR with CCUS
■ Hydrogen must be produced from renewable energy sources defined in HRS §269-91 to meet our RPS requirement, which precludes our use of fossil fuel–based hydrogen
Water Splitting
■ Direct-solar
■ Low-temperature electrolysis
■ High-temperature electrolysis
■ Direct-solar technology is not yet a
commercially viable technology
While electrolyzer technology exists that can be
scaled to produce larger quantities of renewable
hydrogen, hydrogen that is used in applications
that are currently needed by the utility (e.g., short-
duration energy storage) are less energy efficient
and not yet cost-competitive with other existing energy technologies. Additionally, large-scale deployment of utility-scale electrochemical generation from hydrogen has not yet been demonstrated and our generating assets are aging and would not be capable of using hydrogen unless substantial modifications and associated delivery infrastructure are made. Sustained safe usage of 100% hydrogen in
generators using thermal combustion has not been demonstrated at scale.
Biomass/Waste
■ Biomass conversion
■ Waste-to-energy
For the biomass/waste pathway, more work must be performed to determine whether it is more
energy efficient to use the biomass/waste directly
in thermal energy generation, convert it to fuel to
be used in thermal energy generation, or convert
it to hydrogen and generate electricity using
thermal or electrochemical generating
technologies. Additionally, more work is needed to better understand the life-cycle GHG emissions of each energy conversion pathway and the associated costs.
There may be potential for renewable hydrogen use in a long-duration energy storage application as that need emerges in the future provided that the hydrogen can be stored at sufficient capacity and using a process that is energy efficient, is cost-effective and aligns with Hawaiʻi’s and
Hawaiian Electric’s goals for reducing carbon-based and GHG emissions.
We will continue to move forward with the
technologies included in our existing plans to
meet our ambitious 2030 decarbonization goals. Hawaiian Electric is encouraged to see the federal- and state-level efforts to establish a hydrogen market and build out the critical infrastructure needed to generate, deliver and store hydrogen. We support development of renewable hydrogen that aligns with Hawai‘i’s decarbonization and renewable energy laws and policies, and end uses that are prioritized for hard-to-decarbonize sectors, including the transportation sector. We
see some potential for hydrogen to compete in
the long term to provide long-duration energy
storage. For now, our near-term Integrated Grid
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Plan continues to focus on technologies that are commercially available and cost-effective, but we will be closely monitoring the expected progress of hydrogen buildout and growth in the renewable hydrogen sector.
6.9.5.1 Emerging Biomass
Technologies
Biomass power generation and biofuel (liquid and gaseous) production technologies have varying
levels of technology readiness. Mature biomass-
based conversion technologies include
combustion, pyrolysis, anaerobic digestion and
transesterification. Emerging technologies include
biomass gasification and direct biophotolysis.
Biomass Gasification
Biomass gasification, or the conversion of biomass
at lower temperatures (compared to combustion)
and partial oxidation with oxygen or steam to produce syngas, has been demonstrated at utility scale but is not widely adopted on a commercial scale. Commercial biomass gasification project development is heavily dependent on availability of quality feedstocks, feedstock handling and pre-processing, and performance of power conversion systems. The performance of energy crops, including crop yield for dedicated biomass energy conversion in Hawai‘i, is crop- and project-specific
and requires further analysis for commercial-scale
implementation. Power generation equipment
mated to the gasifier, including gas turbines and
internal-combustion engines, are mature
technologies; however, gas cleanup of the gasified
biomass (e.g., removal of tars, oils and solids) remains an area of development.
Direct Biophotolysis
Direct biophotolysis, or the use of the photosynthetic process by algae and cyanobacteria to split water into hydrogen and oxygen, has several areas of development
including harvesting and processing techniques for microalgae biomass, fourth-generation biofuels using genetic modification for higher carbon dioxide (CO2) capture and lipid production, and genetic engineering to lower lignin content
and improve efficiency of cellulolytic fungal
enzymes.
In Hawaiʻi, certain biomass energy project
development will be challenged by land
availability in competition with other renewable energy resources (wind and solar), economics and issues related to carbon neutrality of biomass-based resources. Biofuels from algae remains a technology to watch, including production in Hawaiʻi.
6.9.5.2 Enhanced Geothermal Systems
In Hawaiʻi, geothermal energy comes from volcanic heat stored deep beneath the earth’s surface where underground reservoirs of water heated from the volcanic heat are tapped to power a steam turbine, which converts the energy
into mechanical work to spin the generator and
produce electricity. Unlike PV or wind energy,
which is variable or intermittent, geothermal
energy is continuous and can produce electricity
without the availability of direct sunlight or wind.
Geothermal energy provides continuous, clean, sustainable, firm power.
Although most of our geothermal resource in Hawaiʻi is hydrothermal with heat, fluid and permeability naturally occurring, Hawaiian Electric is also tracking the development of EGSs where underground heat or hot rock is present, but limited rock permeability or fluid is available. In this case, human-made reservoirs are needed. In
an EGS, fluid is injected into the subsurface to
cause preexisting fractures to open, creating
permeability that can receive water to pick up the
heat and be pumped up to the surface and
flashed in steam/vapor to power a turbine to spin
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a generator to make electricity. The technology behind EGS is well known in the oil and gas industry but is a rather new approach for geothermal energy.
Currently, Hawaiʻi has only one geothermal energy
conversion plant, known as Puna Geothermal
Venture (PGV), located at the Kilauea East Rift
Zone in Puna, on the island of Hawaiʻi. The PGV
facility is located above a natural geothermal
reservoir and geothermal fluids are brought to the surface through production wells where heat is extracted, used to produce electricity, cooled and later reinjected back into the ground through injection wells. Currently, PGV is producing about 23 MW to Hawaiʻi Island’s grid and is contracted to provide up to 38 MW (nameplate rating) of firm power electricity. PGV plans to expand to 46 MW and then to 60 MW after future phased repowering upgrades.
Currently, the State has only one site located on
Hawaiʻi Island where geothermal energy resources
have been proven. However, the University of
Hawaiʻi’s Hawaiʻi Groundwater and Geothermal
Resource Center (HGGRC) found geothermal potential on all islands in the state of Hawaiʻi, but that geothermal potential is largely unknown.28 Further geothermal resources assessments and characterization are needed, including drilling of exploratory wells to validate thermal resources and assess generation project viability. More funding is needed to locate, characterize and quantify the subsurface geothermal resource to reduce the risks and improve the economics for
more geothermal energy plants in Hawaiʻi. The
State needs to look for potential sites beyond
Puna, especially on Oʻahu where most of the
28 Thomas, D.M., 1985. Geothermal resources assessment in Hawaii, Hawaiʻi Institute of Geophysics.
29 Geothermics: Play fairway analysis of geothermal resources across the state of Hawaii, N. Lautze, D. Thomas, D. Waller, N.
population resides and works and has the highest demand for electricity. HGGRC estimates that Oʻahu has some potential geothermal capacity to displace fossil fuels in the Koʻolau volcano or Waiʻanae volcano caldera.29 The island of Maui
also has a high to very high development viability
in the Haleakala southwest rift.
6.9.5.3 Ocean Thermal Energy
Conversion
OTEC is a firm renewable energy technology that
may provide a sustainable alternative to
conventional fossil-fuel plants, helping to reduce
GHG and combat climate change. OTEC uses the
temperature difference between the sun-warmed
surface water and the cold, deep water in the
ocean to generate a constant, clean source of electricity. In closed-cycle OTEC, warm seawater is used to boil a working fluid such as ammonia into a vapor through a heat exchanger (evaporator) used to drive a turbine connected to a generator to produce electricity. After passing through the turbine, the working fluid is cooled with cold, deep seawater through another heat exchanger (condenser) and condensed into a liquid that is pumped back to the evaporator to complete the
cycle. OTEC requires a temperature difference of
at least 20 degrees Celsius/36 degrees Fahrenheit
to power a turbine to produce electricity. Power is
continuous and independent of the weather.
OTEC plants require large volumes of seawater, large seawater pumps and intake piping systems, and large-diameter cold-water pipes to transport seawater to the OTEC plant and back to the ocean and they operate in a hostile and corrosive environment. Biofouling of the heat exchangers,
Frazer, N. Hinz, G Apuzen-Ito, Geothermics | Journal | ScienceDirect.com by Elsevier.
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corrosion, frequency instabilities in the generator, outgassing of cold seawater in condensers, and impacts to marine life with the discharge of seawater still need to be researched especially as OTEC plants scale up.30 Although the OTEC
technology has been around since the 1970s and
is technically feasible, it has not been
commercialized at scale because it is expensive,
may have environmental risks to marine life, and has not been tested at large scale. Upfront capital
costs are extremely high, and efficiency for energy conversion is low, making it difficult to obtain financing for commercial-sized OTEC projects. In the 1980s, OTEC was considered too expensive and not economical. However, with technical improvements such as locating the OTEC plants on floating offshore platforms instead of inland installations to minimize the piping runs,
development of large-capacity heat exchangers
optimized for OTEC, and changes in social
attitudes to OTEC, there is currently
commercialization interest, especially in Japan.31
30 UIRENA Ocean Energy Technology Brief 1, International Renewable Energy Agency, June 2014, www.irena.og.
31 OTEC Viability as a Catalyst for Transformative Island Development, Institute of Ocean Energy Saga University Japan, Microsoft PowerPoint - Japan OTEC for ADB MARES Webinar 202209 public.pptx (development.asia)
Recent demonstration projects include a 100 kW closed-cycle OTEC project in Okinawa, Japan, which operated continuously from 2010 to 2019 and has operated intermittently since 2019. In 2015, Makai Ocean Engineering added a 105 kW
turbine generator to the Ocean Energy Research
Center, located at the National Energy Laboratory
of Hawaii Authority in Kailua-Kona on Hawaiʻi
Island. This closed-cycle binary power facility that
uses ammonia as working fluid to drive the
turbine-generator was the world’s largest operating OTEC plant. Makai Ocean Engineering continues to be active in OTEC heat exchanger research and development.
Various OTEC projects have been announced. In 2013, Lockheed Martin announced plans to build a 10 MW OTEC plant in the South China Sea with Hong Kong–based consortium Reignwood, but information on its status is lacking. In March 2023,
Mitsui O.S.K. Lines Ltd. announced plans to build a
1 MW demonstration project in Okinawa, Japan
(off Kume Island) targeted for commercial
operation by 2026. 32
32 Ocean Thermal Energy Conversion Demonstration Project in Okinawa Selected by Japan's Ministry of the Environment - Aiming to Commercialize World's 1st Ocean Thermal Energy Conversion by around 2026 - | Mitsui O.S.K. Lines (mol.co.jp)
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7 Resilience Planning
Reliability and resilience is a top priority for our customers. As extreme events increase in
frequency, we have seen the devasting impacts to grids that are unable to withstand these
impacts have on society. We must act now to make our grid more resilient to better prepare
the state for an extreme event. We have proposed an initial Climate Adaptation
Transmission and Distribution Resilience Program that focuses on least-regrets hardening of
grid infrastructure across all islands we serve. We have a long way to reach our desired
target level of grid resilience. In this section we describe a strategy and roadmap to guide
future resilience investments that balance affordability and resilience needs.
7.1 Resilience Strategy and
Approach
Resilience is the ability of a system or its components to adapt to changing conditions and withstand and rapidly recover from disruptions. For critical infrastructure including electric power
grids, resilience is generally considered to be the
ability to anticipate, absorb, adapt to and rapidly
recover from a potentially catastrophic event
while sustaining mission-critical functions.
Hawaiian Electric is a critical infrastructure
provider. Five of the state’s six island power grids are operated by Hawaiian Electric, which serves 95% of Hawaiʻi’s 1.4 million residents. Among those, we serve the headquarters of the U.S. Indo-Pacific Command and the 36,000 active-duty military members in Hawaiʻi. Hawaiian Electric is the sole electric power provider to the highest geographic concentration of critical defense facilities in the nation. Widespread loss of electricity for extended periods could have
significant impacts including disruption to
community-lifeline and mission-critical services,
loss of life, public health emergencies,
environmental damage and severe economic and
social disruption. These impacts grow with
increasing electrification of transportation,
hybrid/remote work and digitization of the
economy.
Hawaiʻi and Hawaiian Electric face a unique and diverse set of resilience threats, vulnerabilities and challenges. Hurricanes, tsunamis, wildfires, lava flows and earthquakes pose significant threats to our system. And the frequency and intensity of hurricanes are expected to increase because of climate change. The effects of these threats are amplified by the significant geographic remoteness and isolation of Hawaiʻi. The Hawaiian
Islands are the most isolated populated landmass
in the world—5 hours from the West Coast by
plane, 5 days by ship. As such, there are limited
evacuation options, and mutual aid from mainland
utilities and material resupply poses significant
logistical complexity and long lead times. Additionally, there are no electrical interconnections between Hawaiian Electric’s five island grids or to the larger mainland grid, so the generation and delivery of electricity is limited to facilities on each island. Most of Hawaiian Electric’s nearly 10,000 miles of transmission and
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distribution lines are overhead, and a significant portion of these overhead lines were built when needed several decades ago to standards in effect at the time that were generally less robust than current standards to withstand extreme wind
events, such as hurricanes. Hawaiʻi’s volcanic
islands have some of the most extreme
topography found in the nation, with power lines
traversing steep, rugged terrain with limited
access for repairs or replacement of damaged
facilities.
The primary goal of Hawaiian Electric’s overall resilience strategy is to reduce the likelihood and severity of severe event impacts. Achieving a target level of resilience will depend on multiple integrated aspects of resilience including emergency response, generation/power supply resilience, transmission and distribution resilience, system/grid operation resilience, cybersecurity,
physical security and business continuity. Each
plays a crucial role in safeguarding the supply and
delivery of electric power in the face of threats to this critical resource.
Various potential environmental, nation-state and actor-based physical and cyber threats may create major disruptions on an electric grid. These events
result in disruptive impacts having various
potential scales and scopes and inform the
engineering considerations and requirements to
improve the resilience of the electric grid. The
scale and scope of these disruptive impacts also shape the economic impact and related value of solutions.
The “bowtie method” (Figure 7-1), as increasingly used in the industry to leverage risk-threat assessments, translates a threat-risk assessment and grid asset vulnerabilities into specific event risk prevention and mitigation analysis and solution identification. A bowtie approach helps identify where and how a portfolio of solutions
will have the greatest impact for customers and communities.
Figure 7-1. DOE resilience bowtie method
First, this method involves identifying solutions to prevent certain events from causing system failures. Preventive measures are considered foundational to ensure that critical transmission lines, substations and distribution circuits
withstand threats to ensure that critical customers
and facilities have power and facilitate rapid
system recovery for all customers. Preventive measures include grid hardening and can typically take from 15 to more than 20 years to complete. Preventive solutions are shown on the left side of the bowtie above.
Second, mitigation solutions can address locations
where preventive solutions cannot physically or
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cost-effectively address the outage risks. Also, mitigation solutions may be used as near-term solutions to address risks for selected priority customers/critical facilities before the longer-term preventive measures can be implemented.
Mitigation solutions are shown on the right side
of the bowtie.
The specific prevention and mitigation solutions
are identified through both utility asset options
and potential third-party solutions (e.g., microgrids). The utility and third-party solutions are evaluated against performance metrics-driven requirements. Additionally, resilience solution prioritization involves assessing the comparative customer and community risk reduction value of the solutions related to associated generation, transmission, substation and distribution infrastructure.
Therefore, our resilience strategy is designed to
address the need to increase our system resilience
to a target level of resilience. This metric-based
target will be determined through stakeholder
engagement supported by severe event
simulation modeling and engineering-economic evaluation. The following outlines Hawaiian Electric’s general approach to system resilience enhancement:
1. Identification and prioritization of system threats. The Resilience Working Group identified and prioritized system threats in 2019. In alignment with Resilience Working Group priorities, Hawaiian Electric prioritized the
Hurricane/Flood/Wind combined threat as
the top threat to address and made this
threat the primary focus of our initial
resilience planning and implementation
efforts.
2. Development of performance targets and rigorous decision-making methods (Section 7.3). This will support efforts to
(1) baseline the current level of grid resilience, (2) identify the target level of resilience needed and (3) identify and optimize a portfolio of preventive and mitigation solutions to cost-effectively address the resilience gap and reach the
target level of resilience. The resulting
resilience gap will be addressed by
implementing preventive and mitigation
solutions over time in a way that seeks to
optimize cost-benefit characteristics of the portfolio while aligning with State and community priorities.
3. System Hardening (Section 7.4). System hardening includes investments to reduce outages and time to restore grid power via damage prevention/reduction. This includes the initial Climate Adaptation Transmission and Distribution Resilience Program, which will begin to address the
most urgent and critical system needs and
those that provide the broadest scope of
customer and societal benefit. Future
phases of foundational system hardening will incorporate performance metrics and quantitative decision-making methods described above to enable metrics-driven and cost-effective grid hardening beyond the initial phase of “no-regrets” investments.
4. Residual Risk Mitigation (Section 7.5). This includes investments to address near-term and longer-term residual risks and
needs of individual customers and
communities, filling gaps that hardening
investments cannot fully mitigate cost-
effectively. This can include needs that are
either planning process-driven or
community-driven.
Figure 7-2 below illustrates how this approach will address the resilience gap by implementing preventive and mitigation solutions over time.
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Figure 7-2. Preventive and mitigation solutions to address resilience gap
As shown in Figure 7-2, the system’s current level of resilience is represented in orange (Current T&D System Resilience). Hawaiian Electric’s Initial T&D Resilience Program, shown in dark blue,
represents the first phase of foundational
hardening investments to increase the resilience
of the system. Subsequent phases of system
hardening are represented in light blue.
In parallel to hardening the system, Planning-
Identified Residual Risk Mitigation Solutions and Community-Driven Local Mitigation Solutions, represented in green and teal, respectively, will further increase system resilience by mitigating residual risks that are not fully avoided or prevented by system hardening. Planning-Identified Residual Risk Mitigation Solutions include solutions driven by Hawaiian Electric’s planning process (e.g., North Kohala Microgrid), while Community-Driven Local Mitigation
Solutions include solutions initiated by customers
or communities such as customer and hybrid microgrids. Collectively, the portfolio of complementary resilience solutions will contribute to achieving the target level of resilience over time.
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7.2 Identification and
Prioritization of System
Threats
In 2019, the Resilience Working Group
collaborated to identify and prioritize resilience threats to the electric grid. The following were the working group’s priority threat scenarios for the Integrated Grid Planning process:
1. Hurricane/Flood/Wind
2. Tsunami/Earthquake
3. Wildfire
4. Physical/Cyber Attack
5. Volcano (Hawaiʻi Island only)
For each threat, the working group considered moderate and severe reference scenarios to
provide a range of potential impacts to consider
when assessing proposed solution options. Our
initial resilience plans focus largely on the working
group’s consensus top-priority threat: Hurricane/Flood/Wind, with a secondary focus on preventing and mitigating utility-caused wildfires. As discussed in Section 7.3, specific performance targets with respect to prioritized threats should be developed and informed by stakeholders as well as the results of simulated threat models to ensure that targets are appropriate, achievable, and reasonable.
7.3 Development of
Performance Targets and
Rigorous Decision-
Making Methods
The development of performance targets to
define the target level of resilience for the grid and associated decision-making framework are key components in resilience planning.
7.3.1 Establish Target Level of
Resilience
After developing and prioritizing system threats, there is a need to quantify and establish the target level of resilience for the system to achieve with respect to these threats. The process for identifying resilience metrics and establishing resilience metric target levels should ensure the following:
1. Metrics are aligned with stakeholder values and priorities. The metrics
quantifying the “target level of resilience”
need to adequately reflect what a
“resilient” system looks like to relevant
stakeholders.
2. Targets are reasonably practicable. The target level of resilience should be physically achievable for a cost that customers are willing to pay.
Establishing the target level of resilience should begin with identifying the categories of metrics that best reflect stakeholder values as the most important metrics to optimize. To begin this process, Hawaiian Electric proposes to implement the Performance Mechanism Development Process
outlined in a recent report titled Performance
Metrics to Evaluate Utility Resilience Investments
(Report), which was funded by DOE and conducted
as part of the Grid Modernization Laboratory
Consortium (GMLC) under the project named
Designing Resilience Communities: A Consequence-Based Approach for Grid Investment
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(DRC).33 The Report provides a roadmap for the development of performance mechanisms for resilience, a list of principles for developing metrics, a menu of suggested metrics for grid resilience as a starting point, and an Excel-based tool for
visualizing the proposed metrics in the form of
reporting templates. A series of technical sessions
should be held (to include Hawaiian Electric, the
PUC, Consumer Advocate and other relevant
stakeholders) to review the performance
mechanism development process laid out by this Report, review the suggested metrics and identify metrics of interest, populate metrics of interest with available data to the extent feasible, and identify data gaps and how to address these gaps in the short and long terms. The Report notes that while some of the metrics can be produced in the nearer term, it also suggests “more challenging ones for
utilities and communities to work towards over the years to come.” Hawaiian Electric expects to use
well-defined and industry-established reliability
metrics (such as the System Average Interruption
Duration Index [SAIDI] and System Average
Interruption Frequency Index [SAIFI]) as a starting point to supplement vulnerability assessments, resilience solution development and circuit or critical customer prioritization.
In an ideal world, it would be possible to design a system such that no customers lose power in severe events. However, such a goal is unlikely to be achievable for a cost that customers are willing to pay. It is therefore important to ensure that the target level of resilience is physically achievable for a reasonable cost. This will require (1)
quantifying the system’s baseline level of
resilience with respect to severe event scenarios
and (2) estimating the level of investment needed
33 https://www.synapse-energy.com/sites/default/files/Performance_Metrics_to_Evaluate_Utility_Resilience_Investments_SAND2021-5919_19-007.pdf
to achieve the target level of resilience. Because resilience planning inherently deals with unpredictable, low-frequency, high-impact events, quantifying the expected performance of a system under severe event scenarios is possible only
through using advanced modeling to derive
simulated performance metric output values.
Therefore, the resilience performance targets that
are established will need to be refined over time
based on knowledge gleaned from system
performance models, described below.
7.3.2 Develop Decision-Making
Methods
As described above, system performance
modeling will be required to quantify the baseline
level of system resilience and model investment options to achieve the desired target level of resilience.
The system performance model would be used to simulate the impacts of severe events on Hawaiian Electric’s systems using a data-driven, bottom-up process. First, system performance vis-à-vis established performance metrics would be used to quantify the baseline level of resilience. Then, subsequent simulations could be run to test various resilience solutions such as hardening,
automatic switching, mini-grids and microgrids,
and compare solutions and combinations of
solutions against one another in terms of their
expected benefits (defined by established performance metrics) versus costs.
This process of testing various resilience solutions and solution portfolios can also provide insight
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into the achievability and cost reasonableness of performance targets to inform future refinement.
Hawaiian Electric has contracted with the Pacific Northwest National Laboratory (PNNL) to develop and implement a performance system model for
Hawaiian Electric’s grids. This work will leverage
and extend the tools that PNNL developed while
working with Puerto Rico.
Hawaiian Electric is also tracking the development
of tools and methods to quantify resilience value, such as Lawrence Berkeley National Laboratory (LBNL) and Edison Electric Institute’s Interruption Cost Estimator 2.0 Tool (ICE 2.0), LBNL’s Power Outage Economics Tool (POET) and Sandia National Laboratory’s (SANDIA) Social Burden Method and associated Resilient Node Cluster Analysis Tool (ReNCAT). While these tools do not themselves model system performance, they can be used to translate the failure and outage data
derived from system performance models into a
quantified value of resilience to further support
investment options analysis and justification.
7.3.3 Stakeholder Engagement
Stakeholder engagement in the resilience planning process is also necessary to ensure prudent decision making. For the current hardening program and beyond, Hawaiian Electric will continue to gather stakeholder input from
Resilience Working Group members and critical
infrastructure partners to understand critical
infrastructure priorities within and between
various critical infrastructure sectors. This will
include refining and maintaining critical load lists
and priorities.
For future phases of system hardening and residual risk mitigation investments, stakeholder engagement will be used to understand the needs and priorities of individual communities to help target future investment analyses. The community
engagement framework that began under the ETIPP effort can be leveraged, along with input and lessons learned gathered from the community meetings on Oʻahu. This input can help Hawaiian Electric identify vulnerabilities and critical
infrastructure considerations that are unique to
each community and analyze appropriate solution
options.
7.4 System Hardening
Given Hawai‘i’s system resilience vulnerabilities
and challenges, significant investment in damage
reduction is imperative for resilience
improvement. We are the most isolated populated landmass in the world with limited on-island crews, materials and equipment. This isolation poses significant difficulties to securing inventory resupply and receiving mutual aid from the mainland. In addition, Hawaiʻi has extreme topographic features with transmission and distribution lines running across steep, rugged terrain with limited access. There are no transmission interties between the separate island
grids or to the mainland grid. If a hurricane were
to strike the current unhardened grids, customers
could be without power for many weeks to many
months, as evidenced by the 1992 Hurricane Iniki
on Kauai and the 2017 Hurricane Maria that struck Puerto Rico. In long-term outages, backup generators become reliant on fuel resupply (and are typically designed only to operate critical facilities at partial capacity). Renewable energy-based microgrids and customer distributed energy resources that are capable of islanding are typically quite limited in islanding duration capability compared to the long outage durations expected from severe events. Therefore, damage
reduction measures are a central need considering
the catastrophic scale and duration of outages
that these types of events can cause on
unhardened island grids. By reducing damage on
the grid, system hardening reduces the residual
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outage gap to be filled by distributed resources and microgrids. Accordingly, system hardening forms the foundation of Hawaiian Electric’s resilience strategy.
7.4.1 Initial Climate Adaptation
Transmission and
Distribution Resilience
Program
Hawaiian Electric’s initial Transmission and Distribution Resilience Program (Docket 2022-0135) represents the first phase of foundational system hardening investment of approximately $190 million across the islands we serve, with the
potential for a 50% match of federal funding. Because resilience performance targets and advanced decision-making methods have not yet been developed, the focus of this initial program is on “no-regrets” investments. No-regrets
hardening investments are those for which there
is high confidence that the investment will provide
broad system and societal benefit even without
the benefit of advanced methods for quantifying
benefits and costs discussed in Section 7.3.
Examples include hardening critical transmission lines, highway crossings and critical poles on distribution circuits serving highly critical community lifeline infrastructure (see Figure 7-3).
Figure 7-3. Components of initial T&D resilience program
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7.4.2 Future System Hardening
Once the performance targets and quantitative
decision-making capabilities discussed in Section
7.3 are developed, future phases of system
hardening will be shaped by established metrics
and quantitative cost-benefit-based analyses.
Incorporating these advanced methods will enable Hawaiian Electric to prioritize hardening investments in a way that optimizes progress toward the target level of resilience for dollars spent in a more data-driven manner. Examples may include targeted undergrounding or community feeder hardening, including hardening work intended to pair with microgrid projects (see
Section 7.5).
7.4.3 Resilience Standards
Development
Improving T&D system resilience will also require evaluating and refining infrastructure equipment
and apparatus standards and design policies in
relation to the target performance metrics. For
example, there are many open questions in power
system resilience related to topics such as wind speed design policies, pole and structural material considerations with respect to wind and fire threats, and resource siting.
Hawaiian Electric is currently evaluating its wind speed design policies. Since 2007, Hawaiian Electric has designed structures to withstand wind loadings consistent with those prescribed in National Electric Safety Code (NESC) 2002. However, NESC is a minimum safety code requirement, and Hawaiian Electric is evaluating
situations where wind speed design should
exceed NESC 2002 requirements.
Hawaiian Electric is also evaluating the costs and
benefits of various pole and structural materials. While wood and non-wood structures are designed using the same wind speed ratings, life-
cycle cost, accessibility, constructibility and environmental considerations may influence which types of materials may be ideal for different scenarios. To prevent wildfire damage, Hawaiian Electric has begun installing fire mesh and applying fire paint to poles in wildfire risk areas.
For generating facilities, each of our competitive
procurements for renewable generation has an
eligibility requirement for the facility’s
infrastructure. To address flood and sea-level rise threats, we require the point of interconnection to be located outside the 3.2-foot sea-level rise exposure area (SLR-XA) as described in the Hawai‘i Sea Level Rise Vulnerability and Adaptation Report (2017); not located within a Tsunami 27 Evacuation Zone; and not located within the Hawaiʻi Department of Land and Natural Resources flood map’s flood zones A, AE, AEF, AH, AO or VE based on the Federal Emergency
Management Agency’s Digital Flood Insurance
Rate Maps.
As we advance our system hardening efforts we
continue to evaluate ways to improve resilience
requirements for generation facilities to guard
against catastrophic damage because of hurricane and wind threats. We currently have stringent performance standards for IPPs, such as grid-forming and black start, which would allow these facilities to provide critical services in the event that our more traditional generators are not capable of doing so. In addition, we require a stringent cybersecurity review of all new facilities.
7.5 Residual Risk Mitigation
In addition to the preventive hardening solutions, Hawaiian Electric has initiated efforts to address
“Residual Risk Mitigation.” This is aimed primarily
at addressing risks at the community or customer
level that are not fully addressed through the
System Hardening investments. While system
hardening will reduce the incidence and duration
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of outage events through damage reduction, even hardened infrastructure can experience failures in a severe event. Therefore, mitigation investments, such as hybrid microgrids for communities or groups of critical loads, will be needed to address
these residual risks by reducing the impacts of
failures that do occur. Residual Risk Mitigation
investments may also be used to fill resilience risk
gaps while longer-term System Hardening
investments are implemented. The North Kohala
microgrid is an example of this type of investment, where a community microgrid is planned to be implemented prior to a longer-term effort to harden the radial sub-transmission line serving the North Kohala community. By installing the microgrid prior to hardening, the microgrid will reduce customer impacts of planned outages to make repairs or upgrades, while also mitigating
impacts of unplanned outage events. Once the line is eventually hardened to resilience standards,
the hardened line will provide the first line of
defense through damage prevention, while the
microgrid will continue to provide residual risk
mitigation for planned or unplanned outages. Residual risk mitigation can also include community- and customer-driven solutions such as customer and hybrid microgrids.
7.5.1 ETIPP Microgrid
Opportunity Map
In 2021, Hawaiian Electric was selected to participate in ETIPP, which provided access to technical support from the National Labs. The project in collaboration with NREL, SANDIA and the Hawaiʻi Natural Energy Institute (HNEI) is currently in progress, and plans to complete a hybrid microgrid opportunity map by Quarter 2 of 2023. The objective of the map is to provide customers and Hawaiian Electric to identify areas that have overlapping criteria, such as criticality,
vulnerability and societal impact. Once completed,
Hawaiian Electric will be able to leverage the map
and underlying data to identify potential areas for utility or hybrid microgrid siting as well as community feeder hardening. See Section 10 for more details.
7.5.2 Resilience Value
Quantification Methods
For community-level residual risk mitigation, methods such as SANDIA’s Social Burden Method and associated ReNCAT may be especially useful for selecting potential microgrid sites within
communities that would represent the highest
avoided interruption benefit per dollar spent on
microgrid development. As discussed in Section
7.3, Hawaiian Electric is tracking the development
of this and other tools/methods for resilience
value quantification.
7.6 Grid Modernization
Dependency
In addition to foundational grid hardening
discussed above, there is a need to incorporate
greater grid operational awareness, control and
automated switching flexibility to enhance
resilience and reliability. The next phase of our proposed grid modernization program is estimated to cost approximately $63 million (including voltage management devices discussed in Section 8) and is designed to provide system operators with a holistic distribution management solution that will enable reliable and resilient operation of its island grids, while managing high and ever-increasing levels of DER penetration in its pursuit of a fully renewable generation
portfolio. To do so, the solution will integrate and
leverage existing operational technology (OT) and
information technology (IT) systems, an expanded
set of smart grid field devices, AMI, customer-sited distributed energy resources, bulk system renewables, and Hawaiian Electric’s National Institute of Standards and Technology (NIST)-
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based Cybersecurity program. The scope of Hawaiian Electric’s next grid modernization (Phase 2) 6-year scope includes:
■ Advanced distribution management system (ADMS) for grid operators to effectively
monitor, visualize, control and predict
conditions on the distribution grid using
substation automation and distribution field
devices in a coordinated fashion.
■ Telecom and OT cybersecurity monitoring solution to converge security feeds from those networks into a centralized Network Operations and Security Center (NOSC) for 24×7 monitoring and response.
■ Targeted proactive deployment of field devices (i.e., smart fuses, smart reclosers, motor-operated switches and smart fault current indictors) to provide enhanced circuit switching flexibility and capability to address
the needs of high-risk circuits, often located
in disadvantaged communities.
Smart fuses and smart reclosers. We plan
to install 188 smart fuses and 207 smart reclosers. They provide reclosing and
isolating capabilities on distribution lines. These devices sectionalize circuits so that
fewer customers experience service interruptions for faults downstream of the device, and can re-establish service automatically after a momentary fault (e.g., vegetation contacting a line) and
increase system operator visibility and
control.
Motor-operated switches. We plan to
install 59 motor-operated switches on the transmission and distribution system.
These devices provide remote-operated, motor-controlled switching and isolation capability, and can sectionalize circuits so that fewer customers experience service interruptions downstream of the device.
Smart fault current indicators. We plan to install 1,251 of these devices to sense fault current to determine the source and
location of outages. These devices will
allow us to identify specific fault locations,
resulting in faster restoration times.
A visual representation of the different
components of the project and how they are
integrated to provide the full solution is illustrated in Figure 7-4.
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Figure 7-4. Hawaiian Electric Grid Flexibility project components
Grid hardening combined with the proposed field
sensing, automated switches in a fault location, isolation and restoration scheme has proved to significantly enhance the resilience of a distribution network. These grid modernization technologies also enable the integration of customer and hybrid microgrid islanding capabilities for resilience and the utilization of their resources for “blue sky” grid services.
As illustrated in the DOE diagram below (Figure 7-5), each of these investment categories,
discussed in this strategy, build upon one another
to create what DOE refers to as the modern distribution pyramid. This pyramid is founded upon safe, resilient and reliable designs and equipment standards, as well as replacement of aging and inadequate infrastructure that incorporates appropriate resilience “hardening.” These physical grid investments are augmented with operational and information technologies to improve grid operational awareness, protection, controls and automation that enable DER utilization and microgrid development.
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Figure 7-5. DOE distribution investment pyramid
Therefore, grid modernization investments enhance both the prevention and mitigation strategies to reduce customer outages and related impacts. Hawaiian Electric’s ability to address the identified resilience and reliability needs as discussed in this strategy is dependent upon the
next phase of grid modernization that seeks to
significantly improve our distribution operational
capabilities commensurate with industry best
practices.
7.7 Resilience Working Group
Hawaiian Electric’s Resilience Strategy addresses
many of the recommendations of the Resilience
Working Group34 by considering threat scenarios
such as Hurricane/Flood/Wind (see Section 7.2 above on identifying and prioritizing system threats); key customer and infrastructure priorities
34 https://www.hawaiianelectric.com/documents/clean_energy_ha
(see Section 7.4.1 above on the Initial T&D Resilience Program); elements of resilience such as reducing the probability of outages and restoration times during a severe event (see Section 7.3 above on establishing performance targets and developing decision-making
methods); all possible lowest-cost solutions
whether best accomplished solely through utility
actions or through a combination of utility,
customer and third-party actions (see Sections 7.4
and 7.5 above on System Hardening and Residual
Risk Mitigation).
Hawaiian Electric will continue to engage the Resilience Working Group and its members to understand critical infrastructure priorities and to develop and assess resilience metrics.
waii/integrated_grid_planning/stakeholder_engagement/working_groups/resilience/20200429_rwg_report.pdf
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8 Grid Needs Assessment
We define the pathways to 100% renewable energy through use of modeling tools to learn
how much clean energy output is needed and from which technologies to meet the expected
customer electricity demand over time. Using the scenarios and forecasts from the data
collection phase we use multiple models to assess grid needs at the generation resource,
transmission and distribution levels.
In consultation with the public and stakeholders, we use leading-edge practices vetted by the TAP to lay out the lowest-cost pathway that considers each island’s unique needs to achieve an affordable, reliable and 100% renewable system.
Near-term resource additions, hybrid solar and wind, provide the foundation for the lowest-cost, reliable pathway. Variable renewables (i.e., hybrid
solar and wind) procured through planned procurements such as Phase 2 Tranche 2 of the
CBRE program and Stage 3 will solicit projects that
fulfill the remaining transmission capacity and
continue to stabilize rates. In the longer term,
transmission network capacity expansion (REZs) will be needed to integrate higher amounts of variable renewables.
We found that resource diversity will complement weather-dependent resources and shore up reliability. Firm renewables procured through the Stage 3 RFP can effectively diversify the resource portfolio. As existing steam plants continue to age with worsening forced outage rates on Oʻahu and lack of spare parts risks the ability to maintain generating units at Māʻalaea on Maui, reliability
can be improved with the addition of the firm
renewables targeted through Stage 3 that act as
standby generation to be dispatched only during
periods of low sun and wind. However, these
resources may serve in more than just a standby role and be increasingly relied upon if adoption of electric vehicles accelerates faster than anticipated and forecasted loads increase significantly in the near term.
Additional variable renewables selected and analyzed by the planning models through 2035 will form the targets for future procurements, discussed in Section 11. Bringing these resources to commercial operation will require the
development of new REZs. Transmission non-
wires alternatives can cost-effectively manage the
buildout of this new transmission, though this
may mean that less than the full technical potential for new variable renewables can be developed. Grid modernization of the distribution system will also be needed to increase hosting capacity for distributed energy resources and accommodate new housing and electrification loads to meet statewide housing and decarbonization goals.
If REZs cannot be developed, future variable renewables after Stage 3 may be delayed until technological advancements or aggregated
distributed energy resources become a more cost-
effective resource option. In this scenario system
stability is a concern with the current state of
customer-scale inverter technology. Expanding
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energy efficiency may also be a cost-effective resource to pursue and solicited through a future procurement.
Ultimately the pathways we lay out serve as a roadmap to grow the customer- and community-
centered energy marketplace to determine the
specific technologies and projects that allow us to
source the solutions we need for the grid that we
want. It also identifies the transmission and
distribution infrastructure needed to enable the grid as a platform to integrate technologies that we acquire from the marketplace.
8.1 Overview of Grid Needs
We identified resources to meet capacity and energy needs to serve customer demand through a multi-step process. Figure 8-1 provides the modeling framework that was developed with stakeholders to employ multiple models, each to its best capabilities, to assess grid needs at different levels. Using this approach, the capacity
expansion model and resource adequacy analysis
were initially run unconstrained, with no system
security or operational rules assumed. The
modeling steps were then iterated to address any
grid need shortfalls and described in each island’s Preferred Plan in this section. See Appendix B for more information on the modeling framework and methodology.
Figure 8-1. Grid needs assessment modeling framework (adapted from HNEI)
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8.1.1 Capacity Expansion
The capacity expansion step develops
representative resource portfolios that illustrate
how different forecast assumptions (i.e.,
forecasted loads, fuel prices and resource costs)
can cause different resource selections to meet
RPS and reliability planning criteria through the planning horizon ending in year 2050. We run the capacity expansion model to evaluate the different pathways described in Section 3.5 as well the “freeze” cases to determine the value of customer programs in Section 11.1.2.
The resource plans developed in the capacity expansion step are intended to provide directional guidance on the types of resources needed to
meet grid needs. Subsequent modeling steps
evaluate resource adequacy, grid operations and
transmission and system security needs using this
initial resource plan as a starting point. The
following is a summary of the capacity expansion
modeling:
■ Across different load scenarios, the models consistently selected high levels of solar, wind and energy storage because of their low cost. These resources are also used to meet load growth due to electrification of transportation and carbon reduction goals.
■ In scenarios with higher electricity demand, the same mix of resources were selected in
higher amounts and some amount of firm
resources were also added to meet the
capacity planning criteria.
■ In a High Fuel Retirement Optimization
scenario, the model accelerated retirements
early in the planning horizon. While this may be preferred from a cost optimization perspective, practically, a staggered deactivation schedule would better ensure that replacement resources could be placed
into service prior to the thermal unit’s planned removal from service.
■ On Oʻahu, if future onshore renewables are limited in a Land-Constrained scenario, offshore wind and firm renewables will be
relied upon to serve demand. Our 2030 GHG
emission reduction goals may be at risk or
need to be served with higher-cost
renewables such as increased use of biofuels
if large-scale solar and wind cannot be
developed cost effectively.
We then conducted a resource adequacy analysis, as further described in Section 8.1.2, to examine key years in the planning horizon. Year 2030 was examined to confirm that the addition of the Stage 3 RFP variable renewable and firm resources results in a reliable system. Year 2035 was examined to identify any capacity and energy shortfalls that would need to be addressed in the next procurement, which is the next step of the Integrated Grid Planning process.
■ In 2030, the Oʻahu and Maui Base scenarios
and the Oʻahu Land-Constrained scenario that include 450 MW of hybrid solar and
some new firm renewable generation from the Stage 3 RFP achieve a loss of load expectation less than 0.1 day per year. The Hawai‘i Island Base scenario that includes some new variable renewable generation from the Stage 3 RFP achieves a loss of load expectation less than 0.1 day per year. Molokaʻi and Lānaʻi continue to maintain at
least a 0.1 day/year loss of load expectation
through the addition of variable renewables
and storage.
■ In 2035, the resources in the Base and Land-
Constrained scenarios continue to provide
sufficient reliability. We tested the High Load scenario to examine what additional resources after the Stage 3 RFP may be needed if actual loads are closer to the High
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Load forecast. This information is provided below in each island’s Resource Adequacy section.
After confirming that the Base and Land-Constrained scenarios would meet the reliability
standard, we assessed the operations and cost of
the resource plan, as further described in Section
8.1.3.
■ On typical days, the majority of system
demand would be served by renewable resources, predominantly large-scale solar, wind and private rooftop solar.
■ By 2030, we could achieve the following RPS on each island: O‘ahu 77%, Hawaiʻi Island 99%, Maui 91%, Lānaʻi 95% and Molokaʻi 92% with a consolidated RPS of 81% and a consolidated emissions reduction relative to 2005 levels of 75%.
■ In 2030, we could achieve 100% renewable
energy for the following percentage of hours
on each island: Oʻahu 14%, Hawai‘i Island
89%, Maui 57%, Lānaʻi 79% and Molokaʻi
80%.
■ Use of fossil-fuel firm generation is expected
to decline dramatically compared to the status quo.
Additional details, supporting analyses and resource plan data can be found in Appendix C.
8.1.2 Probabilistic Resource
Adequacy
The resource adequacy step examines the reliability of the portfolios built in the RESOLVE model, which is used to optimize the resource portfolio for cost and reliability, among other factors. We then evaluated reliability of the system using metrics such as loss of load expectation (LOLE), loss of load events (LOLEv), loss of load hours (LOLH) and expected unserved energy (EUE)
and compared their reliability against a known standard.
We focus primarily on loss of load expectation, which measures the average number of days per year where there is unserved energy (i.e.,
insufficient electricity supply to meet demand),
and expected unserved energy, which is the
amount of unserved energy in a given year.
We use the loss of load expectation of 0.1 day per
year, which is commonly used in North America today and means that the probability of unserved energy occurring in a day (regardless of duration or magnitude) is 1 day every 10 years. A lower loss of load expectation indicates a more reliable system. The TAP has indicated that changes to this criterion are being researched and studied and, as a result, it may change in the future.
We stress tested the portfolios against 5 weather years (2015–2019 solar and wind data) and 50 random thermal unit outage draws for a total of
250 samples of different conditions for available
production from variable renewables and
availability of firm generation thermal units.
Because the probabilistic resource adequacy is a
computing resource-intensive process, only 250 samples were analyzed and only select years were examined rather than the entire planning horizon. Although the 5 weather years may not capture all types of extreme weather events that have occurred, in the near term, the majority of generation is still served by aging thermal units and unit outages have the largest impact on reliability. For this reason, the number of outage draws are weighted more heavily than the number of weather years.
We selected 2030 and 2035 as the focus years for
this analysis. By 2030, we expect that the resources
procured through Stage 3 will achieve commercial
operations, so studying 2030 will confirm whether the capacity and energy targeted in this
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procurement will satisfy near-term reliability and will assess the reliability risk if we fall short of acquiring the resources sought in our Stage 3 RFP—we explore this in detail in Section 12.
8.1.3 Grid Operations
We analyzed the Base resource plan in PLEXOS to capture the system cost over the planning horizon and provide a view of how existing and new generators are expected to operate to meet electricity demand. The Oʻahu Land-Constrained plan was also analyzed in PLEXOS to determine how the dispatch may change.
We also analyzed separate Status Quo scenarios in PLEXOS and this is presented in Appendix C. At a
high level, this scenario assumed the Base forecast
for rooftop solar and energy storage, energy
efficiency and electric vehicles; commercial
operations of Stage 1, Stage 2 and CBRE Phase 2
Tranche 1 projects; successful renegotiation of
PPAs for existing IPPs projects; and continued operation of most existing thermal units. Future resources selected by RESOLVE were not included.
8.1.4 Transmission and System
Security Needs
Transmission and system security needs are identified to address transmission system capacity shortages because of future generation interconnection and load growth, and system dynamic stability needs to maintain future system stability within transmission planning criteria. In this section, we describe summary results for each island system. In Appendix D, details of the transmission analysis for each island are presented. The following summarizes our observations and recommendations from the transmission needs analysis:
■ Transmission network expansion is critical
for interconnecting significant quantities of
large-scale renewable energy and serving future load growth. The Maui system may require transmission network expansion earlier, starting from the Stage 3 procurement, and the Oʻahu and Hawaiʻi
Island systems may require transmission
network expansion in later years, depending
on the location of future projects. We also
discuss non-wire alternatives to defer transmission network expansion, such as
energy storage or limiting project interconnection size of the total potential in a local area or zone.
■ Location of future generation projects matters. Projects interconnected at the proper locations may defer transmission line upgrades but also mitigate undervoltage issues that cannot be fixed solely by
transmission line upgrades. This is especially
true for the Hawaiʻi Island system.
■ Grid-forming capability is critical for future
system stability. To mitigate stability risks
caused by momentary cessation of
distributed energy resources or other grid-following resources during a system event, the study identifies minimum requirement of grid-forming resource capacity or “MW headroom” as a function of DER generation to maintain system stability performance within the planning criteria. The grid-forming resource MW headroom is the amount of megawatts available to respond to a grid event (i.e., rated capacity less the current
output capacity). The MW headroom
requirement is directly related to the amount
of distributed generation outputting to the
system at any given time. With increased
penetration of inverter-based resources and DER, coupled with the retirement of synchronous generation resources, grid-forming resources will be required to provide other functions to stabilize the grid,
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such as strong and robust dynamic reactive current contribution during system fault and post-fault clearing, damping oscillations. Because of the uncertainty of the future generating resource portfolio, with which
these requirements are highly correlated,
additional studies and analyses will need to
continue to determine the adequacy of grid-
forming resources.
It is worth noting that we have yet to
obtain actual grid-forming field operation experience to validate the modeling studies. We based our recommendations on observed performance from the grid-forming resource models. Industry experience indicates promising performance of grid-forming resources at utilities such as Kauai Island Utility
Cooperative and Australia Energy Market
Operator. It will be important to perform
model validation and performance reviews
based on field operation data once the
grid-forming resources are online.
8.1.4.1 Important Study Assumptions
and Scope Limitations
For future large-scale generation interconnection,
the study assumes that current interconnection
sites with available grid capacity will be used first. Also, projects that withdrew from the Stage 1 or
Stage 2 procurement are assumed to return in some form during the Stage 3 procurement. Once all existing capacity is occupied, future interconnection sites will be selected based on the renewable potential, community feedback and cost of system upgrades. It is possible that actual project interconnections in future procurements are at different locations. Different
interconnection locations can drive very different transmission system capacity upgrade needs.
For each scenario, load is allocated in proportion
to existing substation loads, aggregated at
transmission substations. In reality, load may increase at different rates across the system.
It is worth noting that to identify transmission system capacity needs to accommodate future large-scale generation projects, scenarios of
continuous cloudy or rainy weather is considered
in the steady-state analyses in which system load
is supplied solely by large-scale generation
projects but not distributed generation.
Dynamic stability is sensitive to advanced grid technology development; therefore, we focus our analysis on near-term years (i.e., before 2040). New grid technology, on both the generation and customer demand sides, may result in different stability needs.
Additionally, our analysis evaluates very high penetration of inverter-based resource and DER scenarios. For example, in the Maui dynamic stability study, all studied scenarios represent 100% inverter-based resources. Currently, the
industry has limited operational experience for the
type of system we project to have in the near
future. Both the study scope and models used for
the dynamic stability study have limitations, and there may be other stability risks that are unknown at this time, and hence, not included in the current study, or represented in current models used for this study.
This analysis is focused on high-level grid needs. Detailed analyses, including fine control tuning for future large-scale generation projects, will be performed as part of the future generation projects’ Interconnection Requirements Studies. Additional information on this analysis, including the High Load scenarios, is provided in Appendix D.
8.1.5 Distribution Needs
Distribution grid needs are identified based on the two distribution services defined in the
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Distribution Planning Methodology.35 To ensure adequate capacity and reliability (back-tie capabilities), the distribution grid needs are identified using two analyses:
■ Hosting capacity grid needs assessed each
circuit’s ability to accommodate the
forecasted DER growth for that circuit. These
grid needs and a description of the hosting
capacity analysis were provided in the
November 2021 Distribution DER Hosting Capacity Grid Needs report 36.
■ Location-based distribution grid needs assessed the ability of distribution circuits and substation transformers to serve forecasted load growth (i.e., load-driven grid needs). This analysis is further described in Appendix E.
8.1.5.1 Stakeholder Engagement and
Feedback
Throughout the process of developing grid needs, we engaged stakeholders and the TAP for feedback and refined the methodology as needed.
During development of the hosting capacity grid
needs, we met with stakeholders in October 2021
and provided a preliminary report for stakeholder
review that included details of the methodology
used and preliminary grid needs results.
Stakeholder feedback was incorporated into the
final version that was filed in November 2021.
Similarly, during development of the load-driven grid needs, we engaged stakeholders throughout
35 See Hawaiian Electric Companies’ Grid Needs Assessment Methodology Review Point, Exhibit 1 Distribution Planning Methodology, filed on November 5, 2021, in Docket 2018-0165.
36 See Hawaiian Electric Companies’ Grid Needs Assessment Methodology Review Point, Exhibit 4 Distribution DER Hosting
the process for feedback on the methodology and preliminary results. The methodology used to develop the location-based forecasts was shared with stakeholders in October 2021 and discussed at the Stakeholder Technical Working Group
meeting. Additionally, as grid needs were
identified later in the process, we met with the
TAP in November 2022 and the Stakeholder
Technical Working Group in January 2023 to
discuss the process to identify grid needs and the
subsequent NWA evaluation to determine if any grid needs were qualified NWA opportunities.
8.1.5.2 Hosting Capacity Grid Needs
Of the 620 circuits37 assessed across the five islands, most had sufficient DER hosting capacity or could accommodate the 5-year hosting capacity38 without infrastructure investments. The remaining circuits where infrastructure investments are required to increase hosting capacity to accommodate the forecasted distributed energy resources are identified as requiring grid needs.
In the Base and Low DER forecasts, infrastructure
investments or distribution upgrades (i.e., wires
solutions) identified are phase balancing, installing
voltage regulators, reconductoring and installing
dynamic load tap changers. The High DER forecast identified similar types of distribution upgrades as in the Base and Low DER forecasts, with the addition of step-down transformer upgrades and converting a feeder section from 4 kilovolts (kV)
Capacity Grid Needs, filed on November 5, 2021, in Docket 2018-0165.
37 The total circuits assessed for each island are: 384 on O‘ahu, 137 on Hawai‘i Island, 88 on Maui Island, 3 on Lānaʻi, and 8 on Moloka‘i.
38 The study period for the hosting capacity analysis was year 2021 through year 2025.
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to 12 kV. The costs to implement these solutions are summarized by island.
8.1.5.3 Location-Based Grid Needs
In the location-based (load-driven) grid needs analysis, 645 circuits39 and 351 substation transformers40 were assessed with a study period through year 2030. The analysis finds that most
substation transformers and circuits have
sufficient capacity to accommodate the forecasted
load demand. For substation transformers and
circuits where there is insufficient capacity, a grid
need is identified.
Most grid needs in the near term are driven by service requests,41 or new load requests to support new housing or commercial development, in specific locations on the distribution system. The grid needs driven by the corporate forecast appear to be a small subset of the total grid needs. In these scenarios, total load growth (e.g., a combination of increase in load demand plus electrification of transportation42) drives the grid
need and occurs mostly in the later time frame
(years 2028 to 2030).
Distribution upgrades (i.e., wires solutions)
identified vary by scenario. Wires solutions
include, but are not limited to, new circuits,
reconductoring, new substation transformers, circuit line extensions and voltage conversions. The costs to implement these solutions are summarized by island and scenario.
39 The total circuits assessed for each island are: 393 on O‘ahu, 148 on Hawai‘i Island, 93 on Maui, 3 on Lānaʻi, and 8 on Moloka‘i.
40 The total substation transformers assessed for each island are: 204 on O‘ahu, 82 on Hawai‘i Island, 62 on Maui, 1 on Lānaʻi, and 2 on Moloka‘i.
41We receive service requests, or new load requests, from residential and commercial developers such as new subdivisions, condominiums, or shopping centers.
8.1.5.4 Distribution Grid Needs
Summary
Because the Hosting Capacity Grid Needs analysis was completed separately from the Location-Based Grid Needs analysis, grid needs resulting from both processes were compared to determine if any grid needs overlapped. In other words, it was determined whether a grid need identified for a circuit during the hosting capacity analysis also could provide a common solution to a grid need identified through the location-based process.
This reconciliation process found that the grid
needs were mutually exclusive—the hosting
capacity grid needs were different from the load-
driven grid needs. The substation transformers
and circuits with hosting capacity grid needs are different from the substation transformers and circuits with load-driven grid needs. This is because hosting capacity grid needs are driven primarily by the DER growth forecast versus load-driven grid needs, which are driven primarily by new service requests, and forecasted DER growth may not be on the same substation transformers or circuits as the new service requests.
Additionally, for the load-driven grid needs, there
are situations where a traditional solution is a
common solution that could solve multiple grid
needs simultaneously. For example, if two circuits
are overloaded on the same substation
transformer, this is counted as two grid needs in the location-based grid needs tables (see Table 8-7, Table 8-20 and Table 8-29)—one mitigation
42 Electrification of transportation is a major driver in load growth across the distribution system. Depending on the pace and actual locations at which electrification is adopted/materialized, the grid needs identified in this analysis may be deferred or no longer needed if the corporate EV forecast does not materialize as forecasted. The impact to a specific circuit or transformer requiring a grid need may be reassessed later prior to a grid need procurement.
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for each circuit. However, if a new circuit is installed, that one solution could solve both grid needs for the two existing overloaded circuits. In the Distribution Grid Needs Summary tables in the following sections, only one grid need is counted
for this type of situation, reflecting the minimum
number of grid needs.
8.1.5.5 Non-wires Alternative
Opportunities
The NWA opportunity evaluation methodology
described in Appendix F is used to determine if
the grid needs identified in each island’s Distribution Grid Needs Summary are qualified or non-qualified non-wires opportunities based on technical requirements and timing of need. In other words, it was determined whether an NWA
procurement was likely and feasible to mitigate
the grid need. This evaluation process consists of
the three-step methodology shown in Figure 8-2
below.
Figure 8-2. Non-wires alternative opportunity evaluation methodology
In Step 1, qualified projects are those with an in-service date beyond 2 years to allow enough lead time for non-wires procurement. For the purposes
of this evaluation, projects with an in-service date
of 2025 or later are deemed qualified. Non-
qualified projects are those with an in-service date
of 2024 or earlier.
In Step 2, additional sourcing criteria are used to evaluate the feasibility of an NWA using performance requirements, forecast certainty,
project economics and market assessment for
qualified projects identified in Step 1. A summary
of the sourcing evaluation criteria is shown in
Table 8-1 below.
Table 8-1. Summary of Non-Wires Alternative Sourcing Evaluation Criteria
Category Favorable Moderate or Uncertain Unfavorable Project Economics $1M and above Between $500k and $1M Less than $500k
Performance Capacity: up to 5 MW and
Duration: up to 4 hours
Capacity: >5 MW and <10 MW or
Duration: >4 hours and <8 hours
Capacity: 10 MW and larger and
Duration: 8 hours or more
Operating Date (Timing) 2025–2027 2028 and later 2024 and earlier (per Step 1)
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In Step 3, using the results of the weighted criteria described above, grid needs are sorted into three possible tracks:
• Track 1: qualified; high likelihood of NWA success for procurement
• Track 2: qualified; pricing/program
approach (for projects less than $1 million)
or reevaluate NWA opportunity in the future
• Track 3: non-qualified opportunities; implement wires solution
Results of the sorting by track is shown in Table 8-2 by scenario.
Table 8-2. NWA Opportunity Projects by Track
Proposed Action Island Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load) Scenario 4 (Faster Technology Adoption) Track 1 (qualified: procurement likely) O‘ahu 5 3 1 6
Track 2 (qualified: pricing approach or reevaluate later) O‘ahu 1 4 3 1
Track 3 (non-qualified) Oʻahu 1 11 2 3
Hawai‘i Island - - - 1
Total (all tracks) n/a 7 18 6 11
8.1.6 Grid Modernization
We are also actively pursuing a grid
modernization program that is foundational to
realizing this Integrated Grid Plan. Phase 1, which
includes the rollout of advanced meters and
associated infrastructure, is currently being implemented with expected completion by the third quarter of 2024.
Phase 2 was resubmitted in April 2023 to the PUC for approval in conjunction with a March 2023 application for federal funding through the IIJA. In addition to the scope described in Section 7.6, Phase 2 includes voltage management devices to
43 The updated field devices scope for Grid Modernization Phase 2 also includes projected needs between 2024 and 2028. The updated Phase 2 field devices scope includes 106 total voltage
increase circuit hosting capacity on the distribution system as described in this section.
The hosting capacity needs analysis informed the scope of voltage management field devices. We
identified 68 voltage regulators and 35 secondary
voltage-ampere reactive (VAR) controllers to
address hosting capacity at the distribution level
between years 2021 and 2025.43
8.1.7 System Protection
Roadmap
The objectives of system protection are to isolate
power system faults, equipment failures or any
regulators of which 46 voltage regulators are common to both the distribution grid needs and the Phase 2 scope.
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other unusual or extreme condition that puts the power system in jeopardy. This includes minimizing the extent and duration of the resulting forced outage and preventing system instability resulting from a system disturbance.
One technical consideration of decreasing system
strength is the impact on protection systems. All
electric utilities use traditional protection systems
to detect and clear faults and maintain system
integrity. The TAP Distribution Subcommittee was interested in how our protection systems will change in response to the higher levels of inverter-based generation. At the November 16, 2022,44 TAP Distribution Subcommittee meeting and the December 1, 2022, TAP meeting we presented our system protection roadmap, which summarized how the protection systems are anticipated to change and what would trigger those changes. For example, if breaker clearing
times are too slow and causing instability, then
faster two-cycle breakers or circuit switchers
would be needed. If line current differential
schemes become slow from lack of system
strength, then moving to traveling-wave schemes
may mitigate those issues.
We are currently in the process of upgrading certain components of our protection scheme; for example, moving from electromechanical relays to more capable microprocessor relays, and upgrading fuses that may not operate timely because of lack of fault current to smart fuses (as part of the grid modernization Phase 2 scope).
The protection system will evolve over time and
will be addressed as the system undergoes
changes. For example, as large-scale generation is
44 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/technical_advisory_panel/20221110_protection_roadmap.pdf
added to the system, protection in that area or region of the grid will be evaluated and addressed to maintain the protection system objectives. Common to the various protection solutions is high-speed communications, which enables
protection to act quickly and decisively based on
situational awareness. This Integrated Grid Plan
does not directly identify future investments
needed to mitigate potential protection issues;
however, as we learn more about our system and
how large-scale and customer-scale inverters perform, we will gain more insight into the protection investments needed for the future.
8.1.8 Preferred Plan
Development
The Preferred Plans developed for each island incorporate the results of the grid needs analyses for capacity expansion, resource adequacy, grid operations and transmission and
system security needs.
Starting with the resource plans developed in the capacity expansion step (RESOLVE), we modified the resource plan additions based on the results of the resource adequacy and grid
operations steps. This included:
■ Reductions in assumed new firm thermal
capacity selected by RESOLVE, contingent
upon the variable renewable target being fulfilled from the planned Stage 3 RFP
■ Increase in BESS durations from the 1- to 2-hour durations selected in RESOLVE to 4 hours to increase their resource adequacy
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contributions and further reduce fossil-fuel use, in line with recent hybrid solar projects
In parallel, we imposed additional model constraints as a result of the transmission and system security needs step, which used the unit
commitment and dispatch from the grid
operations step as an input. This included:
■ Headroom capacity on grid-forming
resources for dynamic stability response
■ Reductions in REZ buildout to avoid conductor overloads
■ A minimum east-side generation requirement for Hawai‘i Island that scales with system load
The Consolidated Preferred Base scenario resource generation and capacity mix over time are shown in Figure 8-3 and Figure 8-4,
respectively. The change in installed capacity
over time for each resource type is shown in Figure 8-5.
Figure 8-3. Consolidated: Preferred Base scenario resource generation mix (2023–2045)
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Figure 8-4. Consolidated: Preferred Base scenario resource installed capacity mix (2023–2045)
Figure 8-5. Consolidated: Preferred Base scenario change in installed capacity by resource type (2023–2045)
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8.2 Oʻahu
This section describes the results of the grid needs assessment for O‘ahu through the multistep
process that includes modeling capacity expansion,
resource adequacy, operations of the system,
transmission and system security needs,
distribution needs and iterations or adjustments
made to determine the preferred plan.
8.2.1 Capacity Expansion
Scenarios
Shown below, in Figure 8-6, is the capacity of the
new resources selected by RESOLVE for the Base,
Low Load, High Load and Faster Technology
Adoption scenarios. In the Base scenario, RESOLVE
builds standalone BESS, hybrid solar and onshore wind, achieving approximately 80% renewable energy by 2030. In 2035 offshore wind is added, and by 2050 biomass is added. The Low Load and
Faster Technology Adoption scenarios do not build the biomass by 2050 while the High Load scenario does. Existing fossil fuel–based resources are shown as firm renewable resources in 2050 because of their switch to biofuels in 2045. All
cases achieve their RPS targets with consistent
increases in utilization of renewable resources.
Figure 8-7 shows the annual generation from all
existing, planned and selected resources and RPS
for Oʻahu for the Base, Low Load, High Load and Faster Technology Adoption scenarios. The DER+DBESS shown here refers to the forecasted DER+DBESS and does not include any DER Aggregate Hybrid Solar, which may be selected by RESOLVE in certain scenarios. If DER Aggregate hybrid solar is selected by RESOLVE, it will be shown separately from the forecasted DER+DBESS. New biofuels includes proxy firm resources from the Stage 3 RFP process.
Figure 8-6. Oʻahu: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, Low Load, High Load and Faster Technology Adoption scenario
Figure 8-7. Oʻahu: annual
generation and RPS from
resources in 2030, 2035 and 2050 for the Base, Low Load, High Load and Faster Technology Adoption scenarios
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8.2.1.1 Land-Constrained Scenarios
In discussing the capacity expansion results of the Oʻahu Land-Constrained scenario with the TAP, they noted that this scenario does not meet our goal of 70% carbon reduction by 2030 and that the assumptions in this scenario to constrain the available large-scale renewables may be closer to reality than other scenarios. When enforcing this
constraint in RESOLVE through the RPS target,
there is a limited change in resource plan
buildout; however, additional generation from
new and existing firm renewables (i.e., biodiesel) is used to meet the 70% carbon reduction goal by 2030 compared to the Land-Constrained scenario that is not required to meet that goal. This indicates that the DER aggregator resource (the only remaining resource option that can be built) is a higher-cost option than the incremental biodiesel generation from firm renewables in 2030 when the decarbonization goal must be met. We note that, because the DER aggregator resource is
not selected until 2045 and 2050 when we must comply with the 100% renewable energy mandate, new advanced generation technologies could become available prior to 2045 that could accelerate the path to 100% renewable energy in a Land-Constrained scenario.
Figure 8-8 shows the capacity of the new
resources selected by RESOLVE. Figure 8-9 shows
the annual generation from all existing, planned
and selected resources and RPS for Oʻahu for the Land-Constrained scenario with 70% RPS requirement in 2030. The DER+DBESS shown here refers to the forecasted DER+DBESS and does not include any DER Aggregate hybrid solar, which may be selected by RESOLVE in certain scenarios. If DER Aggregate Hybrid Solar is selected by RESOLVE, it will be shown separately from the forecasted DER+DBESS. New biofuels includes proxy firm resources from the Stage 3 RFP
process.
Figure 8-8. Oʻahu: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, Land-Constrained
and Land-Constrained with 70%
RPS by 2030 constraint
Figure 8-9. Oʻahu: annual generation and RPS from resources in 2030, 2035 and 2050 for the Base, Land-Constrained and Land-Constrained with 70% RPS by 2030 constraint
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8.2.1.2 High Fuel Retirement
Optimization Scenario
We evaluated a High Fuel Retirement Optimization scenario to determine the impact to our fossil-fuel retirement plans and other resources. In the High Fuel Retirement Optimization scenario, RESOLVE chooses to retire around 1,060 MW of thermal capacity (see Figure 8-10). Because RESOLVE performs a linear optimization, the additional retirements may consist of partial unit retirements. These
additional retirements mostly occur early in the
planning horizon before 2030 with an additional
150 MW in 2030. The retirements are replaced
with biomass and increased amounts of hybrid solar. By 2050, the High Fuel Retirement Optimization scenario builds less hybrid solar and offshore wind because of the increased amount of biomass installed in 2030.
Because RESOLVE front-loads the removal of units early in the planning horizon, extreme care must
be taken to ensure that customers are not adversely affected by an inadequate system. It is anticipated that removal of existing thermal generating units would result in a loss of load expectation greater than 0.1 day per year.
Additionally, this scenario significantly accelerates
the buildout of hybrid solar compared to the Base
scenario, which would require an extraordinary
effort by the marketplace to ensure that sufficient
resources are built prior to retirement of firm
generation. In practice, to ensure that sufficient replacement resources are in service to facilitate the retirements selected in this sensitivity, the unit removals would need to be staggered similar to our proposed removal-from-service schedule. Otherwise, the retirements shown in this sensitivity would increase the risk of unserved energy to our customers.
Figure 8-10 shows the capacity of the new
resources selected by RESOLVE, comparing the
Base and High Fuel Retirement Optimization
scenarios.
Figure 8-10. Oʻahu: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base and High Fuel Retirement Optimization
scenarios
However, the High Fuel Retirement Optimization scenario validates a key point, that we must urgently move to integrate lower-cost renewable
resources (than the price of fossil fuel) as soon as
practicable to lower the cost of electricity.
Figure 8-11 shows the annual generation from all existing, planned and selected resources and RPS for Oʻahu for the Base and High Fuel Retirement Optimization scenarios.
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Figure 8-11. Oʻahu: annual generation and RPS from resources in 2030, 2035 and 2050 for the Base and High Fuel Retirement Optimization scenarios
The DER+DBESS shown here refers to the forecasted DER+DBESS and does not include any DER Aggregate Hybrid Solar, which may be selected by RESOLVE in certain scenarios. If DER
Aggregate hybrid solar is selected by RESOLVE, it
will be shown separately from the forecasted
DER+DBESS. New biofuels includes proxy firm
resources from the Stage 3 RFP process.
8.2.1.3 No Offshore Wind Scenario
A key component in the Oʻahu resource plans is
offshore wind with a large capacity being built in
both the Base and Land-Constrained scenarios. Because concerns were raised by the TAP and public on the uncertainty that this resource can be developed, we ran additional scenarios where offshore wind was removed as an available resource option.
Figure 8-12 shows the capacity of the new resources selected by RESOLVE. Figure 8-13 shows the annual generation from all existing, planned and selected resources and RPS for Oʻahu for the Base and Land-Constrained scenarios with and without offshore wind available.
As shown in Figure 8-12, if offshore wind is not an
option, more hybrid solar is developed in the Base
scenario and more DER Aggregate is developed in
the Land-Constrained scenario. As shown in Figure 8-13, without offshore wind, in 2050, there is more generation from the hybrid solar and biomass in the Base scenario, and DER Aggregate and new biofuels (generation) in the Land-Constrained scenario. Figure 8-13 also shows that in the Land-Constrained scenario in 2035, there is significantly more generation from existing fossil fuel–based units and a significantly lower RPS achievement.
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Figure 8-12. Oʻahu: cumulative new capacity from resources in 2030, 2035 and 2050 for the Base, Base without Offshore Wind, Land-Constrained and Land-Constrained without Offshore Wind scenarios
Figure 8-13. Oʻahu: annual generation and RPS from resources in 2030, 2035 and 2050 for the Base, Base without Offshore Wind, Land-Constrained and Land-Constrained without Offshore Wind scenarios
This underscores that our lowest-cost renewable options—onshore wind, hybrid solar and offshore wind—are critical to meeting our decarbonization
goals. We must continue to diligently work with
communities to keep as many of these resource
options on the table as possible.
8.2.2 Resource Adequacy
In 2030, several key decision points are illustrated
by the probabilistic resource adequacy analyses.
By 2030, 371 MW of existing thermal capacity is planned to be removed from service. The impact of this planned removal is mitigated by the addition of new resources through the Stage 3 RFP. However, if we acquire less than the full
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Stage 3 targeted need, additional resources may be needed through additional procurements or planned removals of fossil fuel–based generation may be delayed. This is not desirable because of the present risks to the existing generation fleet as discussed in Section 12.
For planning purposes, we have assumed a
stepwise approach to retirements or deactivations
of our existing fossil fuel–based generating fleet
on Oʻahu, as shown in Table 8-3. The scheduled removal from service for Oʻahu is based primarily on the age of the unit.
Table 8-3. Generating Unit Deactivation/Retirement Assumptions
Year Generating Unit
2024 Waiau 3–4 removed from service (93.5 MW) (75–78 years old) 2027 Waiau 5–6 removed from service (108.1 MW) (67–69 years old)
2029 Waiau 7–8 removed from service (169.1 MW)
(62–64 years old)
2033 Kahe 1–2 removed from service (164.9 MW) (70–71 years old)
2037 Kahe 3–4 removed from service (171.5 MW)
(66–68 years old)
2046 Kahe 5–6 removed from service (269.5 MW) (66–73 years old)
If development of future large-scale renewables is limited in a Land-Constrained scenario:
■ We expect loss of load of less than 0.1 day per year, assuming that the planned deactivations through 2030 and the full
target for the Stage 3 procurement is
acquired (300 MW of new firm generation by
2029 and 450 MW of new variable renewable
generation paired with storage by 2027).
Acquisition of the full Stage 3 procurement targets may facilitate the deactivation of additional fossil fuel–based generators by 2030, beyond the planned removals.
■ We expect a loss of load greater than 0.1 day per year (less reliable) if less than the full
target for firm renewables in the Stage 3 procurement is acquired (e.g., 150 MW of new firm generation by 2029 and 450 MW of new variable renewable generation paired with storage).
If development of future large-scale renewables
reaches the target presented in the Base scenario:
■ We expect loss of load of less than 0.1 day
per year, assuming that the planned
deactivations through 2030, the full target for the Stage 3 procurement is acquired (300 MW of new firm generation by 2029 and 450 MW of new variable renewable generation paired with storage by 2027), and the marketplace delivers a combination of resources, consistent with the Base scenario, hybrid solar (1,150 MW), onshore wind (160 MW) and standalone storage (170 MW). Procurement of the full Stage 3 targets and
additional variable renewable and storage
resources may also facilitate the removal of
further existing thermal units.
■ We expect loss of load of less than 0.1 day
per year if less than the full target for the
firm renewables in the Stage 3 procurement is acquired (150 MW of new firm generation by 2029 and 450 MW of new variable renewable generation paired with storage by 2027) and the same combination of Base scenario resources. These resources may also facilitate the removal of additional fossil fuel–based generators by 2030, beyond the
planned removals.
By 2035, we assumed deactivation of an additional
165 MW of existing fossil-fuel capacity after
deactivating 371 MW by 2030. The reliability
impact of this planned deactivation is mitigated by
the addition of new resources through the Stage 3 procurement. However, if less than the full Stage 3
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target is acquired, additional resources may be needed through the solution sourcing process.
If development of future large-scale renewables is limited in a Land-Constrained scenario:
■ We expect loss of load of less than 0.1 day
per year, assuming that the planned
deactivations through 2035, the full target
for the Stage 3 procurement is acquired (300
MW of new firm generation by 2029, an
additional 200 MW of new firm generation by 2033, and 450 MW of new variable renewable generation paired with storage by 2027), and the marketplace delivers 400–500 MW of offshore wind. Procurement of the full Stage 3 targets and offshore wind may also facilitate the deactivation of additional fossil fuel–based generators by 2035.
■ We expect loss of load of greater than 0.1 day per year if less than the full target for
the firm renewables in the Stage 3
procurement is acquired (150 MW of new
firm generation by 2029 and 450 MW of new
variable renewable generation paired with
storage by 2027) and Kalaeloa Partners’ combined cycle plant expires at the end of its amended 10-year contract term. Reliability can be improved to a loss of load expectation of less than 0.1 day per year by reactivating units previously deactivated at Kahe and Waiau.
If development of future large-scale renewables achieves their technical potential in the Base scenario:
■ We expect loss of load of less than 0.1 day per year, assuming the planned
deactivations through 2035, the full target
for the Stage 3 RFP is procured (300 MW of
new firm generation by 2029, an additional
200 MW of new firm generation by 2033,
and 450 MW of new variable renewable
generation paired with storage by 2027), and the marketplace delivers a combination of resources, consistent with the Base scenario, hybrid solar (1,150 MW), onshore wind (160 MW), offshore wind (400–500 MW) and standalone storage (170 MW). Procurement of the full Stage 3 procurement targets and offshore wind may also facilitate the
deactivation of additional steam units by 2035.
■ We expect loss of load to be less than 0.1
day per year if we acquire less than the full
target for the firm renewables in the Stage 3
procurement (150 MW of new firm generation by 2029 and 450 MW of new variable renewable generation paired with storage by 2027), Kalaeloa Partners’ combined cycle plant expires at the end of its amended 10-year contract term, and we acquire the same combination of Base scenario resources.
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Probabilistic Resource Adequacy
Summary
Table 8-4 shows the 2030 Resource Adequacy results for the Base and Land-Constrained
resource plans that were produced by RESOLVE. The results show that, in 2030, both resource plans developed by RESOLVE should meet our reliability targets.
Table 8-4. Probabilistic Analysis: Results Summary, Oʻahu, 2030—Summary of Base and Land-Constrained 2030
Resource Adequacy Results
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/Year)
LOLEv (Event/Year)
LOLH (Hours/Year)
EUE (MWh/Year)
EUE (%)
RESOLVE Base 1,173 300 450 164 1,145 167 0.00 0.00 0.00 0.00 0.000
RESOLVE Land-Constrained 1,173 300 450 0 0 54 0.00 0.00 0.01 0.00 0.000
Table 8-5 shows the 2035 resource adequacy results for the Base and Land-Constrained resource plans that were produced by RESOLVE. In
the Land-Constrained resource plan, RESOLVE
selected a 153 MW combined cycle to be installed
in 2035. In the 2035 probabilistic resource adequacy analysis, however, the 153 MW combined cycle was assumed not to be installed
to test whether this firm generator is needed for
resource adequacy.
Table 8-5. Probabilistic Analysis: Results Summary, Oʻahu, 2035—Summary of Base and Land-Constrained 2035 Resource Adequacy Results
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/Year)
LOLEv (Event/Year)
LOLH (Hours/Year)
EUE (MWh/Year)
EUE (%)
RESOLVE Base 800 508 450 564 1,145 167 0.00 0.00 0.00 0.00 0.000 RESOLVE Land-Constrained 800 508 450 430 0 194 0.00 0.01 0.01 0.00 0.000
RESOLVE Base, High Load 800 508 450 564 1,145 167 0.00 0.00 0.00 0.00 0.000
RESOLVE Land-Constrained, High Load
800 508 450 430 0 194 0.65 1.42 3.28 0.60 0.007
The results show that, in 2035, both the Base and Land-Constrained plans developed by RESOLVE should meet our reliability targets assuming the Base load forecast. Under the High Load scenario, however, the Land-Constrained plan may fall short of the reliability target.
As is shown in greater detail in Section 12, in
2035, assuming a High Load scenario and all 450
MW of hybrid solar from the Stage 3 RFP:
■ Approximately 1,225 MW of new hybrid solar is needed, in addition to the 450 MW of hybrid solar from Stage 3, to bring the system loss of load expectation below 0.1 day per year.
■ Approximately 200 MW of new firm generation is needed, in addition to the 500 MW of firm generation from Stage 3, to
bring the system loss of load expectation
below 0.1 day per year.
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See Section 12.3 for more details on risks of the resource portfolio given uncertainties in procuring and acquiring the optimal mix of resources, and a summary of the various resource adequacy scenarios performed.
Further analysis is needed in the future for an
offshore wind addition as it does not have a
robust historical record of production in Hawaiʻi
(unlike onshore wind and solar), which could
materially impact its reliability contributions.
8.2.3 Grid Operations
The transition to 100% renewables will necessitate a change in how the firm thermal generators on our system operate. Renewable resources and
storage will reduce our reliance on existing fossil
fuel–based generators to serve load. This is shown
in the daily energy profiles and operational
statistics in this section. Reducing dependence on
fossil fuel–based generators will improve reliability
given that our fossil fuel–based generators are currently more than 60 years old, as shown in Appendix C, and experiencing higher outage rates. The analysis in Section 9 also shows that utility rates may be lower than if we continue to rely on fossil fuels.
Sometimes the total generation exceeds the system load during the day. This surplus energy from the grid is used to charge the standalone BESS. In the energy profiles, the standalone BESS energy charging load is the striped layer while the
standalone BESS dispatch is shown as solid. The
standalone BESS charging load is shown to
confirm that the excess energy shown is charging
the BESS and not being curtailed. The energy used
to charge the standalone BESS doesn’t necessarily
come from any particular resource type.
8.2.3.1 Status Quo Typical Operations
As stated above, a Status Quo scenario was run through PLEXOS. In this scenario, it assumed the Base forecast, commercial operations of Stage 1, Stage 2 and CBRE Phase 2 Tranche 1 projects; successful renegotiation of existing IPPs; and continued operation of most existing thermal units. The Status Quo plan excluded CBRE Phase 2 Tranche 2, Stage 3 RFP resources and future resources selected by RESOLVE. Shown below in Figure 8-14 and Figure 8-15 are the dispatch of
the resources in a Status Quo resource plan in
2030 and 2035, respectively, for a few days with
average load.
Figure 8-14. Oʻahu: detailed Status Quo energy profile, 2030 median load day (November 7–9, 2030)
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Figure 8-15. Oʻahu: detailed Status Quo energy profile, 2035 median load day (May 16–18, 2035)
8.2.3.2 Base Scenario Typical
Operations
The dispatch of the resources in the Base resource
plan in 2030 and 2035, respectively, for a few days
with average load are shown below in Figure 8-16
and Figure 8-17. In the Base resource plan, during
midday, most of the load is expected to be met from variable renewable resources. The firm fossil fuel–based generators are used primarily during morning and evening hours.
Figure 8-16. Oʻahu: detailed Base energy profile, 2030 median load day (April 14–16, 2030)
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Figure 8-17. Oʻahu: detailed Base energy profile, 2035 median load day (October 12–14, 2035)
8.2.3.3 Land-Constrained Scenario
Typical Operations
The dispatch of the resources in the Land-
Constrained resource plan in 2030 and 2035,
respectively, for a few days with average load are
shown below in Figure 8-18 and Figure 8-19. In
the Land-Constrained scenario, we expect greater fossil fuel–based generation during midday than the Base scenario because of the lower amount of future renewables being added.
Figure 8-18. Oʻahu: detailed Land-Constrained energy profile, 2030 median load day (April 14–16, 2030)
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Figure 8-19. Oʻahu: detailed Land-Constrained energy profile, 2035 median load day (October 12–14, 2035)
8.2.3.4 Operations of Firm Generation
We can gather insights into the changing role of firm generation by evaluating the average number of starts of different types of firm generators and the amount those generators run, or the capacity factor, which is the percentage of hours a generator runs based on its rated capacity. The
average number of starts and capacity factor,
respectively, of the utility-owned thermal
generators and Stage 3 thermal generators for the
Status Quo, Base and Land-Constrained resource
plans in 2030 and 2035 are shown in Figure 8-20
and Figure 8-21. Appendix C shows which thermal generators are categorized as “Baseload,” “Cycling” and “Peaking.” “New” generators include thermal generators procured through the Stage 3
RFP, which were modeled as 6–50 MW combustion turbines and a 200 MW combined cycle plant and any RESOLVE selected thermal generators, which included a 153 MW combined cycle in 2035 in the Land-Constrained scenario.
Capacity factor was averaged for generators with
similar operating characteristics. Because the Base
resource plan adds more renewable resources in
those years than the Land-Constrained plan, the
generators have lower capacity factor and starts. Because the Status Quo plan doesn’t add any new resources in the future, it has higher capacity factor and starts than the Base and Land-Constrained resource plans.
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Figure 8-20. Oʻahu: utility-owned and Stage 3 thermal generators average number of starts, 2030 and 2035 for Status Quo, Base and Land-Constrained scenarios
Figure 8-21. Oʻahu: utility-owned and Stage 3 thermal generators capacity factor, 2030 and 2035 for Status Quo, Base and Land-Constrained scenarios
8.2.4 Transmission and System
Security Needs
We analyzed the O’ahu Base, Land-Constrained and High Load resource plans to determine
transmission and system security needs by
performing steady-state and dynamic stability
analyses for selected years with major large-scale
resource additions, including:
■ Oʻahu system Base scenario resource plan and Land-Constrained scenario resource plan: 2030, 2035, 2046 and 2050
■ Oʻahu system High Load scenario resource plan: 2030 and 2035
A summary of the system security study for the
Oʻahu Base scenario resource plan and the
Oʻahu Land-Constrained resource plan is listed in the following sections. The detailed study is described in Appendix D. Both the summary and details of the system security study for the Oʻahu High Load scenario resource plan are shown in Appendix D.
8.2.4.1 Summary of Base Scenario
Resource Plan
In the near term, it is unlikely that the Oʻahu transmission system will require transmission network expansion, but beyond 2040 both the interconnection of large-scale generation projects
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from REZ development and system load increase would trigger transmission network expansion.
It will be important to consider large-scale battery energy storage, energy efficiency, demand response and distributed energy resources to
reduce loading in the urban core to avoid
overloading 138 kV overhead and underground
lines. Additionally, the western part of the system
already has major generation stations, and further
large-scale renewable resources located on the west side of the island would cause generation congestion on the 138 kV system when a contingency of losing one or multiple transmission lines occurs. It is important to note that full development of REZs on the north shore of the island would require significant transmission network expansion around the Wahiawa 138 kV substation, which is similar to what was found in the 2021 REZ study report.
For system stability condition in future years, as a
result of interconnecting large quantities of hybrid
solar with grid-forming control, system stability performance is well within planning criteria. However, system stability performance is highly dependent on future grid-forming resources procured from the development of REZs. It is
strongly recommended to continue to procure
resources with grid-forming capability and
provide specific control recommendations during
project interconnection requirement studies.
Given uncertainties in future resource
procurement and the need to obtain field operation experience of grid-forming resources as often and early as possible, we recommend retrofitting existing grid-following hybrid solar resources; for example, Stage 1 hybrid solar projects that use grid-following inverters.
The following tables summarize the study results for the select years of the Oʻahu Base scenario resource plan.
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Summary Studied resource plan Studied year
Base scenario resource plan 2030
By 2030, the Oʻahu system will have new generation from Stage 3 Oʻahu RFP procurement and initial REZ development. Specifically, there will be 450 MW RDG and 300 MW firm generation procured through the Stage 3 Oʻahu RFP activity; 510 MW RDG development from REZs 1, 2 and 7; and 543 MW RDG development from REZs 3, 4, 5 and 6. Most of this new generation will be interconnected at the Oʻahu 138 kV system. The REZ development is expected to have both solar and wind generation. In this time frame, it is also planned to remove 371 MW generation from the Waiau power plant.
System Resource Summary and Forecasted Demand (MW) Firm generation Onshore standalone wind Standalone grid-scale solar Grid-scale hybrid solar/BESS Standalone BESS DER System peak load 1,462 257 168 1,573 219 1,171 1,364
REZ Enablement
Examples of REZ enablement are shown as following for zones with lower MW potential (upper) and higher MW potential (lower). Red color means new enablement facility, and black color means existing facility.
REZ Enablement Cost Estimate
Renewable energy zone 1 2 3 4 5 6 7
Cost ($MM) per MW 0.21 0.27 1.32 0.82 1.51 0.62 N/A
REZ enablement ($MM) 24.6 87.6 448.4–819.9 N/A
Grid Needs: Transmission System Networks Expansion
Network expansion cost estimate $161.4 million Alternative for this conductor upgrade will be to reduce Ewa Nui REZ generation interconnection from 324 MW to 175 MW.
Grid Needs: System Stability Needs
Grid has sufficient grid-forming resources to maintain system stability but the system must be operated so that grid-forming headroom/DER generation ratio is at least 0.7.
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed REZ
Not Developed REZ
G
G
324 MW
336 AAC
Group 2
CB CB CB
CB CB CB
Ewa Nui 138 kV
G
G
336 AAC
336 AAC
336 AAC CB CB CB
CB CB CB
Waiau-Ewa Nui 2 Line
Waiau-Ewa Nui 1 Line
CEIP-Ewa Nui Line
Kalaeloa-Ewa Nui Line
G
G
G
G
437 MW
CB CB CB
CB CB CB
CB CB CB
CB CB CB
556 AAC
556 AAC
556 AAC
556 AAC
G
CB CB CBG
171 MW
Halawa138 kVGroup 5
CB CB CB
CB CB CB
New 138 kV Switching Station 1590 AAC
1590 AAC
1590 AAC
1590 AAC
Ewa Nui Waiau
Existing 138 kV Line ReconductorExisting 138 kV Substation
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Summary Studied resource plan Studied year
Base scenario resource plan 2035
In addition to previous system resource changes by 2030, by 2035, the Oʻahu system will have 64 MW large-scale standalone battery energy storage and 509 MW offshore wind. There is no further development of REZs. We assumed there will be 208 MW firm generation procured and interconnected at the Kalaeloa substation.
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed REZ
Not Developed REZ
Offshore Wind
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Offshore wind Standalone grid-scale solar Grid-scale hybrid solar Standalone BESS DER System peak load
1,297 257 509 157 1,573 282 1,295 1,432
REZ Enablement
There is no REZ development between 2031 and 2035. In this time frame, the development that requires interconnection facility is the 509 MW offshore wind, which requires expansion of the Koʻolau substation by adding four breakers and a half bay for the offshore wind interconnection. The cost estimate is $50.6 million.
Grid Needs: Transmission System Networks Expansion
None. But high conductor loading is observed on multiple 138 kV overhead conductors. It is recommended to reduce large-scale generation interconnection at Koʻolau substation by 10 MW.
Grid Needs: System Stability Needs
Grid has sufficient grid-forming resources to maintain system stability, but the system must be operated so that grid-forming headroom/DER generation ratio is at least 0.70.
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Summary Studied resource plan Studied year
Base scenario resource plan 2045
In addition to previous system resource changes, by 2045, the Oʻahu system will finish developing the majority of REZs 1, 2, 3, 4, 5, 6 and 7, with only 106 MW potential remaining undeveloped. Meanwhile, 452 MW solar potential of REZ 8 will be developed by 2045. System load is forecasted with significant growth: 1,692 MW peak demand at 2046. Both REZ development and system load growth drive large amount of Oʻahu transmission system network expansion.
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed REZ
Not Developed REZ
Offshore Wind
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Offshore wind Standalone grid-scale solar Grid-scale hybrid solar Standalone BESS DER System peak load
1,126 287 509 441 2077 315 1,454 1,692
REZ Enablement
Renewable energy zone 3 4 5 6 8
Cost ($MM) per MW 1.32 0.82 1.51 0.62 1.25
REZ enablement ($MM) 1084.6–1468.5 565.0 Grid Needs: Transmission System Networks Expansion
Network expansion cost estimate $3,980.5 million Grid Needs: System Stability Needs
Not studied.
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Summary Studied resource plan Studied year
Base scenario resource plan 2050
By 2050, 3,344 MW of all eight REZs are fully developed. System load is forecasted with significant growth: 1,829 MW peak demand at 2050, which could possibly cause underground cable replacement for 138 kV underground cable among School Street, Iwilei and Archer 138 kV substations. All Kahe fossil fuel–based generation units are retired by 2050. Besides switching fossil fuel to biodiesel fuel for remaining firm units, 135 MW new firm units will be added to the Oʻahu system by 2050.
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed REZ
Not Developed REZ
Offshore Wind
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Offshore wind Standalone grid-scale solar Large-scale hybrid solar Standalone BESS DER System peak load
1,010 287 509 480 3,558 333 1,497 1,829
REZ Enablement
Renewable energy zone 3 4 5 6 8 Cost ($MM) per MW 1.32 0.82 1.51 0.62 1.25
REZ enablement ($MM) 86.9–160.1 892.5
Grid Needs: Transmission System Networks Expansion
Network expansion cost estimate $1,208.9 million Reducing load from 138 kV substations Kamoku, Kewalo and Archer by 37 MW can avoid cable replacement for the 138 kV underground cable Archer-School, Archer-Iwilei. This can be realized by adding generation such as large-scale energy storage in those substations, or procure demand response on circuits supplied by those substations, or implementing an EE program. Full development of the north shore REZ (i.e., zone 8) would also cause overloading on the 138 kV lines connected with Wahiawa substation. By reducing generation interconnection size at Wahiawa substation by 220 MW, the line overloading will be mitigated. Grid Needs: System Stability Needs
Not studied.
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8.2.4.2 Summary of Land-Constrained
Scenario Resource Plan
The Land-Constrained scenario resource plan requires much less transmission network expansion needed compared to the Base scenario resource plan. Still, it is suggested to install a large-scale BESS project on the east side of the island, close to the urban core load center, to avoid 138 kV overhead line or underground cable overloading.
Because of the limited amount of large-scale
resources in the Land-Constrained scenario, it is
likely that additional large-scale grid-forming
resources will be needed (i.e., retrofit of existing
renewable plants or new standalone energy
storage) to maintain system stability within the
Oʻahu transmission planning criteria. The study recommends that the minimum requirement of available MW headroom from large-scale grid-forming resource should be 70% of DER
generation. Without sufficient MW headroom from a grid-forming resource, future renewables may be delayed until technological advancements, such as removing customer-scale inverter technology momentary cessation characteristics,
are resolved or until cost-effective special grid
stability tools (e.g., grid-forming STATCOM) are
available. Currently, we have been reaching out to
original equipment manufacturers of customer-
scale inverters to address the inverter momentary
cessation issue, as well as looking into grid-scale stability tools in the planning process.
Additionally, with the significant quantity of DER selected in 2045 under the Land-Constrained scenario, there may be stability concerns because of momentary cessation. Significant upgrades to the transmission and distribution system may also be needed to interconnect the DER selected by RESOLVE at the end of the planning horizon.
Summary Studied resource plan Studied year
Land-Constrained scenario resource plan 2030 By 2030, the Oʻahu system will have all new generation from Stage 3 Oʻahu procurement on the transmission and sub-transmission side. Specifically, there will be 450 MW RDG and 300 MW firm generation procured through the Stage 3 Oʻahu RFP. Most of these new resources are expected to be interconnected at the Oʻahu 138 kV system. In this time frame, it is also planned to remove 371 MW generation from the Waiau power plant.
RFP Stage 3 Projects
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Standalone grid-scale solar Large-scale hybrid solar Standalone BESS DER System peak load
1,462 123 168 684 135 1,171 1,364
Grid Needs: Transmission System Networks Expansion
None
Grid Needs: System Stability Needs System may need more grid-forming resource, and it is recommended to maintain MW headroom of grid-forming resource/DER generation ratio of at least 0.7. If the ratio cannot be maintained, it is recommended to dispatch more synchronous machine resources to create more headroom from the grid-forming resource, or curtail DER generation.
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Summary Studied resource plan Studied year
Land-Constrained scenario resource plan 2035
In addition to previous system resource changes by 2030, by 2035, the Oʻahu system will have 105 MW large-scale standalone battery energy storage and 400 MW offshore wind. 153 MW firm resource will also be added to the system by 2035. There will be 208 MW firm generation procured and interconnected at the Kalaeloa substation. 30 MW wind will be added to the system to meet the system demand.
RFP Stage 3 Projects
New Onshore Resource Between 2031 and 2035
Offshore Wind
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Offshore wind Standalone grid-scale solar Large-scale hybrid solar Standalone BESS DER System peak load
1,450 123 400 157 684 240 1,295 1,432
Grid Needs: Transmission System Networks Expansion None
Grid Needs: System Stability Needs
System may need more grid-forming resources, and it is recommended to maintain MW headroom of grid-forming resource/DER generation ratio of at least 0.7. If the ratio cannot be maintained, it is recommended to dispatch more synchronous machine-based resource to create more headroom from the grid-forming resource.
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Summary Studied resource plan Studied year
Land-Constrained scenario resource plan 2045
In addition to previous system resource changes, by 2045, the Oʻahu system will add another 153 MW firm generation into the system. Also, 169 MW standalone solar and 93 MW wind development from retired solar and wind locations will be completed by 2045. 169 MW new large-scale standalone battery energy storage will be interconnected to the system from transmission substations. System load is forecasted with significant growth: 1,692 MW peak demand at 2046. On the distribution side, 783 MW distributed energy resources coupled with 1,567 MWh distributed energy storage will be added to the system to supply system load demand.
RFP Stage 3 Projects
New Onshore Resource Between 2031 and 2035
Offshore Wind
New Onshore Resource Between 2036 and 2045
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Offshore wind Standalone grid-scale solar Grid-scale hybrid solar/BESS
Standalone BESS DER System peak load
1,432 123 400 169 684 399 3,020 1,692
Grid Needs: Transmission System Networks Expansion
Network expansion cost estimate $2,291.6 million
Grid Needs: System Stability Needs The dynamic stability study was not performed. However, according to the available grid-forming resource and significant DER additions, the system may require more large-scale grid-forming resources. This could be more grid-forming energy storage interconnected on the subtransmission or transmission grid, or grid-forming STATCOM interconnected on the transmission grid.
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Summary Studied resource plan Studied year
Land-Constrained scenario resource plan 2050
From 2046 to 2050, the only large-scale resource added to the Oʻahu system as planned is a 119 MW/1,110 MWh large-scale battery energy storage system. Kahe 5 and 6, the only remaining fossil fuel–based generation at Kahe power plant, will be retired in 2050. It is also planned to add 1,017 MW distributed energy resources, coupled with 2,033 MWh distributed energy storage on the distribution system. System peak load is forecasted to be 1,829 MW by 2050. The load increase will require conductor upgrade to replace the 138 kV underground conductor Archer-School and Archer-Iwilei.
RFP Stage 3 Projects
New Grid-Scale Onshore Resource Between 2031 and 2035Offshore Wind
New Onshore Grid-Scale Resource Between 2036 and 2045
New Onshore Resource Between 2046 and 2050
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Offshore wind Standalone grid-scale solar Grid-scale hybrid solar/BESS
Standalone BESS DER System peak load
1,163 123 400 169 684 519 5,097 1,829
Grid Needs: Transmission System Networks Expansion
Networks expansion cost estimate $345.1 million
Reducing load from 138 kV substations Kamoku, Kewalo, School St. and Iwilei by 20 MW can avoid cable replacement for the 138 kV underground cables Archer-School and Archer-Iwilei. This can be realized by adding generation such as large-scale battery energy storage at those substations, acquiring demand response on circuits supplied by those substations, or implementing a targeted EE program.
Grid Needs: System Stability Needs
The dynamic stability study for this scenario was not performed. However, the recommendation for the Oʻahu system regarding system stability needs is similar to what is recommended for the 2045 scenario.
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8.2.5 Distribution Needs
This section discusses distribution needs as they pertain to the grid needs assessment for Oʻahu.
8.2.5.1 Hosting Capacity Grid Needs
Of the 384 circuits assessed on O‘ahu, most have
sufficient DER hosting capacity or could
accommodate the 5-year hosting capacity without
infrastructure investments. The remaining circuits
where infrastructure investments are required to increase hosting capacity to accommodate the forecasted distributed energy resources are identified as requiring grid needs. Infrastructure investments or distribution upgrades (i.e., wires solutions) to mitigate the grid needs are identified with cost estimates. The grid needs and solutions are summarized in Table 8-6.
Table 8-6. O‘ahu Hosting Capacity Grid Needs (Years 2021–2025)
Parameter (Nominal $) Base DER Forecast High DER Forecast Low DER Forecast
Number of grid needs 6 16 5
Cost summary (wires solutions) $792,000 $3,895,000 $648,000
A complete list of the hosting capacity grid needs can be found in the Distribution DER Hosting Capacity Grid Needs report.
8.2.5.2 Location-Based Grid Needs
Of the 393 circuits and 204 substation transformers assessed on O‘ahu, most have sufficient capacity to accommodate the forecasted load demand. For substation transformers and circuits where there is insufficient capacity, a grid need is identified. Infrastructure investments or distribution upgrades (i.e., wires solutions) to mitigate the grid needs are identified with cost
estimates. The grid needs and solutions are
summarized in Table 8-7.
A complete list of the load-driven grid needs can
be found in Appendix E.
Table 8-7. O‘ahu Location-Based Grid Needs (Years 2023–2030)
Parameter (Nominal $) Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load) Scenario 4 (Faster Technology Adoption) Number of grid needs 22 41 19 29
Cost summary (wires solutions) $95,724,000 $152,426,000 $77,900,000 $165,934,000
8.2.5.3 Distribution Grid Needs
Summary
The minimum number of grid needs identified (i.e., minimum wires solutions) by scenario by
island is shown in Table 8-8 below. This includes both hosting capacity and location-based grid needs.
Table 8-8. O‘ahu Minimum Grid Needs Solutions Identified (Years 2023–2030)
Island (Nominal $) Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load) Scenario 4 (Faster Technology Adoption) Number of grid needs 18 30 26 30
Cost summary (wires solutions) $51,806,000 $68,225,000 $52,097,000 $59,999,000
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8.2.5.4 NWA Opportunities
Results of applying the NWA opportunity evaluation methodology described in Section 8.1.4.5 are summarized in Table 8-9 through Table 8-12 below for O‘ahu by scenario.
Base Scenario
Table 8-9. O‘ahu NWA Opportunity Projects by Track: Base
Proposed Action Operating Date Transformer Circuit Description Cost (Nominal $) Track 1
(qualified: procurement likely)
2025 CEIP 3 CEIP 46 Reconductor $3,930,000
2026 Kapolei 2 Kapolei 4 Circuit line extension $2,091,000
2026 Wahiawa 3 (138 kV) Wahiawa-Waimano New substation transformer and circuit $15,012,000
2027 Kamokila 2 N/A Circuit line extension $1,914,000
2027 Kewalo T3 N/A New substation transformer $6,404,000
Track 2 (qualified: pricing approach or re-evaluate later)
2028 Kuilima 2 N/A New substation transformer $3,160,000
Track 3 (non-qualified) 2025 Waipio 1 N/A New substation transformer $2,880,000
High Load Customer Technology
Adoption Bookend Scenario
Table 8-10. O‘ahu NWA Opportunity Projects by Track: High Load Customer Technology Adoption Bookend
Proposed Action Operating Date Transformer Circuit Description Cost (Nominal $) Track 1 (qualified: procurement likely) 2025 Ewa Nui 2 Ewa Nui 2 New substation transformer and circuit $3,634,000
2026 Kuilima 2 N/A New substation transformer $2,970,000
2027 Kewalo T3 N/A New substation transformer $6,404,000
Track 2 (qualified: pricing approach or reevaluate later)
2025 Kamokila 2 N/A Circuit line extension $2,480,000
2028 CEIP 2 CEIP 3 Circuit line extension $5,072,000
2028 Fort Weaver 1 N/A New substation transformer $3,160,000
2028 Hauula Hauula Reconductor $780,000
Track 3 (non-qualified) 2025 Kapolei 2 Kapolei 4 New substation transformer and circuit $3,684,000
2025 Piikoi 4 Piikoi 8 Reconductor $270,000
2025 Wahiawa 3 (138 kV) Wahiawa-Waimano New substation transformer and circuit $15,012,000
2028 Kahuku Kahuku Reconductor $187,000
2028 Kunia Makai 1 N/A New switch and transfer load $26,000
2029 Ewa Nui 1 Ewa Nui 1 Circuit line extension $149,000
2029 Hoaeae 1 Hoaeae 1 New switch $25,000 2029 Kaneohe 1 Heeia Transfer load $26,000
2029 Puunui 2 Heights Reconductor, voltage regulator and fuse resizing
$473,400
2030 Makaha 2 N/A New switch $26,000
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Low Load Customer Technology
Adoption Bookend Scenario
Table 8-11. O‘ahu NWA Opportunity Projects by Track: Low Load Customer Technology Adoption Bookend
Proposed Action Operating Date Transformer Circuit Description Cost (Nominal $) Track 1
(qualified: procurement likely)
2027 Kewalo T3 N/A New substation transformer $6,404,000
Track 2
(qualified: pricing approach or reevaluate later)
2028 CEIP 2 CEIP 3 Circuit line extension $5,072,000
2028 Wahiawa 3 (138 kV) N/A New substation transformer and circuit $15,012,000
2029 Kuilima 2 N/A New substation transformer $3,260,000
Track 3
(non-qualified)
2025 Waialae 1 4 kV Wai-Wilhelmina Install two 1ph line regulators $140,000
2025 Waimanalo Bch 1 Waimanalo Dynamic LTC $154,000
Faster Technology Adoption Bookend
Scenario
Table 8-12. O‘ahu NWA Opportunity Projects by Track: Faster Technology Adoption Bookend
Proposed Action Operating Date Transformer Circuit Description Cost (Nominal $) Track 1 (qualified: procurement likely) 2026 Kamokila 2 N/A Circuit line extension $1,857,999 2026 Kapolei 2 Kapolei 4 Circuit line extension $2,091,012
2026 Wahiawa 3 (138 kV) N/A New substation transformer and circuit $15,012,000
2027 Barbers Pt Tank Farm 2 Industrial Circuit line extension $5,071,920
2027 CEIP 3 CEIP 46 Reconductor $3,930,000
2027 Kewalo T3 N/A New substation transformer $6,404,000
Track 2
(qualified: pricing approach or re-evaluate later)
2029 Kuilima 2 N/A New substation transformer $3,260,000
Track 3 (non-qualified) 2025 CEIP 2 CEIP 3 New switch $23,330
2025 Waialae 1 4 kV Wai-Wilhelmina Install two 1ph line regulators $140,000
2025 Waimanalo Bch 1 Waimanalo Dynamic LTC $154,000
8.2.6 Preferred Plan
The capacity expansion modeling conducted in RESOLVE was the starting point for identifying grid needs and developing a resource plan. Probabilistic resource adequacy analyses were then performed to confirm that the portfolio of resources selected in the resource plan were reliable. Based on the results of this analysis, the following changes were made:
■ Removed the 153 MW combined cycle
selected by RESOLVE in 2035 in the Land-
Constrained scenario as the system met the
loss of load standard without this resource.
Resource adequacy analysis will need to be
performed for years after 2035 to check if
the system still meets the loss of load standard without this resource, and if not, this resource may be added back into the resource plan.
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■ Removed the biomass selected by RESOLVE in 2045 and 2050 in the Base scenario as the system met the loss of load standard in earlier years without this resource. Resource adequacy analysis will need to be performed
for years after 2035, following the
completion of the Stage 3 RFP, to check if
the system still meets the loss of load
standard without this resource, and if not,
this resource may be added back into the
resource plan.
■ Removed 82 MW Group 1 and 82 MW Group 3 onshore wind because of community feedback from the west O‘ahu and North Shore communities where Groups 1 and 3 are located. The energy from this resource was used to inform the Stage 3 variable renewable energy target based on
prior modeling45 and converted into an
equivalent hybrid solar project in the
Integrated Grid Plan.
■ Increased duration of paired and standalone
BESS to 4 hours to match current market
conditions.
■ Updated the Stage 3 RFP variable renewable proxy to reflect the current target, which was adjusted for the withdrawal of Barber’s Point Solar.
■ Assumed 300 MW of Stage 3 firm renewable in 2029, which was the minimum Stage 3 firm renewable target for 2029.
In parallel, transmission and system security needs were identified, including reductions in the REZ
buildout as an NWA to additional transmission
expansion. Based on the results of this analysis,
the following changes were made:
45 See July 2022 Oʻahu Near-Term Grid Needs Assessment, https://www.hawaiianelectric.com/a/11166
■ Base scenario
2027: 70% grid-forming headroom capacity for dynamic stability
2030: reduce Ewa Nui Group 1 REZ by 150 MW to avoid conductor overloads
(includes removal of onshore wind in
2029)
2036: reduce Koʻolau Group 2 REZ by 10
MW to avoid conductor overloads
2050: reduce Wahiawa Group 3 REZ by
220 MW to avoid conductor overloads (includes removal of onshore wind in 2029)
■ Land-Constrained scenario
2027: 70% grid-forming headroom capacity for dynamic stability
2050: limit Ewa Nui BESS in Group 1 REZ and Hoʻohana battery energy storage to
less than or equal to 142 MW
Additional capital costs were identified to
interconnect resources in the REZs selected in
RESOLVE. While the REZ enablement costs were
already included as part of the RESOLVE
modeling, they are listed here in Table 8-13 for completeness alongside new network expansion costs.
The Status Quo and Land-Constrained scenario transmission network expansion costs reflect estimated transmission needed to expand capacity, as identified in the transmission needs analysis, to serve load growth because of electrification of transportation.
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Table 8-13. Oʻahu Transmission Capital Costs
Nominal Transmission Costs ($MM) Base Land Constrained Status Quo
Year REZ Enablement Network Expansion REZ Enablement Network Expansion REZ Enablement Network Expansion 2029 $114 - $62 - - -
2030 $942 - - - - -
2035 $62 - - - - -
2040 $799 - - - - -
2045 $2,241 $3,482 - $1,991 - $529
2050 $1,112 $1,018 - $293 - $293
Table 8-14 and Table 8-15 show a comparison of the production cost for the Oʻahu Base and Land-Constrained scenarios, respectively, with and without the transmission constraints. Production costs include payments for fuel, operations and maintenance (O&M) and IPP payments but do not
include the transmission capital cost shown earlier in Table 8-13.
The purpose of Table 8-14 and Table 8-15 was to
determine if the transmission constraints, which
include modifications to the REZ buildout and the additional reserve for dynamic stability, materially impact the cost for fuel, O&M and IPP payments. By comparing the production costs in the Land-Constrained scenario without REZ development, which is shown in Table 8-15, it appears that the dynamic stability requirement does not significantly change production costs. By comparing the production costs in the Base scenario, which is shown in Table 8-14, the
reductions in REZ buildout cause higher
production costs but also avoid larger capital
costs for new transmission or reconductoring if
the REZ remained at the original size.
Table 8-14. Comparison of Oʻahu Base Scenario Production Costs with and without Transmission Constraints
NPV ($MM) With Transmission Constraints
Without Transmission Constraints
(2023–2050) $16,710 $15,869
Table 8-15. Comparison of Oʻahu Land-Constrained Scenario Production Costs with and without Transmission Constraints
NPV ($MM) With Transmission Constraints Without Transmission Constraints (2023–2050) $19,439 $19,446
The Preferred Base scenario resource generation
and capacity mix over time are shown in Figure 8-22 and Figure 8-23, respectively. The change in installed capacity over time for each resource type is shown in Figure 8-24. See Appendix C for the Base Preferred Plan with planned and new resource additions listed by year.
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Figure 8-22. Oʻahu: Preferred Base scenario resource generation mix (2023–2045)
Figure 8-23. Oʻahu: Preferred Base scenario resource installed capacity mix (2023–2045)
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Figure 8-24. Oʻahu: Preferred Base scenario change in installed capacity by resource type (2023–2045)
The Preferred Land-Constrained scenario resource generation and capacity mix over time are shown in Figure 8-25 and Figure 8-26, respectively. The
change in installed capacity over time for each resource type is shown in Figure 8-27.
See Appendix C for the Land-Constrained Preferred Plan with planned and new resource additions listed by year.
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Figure 8-25. Oʻahu: Preferred Land-Constrained scenario resource generation mix (2023–2045)
Figure 8-26. Oʻahu: Preferred Land-Constrained scenario resource installed capacity mix (2023–2045)
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Figure 8-27. Oʻahu: Preferred Land-Constrained scenario change in installed capacity by resource type (2023–2045)
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8.3 Hawaiʻi Island
This section describes the results of the grid needs assessment for Hawai‘i Island through the
multistep process that includes modeling capacity
expansion, resource adequacy, operations of the
system, transmission and system security needs,
distribution needs and iterations or adjustments
made to determine the preferred plan.
8.3.1 Capacity Expansion
Scenarios
Shown below, in Figure 8-28, is the capacity of the
new resources selected by RESOLVE for the Base,
Low Load, High Load and Faster Technology
Adoption scenarios. In the Base scenario, initially
onshore wind and standalone energy storage are selected. As electricity demand increases over time, the model selects geothermal and hybrid solar as part of the optimal plan. The Low Load
scenario selects only onshore wind and standalone energy storage. The Faster Technology Adoption and High Load scenarios select new firm resources in addition to larger quantities of new resources than in the Base scenario. Existing fossil
fuel–based resources are shown as firm renewable
resources in 2050 because of their switch to
biofuels in 2045. All scenarios achieve their RPS
targets with consistent increases in the use of
renewable resources.
The Hawaiʻi Island resource portfolio has the most diverse set of resources of any island. This includes solar, wind, energy storage, geothermal and hydroelectric power. Together these resources will greatly reduce the reliance on fossil fuel–based generators, achieving near 100% renewable energy by 2030. Though the forecast generation varies over the range of scenarios, the types of resources used are consistent, as shown in Figure 8-28.
Figure 8-28. Hawaiʻi Island: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, Low Load,
High Load and Faster Technology
Adoption scenarios
Figure 8-29 shows the annual generation from all existing, planned and selected resources and RPS for Hawaiʻi Island for the Base, Low Load, High Load and Faster Technology Adoption scenarios.
The DER+DBESS shown here refers to the forecasted DER+DBESS and does not include any DER Aggregate Hybrid Solar, which may be selected by RESOLVE in certain scenarios. If DER Aggregate Hybrid Solar is selected by RESOLVE, it will be shown separately from the forecasted DER+DBESS.
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Figure 8-29. Hawaiʻi Island: annual generation and RPS from resources in 2030, 2035 and 2050 for the Base, Low Load, High Load and Faster Technology Adoption scenarios
8.3.1.1 High Fuel Retirement
Optimization Scenario
In addition to the planned retirements of Hill 5
and Hill 6 and with Puna Steam on standby status,
the High Fuel Retirement Optimization scenario chooses to retire an additional 54 MW of thermal
capacity (see Figure 8-30). Because RESOLVE performs a linear optimization, the additional
retirements may consist of partial unit retirements. These additional retirements occur early in the planning horizon before 2030 and are replaced with new wind, geothermal and firm resources. The Hamakua Energy Partners (HEP) contract is assumed to expire by the end of 2030 for both the Base and High Fuel Retirement Optimization scenarios.
Figure 8-30. Hawaiʻi Island:
cumulative new capacity selected
by RESOLVE in 2030, 2035 and
2050 for the Base and High Fuel Retirement Optimization scenarios
Even with the additional retirements, the Optimized Retirement scenario annual generation is similar to the Base scenario annual generation as shown in Figure 8-31.
It does not appear that the resource plan is particularly sensitive to high fuel costs; that is, the Base scenario already significantly reduces our reliance on fossil fuel. Further opportunities to retire fossil fuel–based generators may be available, as discussed in Section 12.
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Figure 8-31. Hawaiʻi Island: annual generation and RPS from resources in 2030, 2035 and 2050 for the Base and High Fuel Retirement Optimization scenarios
8.3.2 Resource Adequacy
By 2030, 49 MW of existing fossil fuel–based generators are planned for deactivation and IPP
HEP PPA is set to expire at the end of 2030. In a
Base scenario, the planned system is expected to
withstand the loss of these resources. However, if
Hawaiʻi Island is expected to be in a High Load
scenario by 2035, additional resources may need
to be acquired or planned deactivations may be delayed.
For Hawaiʻi Island, Puna Steam is assumed on standby status and Hill 5 and 6 is assumed to be retired by 2027, as shown in Table 8-16. This is largely due to compliance with environmental (regional haze) regulations. If these units continue operation past that date, these generating units need to be retrofitted with environmental controls.
Table 8-16. Generating Unit Deactivation/Retirement
Assumptions
Year Generating Unit
2025 Puna Steam on standby (15.5 MW)
2027 Hill 5–6 removed from service (33.8 MW)
8.3.2.1 Probabilistic Resource
Adequacy Summary
The planned Hawaiʻi Island system in 2030 is
expected to meet the Base scenario system load
assuming the planned deactivations through 2030
(see Table 8-17). Even if the Stage 3 procurement
doesn’t meet its target procurement, the 2030
Hawaiʻi Island system is expected to meet our reliability targets under the Base scenario.
Table 8-17. Probabilistic Analysis: Results Summary, Hawaiʻi Island, 2030
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 RFP (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base, no Stage 3 228 0 0 48 0 7/12 0.000 0.000 0.000 0.000 0.000
The planned Hawaiʻi Island system in 2035 under
the Base scenario load is expected to meet the
loss of load expectation reliability threshold
assuming the planned deactivations through 2035
(see Table 8-18). The 2035 Base scenario system is
still reliable without either the Stage 3 hybrid solar
or the future renewables added by RESOLVE.
However, additional resources are needed in a
High Load scenario.
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Table 8-18. Probabilistic Analysis: Results Summary, Hawaiʻi Island, 2035
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 RFP (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base, no Stage 3 228 0 0 48 3 7 0.076 0.144 0.220 0.002 0.000
Base 228 0 140 48 3 7 0.000 0.000 0.000 0.000 0.000 Base, no future RE 228 0 140 0 0 0 0.008 0.024 0.032 0.000 0.000
Base, High Load 228 0 140 48 3 7 5.18 10.5 19.8 0.475 0.030
Base, High Load, no future RE
228 0 140 0 0 0 28.9 64.2 149 4.70 0.454
The results show that, in 2030 and 2035, the Base plans developed by RESOLVE should meet our reliability targets. However, additional resources are needed if Hawaiʻi Island is in a High Load scenario. See the Resource Adequacy section in Section 12.3, summarized below, for more analysis of the resources needed to meet reliability targets in these scenarios.
Table 8-17 shows that the 2030 Base scenario has
a loss of load expectation of 0. For the resource
adequacy analysis in Section 12.3 where we show
how loss of load expectation changes when resources are added or removed, it’s helpful to compare systems with non-zero loss of load expectation. For this reason, HEP combined cycle was assumed to be retired a year early in 2030 for the Section 12.3 resource adequacy analysis. In 2030, assuming a Base scenario load forecast with HEP combined cycle already retired:
■ Even without the full Stage 3 procurement
target of 140 MW of hybrid solar, the 2030
system’s loss of load expectation is less than
0.1 day per year.
■ Though 140 MW of hybrid solar is not
needed to meet the reliability target in 2030,
acquiring 60 MW of hybrid solar will reduce the loss of load expectation by an order of magnitude as shown in Section 12.3.
■ A loss of load less than 0.1 day per year is expected even if HEP combined cycle and some additional firm generators are removed.
In 2035, assuming a High Load scenario, no future renewables, and all 140 MW of hybrid solar from the Stage 3 RFP:
■ Approximately 450 MW of additional hybrid
solar is needed to bring the system loss of
load expectation down below 0.1 day per
year.
■ Approximately 50 MW of additional firm generation is needed to bring the system loss of load expectation down below 0.1 day per year.
See Section 12.3 for more details on risks of the resource portfolio given uncertainties in procuring and acquiring the optimal mix of resources.
8.3.3 Grid Operations
The transition to 100% renewables will necessitate
a change in how the thermal generators on our system operate. Renewable resources and storage
will reduce our reliance on existing fossil fuel–based generators to serve load. This is shown in the daily energy profiles and operational statistics in this section. Reducing dependence on fossil fuel–based generators will improve reliability
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given that our fossil fuel–based generators are currently more than 60 years old, as shown in Appendix C, and experiencing higher outage rates. The analysis in Section 9 also shows that utility rates will be lower than if we continue to rely on fossil fuels.
Sometimes the total generation exceeds the
system load during the day. This surplus energy
from the grid is used to charge the standalone
BESS. In the energy profiles, the standalone BESS energy charging load is the striped layer while the standalone BESS dispatch is shown as solid. The standalone BESS charging load is shown to confirm that the excess energy shown is charging the BESS and not being curtailed. The energy used
to charge the standalone BESS doesn’t necessarily come from any particular resource type.
8.3.3.1 Status Quo Typical Operations
For the Hawaiʻi Island Status Quo scenario, HEP combined cycle, Hawi wind, Tawhiri wind and Wailuku hydro are assumed to remain in service. Hill 5 and Hill 6, and Puna Steam are assumed to be retired with Puna Steam on standby status.
The dispatch of resources during the median load
day as well as the day directly preceding and
following the median load day of the Status Quo
scenario in 2030 and 2035, respectively, are shown
below in Figure 8-32 and Figure 8-33. This shows how the resource portfolio meets the system load over a typical few days during a given year.
Figure 8-32. Hawaiʻi Island: detailed Status Quo energy profile, 2030 median load day (February 6–8, 2030)
Figure 8-33. Hawaiʻi Island: detailed Status Quo energy profile, 2035 median load day (September 29–October 1, 2035)
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8.3.3.2 Base Scenario Typical
Operations
The dispatch of resources during the median load day as well as the day directly preceding and following the median load day of the Base scenario in 2030 and 2035, respectively, are shown below in Figure 8-34 and Figure 8-35. In the Base
scenario, during midday, most of the load is expected to be met from variable renewable and geothermal resources. In 2030, firm fossil fuel–based generators are used primarily during morning and evening hours and by 2035 the
system is effectively operating on 100% renewable
energy.
Figure 8-34. Hawaiʻi Island: detailed Base energy profile, 2030 median load day
Figure 8-35. Hawaiʻi Island: detailed Base energy profile, 2035 median load day
8.3.3.3 Operations of Firm Generation
Insights can be gathered into the changing role of firm generation by evaluating the frequency with which different types of firm generators are
started and their capacity factor, which is the
percentage of hours a generator runs based on its
rated capacity. The average number of starts and
capacity factor, respectively, of the utility-owned
thermal generators for the Status Quo and Base
resource plans in 2030 and 2035 are shown in
Figure 8-36 and Figure 8-37. Appendix C shows
which thermal generators are categorized as
“Baseload,” “Cycling” and “Peaking.” “New”
generators include thermal generators procured
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through Stage 3 RFP and any RESOLVE selected thermal generators. Because the Status Quo scenario relies more heavily on thermal
generators, the generators are started more frequently and operate with a higher capacity factor than in the Base scenario.
Figure 8-36. Hawaiʻi Island:
utility-owned thermal generator
average number of starts, 2030 and 2035 for Status Quo and Base scenarios
Figure 8-37. Hawaiʻi Island:
utility-owned thermal generator
capacity factor, 2030 and 2035
for Status Quo and Base scenarios
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8.3.4 Transmission and System
Security Needs
We analyzed Hawai’i Island Base and High Load scenario resource plans to determine transmission and system security needs by performing steady-state analyses and dynamic stability analyses for selected years with major large-scale resource additions, including:
■ Hawaiʻi island system Base scenario resource plan: 2032 and 2050
■ Hawaiʻi island system High Load scenario
resource plan: 2032 and 2036
A summary of the system security study for the
Hawaiʻi Island Base scenario resource plan is
listed in the following sections. The detailed
study is described in Appendix D. Both the summary and details of the system security study for the Hawaiʻi Island High Load scenario resource plan are shown in Appendix D.
8.3.4.1 Summary of Base Scenario
Resource Plan
For the Hawaiʻi island Base scenario resource plan, the cross-island tie L6200 line and west side L8100/8900 line has risk of overloading condition in both the near term and long term. The cross-island tie L6200 overloading normally happens
when there is significant unbalance of generation on the two sides of the island, and because of the contingency, there is a large amount of power flow from the west side of the island toward the east side of the island through a few lines,
including the L6200. This overloading can be
mitigated by either reconductoring of the L6200
line to 556 AAC or balancing west-side and east-
side generation. The overloading of the
L8100/8900 line is normally caused by a large flow
of power from the east side to the west side of the system when the L6800 line is tripped, especially when there is too much generation interconnected at Keamuku substation.
The steady-state analysis for the Hawaiʻi Island system also showed that unbalanced generation dispatched between the west side and east side of the island would cause a significant undervoltage issue on either the southern or northern part of
the system. This undervoltage issue will become
much worse when no generation resource is
interconnected in south Hawaiʻi. It is
recommended that the Hawaiʻi Island system have
a resource (capable of providing voltage support)
in south Hawaiʻi.
The following tables summarize the study results for the Base scenario resource plan.
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Summary Studied resource plan Studied year
Base scenario resource plan 2032
By 2030, the Hawaiʻi system will have new generation from Stage 3 procurement and REZ development, which includes 48 MW wind generation of REZ development by 2029 and 140 MW Stage 3 procurement of hybrid solar generation by 2030, interconnecting at the Hawaiʻi island 69 kV system. It is also assumed that three firm generation plants will be removed by 2031: the 34 MW Hill 5 and 6 will be removed by 2027, the 21 MW Tawhiri wind generation PPA is assumed to expire by 2028, and the 58 MW HEP is assumed to expire by the end of 2030. The system peak load is forecasted to reach 214 MW by 2032.
RFP Stage 3 Projects
REZ Project
2029
System Resource Summary and Forecasted Demand (MW)
Fossil fuel–based generation Onshore standalone wind Geothermal generation Large-scale hybrid solar Hydro DER System peak load
85.8 58.5 46 200 16.6 171 214
REZ Enablement
Interconnection sites for the 140 MW Stage 3 projects and 48 MW onshore wind generation are as follows: Keamuku substation: 30 MW, Puueo substation: 30 MW, Kanoelehua substation: 30 MW, Ouli substation: 20 MW, Poopoomino substation: 30 MW The interconnection of 48 MW wind generation from REZ development is assumed at the Keamuku substation. The estimated REZ enablement cost for the 48 MW onshore wind interconnection at the Keamuku substation is $37.8 million. Grid Needs: Transmission System Networks Expansion
None
L6200 overloading observed in the study because of maximum west generation dispatches in which the 214 MW system load is solely supplied by generation from the west side of the island. The solution for deferring the L6200 reconductor is to maintain the minimum generation dispatch requirement on the east side of the system. The minimum MW generation dispatched from the east side of the system is calculated by the following equation:
East side minimum generation (MW) = 𝑺𝑺𝑺𝑺𝑺𝑺𝑺𝑺𝑺𝑺𝑺𝑺 𝑺𝑺𝒕𝒕𝑺𝑺𝒕𝒕𝒕𝒕 𝒕𝒕𝒕𝒕𝒕𝒕𝒍𝒍−𝟏𝟏𝟏𝟏𝟏𝟏𝟐𝟐𝟏𝟏𝟏𝟏−𝟏𝟏𝟏𝟏𝟏𝟏∙𝟐𝟐𝟐𝟐
If the system total load is lower than 174 MW, there is no minimum MW requirement of generation dispatched on the east side of the system. Dependent on the system total load and the east-side generation resources chosen to meet this minimum requirement, the east side may require 20 MVAR of additional reactive power capability to resolve potential north/east voltage violations. At the peak load with 20 MW generation on the east side of the island, the following options are viable for mitigating north/east undervoltage violations: All 3 units of PGV online.
Puna CT3 online with 2.8 MVAR additional reactive capability required at Kanoelehua or Puueo substations. Stage 3 Kanoelehua with 20 MVAR additional reactive capability required at Kanoelehua. Stage 3 Kanoelehua and Puueo (split output) with 20 MVAR additional reactive capability required between the two locations. The additional reactive capability at Kanoelehua and Puueo are in addition to the assumed capability of the Stage 3 resources at that location. To mitigate a high loading condition of L8900/8100, it is recommended to move generation interconnection from Keamuku and the east toward the further west side system (e.g., Keahole substation) when the system total load reaches above 200 MW.
To mitigate undervoltage violation identified on the south side of the system, it is recommended to have a resource interconnected at Keauhou substation with at least 10.4 MVAR capability or at Kamaoa substation with 13.7 MVAR or 13.3 MW capability. The reactive power capability can be replaced by active power capability, or the combination of reactive power and active power capability.
Grid Needs: System Stability Needs
After adding 140 MW Stage 3 hybrid solar projects with grid-forming battery energy storage component, it is expected that Hawaiʻi Island system stability performance will stay within planning criteria, and no additional system stability needs were identified. When PGV units are online, at minimum, a total of 60 MW grid-forming hybrid solar project is required. A 30 MW grid-forming hybrid solar project is required on both east and west sides of the Hawaiʻi Island system, while maintaining grid-forming resource headroom as 24% of DER generation. When PGV units are offline, at minimum, a total of 110 MW grid-forming resource is required. The east side of the system will need 50 MW grid-forming resource online and the west side of the system will need 60 MW grid-forming resource online, while together maintaining grid-forming resource headroom as 61% of DER generation.
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Summary Studied resource plan Studied year
Base scenario resource plan 2050
In addition to previous system resource changes by 2031, by 2035, the Hawaiʻi Island system will have 2 MW standalone battery energy storage and 3 MW hybrid solar from the REZ development. It is assumed that both interconnections will be in distribution circuits by considering their MW size. In 2040, there will be another 20 MW hybrid solar generation developed from the REZ. In 2045, all fossil fuel–based generation will have fuel switch to biodiesel. In the same year, there will be 30 MW geothermal generation and 2 MW standalone battery energy storage interconnected to the system. By 2050, an additional 14 MW hybrid solar and 2 MW onshore wind generation will be developed from the REZ. The system annual peak load is forecasted to reach 295 MW by 2050.
RFP Stage 3 Projects
REZ Project2029
REZ Projects2040
Geothermal2045
REZ Projects2050
System Resource Summary and Forecasted Demand (MW) Fossil fuel–based generation
Onshore standalone wind
Geothermal generation Large-scale hybrid solar Hydro DER System peak load
85.8 60.5 76 237 16.6 271 295
REZ Enablement It is assumed that the geothermal generation in service in 2045 will be interconnected at Haina substation, and the REZ generation will be interconnected at Pepeekeo substation (20 MW) in 2040 and Kaumana substation (17 MW) in 2050. High-level cost estimate for the 20 MW interconnection REZ enablement at the Pepeekeo substation is $24.5 million, and for the 17 MW interconnection REZ enablement at the Kaumana substation is $27.9 million. Grid Needs: Transmission System Networks Expansion
Network expansion cost estimate $100.1 million To mitigate undervoltage violations on the north side of the system, it is recommended to dispatch an east unit (e.g., PGV) at 5 MW or higher. To mitigate undervoltage violation on the south and southwest side of the system, it is recommended to have a resource interconnected at Kamaoa with 22.5 MW generation capacity.
Grid Needs: System Stability Needs
Not studied.
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8.3.5 Distribution Needs
This section discusses distribution needs as they
pertain to the grid needs assessment for Hawaiʻi
Island.
8.3.5.1 Hosting Capacity Grid Needs
Of the 137 circuits assessed on Hawai‘i Island,
most have sufficient DER hosting capacity or could
accommodate the 5-year hosting capacity without
infrastructure investments. The remaining circuits where infrastructure investments are required to increase hosting capacity to accommodate the forecasted distributed energy resources are identified as requiring grid needs. Infrastructure investments or distribution upgrades (i.e., wires solutions) to mitigate the grid needs are identified with cost estimates. The grid needs and solutions are summarized in Table 8-19.
Table 8-19. Hawai‘i Island Hosting Capacity Grid Needs (Years 2021–2025)
Parameter (Nominal $) Base DER Forecast High DER Forecast Low DER Forecast Number of grid needs 2 2 2
Cost summary (wires solutions) $630,000 $630,000 $630,000
A complete list of the hosting capacity grid needs can be found in the Distribution DER Hosting Capacity Grid Needs report.
8.3.5.2 Location-Based Grid Needs
Of the 148 circuits and 82 substation transformers assessed on Hawai‘i Island, most have sufficient capacity to accommodate the forecasted load demand. For substation transformers and circuits where there is insufficient capacity, a grid need is identified. Infrastructure investments or distribution upgrades (i.e., wires solutions) to
mitigate the grid needs are identified with cost
estimates. The grid needs and solutions are
summarized in Table 8-20.
Table 8-20. Hawai‘i Island Location-Based Grid Needs (Years 2023–2030)
Parameter (Nominal $) Scenario 1 (Base)
Scenario 2 (High Load)
Scenario 3 (Low Load)
Scenario 4 (Faster Technology Adoption) Number of grid needs 3 3 3 4
Cost summary (wires solutions)
$2,680,000 $2,680,000 $2,680,000 $3,153,000
A complete list of the load-driven grid needs can
be found in Appendix E.
8.3.5.3 Distribution Grid Needs
Summary
The minimum number of grid needs identified
(i.e., minimum wires solutions) by scenario by
island is shown in Table 8-21. This includes both hosting capacity and location-based grid needs.
Table 8-21. Hawai‘i Island Minimum Grid Needs Solutions Identified (Years 2023–2030)
Island (Nominal $) Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load) Scenario 4 (Faster Technology Adoption) Number of grid needs 5 5 5 6
Cost summary (wires solutions) $3,310,000 $3,310,000 $3,310,000 $3,783,000
8.3.5.4 NWA Opportunities
No NWA opportunities were identified for Hawai‘i
Island in the Base, High Load and Low Load
scenarios. Results for the Faster Technology
Adoption scenario are shown in Table 8-22.
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Faster Technology Adoption Scenario
Table 8-22. NWA Opportunity Projects by Track: Faster Technology Adoption Bookend
Proposed Action Operating Date Transformer Circuit Description Cost (Nominal $) Track 3 (non-qualified) 2030 Waikoloa N/A New circuit and tie $473,000
8.3.6 Preferred Plan
The capacity expansion modeling conducted in
RESOLVE was the starting point for identifying
grid needs and developing a resource plan.
Probabilistic resource adequacy analyses were then performed to confirm that the portfolio of resources selected in the resource plan were reliable. In parallel, transmission and system security needs were identified. Based on the results of this analysis, the following changes were made:
■ 2030: 24% grid-forming headroom capacity with PGV online or 61% grid-forming headroom capacity without PGV online for dynamic stability
■ 2032: minimum east-side generation that
scales with system load
For the purposes of this analysis,
geothermal resources added by RESOLVE
and Stage 3 hybrid solar are considered east-side resources.
Additional capital costs were identified to interconnect resources in the REZs selected in RESOLVE. While the REZ enablement costs were already included as part of the RESOLVE modeling, they are listed here in Table 8-23 for completeness alongside new network expansion costs.
The Status Quo scenario transmission network expansion costs reflect estimated transmission
needed to expand capacity, as identified in the
transmission needs analysis, to serve load growth because of electrification of transportation.
Table 8-23. Hawaiʻi Island Transmission Capital Costs
Nominal Transmission Costs ($MM)
Base Status Quo
Years REZ Enablement Network Expansion REZ Enablement Network Expansion
2029 $45 - - -
2031 - - - $96
2035 $3 - - -
2040 $24 - - - 2050 $26 - - -
Table 8-24 shows a comparison of the Hawaiʻi Island Base production costs with and without transmission constraints.
Comparing the production costs with and without
the transmission constraints identified above
shows that the dynamic stability and minimum
east-side generation requirements do not
significantly change production costs, and reduced capital cost of transmission upgrades.
Table 8-24. Comparison of Hawaiʻi Island Base Scenario Production Costs with and without Transmission Constraints
NPV ($MM) With Transmission Constraints Without Transmission Constraints (2023–2050) $2,122 $2,122
The Preferred Base scenario resource generation and capacity mix over time are shown in Figure 8-38 and Figure 8-39, respectively. The change
in installed capacity over time for each resource type is shown in Figure 8-40. See Appendix C for the Base Preferred Plan with planned and new resource additions listed by year.
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Figure 8-38. Hawaiʻi Island: Preferred Base scenario resource generation mix (2023–2045)
Figure 8-39. Hawaiʻi Island: Preferred Base scenario resource installed capacity mix (2023–2045)
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Figure 8-40. Hawaiʻi Island: Preferred Base scenario change in installed capacity by resource type (2023–2045)
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8.4 Maui
This section describes the results of the grid needs assessment for Maui through the multistep process that includes modeling capacity expansion, resource adequacy, operations of the system, transmission and system security needs, distribution needs and iterations or adjustments made to determine the preferred plan.
8.4.1 Capacity Expansion
Scenarios
Shown below, in Figure 8-41, is the capacity of the new resources selected by RESOLVE for the Base, Low Load, High Load and Faster Technology Adoption scenarios. In the Base scenario, onshore
wind is selected, primarily because of its low cost,
and achieves 95% renewable energy by 2030. As
electricity demand increases hybrid solar is added
in the later years. In scenarios with Faster
Technology Adoption, High Load and Low Load
shown in Figure 8-41, similar resources are selected; however, their amounts change with the magnitude of forecasted load. In the High Load scenario renewable firm resources are added in 2035 and increases in magnitude following the
load forecast as the years progress. Existing fossil
fuel–based resources are shown as firm renewable
resources in 2050 because of their switch to
biofuels in 2045.
Figure 8-42 shows the annual generation from all existing, planned and selected resources and RPS for Maui for the Base, Low Load, High Load and Faster Technology Adoption scenarios. The DER+DBESS shown here refers to the forecasted DER+DBESS and does not include any DER Aggregate hybrid solar, which may be selected by RESOLVE in certain scenarios. If DER Aggregate hybrid solar is selected by RESOLVE, it will be shown separately from the forecasted
DER+DBESS. New biofuels includes proxy firm
resources from the Stage 3 RFP process.
Figure 8-41. Maui: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, Low Load, High
Load and Faster Technology
Adoption scenarios
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Figure 8-42. Maui: annual generation and RPS from resources in 2030, 2035 and 2050 for the Base, Low Load, High Load and Faster Technology Adoption scenarios
8.4.1.1 High Fuel Retirement
Optimization Scenario
In addition to the planned retirements of Māʻalaea
1–13 and Kahului 1–4, the High Fuel Retirement
Optimization scenario chooses to retire 54 MW of
firm generation capacity shown in Figure 8-43. All additional retirements occur early in the planning horizon before and in 2030.
Because the model front-loads the removal of units early in the planning horizon, extreme care must be taken to ensure that customers are not adversely affected by an inadequate system. Additionally, this scenario accelerates the buildout
of hybrid solar and adds new firm generating resources compared to the Base scenario. In practice, to ensure that sufficient replacement resources are in service to facilitate the retirements selected in this sensitivity, the unit removals would need to be staggered similar to our proposed removal-from-service schedule. Otherwise, the retirements shown in this sensitivity would increase the risk of unserved
energy to our customers. The retirements shown
in this sensitivity comprise partial unit retirements
because of the linear optimization aspect of the
model.
Figure 8-43. Maui: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050
for the Base and High Fuel
Retirement Optimization
scenarios
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Shown in Figure 8-44, the expected renewable energy achievement does not significantly increase under the high fuel price sensitivity (95% compared to 96% in 2030).
Figure 8-44. Maui: annual
generation and RPS from
resources in 2030, 2035 and 2050 for the Base and High Fuel scenarios
8.4.2 Resource Adequacy
On Maui, several key decision points are illustrated by the probabilistic resource adequacy analyses. By 2030, we plan for the removal of 122 MW of existing fossil-fuel firm generation. The
impact of this planned removal is mitigated by the
addition of new resources through the Stage 3
procurement. However, if we acquire less than the
full Stage 3 targeted need, additional resources
may need to be acquired through additional
procurements.
For Maui, Kahului 1–4 and Māʻalaea 10–13 are assumed to be retired by 2027 to comply with regional haze rules and Māʻalaea 1–9 are assumed to be retired by 2030, as shown in Table 8-25. This is largely due to the lack of replacement parts for maintenance.
Table 8-25. Generating Unit Deactivation/Retirement Assumptions
Year Generating Unit
2027 Kahului 1–2 removed from service (9.47 MW) Kahului 3–4 removed from service (23 MW) Māʻalaea 10–13 removed from service (49.36 MW)
2030 Māʻalaea 1–3 removed from service (7.5 MW) Māʻalaea 4–9 removed from service (33 MW)
If development of future large-scale renewables reaches the target presented in the Base scenario:
■ We expect loss of load of less than 0.1 day per year, assuming planned deactivations through 2030 and the full targeted need for the Stage 3 procurement is acquired (40 MW of new firm generation and 191 MW of new
hybrid solar or wind by 2027).
■ We expect loss of load of less than 0.1 day
per year even if we acquire less than the full
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target for Stage 3 (40 MW of new firm generation and 191 MW of new hybrid solar or wind by 2027). If we fulfill the firm renewable target but not the variable renewable target, we expect a loss of load of
less than 0.1 day per year. If we fulfill the
variable renewable target, between 9 and 18
MW of new firm renewables are needed to
achieve a loss of load expectation less than
0.1 day per year.
By 2035, we do not assume any additional thermal unit deactivations or retirements. The Stage 3 acquired resources are still needed to maintain reliability.
■ We expect loss of load of less than 0.1 day per year, assuming planned deactivations through 2030 and we acquire the full target sought in Stage 3 procurement (40 MW of new firm generation and 191 MW of new
variable renewable generation paired with
storage by 2027).
Probabilistic Resource Adequacy
Summary
Table 8-26 shows the 2030 Resource Adequacy results for the Base resource plans that were
produced by RESOLVE. The results show that, in
2030, the resource plan developed by RESOLVE
should meet our reliability target.
Table 8-26. Probabilistic Analysis: Results Summary, Maui Island, 2030
Scenario Existing Firm New Firm Stage 3 RFP Future Wind Future Hybrid Solar
Future Standalone BESS
LOLE LOLEv LOLH EUE (GWh) EUE (%)
Base 119 36 191 13 0 0 0.00 0.01 0.02 0.0001 0.00
Table 8-27 shows the 2035 Resource Adequacy results for the Base resource plan with the Base Load and High Load forecast. The results show that, in 2035, the Base resource plan meets the
loss of load expectation target but with a high load forecast, the Base plan does not meet the loss of load expectation target.
Table 8-27. Probabilistic Analysis: Results Summary, Maui Island, 2035
Scenario Existing Firm New Firm Stage 3 RFP Future Wind Future Hybrid Solar
Future Standalone BESS
LOLE LOLEv LOLH EUE (MWh) EUE (%)
Base Load 119 41 191 24 37 0 0.013 0.10 0.24 0.00 0.000
High Load 119 41 191 24 37 0 3.58 7.08 14.79 0.32 0.030
See the Resource Adequacy section in Section 12.3, summarized below, for more analysis of the resources needed to meet reliability targets in these scenarios.
In 2035, assuming a High Load scenario and all of
Stage 3 RFP (191 MW of hybrid solar and 40 MW
of renewable firm) and 37 MW of hybrid solar from the RESOLVE model:
■ Approximately 540 MW of additional hybrid
solar is needed to bring the system loss of
load expectation down below 0.1 day per
year.
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■ Approximately 33 MW of additional firm generation is needed to bring the system loss of load expectation down below 0.1 day per year.
See Section 12 for more details on risks of the
resource portfolio given uncertainties in procuring
and acquiring the optimal mix of resources.
8.4.3 Grid Operations
The transition to 100% renewables will necessitate a change in how the thermal generators on our system operate. Renewable resources and storage will reduce our reliance on existing fossil fuel–based generators to serve load. This is shown in the daily energy profiles and operational statistics in this section. Reducing dependence on fossil
fuel–based generators will improve reliability
given that our fossil fuel–based generators are
currently more than 60 years old, as shown in
Appendix C, and experiencing higher outage rates.
The analysis in Section 9 also shows that utility rates will be lower than if we continue to rely on fossil fuels.
Sometimes the total generation exceeds the system load during the day. This surplus energy from the grid is used to charge the standalone BESS. In the energy profiles, the standalone BESS energy charging load is the striped layer while the
standalone BESS dispatch is shown as solid. The
standalone BESS charging load is shown to
confirm that the excess energy shown is charging
the BESS and not being curtailed. The energy used
to charge the standalone BESS doesn’t necessarily
come from any particular resource type.
8.4.3.1 Status Quo Typical Operations
For the Maui Island Status Quo scenario, Māʻalaea 1–9 are assumed to remain in service and Kaheawa Wind Power 1, Kaheawa Wind Power 2 and Auwahi Wind are assumed to have their contracts continued for the study period.
The energy profiles shown in Figure 8-45 and Figure 8-46 show the median load day in 2030 and 2035 of the Status Quo scenario as well as the day directly preceding and following the median
load day. This shows how the resource portfolio is
meeting the system load over a typical few days
during a given year.
Figure 8-45. Maui: detailed Status Quo energy profile, 2030 median load day (April 1–3, 2030)
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Figure 8-46. Maui: detailed Status Quo energy profile, 2035 median load day (November 21–23, 2035)
8.4.3.2 Base Scenario Typical
Operations
The dispatch of the resources in the Base resource
plan in 2030 and 2035, respectively, for a few days
with average load is shown in Figure 8-47 and
Figure 8-48. In the Base scenario, during midday,
most of the load is expected to be met from variable renewable resources. In 2030 and 2035 the system is effectively operating on 100% renewable energy.
Figure 8-47. Maui: detailed Base scenario energy profile, 2030 median load day
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Figure 8-48. Maui: detailed Base scenario energy profile, 2035 median load day
8.4.3.3 Operations of Firm Generation
We can gather insights into the changing role of
firm generation by evaluating the average number
of starts of different types of firm generators and
the amount those generators run, or the capacity factor, which is the percentage of hours a generator runs based on its rated capacity. The average number of starts and capacity factor, respectively, of the utility-owned thermal generators and Stage 3 thermal generators for the Status Quo and Base resource plans in 2030 and 2035 are shown in Figure 8-49 and Figure 8-50. Appendix C shows which thermal generators are
categorized as “Baseload,” “Cycling” and
“Peaking.” “New” generators include thermal generators procured through the Stage 3 RFP, which were modeled as 2-8 MW internal-combustion engines. Because the Status Quo scenario relies more heavily on older thermal cycling generators, the generators are started less frequently and operate with a higher capacity factor than in the Base scenario in 2030. Because the Base scenario has newer internal-combustion engines, there are more unit starts and higher
capacity factors initially that decrease as more
wind and hybrid solar is added to the system.
Figure 8-49. Maui: utility-owned and Stage 3 thermal generators average number of starts, 2030 and 2035 for Status Quo and Base
scenario
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Figure 8-50. Maui: utility-owned and Stage 3 thermal generators capacity factor, 2030 and 2035 for Status Quo and Base scenario
8.4.4 Transmission and System
Security Needs
We analyzed the Maui Base and High Load scenario resource plans to determine transmission and system security needs by performing steady-state analyses and dynamic stability analyses for selected years with major large-scale resource additions, including:
■ Maui system Base scenario resource plan: 2027, 2035, 2041, 2045 and 2050
■ Maui system High load scenario resource
plan: 2027, 2030 and 2035
A summary of the system security study for the
Maui Base scenario resource plan is listed in the following sections. The detailed study is described in Appendix D. Both the summary and details of the system security study for the Maui High Load scenario resource plan are shown in Appendix D.
8.4.4.1 Summary of Maui Base
Scenario Resource Plan
In the Maui Base scenario resource plan, significant large-scale resources will be interconnected to the system, requiring transmission network expansion for REZ development and forecasted load increases from electrification.
The large-scale resources in the Base plan provide the system with sufficient grid-forming resources
and maintain system stability within the Maui
transmission planning criteria. The following
tables summarize the study results for the Maui
Base scenario resource plan.
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Summary
Studied resource plan Studied year
Base scenario resource plan 2027
By 2027, the Maui system will have new generation, which includes 171 MW renewable dispatchable generation and 36 MW firm generation, interconnected at the Maui 69 kV system. Meanwhile, the Maui system will finish Waena switchyard construction, Kahului Power Plant retirement and conversion of units 3 and 4 to synchronous condensers, and retirement of Māʻalaea Power Plant units 10–13. The system peak load is forecasted to reach 207 MW by 2028.
A
A
A
C
C
B
RFP Stage 3 Projects
A B C REZ
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Large-scale hybrid solar Standalone BESS DER System peak load
197.5 42 296 40 170.7 207
REZ Enablement
No REZ enablement cost estimate because by 2027 existing locations are proposed to be used for Stage 3. Interconnection sites for the 171 MW Stage 3 projects and 36 MW firm generation are as follows:
Substation/switching station interconnections: Lahainaluna substation station: 60 MW, KWP 2 substation: 30 MW
Waena switch yard: 40 MW firm generation Kealahou substation: 21 MW 69 kV transmission line interconnection:
MPP: Waiinu line interconnection—30 MW, through a new substation STG3.1 MPP: Lahainaluna line interconnection—30 MW, through a new substation STG3.2
Grid Needs: Transmission System Network Expansion
Network Cost Estimate $10.5 million
Alternative options for above reconductor upgrade include reducing grid-scale resource interconnection MW size by 24 MW on west Maui and reducing grid-scale resource interconnection MW size in Waena switchyard, up-country or south Maui by 16 MW.
Grid Needs: System Stability Needs
After adding 171 MW Stage 3 RDG projects with grid-forming BESS component, it is expected that Maui system stability performance will stay within planning criteria, and no additional grid needs regarding system stability are identified. Maui system single point of failure limit can be increased to 30 MW as well.
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Summary Studied resource plan Studied year
Base scenario resource plan 2035
In addition to previous system resource changes by 2027, by 2035, the Maui system will have 66 MW large-scale onshore wind generation, 37 MW hybrid solar generation interconnected at Maui transmission system. This new generation will be developed in REZ C. Also, it is planned that the Māʻalaea Power Plant units 1–9 will be removed by 2030, and assumed wind power generation Kaheawa Wind Power 2 and Auwahi will be retired by 2033. The system annual peak load is forecasted to reach 235 MW by 2036.
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
System Resource Summary and Forecasted Demand (MW) Firm generation Onshore standalone wind Large-scale hybrid solar Standalone BESS DER System peak load
152 66 333 40 202 237 REZ Enablement
From 2028 to 2035, 5 MW onshore wind generation in 2029, 8 MW onshore wind generation in 2030, 53 MW onshore wind in 2035, and 37 MW hybrid solar, connected to REZ C, totaling 103 MW. It is assumed that there will be a new switching station in REZ C.1 on the MPP-Waena line that will host 43 MW out of 103 MW generation, and the remaining 60 MW will be hosted in the Waena switchyard. The cost of REZ enablement for the 60 MW generation interconnection at the Waena switchyard is estimated as $13.5 million. For the new switching station REZ C.1, the REZ enablement cost is estimated as $5.8 million.
Grid Needs: Transmission System Networks Expansion
Networks expansion cost estimate $96.2 million Grid Needs: System Stability Needs
None
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Summary Studied resource plan Studied year
Base scenario resource plan 2040
In 2040, another 61 MW REZ C development will be completed. It is assumed that 61 MW will be interconnected at Waena switchyard. Meanwhile, there will be retirement of existing 5.7 MW distribution interconnected solar. System annual peak demand is forecasted to reach 266 MW in 2041. A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects
2029-2035
REZ Projects2040
A B C REZ
System Resource Summary and Forecasted Demand (MW) Firm generation Onshore standalone wind Large-scale hybrid solar Standalone BESS DER System peak load 152 84 376 40 218 266
REZ Enablement
The new 61 MW of generation in the REZ C development is assumed to interconnect at the Waena switchyard, which will require two breakers and a half bay for the generation interconnection.
Cost estimate of REZ enablement for 61 MW interconnection is $15.6 million. Grid Needs: Transmission System Networks Expansion
Network expansion cost estimate $51.9 million
An alternative option for adding a new circuit between Māʻalaea Power Plant and Waena switchyard is to reduce large-scale generation interconnection from the REZ C development by 48.4 MW.
Grid Needs: System Stability Needs
None
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Summary Studied resource plan Studied year
Base scenario resource plan 2045
In 2045, 66 MW hybrid solar generation and 41 MW onshore wind generation will be developed in REZ C; 15 MW hybrid solar generation will be developed in REZ B. Also, all the remaining fossil-fuel units will switch to biodiesel. The system annual peak demand is forecasted to reach 289 MW in 2046. A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
REZ Projects2040
REZ Projects2045
A B C REZ
System Resource Summary and Forecasted Demand (MW)
Firm generation Onshore standalone wind Grid-scale hybrid solar Standalone BESS DER System peak load
152 125 457 40 229 289
REZ Enablement
According to the resource plan, 15 MW generation from REZ B and 107 MW generation from REZ C will be interconnected to the Maui system. In the study, the following interconnection sites are assumed:
Auwahi substation: 15 MW STG3.1: 30 MW Kanaha substation (23 kV): 30 MW
New switching station, zone C.2, on Waena-Kealahou line: 47 MW The cost estimate of the REZ enablement for the 30 MW interconnection at the STG 3.1 substation is $3.9 million, for the 30 MW interconnection at the Kanaha substation 23 kV side is $3.8 million, and for the 47 MW interconnection at the new substation REZ C.2 is $7.8 million. The total estimate for the REZ enablement is $15.4 million.
Grid Needs: Transmission System Networks Expansion
Network expansion cost estimate $171.2 million
An alternative option for the reconductor of the Kamaole-Kealahou line is to reduce south Maui generation interconnection size by 7 MW. Grid Needs: System Stability Needs
Not studied.
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Summary Studied resource plan Studied year
Base scenario resource plan 2050
In 2050, 57 MW hybrid solar generation will be developed in REZ C; 57 MW hybrid solar generation will be developed in REZ B. System annual peak demand is forecasted to reach 310 MW in 2050.
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
REZ Projects2040
REZ Projects2045
REZ Projects2050
A B C REZ
System Resource Summary and Forecasted Demand (MW) Firm generation Onshore standalone wind Large-scale hybrid solar Standalone BESS DER System peak load
152 125 571 40 240 310
REZ Enablement In the study, the following interconnection sites are assumed for the 114 MW generation development in REZs B and C: REZ B.1 Substation: 51 MW Auwahi Substation: 7 MW
REZ C.2 (Waena-Kealahou) Substation: 13 MW New switching station, REZ C.3, on Waena-Pukalani line: 44 MW The estimated cost for REZ enablement in REZ B.1 substation is $9.0 million and for REZ enablement of building the REZ C32 is $ 9.0 million. The total REZ enablement estimated cost is $18.0 million. It is assumed in the study that the 7 MW generation interconnection at the Auwahi substation and 13 MW generation interconnection at the REZ C.2 substation are interconnected without adding a new breaker and a half bay but just expansion of previously developed projects.
Grid Needs: Transmission System Networks Expansion
Besides above adding a new 69 kV line between Waena switchyard and Pukalani substation, it is also proposed to replace the two 69/23 kV tie transformers at Kanaha substation by two units of larger transformers with a forced-air rating of at least 24 MVA. Network expansion cost, including upgrade of two tie transformers $123.1 million
An alternative of upgrading two units of the Kanaha tie transformer is to use DER program, or demand response program, or EE program to reduce peak load of the Maui 23 kV network by at least 4 MW. Grid Needs: System Stability Needs
Not studied
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8.4.5 Distribution Needs
This section discusses distribution needs as they pertain to the grid needs assessment for Maui.
8.4.5.1 Hosting Capacity Grid Needs
Of the 88 circuits assessed on Maui, most have
sufficient DER hosting capacity or could
accommodate the 5-year hosting capacity without
infrastructure investments. The remaining circuits
where infrastructure investments are required to increase hosting capacity to accommodate the forecasted distributed energy resources are identified as requiring grid needs. Infrastructure investments or distribution upgrades (i.e., wires solutions) to mitigate the grid needs are identified with cost estimates. The grid needs and solutions are summarized in Table 8-28.
Table 8-28. Maui Hosting Capacity Grid Needs (Years
2021–2025)
Parameter (Nominal $) Base DER Forecast High DER Forecast Low DER Forecast Number of grid needs 3 7 3
Cost summary (wires solutions)
$2,500,000 $3,315,000 $2,500,000
A complete list of the hosting capacity grid needs
can be found in the Distribution DER Hosting
Capacity Grid Needs report.
8.4.5.2 Location-Based Grid Needs
Of the 93 circuits and 62 substation transformers assessed on Maui, most have sufficient capacity to accommodate the forecasted load demand. For substation transformers and circuits where there is insufficient capacity, a grid need is identified. Infrastructure investments or distribution upgrades (i.e., wires solutions) to mitigate the grid
needs are identified with cost estimates. The grid
needs and solutions are summarized in Table
8-29.
Table 8-29. Maui Location-Based Grid Needs (Years 2023–2030)
Parameter (Nominal $)
Scenario 1 (Base)
Scenario 2 (High Load)
Scenario 3 (Low Load)
Scenario 4 (Faster Technology Adoption) Number of grid needs 1 1 1 1
Cost summary (wires solutions)
$63,000 $63,000 $63,000 $63,000
A complete list of the load-driven grid needs can
be found in Appendix E.
8.4.5.3 Distribution Grid Needs
Summary
The minimum number of grid needs identified
(i.e., minimum wires solutions) by scenario by
island is shown in Table 8-30. This includes both hosting capacity and location-based grid needs.
Table 8-30. Maui Minimum Grid Needs Solutions Identified (Years 2023–2030)
Island (Nominal $) Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load) Scenario 4 (Faster Technology Adoption) Number of grid needs 4 4 8 8
Cost summary (wires solutions) $2,513,000 $2,513,000 $3,377,000 $3,377,000
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8.4.5.4 NWA Opportunities
No NWA opportunities are identified for Maui.
8.4.6 Preferred Plan
The capacity expansion modeling conducted in
RESOLVE was the starting point for identifying
grid needs and developing a resource plan.
Probabilistic resource adequacy analyses were
then performed to confirm that the portfolio of
resources selected in the resource plan were reliable. Based on the results of this analysis, the following changes were made:
■ Reduced the Stage 3 firm renewable proxy from five 8.14 MW units to two 8.14 MW units based on 2030 resource adequacy results
■ Increased duration of paired and standalone BESS to 4 hours to match current market
conditions
■ Updated the Stage 3 RFP variable renewable
proxy to reflect the current target, which was
adjusted for the withdrawal of Kahana Solar.
In parallel, transmission and system security needs
were identified. Based on the results of this analysis, the following changes were made:
■ 2027: 60% grid-forming headroom capacity for dynamic stability (see Maui system security study results in Appendix D)
■ 2045: reduce south Maui generation (Paeahu, Kamaole, Auwahi [rebuilt], REZ Group B) by 7 MW
Additional capital costs were identified to
interconnect resources in the REZs selected in
RESOLVE. While the REZ enablement costs were
already included as part of the RESOLVE
modeling, they are listed here in Table 8-31 for completeness alongside new network expansion costs.
The Status Quo scenario transmission network expansion costs reflect estimated transmission
needed to expand capacity, as identified in the
transmission needs analysis, to serve load growth
because of electrification of transportation.
Table 8-31. Maui Transmission Capital Costs
Nominal Transmission Costs ($MM)
Base Status Quo
Years REZ Enablement Network Expansion REZ Enablement Network Expansion
2030 $50 $11 - 2 2035 $18 $89 - 22
2040 $14 $47 - -
2045 $13 $131 - 68
2050 $15 $120 - 13
Table 8-32 presents a comparison of Maui Island
Base scenario production costs with and without
transmission constraints.
Table 8-32. Comparison of Maui Island Base Scenario Production Costs with and without Transmission Constraints
NPV ($MM) With Transmission Constraints Without Transmission Constraints (2023–2050) $2,229 $2,233
The Preferred Base scenario resource generation and capacity mix over time are shown in Figure 8-51 and Figure 8-52, respectively. The change in installed capacity
over time for each resource type is shown in
Figure 8-53. See Appendix C for the Base Preferred Plan with planned and new resource additions listed by year.
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Figure 8-51. Maui: Preferred Base scenario resource generation mix (2023–2045)
Figure 8-52. Maui: Preferred Base scenario resource installed capacity mix (2023–2045)
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Figure 8-53. Maui: Preferred Base scenario change in installed capacity by resource type (2023–2045)
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8.5 Molokaʻi
This section describes the results of the grid needs assessment for Moloka‘i through the multistep
process that includes modeling capacity
expansion, resource adequacy, operations of the
system, transmission and system security needs,
distribution needs and iterations or adjustments
made to determine the preferred plan.
8.5.1 Capacity Expansion
Scenarios
Shown below, in Figure 8-54, is the capacity of the
new resources selected by RESOLVE for the Base,
Low Load, High Load and Faster Technology
Adoption scenarios. The Base scenario selects
high levels of hybrid solar and achieves 92% renewable energy by 2030. In the Base, High Load, Low Load and Faster Technology Adoption scenarios, the types of resources selected by
RESOLVE remain the same (hybrid solar and standalone BESS); only the quantity changes proportional to the growth of electricity demand. Existing fossil fuel–based resources are shown as firm renewable resources in 2050 because of their switch to biofuels in 2045.
Figure 8-55 shows the annual generation from all
existing, planned and selected resources and RPS
for Molokaʻi for the Base, Low Load, High Load
and Faster Technology Adoption scenarios. The DER+DBESS shown here refers to the forecasted DER+DBESS and does not include any DER Aggregate hybrid solar, which may be selected by RESOLVE in certain scenarios. If DER Aggregate hybrid solar is selected by RESOLVE, it will be shown separately from the forecasted DER+DBESS.
Figure 8-54. Molokaʻi: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, Low Load, High Load and Faster Technology Adoption scenarios
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Figure 8-55. Molokaʻi: annual generation and RPS from resources in 2030, 2035 and 2050 for the Base, Low Load, High Load and Faster Technology Adoption scenarios
High Fuel Retirement Optimization
Scenario
In the High Fuel Retirement Optimization
scenario, shown in Figure 8-56 and Figure 8-57,
RESOLVE retires approximately 10.4 MW of existing thermal generation in 2030 and builds more hybrid solar than the Base plan.
Figure 8-56. Molokaʻi: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base and High Fuel Retirement Optimization scenarios
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Figure 8-57. Molokaʻi: annual generation and RPS from resources in 2030, 2035 and 2050 for the Base and High Fuel Retirement Optimization scenarios
8.5.2 Resource Adequacy
We did not make any retirement assumptions for
Moloka‘i; however, as more renewable resources
are brought online, we will continue to assess
resource adequacy and determine if system conditions warrant retiring existing fossil fuel–based generators.
Probabilistic Resource Adequacy
Summary
The Base scenario, which assumed 15.18 MW of
existing firm and 11.5 MW of future hybrid solar, showed a loss of load expectation of 0 days per year, meeting the targeted level of reliability. To create curves to illustrate the relationship between loss of load expectation and variable and firm capacity, different scenarios were run where one type of resource was held constant. In the variable resource sensitivity, the amount of firm capacity
was held constant and in the firm resource sensitivity the variable resource was held constant.
The High Load scenario for these resource adequacy runs assumed the same amount of
resources as the Base scenario except with a
higher load. These runs still showed a loss of load
expectation of 0 days per year across the board,
meeting the targeted level of reliability. To create
curves to illustrate the relationship between loss
of load expectation and resource capacity, different scenarios were run where one type of resource was held constant. In the variable resource sensitivity, the amount of firm capacity was held constant and in the firm resource sensitivity the variable resource was held constant.
Table 8-33 presents a probabilistic resource adequacy analysis results summary for Molokaʻi.
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Table 8-33. Probabilistic Resource Adequacy Analysis: Results Summary, Moloka‘i
Scenario Existing Firm New Firm Stage 3 RFP Future Wind Future Hybrid Solar
Future Standalone BESS
LOLE LOLEv LOLH EUE (GWh) EUE (%)
Base, 2030 15.18 0 0 0 11.5 0.5 0.00 0.00 0.00 0.00 0.00
Base, no future RE, 2035
15.18 0 0 0 0 0.5 0.00 0.00 0.00 0.00 0.00
Base, High Load, no future RE, 2035
15.18 0 0 0 0 0.5 0.00 0.00 0.00 0.00 0.00
See Section 12.3 for more details on risks of the
resource portfolio given uncertainties in procuring and acquiring the optimal mix of resources.
8.5.3 Grid Operations
The transition to 100% renewables will necessitate a change in how the thermal generators on our system operate. Renewable resources and storage will reduce our reliance on existing fossil fuel–based generators to serve load. This is shown in the daily energy profiles and operational statistics in this section. Reducing dependence on fossil fuel–based generators will improve reliability
given that our fossil fuel–based generators are
currently more than 60 years old, as shown in
Appendix C, and experiencing higher outage rates.
The analysis in Section 9 also shows that utility
rates will be lower than if we continue to rely on
fossil fuels.
Sometimes the total generation exceeds the system load during the day. This surplus energy
from the grid is used to charge the standalone BESS. In the energy profiles, the standalone BESS energy charging load is the striped layer while the
standalone BESS dispatch is shown as solid. The
standalone BESS charging load is shown to
confirm that the excess energy shown is charging
the BESS and not being curtailed. The energy used to charge the standalone BESS doesn’t necessarily come from any particular resource type.
8.5.3.1 Status Quo Typical Operations
The Status Quo scenario does not include the hybrid solar and standalone energy storage from RESOLVE that is included in the Base scenario. Figure 8-58 and Figure 8-59 show the dispatch of the resources in a Status Quo resource plan in 2030 and 2035, respectively, for a few days with average load. With the decreased amount of hybrid solar and standalone storage, the Status Quo system still relies on existing firm units quite
heavily. As shown in Figure 8-58 the load is almost
completely served by the existing fossil-fuel units.
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Figure 8-58. Moloka‘i: detailed Status Quo energy profile, 2030 median load day (January 9–11, 2030)
Figure 8-59. Moloka‘i: detailed Status Quo energy profile, 2035 median load day (October 1–3, 2035)
8.5.3.2 Base Scenario Typical
Operations
Figure 8-60 and Figure 8-61 show the dispatch of the resources in a Base scenario resource plan in
2030 and 2035, respectively, for a few days with
average load. Compared to the Status Quo
scenario above, the Base scenario shows a much
lower reliance on the existing firm fossil units. By
2035 the system uses the existing firm fossil units much less than in the Status Quo scenario.
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Figure 8-60. Moloka‘i: detailed Base energy profile, 2030 median load day (January 9–11, 2030)
Figure 8-61. Moloka‘i: detailed Base energy profile, 2035 median load day (October 1–3, 2035)
8.5.3.3 Operations of Firm Generation
Figure 8-62 and Figure 8-63 show thermal
generators capacity factor and average number of
starts, respectively, for the 2030 and 2035 for Status Quo and Base scenarios. Appendix C shows which thermal generators are categorized as “Baseload,” “Cycling” and “Peaking.” Without the
hybrid solar and standalone storage included in the Base scenario, the system in the Status Quo scenario uses the baseload and peaking units a lot more, shown by the higher capacity factor of the baseload units increase over time with the load. However, because the Base scenario is less reliant on the firm units, the capacity factor for the baseload units decreases over time.
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Figure 8-62. Moloka‘i: utility-owned thermal generators capacity factor, 2030 and 2035 for Status Quo and Base scenario
Figure 8-63. Moloka‘i: utility-owned thermal generators
average number of starts, 2030
and 2035 for Status Quo and Base
scenario
8.5.4 System Security Needs
Moloka‘i does not have a transmission system, so
our analysis did not evaluate the REZ concept;
however, we performed a system stability analysis. We analyzed the Base scenario resource plan post-Stage 3 procurement and 2050. We also analyzed the High Load resource plan for near-term years (i.e., between post-Stage 3 procurement and before 2040), which can be
found in Appendix D. We analyzed selected years with major grid scale resource additions, including:
■ Molokaʻi system Base scenario resource plan:
2029, 2030 and 2050
■ Molokaʻi system High load scenario resource
plan: 2029, 2030 and 2050
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8.5.4.1 Summary of Base Scenario
Resource Plan
We performed a system dynamic stability review with very low synchronous machine generation or no synchronous machine generation online. We evaluated system stability in the presence of a three-phase to ground fault with zero fault impedance for 2 seconds duration, or in the presence of a single phase to ground fault with 40-ohm fault impedance for 20 seconds duration.
We concluded that when powered by 100% grid-
forming inverter-based resources the Molokaʻi
system exhibits acceptable stability performance
in the years from 2030 to 2050; however, the
system may experience diesel unit out-of-
synchronism issues before 2030 when the system relies on the existing diesel units.
8.5.5 Distribution Needs
This section discusses distribution needs as they pertain to the grid needs assessment for Molokaʻi.
8.5.5.1 Hosting Capacity Grid Needs
Of the eight circuits assessed on Moloka‘i, most
have sufficient DER hosting capacity or could
accommodate the 5-year hosting capacity without
infrastructure investments. The remaining circuits
where infrastructure investments are required to
increase hosting capacity to accommodate the
forecasted distributed energy resources are identified as requiring grid needs. Infrastructure investments or distribution upgrades (i.e., wires solutions) to mitigate the grid needs are identified with cost estimates. The grid needs and solutions are summarized in Table 8-34.
Table 8-34. Moloka‘i Hosting Capacity Grid Needs
(Years 2021–2025)
Parameter (Nominal $) Base DER Forecast High DER Forecast Low DER Forecast Number of grid needs 3 5 3
Cost summary (wires solutions)
$1,260,000 $1,764,000 $1,260,000
A complete list of the hosting capacity grid needs can be found in the Distribution DER Hosting Capacity Grid Needs report.
8.5.5.2 Location-Based Grid Needs
Of the eight circuits and two substation transformers assessed on Moloka‘i, all have sufficient capacity to accommodate the forecasted load demand. No grid needs are identified.
8.5.5.3 Distribution Grid Needs
Summary
The minimum number of grid needs identified (i.e., minimum wires solutions) by scenario by
island is shown in Table 8-35 below. This includes
both hosting capacity and location-based grid
needs.
Table 8-35. Moloka‘i Minimum Grid Needs Solutions Identified (Years 2023–2030)
Island (Nominal $) Scenario 1 (Base) Scenario 2 (High Load)
Scenario 3 (Low Load)
Scenario 4 (Faster Technology Adoption) Number of grid needs 3 3 5 5
Cost summary (wires solutions)
$1,260,000 $1,764,000 $1,260,000 $1,260,000
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8.5.5.4 NWA Opportunities
No NWA opportunities are identified for Moloka‘i.
8.5.6 Preferred Plan
The capacity expansion modeling conducted in
RESOLVE was the starting point for identifying
grid needs and developing a resource plan.
Battery duration was increased to 4 hours to
match current market conditions. We then
performed probabilistic resource adequacy analyses to confirm that the portfolio of resources
selected in the resource plan were reliable. No additional system constraints or transmission costs were identified.
The Preferred Base scenario resource generation and capacity mix over time are
shown in Figure 8-64 and Figure 8-65,
respectively. The change in installed capacity over time for each resource type is shown in Figure 8-66. See Appendix C for the Base Preferred Plan with planned and new resource
additions listed by year.
Figure 8-64. Molokaʻi: Preferred Base scenario resource generation mix (2023–2045)
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Figure 8-65. Molokaʻi: Preferred Base scenario resource installed capacity mix (2023–2045)
Figure 8-66. Molokaʻi: Preferred Base scenario change in installed capacity by resource type (2023–2045)
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8.6 Lānaʻi
This section describes the results of the grid needs assessment for Lānaʻi through the multistep
process that includes modeling capacity
expansion, resource adequacy, operations of the
system, transmission and system security needs,
distribution needs and iterations or adjustments
made to determine the preferred plan.
8.6.1 Capacity Expansion
Scenarios
Shown below, in Figure 8-67, is the capacity of the
new resources selected by RESOLVE for the Base,
Low Load, High Load and Faster Technology
Adoption scenarios. The Lānaʻi CBRE request for
proposal targeting 35.8 GWh of variable renewable energy, which translates to approximately 16 MW hybrid solar, will bring Lānaʻi to nearly 100% RPS. An additional 5 MW hybrid solar was identified int the Base scenario by 2030. The CBRE request for proposal may also allow for deactivation of fossil fuel–based generation.
Similar amounts of hybrid solar and standalone BESS are selected across the different scenarios in addition to the 16 MW hybrid solar modeled for the CBRE request for proposal.
There is uncertainty surrounding the resorts,
which represents nearly 50% of Lānaʻi’s load
today. The CBRE request for proposal may be
oversized if the resorts exit the grid. The hybrid
solar proxy resource for the CBRE request for
proposal was removed in the No Resorts scenario. The model was allowed to re-optimize and selected approximately 10 MW hybrid solar, a smaller amount than the CBRE request for proposal target.
Figure 8-68 shows the annual generation from all existing, planned and selected resources and RPS for Lānaʻi for the Base, Low Load, High Load and Faster Technology Adoption scenarios. The DER+DBESS shown here refers to the forecasted
DER+DBESS and does not include any DER
Aggregate hybrid solar, which may be selected by
RESOLVE in certain scenarios. If DER Aggregate
hybrid solar is selected by RESOLVE, it will be
shown separately from the forecasted DER+DBESS.
Figure 8-67. Lānaʻi: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, Low Load, High Load, Faster Technology Adoption and No Resorts
scenarios
Lānaʻi achieves nearly 100% RPS with the CBRE request for proposal and additional hybrid solar
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selected by RESOLVE. The existing fossil fuel–powered firm generation is converted to 100% biofuel by 2045.
Figure 8-68. Lānaʻi: annual
generation and RPS from
resources in 2030, 2035 and 2050
for the Base, Low Load, High Load, Faster Technology Adoption and No Resorts scenarios
8.6.1.1 High Fuel Retirement
Optimization Scenario
The High Fuel Retirement Optimization scenario
retired 5 MW of existing fossil fuel–based generation upfront in 2030. Because RESOLVE performs a linear optimization, the additional
retirements may consist of partial unit retirements. RESOLVE builds hybrid solar to replace the retired capacity. RESOLVE builds 0.3 MW biofuel-based generation by 2050. Figure 8-69 shows cumulative new capacity and Figure 8-70 shows annual generation and RPS for Lānaʻi.
Figure 8-69. Lānaʻi: cumulative
new capacity selected by
RESOLVE in 2030, 2035 and 2050
for the Base and High Fuel Retirement Optimization scenarios
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Although 5 MW of existing fossil fuel–based generation is removed in the High Fuel Retirement Optimization scenario, the annual
generation is similar between the Base and High Fuel scenarios.
Figure 8-70. Lānaʻi: annual
generation and RPS from resources in 2030, 2035 and 2050 for the Base and High Fuel Retirement Optimization scenarios
8.6.2 Resource Adequacy
We did not make any retirement assumptions for Lānaʻi; however, as more renewable resources are brought online, we will continue to assess resource adequacy and determine if system conditions warrant retiring existing fossil fuel–based generators.
Probabilistic Resource Adequacy
Summary
The Base resource plan in 2030 includes 10 MW existing firm, 16 MW hybrid solar for the CBRE request for proposal, 5 MW future hybrid solar
and 0.6 MW standalone BESS. The loss of load
expectation is 0 days per year and no unserved energy is observed in the 250 samples.
For the 2035 outlook, we analyzed the High Load
scenario. The High Load resource plan in 2035
includes 10 MW existing firm, 16 MW hybrid solar for the CBRE request for proposal, 7 MW future hybrid solar and 0.6 MW standalone BESS. The loss of load expectation is 0 days per year and no unserved energy is observed in the 250 samples.
Table 8-36 presents a probabilistic resource adequacy analysis results summary for Lānaʻi.
Table 8-36. Probabilistic Resource Adequacy Analysis: Results Summary, Lānaʻi
Scenario Existing Firm New Firm CBRE RFP Future Wind Future Hybrid Solar
Future Standalone BESS
LOLE LOLEv LOLH EUE (GWh) EUE (%)
Base, 2030 10 0 16 0 5.2 0.6 0 0 0 0 0
Base, 2035 10 0 16 0 5.5 0.6 0 0 0 0 0
Base, High Load, 2035
10 0 16 0 7.2 0.6 0 0 0 0 0
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See Section 12.3 for more details on risks of the resource portfolio given uncertainties in procuring and acquiring the optimal mix of resources.
8.6.3 Grid Operations
The transition to 100% renewables will necessitate
a change in how the thermal generators on our system operate. Renewable resources and storage will reduce our reliance on existing fossil fuel–based generators to serve load. This is shown in the daily energy profiles and operational statistics in this section. Reducing dependence on fossil fuel–based generators will improve reliability given that our fossil fuel–based generators are currently more than 60 years old, as shown in Appendix C, and experiencing higher outage rates.
The analysis in Section 9 also shows that utility
rates will be lower than if we continue to rely on
fossil fuels.
Sometimes the total generation exceeds the
system load during the day. This surplus energy from the grid is used to charge the standalone
BESS. The standalone BESS charging load is shown to confirm that the excess energy shown is charging the BESS and not being curtailed. The energy used to charge the standalone BESS doesn’t necessarily come from any particular resource type.
8.6.3.1 Status Quo Typical Operations
The Status Quo resource plan includes the existing
fossil fuel–based generation and a proxy resource
for the 17.5 MW hybrid solar project selected
through the CBRE RFP. There are no additional
future resources.
Figure 8-71 and Figure 8-72 show the dispatch of the resources in the Status Quo resource plan in 2030 and 2035, respectively, for a few days with average load. The load is carried primarily by hybrid solar and BESS. Fossil fuel–based generation is dispatched during the evening and can be dispatched during the day when there is insufficient solar.
Figure 8-71. Lānaʻi: detailed Status Quo energy profile, 2030 median load day (July 21–23, 2030)
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Figure 8-72. Lānaʻi: detailed Status Quo energy profile, 2035 median load day (June 22–24, 2035)
8.6.3.2 Base Scenario Typical
Operations
The Base resource plan includes the existing fossil
fuel–based generation, the CBRE request for
proposal and additional future resources selected
by RESOLVE.
Figure 8-73 and Figure 8-74 show the dispatch of
the resources in the Base resource plan in 2030 and 2035, respectively, for a few days with average load. The additional future resources selected by RESOLVE displace almost all of the fossil fuel–based generation seen above for the Status Quo scenario. Fossil fuel–based generation is mostly dispatched at night.
Figure 8-73. Lānaʻi: detailed Base
energy profile, 2030 median load
day (July 21–23, 2030)
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Figure 8-74. Lānaʻi: detailed Base energy profile, 2035 median load day (June 22–24, 2035)
8.6.3.3 Operations of Firm Generation
Figure 8-75 and Figure 8-76 show the average
number of generator starts and the generator
capacity factor in 2030 and 2035 for the Status
Quo and Base scenarios. Appendix C shows which
thermal generators are categorized as “Baseload,” “Cycling” and “Peaking.” Fossil fuel–based generation is dispatched significantly less in the Base scenario compared to Status Quo.
Figure 8-75. Lānaʻi: utility-owned thermal generators average number of starts, 2030 and 2035 for Status Quo and Base scenario
0
50
100
150
200
250
300
350
400
450
2030 2035 2030 2035
Status Quo Base
Av
e
r
a
g
e
N
u
m
b
e
r
o
f
S
t
a
r
t
s
New
Peaking
Cycling
Baseload
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Figure 8-76. Lānaʻi: utility-owned thermal generators capacity factor, 2030 and 2035 for Status Quo and Base scenario
8.6.4 System Security Needs
Lānaʻi does not have a transmission system, so our analysis did not evaluate the REZ concept; however, we performed a system stability analysis. We analyzed the Base scenario resource plan post-Stage 3 procurement and 2050. We also
analyzed the High load resource plan for near-
term years (i.e., between post-Stage 3 and before
2040), which can be found in Appendix D. We
analyzed selected years with major grid scale
resource additions, including:
■ Lānaʻi system Base scenario resource plan:
2029 and 2050
■ Lānaʻi system High load scenario resource plan: 2029 and 2050
■ Lānaʻi system No Resort scenario resource plan: 2029, 2030 and 2050
8.6.4.1 Summary of Base Resource
Plan
For Lānaʻi, we performed a system dynamic stability review with very low synchronous machine generation or no synchronous machine generation online. We evaluated system stability in the presence of a three-phase to ground fault with zero fault impedance for 2 seconds duration,
or in the presence of a single phase to ground
fault with 40-ohm fault impedance for 20 seconds duration.
We concluded that when powered by 100% grid-forming inverter-based resources the Lānaʻi system in the scenario without resort load, exhibits acceptable system stability performance in the years from 2030 to 2050. The system may exhibit diesel unit out-of-synchronism before 2029 when the system relies on the existing diesel
units. In the scenario with the resort load, the
system has a large grid-forming inverter-based
resource (with 15.8 MW capacity). In this scenario,
the system survives both the 2 seconds duration
three-phase to ground fault and the 20 seconds
high impedance single phase to ground fault.
8.6.5 Distribution Needs
This section discusses distribution needs as they pertain to the grid needs assessment for Lānaʻi.
8.6.5.1 Hosting Capacity Grid Needs
Of the three circuits assessed on Lānaʻi, two have insufficient DER hosting capacity to accommodate the 5-year hosting capacity without infrastructure
investments and require grid needs. Infrastructure
investments or distribution upgrades (i.e., wires
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solutions) to mitigate the grid needs are identified with cost estimates. The grid needs and solutions are summarized in Table 8-37.
Table 8-37. Lānaʻi Hosting Capacity Grid Needs (Years 2021–2025)
Parameter (Nominal $) Base DER Forecast High DER Forecast Low DER Forecast Number of grid needs 2 2 2
Cost summary (wires solutions) $504,000 $504,000 $504,000
A complete list of the hosting capacity grid needs can be found in the Distribution DER Hosting Capacity Grid Needs report.
8.6.5.2 Location-Based Grid Needs
Of the three circuits and one substation transformer assessed on Lānaʻi, all have sufficient capacity to accommodate the forecasted load demand. No grid needs are identified.
8.6.5.3 Distribution Grid Needs
Summary
The minimum number of grid needs identified
(i.e., minimum wires solutions) by scenario by island is shown in Table 8-38. This includes both hosting capacity and location-based grid needs.
Table 8-38. Lānaʻi Minimum Grid Needs Solutions Identified (Years 2023–2030)
Island (Nominal $) Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load) Scenario 4 (Faster Technology Adoption) Number of grid needs 2 2 2 2
Cost summary (wires solutions) $504,000 $504,000 $504,000 $504,000
8.6.5.4 NWA Opportunities
No NWA opportunities are identified for Lānaʻi.
8.6.6 Preferred Plan
The capacity expansion modeling conducted in RESOLVE was the starting point for identifying grid needs and developing a resource plan. Battery duration was increased to 4 hours to match current market conditions. We then performed probabilistic resource adequacy analyses to confirm that the portfolio of resources
selected in the resource plan were reliable. No
additional system constraints or transmission
costs were identified.
The Preferred Base scenario resource generation and capacity mix over time are shown in Figure 8-77 and Figure 8-78, respectively. The change in installed capacity
over time for each resource type is shown in Figure 8-79. See Appendix C for the Base Preferred Plan with planned and new resource additions listed by year.
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Figure 8-77. Lānaʻi: Preferred Base scenario resource generation mix (2023–2045)
Figure 8-78. Lānaʻi: Preferred Base scenario resource installed capacity mix (2023–2045)
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Figure 8-79. Lānaʻi: Preferred Base scenario change in installed capacity by resource type (2023–2045)
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9 Customer Impacts
In Section 8, we conducted a grid needs assessment to determine the optimal, Preferred
Plans that meet reliability standards while achieving 100% renewable energy by 2045. In this
section we examine the financial and environmental impacts to customers of those
Preferred Plans by assessing bill impacts and carbon emissions.
Customers continue to stress the importance of affordability, and the State has set ambitious
decarbonization targets to achieve economy-wide
50% carbon emissions reduction by 2030 and net
negative carbon emissions reductions by 2045
compared to 2005 levels. We found that our
Preferred Plans stabilize electric bills and rates and
reduce emissions for the good of the environment. Under the Preferred Plans, bills are relatively flat (and in some cases lower) over the long term despite increasing revenue requirements that are needed to enable the grid to integrate more renewables and electrify the transportation sector.
Our ambitious Preferred Plans also have the potential to reduce carbon emissions by 75% in
2030 compared to 2005 levels. However, in 2030
in a Land-Constrained scenario, carbon emissions
are nearly two times the Base Preferred Plan. By
2045, our Preferred Plans achieve 94% carbon
emissions reductions; achieving net zero will
require natural carbon sinks, carbon capture or advancements in negative emissions technologies. Electrification of transportation results in significant carbon reductions through 2050.
9.1 Financial and Bill Analysis
This section provides the financial analyses of the Integrated Grid Plan. It presents the strategies
needed to swiftly decarbonize the electric grid and manage risks to affordability, resilience and
reliability and each island’s residential customer
electricity rate and bill impacts for the Preferred
Plans compared to the Status Quo. These analyses
should not be used as precise long-term projections of customer rates. The value of these
projections is not in the precise values but in the relative results of planning to inform a Preferred Plan. Actual values could vary significantly with changes in assumptions including resource costs, detailed engineering, new renewable technologies, fuel prices, energy efficiency, tax policy, fiscal policy and other factors.
The following information is provided by island:
■ Revenue requirements
■ Capital expenditures
■ Residential customer bill and rate impacts
9.1.1 Revenue Requirements
The revenue requirement calculations include the investments needed to create a modern and resilient grid for our Preferred Plans and Status Quo scenarios. The calculations include operating and maintenance costs, taxes other than income, and return on existing and future utility asset investments.
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Although revenue requirements will increase in the transition to clean energy, they will be lower than if we continue to supply the grid with fossil fuel–based generation.
If land for renewable projects is more limited in
the future, we will need to consider higher-cost
alternatives. If low-cost renewables are not
available in sufficient quantities such as in the
Land-Constrained scenario, higher-cost
alternatives such as increased use of biofuels will need to be considered to meet decarbonization goals.
9.1.2 Capital Expenditures
Capital expenditure projections in distribution
upgrades, expanding or creating new transmission
interconnection points between renewable
projects, improving the resilience of the
transmission and distribution grid, and all other
utility capital expenditures (referred to as
“balance-of-utility business capital expenditures”) are included in the analysis.
■ Distribution upgrades are needed to support electrification and expansion of private rooftop solar hosting capacity, and support expanded distribution capacity for new housing and commercial developments.46
■ Transmission network expansion and infrastructure to enable REZs are needed to
create hubs and enabling transmission
facilities for large-scale projects that will
streamline interconnection and provide
access to untapped renewable potential and
growth in electrified loads.
46 We note that while the transmission needs analysis evaluated infrastructure needed to support electrification through 2050, the distribution needs analysis did not evaluate infrastructure required to support electrification beyond 2030.
47 RBA is the Revenue Balancing Account that continues the decoupling mechanism under the Performance-Based
■ Resilience grid investments are needed to prepare the grid to withstand natural disasters and support deploying microgrids. This also includes the complete rollout of AMI of phase 2 grid modernization to
enhance system reliability and resilience. The
capital expenditures for these two programs
assume that we will receive funding through
IIJA to offset the program costs.
■ Balance-of-utility capital expenditures
represent all other utility investments.
9.1.3 Residential Customer Bill
and Rate Impacts
The residential customer bill and rate impacts uses
the Annual Revenue Adjustment (ARA) approach, illustrating the bill impact of incremental
Integrated Grid Plan revenue requirement costs and savings through the Energy Cost Recovery Clause (ECRC), Purchased Power Adjustment Clause (PPAC) and Revenue Balancing Account (RBA) rates. These terms are defined below:
■ ARA is an annual adjustment to target revenues based on an ARA formula.
■ ECRC includes the cost for utility fuel and purchased energy from IPPs.
■ PPAC includes the payments for capacity and
operation and maintenance, and lump-sum
payments, to IPPs.
■ RBA,47 among other items, includes
decoupling, the ARA and the Extraordinary
Project Recovery Mechanism (EPRM).
Regulation Framework. This mechanism allows Hawaiian Electric to recover target test year revenues from customers, independent of the level of sales.
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The overall impact on a residential customer’s bill is the combination of usage and rates. Residential customer rates were modeled using existing customer and non-fuel energy charges, the ECRC revenue requirement allocated across projected
kWh sales, the PPAC revenue requirement for
residential allocated across projected residential
kWh sales, and the RBA revenue requirement
divided by the sum of base and PPAC revenue, to
be applied as a percentage to the customer’s base
and PPAC charges in this illustration. Over the planning period, residential kWh sales are projected to increase as a result of electrification of transportation. As a result of increasing revenue requirement in combination with increasing sales, residential customer bills and rates are projected to remain relatively flat over the planning period, demonstrating the benefits of electrification of the transportation sector.
9.2 Oʻahu Financial Impacts
The data and analyses presented in this section
cover the O‘ahu service territory and customers. For O‘ahu, the Base Preferred Plan shows the lowest overall revenue requirements over the 2023 to 2050 planning period.
9.2.1 Revenue Requirements
Table 9-1 shows the net present value (NPV) of
the annual revenue requirements for the Base and
Land-Constrained Preferred Plan and Status Quo
scenarios.
Table 9-1. Net Present Value of Revenue Requirement
NPV of Revenue Requirement ($000)
($000) % Increase from Lowest-Cost Scenario Base scenario $29,397,330 -
Status Quo scenario $33,886,081 15%
Land-Constrained scenario $30,357,218 3%
Figure 9-1 illustrates the annual revenue requirements in nominal dollars for all three scenarios.
Figure 9-1. O‘ahu: comparison of revenue requirement (nominal $)
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9.2.2 Capital Expenditure
Projections
Table 9-2, Table 9-3 and Table 9-4 summarize the
capital expenditures identified in the Base
Preferred Plan, Status Quo and Land-Constrained
Preferred Plan, respectively.
Table 9-2. Capital Expenditures (Nominal $): Base Scenario Preferred Plan
('000) 2023–25 2026–30 2031–35 2036–40 2041–45 2046–50 Total
Distribution upgrades $12,527 $39,278 $0 $0 $0 $0 $51,805
Transmission interconnection $22,794 $1,032,990 $62,456 $798,919 $5,723,323 $2,129,656 $9,770,138
Resilience $12,768 $36,831 $0 $0 $0 $0 $49,599
Grid mod phase 2 $14,501 $11,965 $0 $0 $0 $0 $26,466
Balance-of-utility business $622,756 $914,143 $924,602 $1,032,996 $1,052,278 $1,156,684 $5,703,458
Total $685,346 $2,035,207 $987,058 $1,831,915 $6,775,601 $3,286,340 $15,601,466
Table 9-3. Capital Expenditures (Nominal $): Status Quo Scenario
('000) 2023–25 2026–30 2031–35 2036–40 2041–45 2046–50 Total
Distribution upgrades $12,527 $39,278 $0 $0 $0 $0 $51,805
Transmission interconnection $0 $0 $0 $0 $528,500 $293,100 $821,600
Resilience $12,768 $36,831 $0 $0 $0 $0 $49,599
Grid mod phase 2 $14,501 $11,965 $0 $0 $0 $0 $26,466
Balance-of-utility business $630,153 $1,015,547 $1,105,691 $1,091,971 $1,124,389 $1,191,265 $6,159,017
Total $669,949 $1,103,621 $1,105,691 $1,091,971 $1,652,889 $1,484,365 $7,108,487
Table 9-4. Capital Expenditures (Nominal $): Land-Constrained Scenario Preferred Plan
('000) 2023–25 2026–30 2031–35 2036–40 2041–45 2046–50 Total
Distribution upgrades $12,527 $39,278 $0 $0 $0 $0 $51,805
Transmission interconnection $0 $0 $62,456 $0 $1,990,600 $293,100 $2,346,156
Resilience $12,768 $36,831 $0 $0 $0 $0 $49,599
Grid mod phase 2 $14,501 $11,965 $0 $0 $0 $0 $26,466
Balance-of-utility business $622,756 $914,143 $924,602 $1,032,996 $1,052,278 $1,156,684 $5,703,458
Total $662,552 $1,002,217 $987,058 $1,032,996 $3,042,878 $1,449,784 $8,177,484
9.2.3 Residential Customer Bill
and Rate Impacts
As a result of an increasing revenue requirement
in combination with increasing sales because of
electrification, residential customer rates and bills are projected to remain relatively flat during the planning period for all scenarios, demonstrating the benefits of electrification of the transportation sector.
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Table 9-5 shows the average annual residential bill increases for all scenarios; however, the smallest increase occurs in the Base Preferred Plan scenario. The bill increase in the Land-Constrained Preferred Plan is also less than the increase in the Status Quo scenario.
Table 9-5. Average Annual Residential Bill Increases
Average Annual Bill Increase (2023–2050) Nominal $
Base scenario 1.28%
Status Quo scenario 3.70%
Land-Constrained scenario 1.32%
Figure 9-2 illustrates the residential customer bill
impact in nominal dollars for a typical 500 kWh
bill for the three scenarios.
Figure 9-2. O‘ahu: typical monthly residential bill (nominal $)
Figure 9-3 illustrates the residential customer
rates nominal dollars for the three scenarios.
Figure 9-3. O‘ahu: residential rates (nominal $/kWh)
Figure 9-4, Figure 9-5 and Figure 9-6 illustrate the cost components to residential customer rates in nominal dollars for the Base Preferred Plan, Status
Quo and Land-Constrained Preferred Plan,
respectively. The ECRC component of residential
rates makes up a larger portion of the total rate in
the Status Quo and Land-Constrained scenarios
compared to the Base Preferred Plan, and
therefore has higher exposure to rate volatility because of fuel prices. In the Base Preferred Plan scenario, PPAC increases while ECRC declines because of the increase in fixed-cost PPAs for hybrid solar, wind and energy storage, and less dependency on fuel-based generation and energy-based PPAs. The Base Preferred Plan scenario RBA component increases because of the investment needed in transmission and distribution infrastructure to enable renewables and electrification.
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Figure 9-4. O‘ahu: cost components to residential rates, Base scenario (nominal $/kWh)
Figure 9-5. O‘ahu: cost components to residential rates, Status Quo scenario (nominal $/kWh)
Figure 9-6. O‘ahu: cost components to residential rates, Land-Constrained scenario (nominal $/kWh)
9.3 Hawai‘i Island Financial
Impacts
The data and analyses presented in this section cover the Hawai‘i Island service territory and customers. For Hawai‘i Island, the Base Preferred Plan shows the lowest overall revenue requirements over the 2023 to 2050 planning period.
9.3.1 Revenue Requirements
Table 9-6 shows the NPV of the annual revenue
requirements for the Base Preferred Plan and
Status Quo scenarios.
Table 9-6. Net Present Value of Revenue Requirement
NPV of Revenue Requirement ($000)
($000) % Increase from Lowest-Cost Scenario Base scenario $4,683,848 -
Status Quo scenario $5,596,654 19%
Figure 9-7 illustrates the annual revenue requirements in nominal dollars for the two scenarios.
Figure 9-7. Hawai‘i Island: comparison of revenue
requirement (nominal $)
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Capital Expenditure Projections
Table 9-7 and Table 9-8 summarize the capital expenditures identified in Status Quo and Preferred Plan, by category.
Table 9-7. Capital Expenditures (Nominal $): Base Scenario
('000) 2023–25 2026–30 2031–35 2036–40 2041–45 2046–50 Total
Distribution upgrades $3,310 $0 $0 $0 $0 $0 $3,310
Transmission interconnection $9,002 $36,010 $3,230 $24,158 $0 $25,848 $98,248
Resilience $4,401 $12,052 $0 $0 $0 $0 $16,453
Grid mod phase 2 $2,887 $12,563 $0 $0 $0 $0 $15,450
Balance-of-utility business $134,806 $226,859 $250,420 $276,484 $305,261 $337,032 $1,530,863
Total $154,407 $287,484 $253,650 $300,642 $305,261 $362,880 $1,664,324
Table 9-8. Capital Expenditures (Nominal $): Status Quo Scenario
('000) 2023–25 2026–30 2031–35 2036–40 2041–45 2046–50 Total
Distribution upgrades $3,310 $0 $0 $0 $0 $0 $3,310
Transmission interconnection $0 $77,026 $19,257 $0 $0 $0 $96,283
Resilience $4,401 $12,052 $0 $0 $0 $0 $16,453
Grid mod phase 2 $2,887 $12,563 $0 $0 $0 $0 $15,450
Balance-of-utility business $134,806 $226,859 $250,420 $276,484 $305,261 $337,032 $1,530,863
Total $145,404 $328,500 $269,677 $276,484 $305,261 $337,032 $1,662,359
9.3.2 Residential Customer Bill
and Rate Impacts
As a result of an increasing revenue requirement in combination with increasing sales because of electrification, residential customer rates and bills are projected to remain relatively flat during the planning period for the Base Preferred Plan, demonstrating the benefits of electrification of the transportation sector. This is especially true on
Hawai‘i Island in 2045 and beyond where, despite
an increase in revenue requirement, electric bills
decrease.
Table 9-9 shows the average annual residential bill increase in the Status Quo scenario and decrease in the Base Preferred Plan.
Table 9-9. Average Annual Residential Bill Increases
Average Annual Bill Increase (2023–2050) Nominal $
Base scenario (0.09)%
Status Quo scenario 2.15%
Figure 9-8 illustrates the residential customer bill
impact in nominal dollars for a typical 500 kWh bill for the two scenarios.
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Figure 9-8. Hawai‘i Island: residential bill (nominal $)
Figure 9-9 illustrates the residential customer rates in nominal dollars for the two scenarios.
Figure 9-9. Hawai‘i Island: residential rates (nominal $/kWh)
Figure 9-10 and Figure 9-11 illustrate the cost components to residential customer rates in
nominal dollars for the Base Preferred Plan and
Status Quo, respectively. The ECRC component of
residential rates makes up a larger portion of the
total rate in the Status Quo compared to the Base
Preferred Plan, and therefore has higher exposure to rate volatility because of fuel prices. In the Base Preferred Plan scenario, PPAC increases while ECRC declines because of the increase in fixed-cost PPAs for hybrid solar, wind and energy storage, and less dependency on fuel-based generation and energy-based PPAs. The Base Preferred Plan scenario RBA component increases because of the investment needed in transmission
and distribution infrastructure to enable renewables and electrification.
Figure 9-10. Hawai‘i Island: cost components to
residential rates, Base scenario (nominal $/kWh)
Figure 9-11. Hawai‘i Island: cost components to
residential rates, Status Quo scenario (nominal $/kWh)
9.4 Maui County Financial
Impacts
The data and analyses presented in this section
cover the Maui County service territory and
customers, and are broken out individually for
Maui, Moloka‘i and Lānaʻi, unless clearly noted.
The Base scenario shows the lowest overall revenue requirements over the 2023 to 2050 planning period for all three islands.
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9.4.1 Revenue Requirements
Table 9-10 shows the NPV of the annual revenue
requirements for the Base Preferred Plan and
Status Quo scenarios for Maui, Moloka‘i and
Lānaʻi.
Table 9-10. Net Present Value of Revenue Requirement
NPV of Revenue Requirement ($000)
($000) % Increase from Lowest-Cost Scenario Base scenario: Maui $4,769,387 -
Status Quo scenario: Maui $5,305,202 11%
Base scenario: Moloka‘i $152,650 -
Status Quo scenario: Moloka‘i $179,995 18%
Base scenario: Lānaʻi $177,201 -
Status Quo scenario: Lānaʻi $190,209 7%
Figure 9-12 illustrates Maui’s annual revenue requirements in nominal dollars.
Figure 9-12. Maui: comparison of revenue requirement (nominal $)
Figure 9-13 illustrates Moloka‘i’s annual revenue requirements in nominal dollars.
Figure 9-13. Moloka‘i: comparison of revenue requirement (nominal $)
Figure 9-14 illustrates Lānaʻi’s annual revenue requirements in nominal dollars.
Figure 9-14. Lānaʻi: comparison of revenue requirement (nominal $)
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Capital Expenditure Projections
Table 9-11 and Table 9-12 summarize the capital expenditures identified in the Status Quo and Preferred Plan, by category, for the Base Preferred
Plan and Status Quo scenarios for Maui County, and are not broken out individually for Maui, Moloka‘i and Lānaʻi.
Table 9-11. Capital Expenditures (Nominal $): Base Scenario—Maui County
('000) 2023–25 2026–30 2031–35 2036–40 2041–45 2046–50 Total
Distribution upgrades $4,277 $0 $0 $0 $0 $0 $4,277
Transmission Interconnection $0 $60,554 $106,638 $60,505 $144,392 $135,086 $507,175
Resilience $5,456 $10,425 $0 $0 $0 $0 $15,881
Grid mod phase 2 $2,999 $9,717 $0 $0 $0 $0 $12,716
Balance-of-utility business $224,994 $249,223 $261,531 $288,751 $318,805 $351,986 $1,695,289
Total $237,726 $329,918 $368,169 $349,256 $463,197 $487,072 $2,235,337
Table 9-12. Capital Expenditures (Nominal $): Status Quo Scenario—Maui County
('000) 2023–25 2026–30 2031–35 2036–40 2041–45 2046–50 Total
Distribution upgrades $4,277 $0 $0 $0 $0 $0 $4,277
Transmission interconnection $0 $1,887 $22,462 $320 $68,090 $12,500 $105,259
Resilience $5,456 $10,425 $0 $0 $0 $0 $15,881
Grid mod phase 2 $2,999 $9,717 $0 $0 $0 $0 $12,716
Balance-of-utility business $224,994 $249,223 $261,531 $288,751 $318,805 $351,986 $1,695,289
Total $237,726 $271,251 $283,993 $289,071 $386,895 $364,486 $1,833,421
9.4.2 Residential Customer Bill
and Rate Impacts
As a result of an increasing revenue requirement in combination with increasing sales because of electrification, residential customer rates and bills are projected to remain relatively flat during the planning period in the Base Preferred Plan, demonstrating the benefits of electrification of the transportation sector.
Table 9-13 shows the average annual residential
bill increases for Maui and Moloka‘i; however, the
bill increases are smaller in the Base Preferred Plan
scenario compared to the Status Quo scenario.
The average annual bill decreases for Lānaʻi in the Base Preferred Plan scenario.
Table 9-13. Average Annual Residential Bill Increases
Average Annual Bill Increase (2023–2050) Nominal $
Base scenario: Maui 0.43%
Status Quo scenario: Maui 2.16%
Base scenario: Moloka‘i 0.78%
Status Quo scenario: Moloka‘i 3.06%
Base scenario: Lānaʻi (0.25)%
Status Quo scenario: Lānaʻi 0.25%
Figure 9-15 illustrates Maui’s residential customer bill impact in nominal dollars for a typical 500 kWh bill for the two scenarios.
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Figure 9-15. Maui: residential bill (nominal $)
Figure 9-16 illustrates Moloka‘i’s residential customer bill impact in nominal dollars for a typical 400 kWh bill for the two scenarios.
Figure 9-16. Moloka‘i: residential bill (nominal $)
Figure 9-17 illustrates Lānaʻi’s residential customer bill impact in nominal dollars for a typical 400 kWh bill for the two scenarios.
Figure 9-17. Lānaʻi: residential bill (nominal $)
Figure 9-18 illustrates Maui’s residential customer rates in nominal dollars for the two scenarios.
Figure 9-18. Maui: residential rates (nominal $/kWh)
Figure 9-19 illustrates Moloka‘i’s residential
customer rates in nominal dollars for the two
scenarios.
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Figure 9-19. Moloka‘i: residential rates (nominal $/kWh)
Figure 9-20 illustrates Lānaʻi’s residential customer
rates in nominal dollars for the scenarios.
Figure 9-20. Lānaʻi: residential rates (nominal $/kWh)
Figure 9-21 and Figure 9-22 illustrate the cost components to residential customer rates in nominal dollars for the Maui Base Preferred Plan and Status Quo, respectively. The ECRC component of residential rates makes up a larger portion of the total rate in the Status Quo compared to the Base Preferred Plan, and therefore has higher exposure to rate volatility
because of fuel prices. In the Base Preferred Plan
scenario, PPAC increases while ECRC declines
because of the increase in fixed-cost PPAs for
hybrid solar, wind and energy storage, and less
dependency on fuel-based generation and
energy-based PPAs. The Base Preferred Plan scenario RBA component increases because of the
investment needed in transmission and distribution infrastructure to enable renewables and electrification.
Figure 9-21. Maui: cost components to residential rates, Base scenario (nominal $/kWh)
Figure 9-22. Maui: cost components to residential
rates, Status Quo scenario (nominal $/kWh)
Figure 9-23 and Figure 9-24 illustrate the cost components to residential customer rates in nominal dollars for the Moloka‘i Base Preferred Plan and Status Quo, respectively. The ECRC component of residential rates makes up a larger
portion of the total rate in the Status Quo
compared to the Base Preferred Plan, and
therefore has higher exposure to rate volatility
because of fuel prices. In the Base Preferred Plan
scenario, PPAC increases while ECRC significantly
declines in 2031 as hybrid solar on a fixed-price
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PPA is added to the system and there is less dependency on fuel-based generation and energy-based PPAs. The Base Preferred Plan scenario RBA component increases because of the investment needed in distribution infrastructure to
enable renewables and electrification.
Figure 9-23. Moloka‘i: cost components to residential rates, Base scenario (nominal $/kWh)
Figure 9-24. Moloka‘i: cost components to residential rates, Status Quo scenario (nominal $/kWh)
Figure 9-25 and Figure 9-26 illustrate the cost
components to residential customer rates in
nominal dollars for the Lānaʻi Base Preferred Plan
and Status Quo, respectively. The ECRC component of residential rates makes up a larger portion of the total rate in the Status Quo compared to the Base Preferred Plan, and therefore has higher exposure to rate volatility
because of fuel prices. In the Base Preferred Plan scenario, PPAC increases while ECRC significantly declines in 2027 as hybrid solar on a fixed-price PPA is added to the system and there is less dependency on fuel-based generation and
energy-based PPAs. The Base Preferred Plan
scenario RBA component is relatively flat as the
Base Preferred Plan did not require as much
investment in distribution infrastructure compared
to other islands.
Figure 9-25. Lānaʻi: cost components to residential rates, Base scenario (nominal $/kWh)
Figure 9-26. Lānaʻi: cost components to residential rates, Status Quo scenario (nominal $/kWh)
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9.5 Emissions and
Environmental
This section provides the forecast for future emissions that result from the Preferred Plans for each island and the estimated trajectory for meeting the decarbonization goals.
9.5.1 Greenhouse Gas Emissions
The renewable resources that are added in the
Preferred Plans drive down emissions as fossil
fuel–based generation is displaced by hybrid solar,
wind and offshore wind. By 2030, we expect to
achieve a reduction in GHG emissions of 75%, relative to 2005 baseline levels. By 2045, some emissions are still produced by H-Power as a byproduct of its waste-to-energy process. Natural carbon sinks, or technologies that can capture
carbon dioxide from the generator stack or extract
it from the atmosphere, may need to be
considered, holistically as a state, to achieve the
State’s net-zero decarbonization goal. Figure 9-27
summarizes the emissions in the Preferred Plans
through 2050. Figure 9-28 summarizes the emissions in the Preferred Plans through 2050 with the Land-Constrained scenario on Oʻahu.
Figure 9-27. Consolidated emissions and percentage reduction compared to 2005 baseline without biogenic CO2
If Oʻahu is Land-Constrained, a consolidated 70% reduction in emissions is delayed from 2030 to 2035 when offshore wind is installed.
The Land-Constrained scenario also highlights
challenges that remain to meet net-zero
emissions by 2045 where the last mile of emissions in 2044 is significant: only 14% of 2005 emissions for the Base scenario but a
much higher 30% of 2005 emissions for the
Land-Constrained scenario.
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Figure 9-28 Consolidated emissions and percentage reduction compared to 2005 baseline without biogenic CO2 with
Land-Constrained scenario on Oʻahu
Regardless of the scenario, remaining emissions
would need to be abated through natural sinks,
carbon capture and storage or a negative emissions technology to achieve net-zero emissions by 2045. The percentage reduction
achieved in 2045 before any carbon capture is
93% in the Base scenario and 90% in the Land-
Constrained scenario. The emissions for each island are provided below in
Table 9-14.
Table 9-14. Preferred Plan Greenhouse Gas Emissions
Emissions (MT CO2e) 2030 2035 2040 2045 2050
Oʻahu 1,836,324 888,921 761,234 525,744 494,213
Hawaiʻi Island 13,987 14,218 17,325 3 8
Maui 84,672 56,921 58,906 31 26
Molokaʻi 2,197 1,567 1,164 1 1 Lānaʻi 2,072 2,031 1,694 1 1
Comparing the Base or Land-Constrained
scenario to the Status Quo illustrates how
effective the Base or Land-Constrained Preferred Plans are at reducing emissions compared to the Status Quo. The Base scenarios have less than half the emissions of
the Status Quo by 2030, which enables the
achievement of the 70% GHG reduction goal.
However, the Land-Constrained scenario, with its more limited resource options, has mostly the same emissions as the Status Quo in the same year.
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Table 9-15, Table 9-16, Table 9-17, Table 9-18
and Table 9-19 provide the emissions in select
years for Oʻahu, Hawaiʻi Island, Maui, Molokaʻi
and Lānaʻi, respectively.
Table 9-15. Oʻahu Greenhouse Gas Emissions Relative to Status Quo
Oʻahu Emissions 2030 2035 2040 2045 2050 Base (MT CO2e) 1,836,324 888,921 761,234 525,744 494,213
Land-Constrained (MT CO2e) 3,359,238 1,756,826 1,741,284 798,996 644,545
Status Quo (MT CO2e) 4,232,203 4,441,825 4,826,553 1,491,483 1,479,260
Base/Status Quo (%) 43% 20% 16% 35% 33% Land-Constrained/ Status Quo (%) 79% 40% 36% 54% 44%
Table 9-16. Hawaiʻi Island Greenhouse Gas Emissions Relative to Status Quo
Hawaiʻi Island Emissions 2030 2035 2040 2045 2050
Base (MT CO2e) 13,987 14,218 17,325 3 8
Status Quo (MT CO2e) 176,875 179,013 203,871 59 111
Base/Status Quo (%) 8% 8% 8% 5% 7%
Table 9-17. Maui Greenhouse Gas Emissions Relative to Status Quo
Maui Emissions 2030 2035 2040 2045 2050 Base (MT CO2e) 84,672 56,921 58,906 31 26
Status Quo (MT CO2e) 203,393 245,526 307,360 308 366 Base/Status Quo (%) 42% 23% 19% 10% 7%
Table 9-18. Molokaʻi Greenhouse Gas Emissions Relative to Status Quo
Molokaʻi Emissions 2030 2035 2040 2045 2050 Base (MT CO2e) 2,197 1,567 1,164 1 1
Status Quo (MT CO2e) 16,976 16,928 17,271 15 15
Base/Status Quo (%) 13% 9% 7% 4% 4%
Table 9-19. Lānaʻi Greenhouse Gas Emissions Relative to Status Quo
Lānaʻi Emissions 2030 2035 2040 2045 2050 Base (MT CO2e) 2,072 2,031 1,694 1 1
Status Quo (MT CO2e) 7,627 7,886 8,051 6 6 Base/Status Quo (%) 27% 26% 21% 17% 15%
9.5.2 Emissions Reductions due
to Electrification of
Transportation
As discussed earlier in this section, electrification of transportation can have positive financial benefits for customers. It also has positive environmental benefits. The adoption of electric vehicles will decrease the statewide emissions of greenhouse gases, furthering the State of
Hawaiʻi’s achievement of its decarbonization goals.
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Figure 9-29. Impact of preferred plans on 2005 state emissions
In the Hawaiʻi Greenhouse Gas Program established by the Department of Health, GHG emission inventories are periodically updated to show progress on achieving statewide GHG reduction goals. Emissions are reported by sector including energy; industrial processes and product use (IPPU); agriculture, forestry and other land use (AFOLU); and waste. Within the energy sector, the major contributors to emissions are stationary
combustion in energy industries and
transportation (primarily ground and aviation). In
the 2005 baseline year, GHG emissions for
stationary combustion in energy industries was
8.33 million metric tons carbon dioxide equivalent
(CO2e) and for ground transportation was 5.04 million metric tons CO2e. This is relative to 2005 total net emissions (including sinks) of 22.81 million metric tons.48 Changes in the electric system as part of the Integrated Grid Plan result in substantial emissions reductions when combining electric sector and light-duty vehicle and eBus
48 See Hawaiʻi Greenhouse Gas Emission Report for 2005, 2018, and 2019 at 26,
emissions by 2045 through reduced fuel. consumption. However, there are significant amounts of emissions within other sectors of the state that must be planned for to achieve the State's goal of net-zero emissions by 2045.
Figure 9-29 shows the emissions impact of the Integrated Grid Planning preferred plans.
In our Base scenario, electric vehicles forecast through 2050 will avoid significant amounts of fuel being consumed, shown in Figure 9-30, and
emissions from burning that fuel, shown in Figure
9-31. While electric vehicles provide a meaningful
reduction to statewide emissions, they will need to
be charged from the grid, which will increase the demand for electricity and can increase the risk of having inadequate generation in the future, as discussed in Section 12.2, if we are unable to bring on low-cost renewable energy at the same pace as EV growth.
https://health.hawaii.gov/cab/files/2023/04/2005-2018-2019-Inventory_Final-Report.pdf
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Figure 9-30. Avoided fuel consumption due to electric vehicle adoption
Figure 9-31. Avoided greenhouse gas emissions due to electric vehicle adoption
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10 Energy Equity
In this section, we discuss our ongoing efforts to address energy inequities and offer
solutions that we can implement and continue to learn from and expand in the future. As the
cost of living in Hawaiʻi continues to rise, we must make electricity affordable and ensure
that we ease the burden of the renewable transition on low- to moderate-income customers
and communities that bear the burden of hosting energy infrastructure in the past and
future. The transition increases access to renewable energy and equitability for all.
The PUC recently opened a proceeding to
investigate energy equity in response to legislative resolutions. The areas for exploration include high energy rates in Hawaiʻi, high percentage of LMI persons, high energy burden, lack of universal access to renewable energy initiatives, need for utility payment assistance, historical siting of fossil-fuel infrastructure, land constraints and regulatory process burdens.
Everyone has an interest in an equitable energy system. As society continues to electrify all aspects of the economy, all customers stand to benefit if
everyone is able to afford electricity and
participate in the transition.
10.1 Equity Definitions
The PUC has defined the following key terms to
guide equity discussions:
■ Equity refers to achieved results where
advantages and disadvantages are not distributed on the basis of social identities. Strategies that produce equity must be targeted to address the unequal needs, conditions and positions of people and communities that are created by institutional and structural barriers.
■ Energy equity refers to the goal of achieving equity in both the social and
economic participation in the energy system,
while also remediating social, economic and health burdens on those historically harmed by the energy system.
■ Low- to moderate-income (LMI) persons are those whose income is at or below 150% of the Hawaiʻi federal poverty limit.
■ Energy burden is the percentage of a household's income spent to cover energy cost.
10.2 LMI Programs
We have recently selected CBRE projects (also known as the shared solar program) through a competitive procurement for LMI community-based solar projects. While we were required to
award a minimum of one project each on Oʻahu,
Maui and Hawaiʻi Island, we awarded seven total
projects as shown in Table 10-1, to provide
greater access to renewable energy to LMI eligible customers.
While these projects may not provide an opportunity to every LMI customer that desires to participate in the renewable transition, it represents a start that will enable us to improve on and expand programs and choices for customers in the future.
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Table 10-1. Community-based Solar Projects for LMI Customers
Island Developer Project Shared Solar Megawatt Capacity
Oʻahu Nexamp Solar & Melink Solar Development Kaukonahua Solar 6 MWh (solar only)
Maui Nexamp Solar Lipoa Solar 3 MW + BESS
Maui Nexamp Solar Makawao Solar 2.5 MW + BESS
Maui Nexamp Solar Piiholo Road Solar 2.5 MW + BESS
Hawaiʻi Island Nexamp Solar Kalaoa Solar A 3 MW + BESS
Hawaiʻi Island Nexamp Solar Kalaoa Solar B 3 MW + BESS
Hawaiʻi Island Nexamp Solar Naalehu Solar 3 MW + BESS
The shared solar program embraces the concept of a community project by giving the surrounding community (i.e., census tract) first priority in subscribing to a shared solar project.
We have also made verification of LMI eligibility
easier for customers and require developers to
dedicate 100% of the project to LMI eligible
customers, reserving at least 60% of the project
for residential LMI customers. Each project will
have different offerings or subscription fees and
arrangements. In exchange for subscribing to a project, LMI customers will receive a monthly bill credit to help reduce their energy costs.
10.3 Affordability and Energy
Burden
Energy burden on LMI customers is one of the affordability metrics measured in the Performance-Based Regulation framework. The metric evaluates the typical and average annual bill for a residential customer as a percentage of a low-income household’s average income (defined as 150% of the Hawaiʻi federal poverty level), by island. Using the electric bill and rate projections in Section 9, Figure 10-1 shows the projected affordability metric based on our Preferred Plans
through 2050 for the typical residential customer on each island.
Our projections show that the transition to clean
energy may reduce the overall energy burden for
the typical residential customer on each island through 2050, compared to today's energy burden.
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Figure 10-1. Typical residential bill as a percentage of low-income average income per island (150% of the federal
poverty level)
10.4 Community Benefits
Package for Grid-Scale
Projects
Through various forums, we have heard the desire
of communities to be more engaged early in the
renewable energy project development process.
We continue to engage communities around the
islands as we develop RFPs and identify future
grid needs. Building upon the outreach to stakeholders and communities in developing recent RFPs, we will continue to listen, learn and work with communities throughout the process of developing the next round of procurements on each island we serve.
Based upon Stakeholder Council
recommendations and past community
feedback, we have expanded community
engagement requirements for prospective
project developers by specifying more detailed
requirements and by adding a requirement for
developers to provide a benefits package for the
surrounding communities.
Our ongoing Stage 3 RFPs require project
developers to commit to financial community benefits. Developers are required to provide at least $3,000 per MW (based on their proposed project size) per year in community benefits. These funds would be donated for actions and/or programs aimed at addressing specific needs
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identified by the host community, or to a 501(c)(3) not-for-profit community-based organization(s) to directly address host community–identified needs.
The developers would provide a documented community benefits package highlighting the
distribution of funds for our review. This
document would be made public on each
project’s website and demonstrate how funds will
directly address needs in the host community.
The community benefits package would also include documentation of each project developer’s community consultation and input collection process to define community needs, along with actions and programs aimed at addressing those needs. Preference would be given to projects that commit to setting aside a larger amount or commit to providing other benefits (including but not limited to creating local jobs, payment of prevailing wages or improving community infrastructure).
In addition, we included the following
modifications to the procurement process in
response to community feedback:
■ Higher scoring to project proposals that are
proposed on land zoned commercial or industrial, land with greater impervious cover or reclaimed land
■ Procedural improvements made to further ensure the protection and preservation of cultural resources
■ Prioritization of local labor and prevailing wage for proposed projects
■ Additional requirements for developers to
provide monthly updates to the community
prior to and throughout the construction
process
10.5 Renewable Energy Zone
Development in
Collaboration with
Communities
The large-scale renewable project community
benefits package is intended to address, in part,
the burdens put onto communities that host clean
energy projects and infrastructure. It does not
mitigate all community concerns, nor does it recognize the future needs of the grid to achieve our decarbonization goals.
The most cost-effective path with current technology will require substantially more land to site clean energy projects along with transmission infrastructure. However, that cannot be accomplished without the acceptance of our communities. As the Stakeholder Council advised
in discussing this topic, “we must go slow to go
fast.” Careful and thoughtful planning with our
communities is needed to turn our vision into
reality.
Stakeholder and public engagement have been a
hallmark of this process. Last year we discussed
more details of our Hawaiʻi Powered vision and focused community discussions on REZ development.
As we discuss in Section 4, we have provided multiple options, in-person and virtually, to provide input. The Hawaiʻi Powered website functions as a centralized hub for public engagement. In seeking this initial round of input on REZs, hawaiipowered.com/rez/ was made
available to the general public. We also conducted
in-person meetings, provided a newsletter
describing the effort to numerous electronic
mailing lists and community organizations, and
ran a 3-week social media campaign. The online
map includes the ability to drop a pin and add comments identifying those places that may be
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suitable as well as areas that are undesirable for development of renewable energy projects. The input gathered through this process will be used to refine the REZ analysis, which will guide planning efforts for transmission infrastructure
needed to support future renewable resource
development, as well as to inform developers
regarding potential site suitability for specific
renewable energy projects through the
procurement process.
A complete list of comments received through our engagement through the Hawaiʻi Powered website is included in Appendix A, and a summary of common themes related to equity is listed below.
10.5.1 Oʻahu
■ The Kahuku and West Oʻahu communities expressed, some strongly, that no windmills should be built. The Waialua community had similar sentiments, and also commented on the lack of support for offshore wind among the community.
■ In general, communities across Oʻahu believed that wind turbines should not be allowed to be built near homes, schools and
farms. Wind turbine placement is
controversial and should be discussed with
communities.
■ Renewable technology was raised often in terms of finding technology that requires less land space and has a smaller footprint. We also received suggestions to evaluate hydro or tidal, geothermal and nuclear energy.
■ Equity (as opposed to equality) was raised to ensure distribution of burden for hosting renewable projects.
■ A desire was expressed to make sure that
electricity generated in a community stays in
that community. For example, Will Waiʻanae
and North Shore side (which have high land potential) be given higher-priority usage over Waikīkī (which is a high energy user)?
■ Many commented that rooftop solar and parking lot solar canopies should be a
priority before turning to land for grid-scale
projects. This sentiment was a frequently
shared comment on all islands.
■ Affordability was a common theme; for
example, one commenter said, “If you drive
the cost of electricity so high that it becomes unsustainable, all effort toward clean energy will be useless. Yes, pursue clean energy options, but do it in a way that puts the burden on [Hawaiian Electric] and the State of Hawaiʻi, not on customers who are already stretched too thin paying energy bills.”
■ Affordability and access to energy options
was another theme; for example, “As a
renter, I feel left out of this process and at
the whim of my landlord.” And “100%
renewable is not feasible and will cost more
than you believe you will save. It is
unattainable for the majority of people. You are placing a huge burden on the bottom of the income bracket.”
■ Many advocated for incentives and programs to participate in rooftop solar, such as community buy-back programs, grant programs (especially for lower-income residents) and subsidized re-roofing/re-paneling.
■ Utilization of existing infrastructure was
discussed, rather than conducting new
development.
■ Residents expressed a desired expansion of
EV charging stations and plug types.
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10.5.2 Maui
■ A common theme we heard on Maui related
to respect for cultural sites and preservation
of Maui’s natural beauty, such as
Haleakala—though some expressed that you
could respect the cultural sites while finding
opportunities.
“Putting up turbines or solar in Central Maui wouldn’t bother me, but beyond that should stay untouched.”
“Ukumehame—the land has been decimated; maybe solar could be used but as long as it doesn’t add to the negative effects already being seen in that area.”
“Concern would be for Hana, lot of
sensitivity there, don’t recommend putting
anything there.”
The Waihe’e, Honua’ula and Mauka areas
also were raised as having cultural
significance.
■ Some community members mentioned opportunities for agricultural lands on Maui that are not farmable, which could be good possibilities for renewable projects, such as in central and west Maui.
■ Adding solar panels to existing infrastructure was mentioned.
■ Renewable technology was raised often in terms of finding technology that requires
less land space and has a smaller footprint.
We also received suggestions to evaluate
hydro, tidal and nuclear energy.
■ Desired expansion of EV charging stations
was expressed.
10.5.3 Hawaiʻi
■ Similar to Oʻahu, Hawaiʻi Island community members want renewable projects sited away from the population so the project does not disrupt anyone.
“While I’m not in favor of wind energy, especially anywhere near populated areas, I believe solar panels should be placed on every single public building possible (schools, government buildings, etc.) and
over parking lots (covered parking).”
■ Concerns were expressed for threats to
endangered species due to wind turbine
blades:
“Renewable energy must not come at the
expense of native habitat and species. Use previously developed land and areas that are already covered with non-permeable surfaces.”
■ Similar to other islands, we received several comments regarding solar canopies to cover parking lots and more rooftop solar.
■ Streamlining the process to participate in rooftop solar was mentioned.
■ Desired expansion of EV charging stations
was expressed.
■ Renewable technology was raised often in
terms of finding technology that requires
less land space and has a smaller footprint. We also received suggestions to evaluate hydrothermal and geothermal energy generation.
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Figure 10-2. Keywords identified from the map comments
Figure 10-2 shows the keywords identified from
the REZ map comments. Each island community has identified both opportunities and challenges,
which provides insight into siting future additional large-scale projects.
The development of REZs will take time to conduct proper community engagement, permitting and siting, among other tasks. Our immediate next step is to acquire information from landowners, through a request for information, who are willing to allow for renewable project development and marry those
with the community comments we have received
to date. Then we intend to work with specific
communities on a REZ and transmission siting
process to potentially develop these areas and to
understand the opportunities and challenges.
10.6 Energy Transitions
Initiative Partnership
Project
We were selected last year as a partner in DOE’s
ETIPP to improve energy resilience and combat climate change. As part of the partnership, Hawaiian Electric is helping to identify areas on O‘ahu that are optimal for developing microgrids to build a more resilient electric grid. Microgrids serve areas that are connected to the electric grid yet can be islanded during an outage to continue providing electricity through a variety of resources, including solar panels, a battery and/or a backup generator.
We hope to reduce initial barriers and complexities
with a map that takes into account the technical
and practical viability of microgrid development.
Microgrids are best suited to areas prone to
prolonged outages during weather events, with clusters of customers and potential availability of renewable energy resources. The map would allow developers to contact potential microgrid participants and work with Hawaiian Electric to apply for the development of a specific microgrid.
Our objective of this effort is to provide customers with a map identifying areas that are good candidates for hosting hybrid microgrids, to improve electrical infrastructure to severe weather with consideration for electric grid layout,
customer-sited resources, reliability, equity, among others.
There are several considerations in mapping
potential microgrid locations like critical facilities and
grid vulnerabilities, but we also explicitly take into account societal impacts such as disadvantaged communities and asset-limited, income-constrained residents, as shown in Figure 10-3.
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Figure 10-3. Description of the three criteria used to identify microgrid opportunities
Figure 10-4 below illustrates the critical facilities
we have included in our initial analysis. As described in Appendix A we sought input from
communities around O‘ahu to acquire local
knowledge to identify critical facilities and vulnerable or societal impact areas.
Figure 10-4. Listing of the types of critical facilities included in the ETIPP analysis
Figure 10-5 and Figure 10-6 illustrate a microgrid
map that can show the areas where criticality,
vulnerability and social impact intersect. These
locations are prime locations for future microgrid
development, which can also inform the
hardening of distribution lines that would connect
critical customers within that microgrid.
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Figure 10-5. Hauʻula potential hybrid microgrids
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Figure 10-6. Map of the Kona Moku identifying locations for microgrid opportunity by criteria
Through these efforts we hope that more resilient energy can benefit our communities by highlighting areas with critical facilities that serve
the greater public, vulnerable areas of the grid and high social-impact areas.
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11 Growing the Energy
Marketplace
We recognize that customers have choices in the way they use energy, which is why they
must be at the center of the way we acquire solutions to the pathways we have laid out.
We want to create and grow a customer- and community-centered marketplace that can seamlessly and quickly deliver solutions to
urgently address our climate goals and ease the
burdens that fossil fuel has on our customers’
bills, environment and economy. Growing
Hawai‘i’s energy marketplace consists of three
main levers: pricing, programs and procurements.
It also allows customers and communities to participate in the process in several ways: by taking advantage of new time-of-use rates, and adopting customer technologies like energy efficiency, electric vehicles or community solar projects. We also hope to give the community a voice in where and how large-scale projects are located and developed. The energy marketplace will deliver the actual technologies and solutions at the best price through competition.
We believe the energy marketplace, with
communities and customers at the center, will
deliver the best solutions, with urgency, and
provide benefits to all customers. It also sets a
framework for inclusive planning of the future
grid, one that works for all.
As we describe in this section, we believe in the
value that customers can deliver with new
technologies, and we also believe that
communities should benefit from hosting clean energy projects and infrastructure. Establishing the energy marketplace is a key pillar that will
provide the predictability to participants and project partners need to take urgent action.
11.1 Customer Energy
Resource Programs
The following sections describe the various mechanisms to grow the marketplace for customer resources and incentivize customer
engagement to participate in the clean energy
transition. These mechanisms include price signals
aligned with system needs and programs with
incentives to spur customer adoption of new
technologies.
11.1.1 Pricing Mechanisms
We have installed advanced meters to more than 40% of our customers on Oʻahu, Maui and Hawaiʻi Island and expect to complete the rollout of advanced meters to all customers in our service territory by the end of the third quarter of 2024.
Advanced rate designs, which have been
incorporated into our analysis, play an important
role in the transition to a decarbonized electric
system. Implementation of new time-of-use rates include three primary components: (1) customer
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charge, (2) grid access charge and (3) time-of-use energy charges. The customer charge is applied as a fixed monthly charge for the cost of customer metering and billing. The grid access charge is a monthly charge for residential and small
commercial customers and a charge based on
measured demand for medium commercial
customers for customer-related service
connection costs. The third component, the time-
of-use energy charge, is a $/kWh charge that
consists of the cost of fuel, investments and operations of the grid and purchased power, and other surcharges, where the ratio of the daytime period (9 a.m. to 5 p.m.), overnight period (9 p.m. to 9 a.m.) and evening peak period (5 p.m. to 9
p.m.) rate is 1:2:3. Figure 11-1 below illustrates the
proposed time-of-use energy charges for
residential customers that is currently pending
PUC approval.
Figure 11-1. Illustrative time-of-use energy charges
The new rate structures are intended to
encourage customer adoption of technologies
such as energy efficiency and rooftop solar and
energy storage, incentivizing energy conservation
and behavioral changes to use energy away from times when the grid is most stressed (the highest-
cost period). This includes ensuring that electric vehicles are not charged during the high demand period in the evening—as assumed in our grid needs analysis under managed vehicle charging. Because these new rates are a fundamental change from traditional electric rates, there will be a rollout period for the first year to a small sample of residential and small/medium commercial
customers who have advanced meters to provide
critical data and experience with these new rate
structures and to determine whether the
advanced rate design is working as intended. The
next period will build on lessons learned to
implement a broader rollout of advanced rate designs.
11.1.1.1 Electric Vehicle Pricing and
Programs Mechanisms
We are committed to supporting decarbonization
of the economy, and have established pricing and
programs to encourage EV adoption. These
pricing options and programs are another way in
which we will grow the energy marketplace with
our customers. These efforts include:
■ EV public fast charging
■ EV tariffs for electric buses and commercial customers
■ eBus make-ready infrastructure pilot, or Charge Up eBus
■ Charge Ready Hawai‘i commercial make-ready infrastructure pilot or Charge Up Commercial
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We have established pricing options for non-residential EV charging that are lower during the midday period from 9 a.m. to 5 p.m. daily to align with our system needs to encourage charging when renewable resources are abundant.
Since 2013 we have been providing EV public fast-
charging stations for customers, and by year end
2023 we plan to have 36 chargers installed across
our service territory. We have proposed an
expansion of this program and revised rates that are cost-competitive with gasoline. These fuel cost savings can help encourage greater EV adoption as it further improves the economics of owning an electric vehicle.
We have also established pricing options of tariffs for electric buses and commercial customers. The tariffs also provide significantly lower demand charges than the corresponding commercial rate schedules, Schedules J and P.
To complement the pricing options, our “Charge
Up” programs are intended to reduce the upfront
costs of installing charging infrastructure for bus
operators, commercial customers and EV service
providers. Participants in these programs are required to use the EV time-of-use rates, which promotes charging during the daytime, but we
have received feedback that this can be challenging for operational efficiencies of some participants.
11.1.2 Customer Programs
Valuation
The “freeze” scenarios described in Section 6.8 can be leveraged to inform the potential value of achieving the forecasted adoption of a particular technology, similar to the work completed in the DER proceeding that led to the creation of the
Battery Bonus program. Customer technologies
not only provide choices for customers to control
their energy bills, but they also remain critical to
reducing the amount of large-scale resources (and
land) that is needed to meet our goals.
Additionally, we hope to create programs where not only customers benefit but the broader grid as well, and customers are equitably compensated for the services they deliver.
The EE, private rooftop solar and EV charging adoption forecasts may be evaluated to determine potential value to inform program development that seeks to achieve the levels forecasted. The general framework for the freeze analysis is shown in Figure 11-2.
Figure 11-2. Illustration of values derived from freeze analysis
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Determining the cost of the system without the forecasted adoption (i.e., frozen at current levels) compared to the cost of the system with the forecasted adoption effectively provides the approximate value of the addition of the customer
energy resource. Using the DER Freeze as an
example, when the distributed energy resources
are frozen at current levels, additional resources
will need to be built and selected by the models
to replace the customer-sited resources assumed
in the forecasted adoption. We can then determine the value of the customer technologies by evaluating the difference in cost between the Base scenario with the forecasted layer and DER Freeze, where the value is effectively avoiding the cost of those additional resources.
The performance characteristics of the resource (i.e., DER capabilities to provide grid services, EV charging profiles, EE supply bundles) are critical to
appropriately valuing a program. From a system
cost perspective, a program could be deemed
cost-effective if the all-in cost of a program is less
than the value determined in the freeze analysis.
The design of the program should also reflect the
performance requirements and services modeled. Any incentives allocated as part of the program should be performance-based to ensure that customers are receiving the commensurate benefits. The freeze analyses are intended to provide high-level guidance to inform more detailed discussions to create new programs or update current ones. The detailed design of
programs may include other cost perspectives, aside from the system cost perspective as
analyzed here, such as the rate impact to all
customers, impact to customers participating in the programs, and impact to non-participating customers, to ensure that programs are being designed equitably.
The results of the Freeze scenarios shown in Table
11-1 indicate that there are cost savings if
distributed energy resources (rooftop solar and
battery energy storage) or energy efficiency is
adopted as forecasted (except on Molokaʻi) and
cost increases if electric vehicles are adopted as forecasted. The values in Table 11-1 are based on the difference in NPV (2029–2050), calculated as the selected scenario minus the Base scenario.
Table 11-1. Avoided Costs for the Freeze Scenarios, Relative to Base
NPV (2018$, $MM)
Base DER Freeze: Base
EV Freeze: Base
Unman-aged EV: Base
EE as a Resource: Base Oʻahu 10,798 775 -1,075 93 1,517 Hawaiʻi Island 1,316 150 -221 13 293
Maui 2,288 178 -282 37 72 Molokaʻi 66 3.7 -1.9 0.2 -1.5
Lānaʻi 70 1.3 -0.9 -0.1 0.5
Compared to unmanaged EV charging, managed charging does provide cost savings on all islands (except Lānaʻi) but not enough to offset the cost increases due to the overall higher demand from electric vehicles. The NPV avoided cost provides the break-even dollars that can inform incentives
or total program costs to incentivize customers to
adopt distributed energy resources or to allow the
dispatch of their electric vehicles as a resource to
serve grid needs.
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11.1.2.1 Oʻahu
Figure 11-3 shows the resource capacity added for the Base, DER Freeze, EE Resource, EV Freeze and Unmanaged EV scenarios, and Figure 11-4 shows
the NPV of the Base, DER Freeze, EE Resource, EV
Freeze and Unmanaged EV scenarios. Cost is
displayed in millions of 2018 dollars (2018$MM).
The following offers a summary of the valuation of customer resources that may be used to inform the design of future or current program updates:
■ The DER Freeze scenario is similar to the Base scenario. Slightly more hybrid solar is selected in the DER Freeze scenario than in the Base scenario to compensate for the lower DER capacity.
More resources built results in an NPV that is approximately 7% higher than the
Base scenario NPV.
■ The EE as a Resource scenario selects the EE
supply bundle, standalone solar and
renewable firm in addition to the renewable
resources selected in the Base scenario. As
shown in Section 11.1.3, the load impact of
the EE supply curves is smaller than the EE load forecast. This results in more selected resources and higher generation need for the EE as a Resource scenario than for the Base scenario.
More resources built results in an NPV that is approximately 14% higher than the Base scenario NPV.
■ The EV Freeze scenario selects fewer
resources than the Base scenario, including
no biomass resource. This highlights the
growing load impact of electric vehicles,
especially over time.
Fewer resources built results in an NPV that is approximately 10% lower than the Base scenario NPV.
The cost of electrification growth is partially offset by the savings from
forecasted distributed energy resources and energy efficiency.
■ The Unmanaged EV scenario is almost the same as the Base scenario with its managed EV forecast.
In 2030, the Unmanaged EV scenario and
Base scenario selected the same resources,
and the selected resource sizes were within
a couple percentage points. In 2050, the
Unmanaged EV scenario selected 6 MW of
new firm renewable generation and an additional 45 MW of Biomass (45% more) over the Base scenario. The other resources selected in the Unmanaged EV scenario have sizes within 5% of the Base scenario.
The minimal NPV difference of 1% also implies little change between the Managed EV and Unmanaged EV scenarios.
Figure 11-3. Oʻahu: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, DER Freeze, EE Supply Curve, EV Freeze and Unmanaged EV scenarios
Figure 11-4. Oʻahu: NPV relative to the Base scenario for the DER Freeze, EE Supply Curve, EV Freeze and Unmanaged EV scenarios
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11.1.2.2 Hawaiʻi Island
Figure 11-5 shows the resource capacity added for the Base, DER Freeze, EE Resource, EV Freeze and Unmanaged EV scenarios, and Figure 11-6 shows
the NPV of the Base, DER Freeze, EE Resource, EV
Freeze and Unmanaged EV scenarios. Cost is
displayed in millions of 2018 dollars.
The following offers a summary of the valuation of
customer resources that may be used to inform the design of future or current program updates:
■ The DER Freeze scenario is similar to the Base scenario. More hybrid solar is selected in the DER Freeze scenario than in the Base scenario to compensate for the lower DER capacity.
More resources built results in an NPV 11% higher than the Base scenario NPV.
■ The EE as a Resource scenario selects the EE
resource, standalone solar and renewable
firm in addition to the renewable resources
selected in the Base scenario. As shown in
Section 11.1.3, the load impact of the EE
supply curves is smaller than the EE load forecast. This results in more selected resources and a higher generation for the EE as a Resource scenario than for the Base scenario.
More resources built results in an NPV 22% higher than the Base scenario NPV.
■ The EV Freeze scenario selects fewer resources than the Base scenario. This highlights the growing load impact of
electric vehicles, especially over time.
Fewer resources built results in an NPV
17% lower than the Base scenario NPV
with the added electrification loads.
The cost of electrification growth is partially offset by the savings from
forecasted distributed energy resources and energy efficiency.
■ The Unmanaged EV scenario is almost the same as the Base scenario with its managed EV forecast.
The 1% NPV increase also implies little
change between the Managed EV and
Unmanaged EV scenarios.
Figure 11-5. Hawaiʻi Island: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, DER Freeze, EE Supply Curve, EV Freeze and
Unmanaged EV scenarios
Figure 11-6. Hawaiʻi Island: NPV relative to the Base scenario for the DER Freeze, EE Supply Curve, EV Freeze and Unmanaged EV scenarios
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11.1.2.3 Maui
Figure 11-7 shows the resource capacity added for the Base, DER Freeze, EE Resource, EV Freeze and Unmanaged EV scenarios, and Figure 11-8 shows the NPV of the Base, DER Freeze, EE Resource, EV Freeze and Unmanaged EV scenarios. Cost is displayed in millions of 2018 dollars.
The following offers a summary of the valuation of
customer resources that may be used to inform
the design of future or current program updates:
■ The DER Freeze scenario is similar to the
Base scenario. More hybrid solar is selected in the DER Freeze scenario than in the Base scenario to compensate for the lower DER capacity.
More resources built results in an NPV 8% higher than the Base scenario NPV.
■ The EE as a Resource scenario selects the EE supply bundles in addition to the renewable resources selected in the Base scenario. As shown in Section 11.1.3, the load impact of
the EE supply curves is larger than the EE
load forecast. This results in more selected
EE measures than the energy efficiency
forecast in the Base scenario.
More resources built results in an NPV 3%
higher than the Base scenario NPV.
■ The EV Freeze scenario selects less hybrid solar and wind resources than the Base scenario. This highlights the growing load impact of electric vehicles, especially over time.
Fewer resources built results in an NPV 12% lower compared to the Base scenario with the added electrification loads.
The cost of electrification growth is
partially offset by the savings from
forecasted distributed energy resources
and energy efficiency.
■ The Unmanaged EV scenario is almost the same as the Base scenario with its managed EV forecast.
The minimal NPV difference of 2% also implies little change between the
Managed EV and Unmanaged EV
scenarios.
Figure 11-7. Maui: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, DER Freeze, EE Supply Curve, EV Freeze and Unmanaged EV scenarios
Figure 11-8. Maui: NPV relative to the Base scenario
for the DER Freeze, EE Supply Curve, EV Freeze and
Unmanaged EV scenarios
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11.1.2.4 Molokaʻi
Figure 11-9 shows the resource capacity added for the Base, DER Freeze, EE Resource, EV Freeze and Unmanaged EV scenarios, and Figure 11-10 shows
the NPV of the Base, DER Freeze, EE Resource, EV
Freeze and Unmanaged EV scenarios. Cost is
displayed in millions of 2018 dollars.
The following offers a summary of the valuation of
customer resources that may be used to inform the design of future or current program updates:
■ The DER Freeze scenario is similar to the Base scenario. Slightly more hybrid solar is selected in the DER Freeze scenario than in the Base scenario to compensate for the lower DER capacity.
More resources built results in an NPV that is approximately 6% higher than the
Base scenario NPV.
■ The EE as a Resource scenario selects the EE
supply bundle in addition to the renewable
resources selected in the Base scenario. As
shown in Section 11.1.3, the load impact of
the EE supply curves is greater than the EE load forecast. This results in slightly fewer selected resources and lower generation need for the EE as a Resource scenario than for the Base scenario.
Fewer resources built results in an NPV that is approximately 2% lower than the Base scenario NPV.
■ The EV Freeze scenario selects fewer resources than the Base scenario. This
highlights the growing load impact of
electric vehicles, especially over time.
Fewer resources built results in an NPV
that is approximately 3% lower than the Base scenario NPV.
The cost of electrification growth is partially offset by the savings from
forecasted distributed energy resources and energy efficiency.
■ The Unmanaged EV scenario is almost the same as the Base scenario with its managed EV forecast
The minimal NPV difference of close to 0%
implies little change between the
Managed EV and Unmanaged EV
scenarios.
Figure 11-9. Molokaʻi: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, DER Freeze, EE Supply Curve, EV Freeze and
Unmanaged EV scenarios
Figure 11-10. Molokaʻi: NPV relative to the Base scenario for the DER Freeze, EE Supply Curve, EV Freeze and Unmanaged EV scenarios
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11.1.2.5 Lānaʻi
Figure 11-11 shows the resource capacity added for the Base, DER Freeze, EE Resource, EV Freeze and Unmanaged EV scenarios, and Figure 11-12
shows the NPV of the Base, DER Freeze, EE
Resource, EV Freeze and Unmanaged EV
scenarios. Cost is displayed in millions of 2018
dollars.
The following offers a summary of the valuation of customer resources that may be used to inform the design of future or current program updates:
■ The DER Freeze scenario is similar to the Base scenario. Slightly more hybrid solar is selected in the DER Freeze scenario than in the Base scenario to compensate for the lower DER capacity.
More resources built results in an NPV
that is approximately 2% higher than the
Base scenario NPV.
■ The EE as a Resource scenario selects the EE
supply bundle and standalone solar in
addition to the renewable resources selected
in the Base scenario. As shown in Section 11.1.3, the load impact of the EE supply curves is greater than the EE load forecast. Despite this, by 2050, there’s slightly more selected resources and higher generation need for the EE as a Resource scenario than for the Base scenario.
More resources built results in an NPV that is approximately 1% higher than the Base scenario NPV.
■ The EV Freeze scenario selects fewer
resources than the Base scenario. This
highlights the growing load impact of
electric vehicles, especially over time.
Fewer resources built results in an NPV that is approximately 1% lower than the Base scenario NPV.
The cost of electrification growth is offset by the savings from forecasted distributed energy resources and energy efficiency.
■ The Unmanaged EV scenario is almost the same as the Base scenario with its managed
EV forecast.
The minimal NPV difference of close to 0%
implies little change between the
Managed EV and Unmanaged EV
scenarios.
Figure 11-11. Lānaʻi: cumulative new capacity selected by RESOLVE in 2030, 2035 and 2050 for the Base, DER Freeze, EE Supply Curve, EV Freeze and Unmanaged EV scenarios
Figure 11-12. Lānaʻi: NPV relative to the Base scenario for the DER Freeze, EE Supply Curve, EV Freeze and Unmanaged EV scenarios
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11.1.3 Energy Efficiency as a
Resource
Evaluating energy efficiency as a selectable resource can help to identify the shapes and costs of cost-effective EE measures as well as validate the sets of measures that were screened for cost-effectiveness in the market potential study.
Appendix B provides additional background on the process to develop the EE bundles. Two key characteristics were used to categorize the energy efficiency measures into separate bundles: load
shape and cost-effectiveness. For load shape,
measures were grouped between evening “peak”
focused measures versus flatter, “other” measures.
For cost-effectiveness, measures were grouped by
their benefit-cost ratio determined in the market potential study where A is greater than 1.2, B is 1.0 to less than 1.2, C is 0.8 to less than 1.0, and D is less than 0.8.
In the supply curve bundling using the market potential study results, the majority of measures were screened to be highly cost-effective in the “A” grouping and flatter “Other” measures provided a significant portion of the energy savings in the Achievable Technical potential.
Their selection in the RESOLVE modeling validates
the benefit-cost testing in the market potential
study, that energy efficiency can be a cost-
effective resource alongside other supply-side
resources and that peak focused measures are not necessarily desired more than flatter measures.
Across all islands, the same measures that were screened to be cost-effective in the market potential study with benefit-cost ratios greater than 1 were also selected by RESOLVE. On Oʻahu and Hawaiʻi Island, the flatter “Other” bundles were preferred and less energy efficiency was selected than in the Base forecast. On Maui and Molokaʻi, “Other” and “Peak” bundles were
preferred with more energy efficiency selected
than in the forecast. On Lānaʻi, only the “Other” bundles were selected with the selected energy efficiency exceeding the forecast.
The model’s preference for the “Other” shape mimics a baseloaded firm unit. While the “Peak”
shape was also selected on some islands, the
“Other” shape was selected in greater quantities,
indicating that reducing system costs in all hours
is more cost-effective than targeting just the peak
hours.
Although the model did not select the exact same amount of energy efficiency as assumed in the Base forecast, the Base forecast provides a reasonable target for energy efficiency to be procured through a grid services type of competitive procurement because other resource, transmission and distribution needs were based on achieving at least the energy efficiency level forecasted in the Base scenario. The procurement
can provide a market test for the cost and
performance of energy efficiency and an
opportunity to evaluate specific EE proposals
rather than the aggregated supply curves
considered here. Additionally, more energy efficiency would contribute toward meeting our carbon reduction goals and could reduce land requirements for large-scale resources.
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11.1.3.1 Oʻahu
In the Oʻahu Base forecast, RESOLVE selected the “Other A” bundle, and no Peak
bundles were selected.
Additionally, as shown in
Figure 11-13, combined
energy efficiency because of codes and standards and the selected “Other A” bundle is less than the base EE forecast for most hours of the day, especially during the evening.
Figure 11-13. Oʻahu: EE Base forecast layer vs. EE RESOLVE selected resources, 2030
11.1.3.2 Hawaiʻi Island
In the Hawai‘i Island Base
forecast, RESOLVE selected the
“Other A” and ”Other B”
bundles, and no “Peak”
bundles were selected. Additionally, as shown in Figure 11-14, combined energy efficiency because of codes and standards and the selected bundles is less than the Base EE forecast for most hours of the day, especially during the evening.
Figure 11-14. Hawaiʻi Island: EE Base forecast layer vs. EE RESOLVE selected resources, 2030
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11.1.3.3 Maui
In the Maui Base forecast, RESOLVE selected the “Peak A,” “Peak B,” “Other A,” and “Other B” bundles. As shown in Figure 11-15, the amount of EE bundles selected were greater than the base EE forecast for all
hours of the day. This indicates
that more energy efficiency than
forecasted on Maui would be
cost-effective for the system.
Figure 11-15. Maui: EE Base forecast layer vs. EE RESOLVE selected resources, 2030
11.1.3.4 Molokaʻi
In the Moloka‘i Base forecast,
RESOLVE selected the “Peak B,”
“Other A,” and “Other B”
bundles. As shown in Figure
11-16, the amount of EE bundles selected were greater than the Base EE forecast for all hours of the day. This indicates that more energy efficiency than forecasted on Moloka‘i would be cost-effective for the system.
Figure 11-16. Molokaʻi: EE Base forecast layer vs. EE RESOLVE selected resources, 2030
11.1.3.5 Lānaʻi
In the Lānaʻi Base forecast,
RESOLVE selected the “Other
A” and “Other B” bundles. As
shown in Figure 11-17, the amount of EE bundles selected were greater than the Base EE forecast for all hours of the day. This indicates that more energy efficiency than forecasted on Lānaʻi would be cost-effective for the system.
Figure 11-17. Lānaʻi: EE Base forecast layer vs. EE RESOLVE selected resources, 2030
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11.2 Procurement Plan
The following sections describe our plans to competitively procure resources aligned with the needs identified in this report. Competitive procurements are governed by the Framework for Competitive Bidding to ensure a fair process, which allows us to seek solutions from the market at the best prices for our customers.
11.2.1 Process
With the preferred resource plans on each island identified, the resource, transmission and distribution needs will inform various RFPs (or other mechanisms like requests for information or expressions of interest) to seek competitive solutions from the market.
The novelty of Integrated Grid Planning is the seamless integration between planning and sourcing solutions from the energy marketplace.
We envision that procurements for various needs
are warranted and, as described in this section, we
plan to procure large-scale resources, NWAs and
grid services. There are specific locational benefits as identified in the transmission and distribution
needs analysis that may also be integrated into the various RFPs.
The Framework for Competitive Bidding, included in Appendix G, which was put forth by the competitive procurement working group and approved by the PUC for use in the Integrated Grid Planning process, was modified to reflect the current planning environment that has evolved in the 14 or more years since the initial framework was created.
The revised Framework for Competitive Bidding
considered a few key areas:
■ Grid needs and system resources. We
updated the framework to describe the steps and process broadly to allow for more
flexibility to meet grid needs to reflect the current market environment, such as new resource technologies and NWAs.
■ Long-term RFP. While no specific updates were made for projects that require longer
development time (i.e., 8–12 years), the
Working Group believed that the updated
framework provides sufficient flexibility to
issue procurements of this type.
■ Interconnection and procurement
scoping. This is an area that the Working Group agreed could be pursued outside the framework and, therefore, no modifications were made. However, we have been working with stakeholders to improve and streamline the interconnection process and have been doing so through the recent CBRE and Stage 3 procurements as well as through the
Performance-Based Regulation proceeding.
Finally, to grow the energy market as intended, we
envision routine procurements to urgently
address the needs as discussed throughout this
report. We have a long way to go to reach our
goals with time running short; to that end these Integrated Grid Plans serve as living roadmaps that provide sufficient guidance to acquire solutions to meet our goals. Similar to the progress we have made through Stage 1, 2 and 3 procurements over the past several years, we expect to continue competitive procurements on a routine basis (i.e., annual or once every 2 years) for the years ahead. While the urgent timeline to meet climate goals may necessitate a large
procurement in the near term, we believe that
smaller procurements on a regular schedule
instead of large procurements (i.e., Stage 2 and 3
RFPs) would lead to a smoother and more
efficient procurement and interconnection process because of the complexity and logistics to develop and execute projects in Hawai‘i.
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11.2.2 Large-scale Competitive
Procurements
Competitive procurements are a key way to ensure that we acquire the lowest-cost, best-fit resources for customers to address affordability.
Additionally, consistent with State policy, and in its Inclinations, the PUC stated its intent to pursue a balanced portfolio of energy resources:
There is clear evidence that pursuing a diverse portfolio of renewable energy resources
provides the best long-term strategy to
maximize the use or renewables to achieve
public policy goals. Project development and
system integration costs may rise as higher
levels of renewable resources are added to each
grid and higher levels of any single energy resource will increase the challenge of adding new projects. Furthermore, as communities with the most abundant indigenous renewable resource are increasingly asked to host energy infrastructure, these communities are understandably concerned with the impacts of these projects and have voiced their opposition in several instances. For these reasons, the Commission supports a balanced and diverse
portfolio of energy resources as the best long-
term strategy to achieve the state’s energy
goals.
The challenges identified in the Inclinations have
come into sharper focus in recent years. Communities are understandably concerned with the use of land and hosting projects in their neighborhoods. As discussed in this report, community engagement is central to the energy system transformation. A balanced portfolio of resources will ultimately increase reliability and resilience, introduce geographic diversity and allow for sustainable uses of land.
Through our community engagement efforts and analysis to evaluate REZs, we are also considering different options to identify communities we can collaborate with to develop REZs to site future renewable projects. Pre-selecting locations or
areas for renewable projects as part of the RFP has
potential benefits, including to engage with
communities early, plan and build infrastructure
needed to enable or expand transmission
capacity, and streamline the procurement process.
We also prefer competitive procurements to specify attributes, services and capabilities required rather than specific technologies. However, recent all-source procurements through the Stage 1 and Stage 2 RFPs have led to the acquisition of exclusively solar paired with 4-hour energy storage and standalone energy storage resources. As described in Section 12.3, as the quantity of solar and storage increases, the value
of solar and storage diminishes in their ability to
fully replace the firm capacity resources that are
expected to be retired over the next decade. To
address critical reliability needs and resource
diversity, a range of technology options should be
considered, including variable and firm generation, fuel flexibility, renewable fuels, long-duration storage, offshore resources and pump storage hydro, among others. These types of projects may take longer to develop than solar and storage projects. In some instances, it may be prudent to specify technologies consistent with the Integrated Grid Plan to send market signals that certain types of attributes are needed to fulfill certain grid needs.
11.2.3 Long-term RFP
To facilitate enabling resource diversity we believe issuing an RFP that allows projects that have longer development times (such as pump storage hydro, offshore wind, geothermal and projects that require transmission infrastructure) to submit proposals is the prudent course of action. These
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are the types of resources and technologies that have either been suggested by communities and stakeholders or selected in the capacity expansion modeling. The long-term RFP concept is supported by intervenors in the Integrated Grid
Planning proceeding. Progression Hawaiʻi stated,
in response to our first review point, that it
supports a “long-term RFP concept as a pathway
to integrate other technologies into the resource
portfolio other than solar and storage that will
enhance the reliability and resilience of the system through resource diversification” (March 4 Reply Comments at 54). Progression Hawaiʻi further recommended that the solicitation allow commercial operations out to 2035 (June Reply Comments at 5).
In preparation for the long-term RFP, we issued an expression of interest for multi-day energy storage in April 2022, and for projects that require
a longer development time frame in July 2022. We
received several responses and we discussed the
results of the expression of interest at the
Stakeholder Technical Working Group meeting in
February 2023. In that meeting, we discussed what
changes to the RFP process would need to occur to facilitate the inclusion of long-term resources into the first round of Integrated Grid Plan procurements.
We identified numerous RFP terms that would require modification if long-term resources were to be included in the same solicitation as more near-term resources. First, both developers and Hawaiian Electric recognized the challenges of
providing and holding to firm pricing for
resources that could be years longer away from
commercial operation than the projects currently
procured. This challenge further impacts the ability to effectively evaluate near-term and long-
term resources if the pricing for long-term resources could change. Other examples of modifications that will likely be necessary include the requirements for certain actions at the time of
bid submission, such as site control, and model submission. In addition, the overall RFP schedule will likely require modification, and contract terms will also need to be developed to contemplate the longer period between contract execution and commercial operations.
Given the necessary differences identified, it is
likely that a separate RFP for long-term resources
will be needed. An RFP with terms that
contemplate the longer development cycle can be better tailored to the uncertainty surrounding bids with significantly later in-service dates. The idea would be to issue both the near-term and long-term procurements in the same time frame.
In the development of the long-term RFP, the PUC also instructed Hawaiian Electric to assess the “feasibility of using existing power plant sites to locate new, quick-start, fuel-efficient, flexible generation, to leverage existing site transmission
and fuel supply infrastructure capacity that would
be freed-up by retirements of existing generating
units” (Order 32053 at 93). While the long-term
RFP has not yet been drafted, we will look to
further explore this possibility.
Pursuant to the PUC’s guidance, we are also exploring if other company-owned sites could be made available for interconnection of a variety of technologies in our RFPs, and further seeking ways to streamline the interconnection process.
11.2.4 Bid Evaluation
Consistent with the approved Framework for
Competitive Bidding and the process employed in
the Stage 1, 2 and 3 RFPs, the Integrated Grid Plan
RFPs will continue to employ a multi-step
evaluation process. Once the proposals are received, they will be subject to a consistent and defined review, evaluation and selection process. We review each proposal submission to determine if it meets the Eligibility Requirements and
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Threshold Requirements. Proposals that have successfully met these requirements will then enter a two-phase process for proposal evaluation, which includes the Initial Evaluation resulting in the development of a Priority List,
followed by the opportunity for Priority List
proposals to provide Best and Final Offers, and
then a Detailed Evaluation process to arrive at a
Final Award Group.
The Initial Evaluation consists of two parts: a price evaluation and a non-price evaluation. The price and non-price evaluations result in a relative ranking and scoring of all eligible proposals. In the Stage 3 RFP, 11 non-price criteria range from community outreach to experience and qualifications, to financial strength and financing plan. While the criteria for the Integrated Grid Planning RFP have yet to be developed, they will largely be similar to what has been included in previous RFPs.
11.2.5 NWA Competitive
Procurement
For the favorable NWA opportunities to address distribution grid needs identified in the
distribution planning process, we will first seek
Expression of Interest (EOI) from developers and
aggregators who are capable of developing grid-
scale renewable projects or aggregating
distributed energy resources/energy efficiency in
locations that will help reduce loading on circuits and transformers that are forecasted to experience overload conditions. Performance requirements in the form of yearly capacity (MW) and energy (MWh) grid needs, along with corresponding hourly peak MW and energy profiles, are provided in the EOI. The NPV replacement or deferral value of the traditional wires solution is also included to provide guidance on the potential cost-competitiveness of NWA solutions.
Upon receiving sufficient interest to develop cost-competitive large-scale renewable projects or aggregating DER/EE projects in the identified locations to address the distribution grid need, we intend to issue targeted RFPs to procure the grid
need resources under the Framework for
Competitive Bidding.
11.2.6 Grid Services Competitive
Procurement
In addition to programs, there are opportunities
to acquire customer energy resources through
competitive procurements as we have done over
the past several years through grid service
purchase agreements.
We plan to continue to seek grid services through
contractual agreements. Based on the EE supply
curve analysis we believe that including energy efficiency as part of the grid services would help to complement existing EE programs, accelerate adoption of energy efficiency, allow for competitive market pricing, and target location-specific benefits.
11.2.6.1 Resilience and Microgrids
As discussed in Sections 7 and 10, resilience is an important part of the Integrated Grid Plan. We currently have in place a microgrid services tariff and a utility-owned and -operated microgrid, the Schofield Generation Station, in partnership with
the U.S. Army to support critical operations. We
are also seeking to develop a microgrid for the
North Kohala community through a competitive
procurement. In the case of North Kohala, the value of the microgrid includes the deferral of a second sub-transmission line (i.e., an NWA) to supply North Kohala whenever there is an outage on the sub-transmission line that feeds the community. We believe that enhancing the resilience of communities through competitive procurement of resilience services would
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substantially meet the objectives of Act 200 and the PUC’s microgrid services proceeding. We plan to apply the lessons learned of the North Kohala RFP and implementation to future procurements that would identify potential microgrid
opportunities that are aligned with our ETIPP,
equity, resilience system hardening program, and
Resilience Working Group efforts. A procurement
would also allow the market to determine the
value and compensation for resilience services,
provide flexibility to determine the performance and capabilities needed for each unique microgrid opportunity, the best way to integrate and use DER for resilience, determine the supply and demand for microgrids in Hawai‘i, and identify prospective developers of microgrids. Additional valuations of resilience consistent with methods currently contemplated by the industry as discussed in Section 7 may also be considered.
11.2.7 Revised Portfolio
Following the selection of programs and projects
in the Integrated Grid Plan procurements, near-
term generic resources identified in the preferred
resource plan to meet grid needs will be replaced by the actual procured resource. In the next cycle
of Integrated Grid Planning or as part of smaller updates, these resources will be assumed as planned additions and a starting point from which incremental grid needs can be identified.
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12 Securing Generation
Reliability and
Assessing Risks
We performed an in-depth generation reliability analysis to establish conditions and
pathways to deactivate, retire or, in some cases, accelerate retirement of fossil fuel–based
generators. This section further describes the risks and uncertainties and potential ways to
mitigate them.
In our discussions with customers, reliability remains of paramount importance as we navigate
the transition to 100% renewable energy. We
must provide reliable service through the
transition, especially as we modernize our
generation portfolio. To have an unreliable system
would undermine the trust we have with our
customers and prevent us from achieving our desired goals.
The existing generating fleet is becoming increasingly less reliable because of age and the way we now operate the grid. We need new, modern generators that can more easily adapt to the changing grid that will be dominated by solar, wind and energy storage resources. New, modern generators also come with higher reliability
compared to the existing fossil fuel–based generators.
Generation reliability is an area of concern in
Performance-Based Regulation and is intertwined
with State policy to retire fossil fuel–based generation as soon as practicable, and the risks associated with continuing to operate our aging generation fleet well past its original design life.
In the Performance-Based Regulation proceeding, the PUC issued Order 37969, identifying several
areas of concern, including grid reliability and
timely retirement of fossil fuel–based generation.
The PUC staff’s objectives in proposing
performance incentives in these areas are to ensure adequate planning and operations of grid
reliability, and accelerate integration of renewable resources ahead of retirement schedules.
In addition, through Order 32053, Ruling on RSWG Work Product, in Docket 2011-0206, the PUC made the following observations in ordering the development of Power Supply Improvement Plans, which are addressed in this section:
1. The impact each retirement, without replacement, would have on adequacy of power supply and reserve margins under
existing capacity planning criteria;
2. An analysis of how the capacity value of
solar, wind, energy storage and demand
response resources will be factored into the determination of the adequacy of power supply;
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3. An analysis of feasibility of utilizing existing power plant sites to locate new, quick-start, fuel-efficient, flexible generation, to leverage existing site transmission and fuel supply infrastructure
capacity that would be freed-up by
retirements of existing generating units
(Order No. 32053 at 92-93)
Moreover, the 2020 management audit conducted
by the PUC noted our current generating fleet
operating risk. The auditor states that “despite best efforts, the risk of failures in parts of the plants—including catastrophic failures—will continue to increase … in our estimation this is an important risk that should not be disregarded and contingency plans should be developed.” (Hawaiian Electric Management Audit Final Report at 168).
In the following section we use data and analysis
to address these issues and offer a path forward
to mitigate these risks.
12.1 Deactivation of Fossil
Fuel–Based Generators
For the purposes of identifying grid needs our analysis assumed that certain amounts of firm fossil fuel–based generating capacity would be removed from operations. The actual deactivation or retirement of generation from service is conditioned upon several factors, including whether sufficient resources have been acquired and placed into service to provide replacement grid services, underwent a proving period to
ensure reliable and stable operation, among other
considerations, such as overall system reliability
and resilience.
The planned removal-from-service schedules for
O‘ahu, Hawai‘i Island and Maui are provided
below in Table 12-1. These schedules represent initial assumptions made on the timing for the removal of utility-owned, fossil fuel–based generating units based primarily on age or environmental regulations.
Retirement decisions are permanent and irreversible, and in some cases, as described below, are forced by environmental compliance or our ability to obtain spare parts to continue
operations of the generator.
Table 12-1. Planned Removal-from-Service Assumptions for O‘ahu, Hawai‘i Island and Maui
Year O‘ahu Hawai‘i Island Maui
2024 Waiau 3–4 removed from service
2025 Puna Steam on standby
2027 Waiau 5–6 removed from service Hill 5–6 removed from service Kahului 1–4, Māʻalaea 10–13 removed from service
2029 Waiau 7–8 removed from service
2030 Māʻalaea 1–3, 4–9 removed from service
2033 Kahe 1–2 removed from service
2037 Kahe 3–4 removed from service 2046 Kahe 5–6 removed from service
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Deactivation is a state where there is no present intention to run the unit, but it is available for reactivation in an emergency. The unit is laid up and preserved and can be reactivated in a number of months if needed.
Standby status is a similar state to deactivation
where there is no present intention to run the
unit, but it could be activated and used in an
emergency.
The Hill 5 and 6 and Kahului 1–4 generators are slated for retirement in their designated years to comply with the State Implementation Plan associated with the U.S. Environmental Protection Agency’s Regional Haze Rule. Likewise, the Puna Steam unit will switch to a cleaner fuel and likely be placed in standby status for the same reasons. Standby status for Puna Steam will improve the resilience of the Hawai‘i Island system. In May 2018, as a result of the loss of PGV
from the Kilauea lava eruption, Puna Steam was
brought back from standby status, which was
critical to meet customer power demands.
Māʻalaea generating unit 7 will be required to
install emission reduction technology by the end of 2027. In the future, other units may be subject to further operational limitations, emission controls or forced retirements to meet environmental compliance needs.
Māʻalaea generators 10–13 have limited life remaining because the engine manufacturer has declared the engines obsolete and notified Hawaiian Electric that spare parts may no longer be available in the future. Because these are
unique engines, aftermarket parts supply is not
reliable. At this time we have secured parts to
allow for the units to continue to operate for the
next few years. At the same time, the Hawaiʻi
Department of Health has identified the need for
emission reductions for these units for the U.S. Environmental Protection Agency’s Regional Haze rule. Such emission reduction systems would require significant investments in obsolete units as previously described. Therefore, we will be required to retire the units between 2029 and 2035 (one in 2029, one in 2030 and two in 2035). However, because of the obsolescence
issue, we believe that the units would reach end of life between 2027 and 2029. Our plans include
ensuring that new resources are brought online
prior to these generating units reaching end of
life. However, given the age of our generating
fleet, it is possible that other generating units may be unexpectedly subject to parts obsolescence in the future.
Figure 12-1 through Figure 12-4 illustrate the age of the current Hawaiian Electric–owned generating fleet, which has served customers well over the past 70 years.
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Figure 12-1. Oʻahu: size and age of utility-owned generating units
Figure 12-2. Hawaiʻi Island: size and age of utility-owned generating units
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Figure 12-3. Maui: size and age of utility-owned generating units
Figure 12-4. Molokaʻi and Lānaʻi: size and age of utility-owned generating units
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By necessity, we operate the existing fossil fuel–based generation fleet at lower minimum loads and cycling units more than they were designed to do. As more renewable projects are integrated over the next few years, generating units,
especially steam generation units, will be under
increasingly variable operations. Operating the
50- to 75-year-old O‘ahu fleet, for example, with
increased load ramping, low‑load operation and
offline cycling accelerates the aging process, which has led to and will continue to cause increasing rates of forced outages and/or derations of firm capacity on a daily basis, as shown in Figure 12-5. These reliability risks must
be urgently addressed—this is foundational to
achieving the State’s decarbonization and
renewable energy goals.
Figure 12-5. Weighted equivalent forced outage rates for Oʻahu, Hawaiʻi Island and Maui County
Major repairs and maintenance are expected on steam units for the reasons described above. Types of repairs include replacement of major turbine components, boiler tubes sections, major valves, major pumps and other critical
components. Likewise, increased maintenance on
valves, boiler refractory, ducts, fans, feed pumps
and other components operating at the edge of
their design curves will result in significant
increases in operation and maintenance expenses.
To address these acute risks, our resource adequacy analysis identifies pathways to
retirement or deactivation of our existing generation fleet as assumed, above, as well as ways to potentially accelerate the retirement or deactivation of our older fossil fuel–based generating units.
In the resource adequacy analysis for Hawaiʻi
Island, we used long-term forced outage rates
that may not wholly reflect the upward trend in
outages observed in the last few years in Figure 12-5. The Hawaiʻi Island analysis may need to be revised in future analyses to reflect recent events
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including significant outages at HEP that has prompted calls for conservation.
12.2 Growth in Electric
Vehicles
Several drivers for near–term growth of EV adoption also pose risks to ensuring sufficient adequacy of supply. Commitments by car rental companies and vehicle manufacturers will increase the availability and diversity of electric vehicles while County and State commitments will increase the coverage of the EV charging network. These
commitments will encourage customers to adopt
electric vehicles and as electric vehicles become
more prevalent, electric demand will increase as
these cars will need to be charged from the grid.
Several trends in EV adoption today already underscore the importance of proactive planning for electric vehicles:
■ Standard & Poor’s estimates that global EV sales grew by about 36% in 202249
■ Hawaiʻi State Energy Office data show 26% year-over-year growth in new EV/plug-in hybrid registrations in Hawaiʻi for 202250
Commitments made by car rental companies and vehicle manufacturers as well as County and State governments will impact near-term EV adoption.
49 https://www.spglobal.com/commodityinsights/en/market-
insights/blogs/metals/013123-ev-sales-momentum-to-face-challenges-in-2023-but-long-term-expectations-unaffected
50 https://energy.hawaii.gov/energy-data/
51 https://www.civilbeat.org/2023/02/honolulus-new-airport-rental-
center-has-lots-of-electric-cars-but-only-one-charging-station/
■ Avis has plans to implement EV charging stations across all Hawaiʻi airports51
■ Hertz aims to convert 25% of its fleet to electric by the end of 202452
■ General Motors, Ford and Stellantis pledged
50% of new EV sales by 203053
■ The Hawaiʻi Department of Transportation
has committed to deploy EV charging
infrastructure and electrify its light-duty
fleet54
■ The City and County of Honolulu is converting its vehicle and bus fleet to all electric by 203555
It’s not a matter of if, but when EV adoption accelerates. Given the development time for renewable projects or firm generation, we must have sufficient capacity several years before it’s needed. The load growth from accelerated EV
adoption could happen quickly; for example, a
State or federal policy could quickly ramp up EV
adoption like the customer-sited solar boom
under net energy metering in the 2010s. Because
of this risk, Section 12.3 examines the High Load
forecast, which incorporates the High EV load layer where aggressive policies are put into place to decarbonize light-duty vehicles and eBuses in the transportation sector.
52 https://www.thedetroitbureau.com/2023/01/rental-car-giant-
enterprise-backs-equitable-ev-charging-infrastructure-expansion/
53 https://www.protocol.com/climate/electric-vehicle-automaker-goals
54 https://hidot.hawaii.gov/blog/2021/04/14/first-electric-vehicles-picked-up-through-the-statewide-multi-agency-service-contract-
arrive/
55 https://www.resilientoahu.org/transportation
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12.3 Generation Reliability Risk Assessment
Based on our experience, acute risks and uncertainties come with large-scale development of both solar and wind generation. We developed reliability curves that provide insight into how reliability may change if the optimal plans (as described in Section 8) are not realized or experience delays. Risks are particularly important to understand as the execution of project development has encountered significant challenges over the past several years and the degrading reliability of our existing generation system.
12.3.1 Oʻahu
Uncertainty in forecasted electricity demand is a large source of risk for Oʻahu. Section 8.2.2 shows how the planned Oʻahu system meets reliability targets in 2030 and 2035 but requires additional resources in a High Load scenario. This section shows how adding or removing resources from the Oʻahu system affects reliability metrics. Shown below in Table 12-2 and Table 12-3 is a summary of the resource adequacy results for different scenarios of future firm and variable plans. Further detailed discussion is presented in the subsequent sections.
Table 12-2. Probabilistic Analysis: Results Summary, Oʻahu 2030
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/Year)
LOLEv (Event/Year)
LOLH (Hours/ Year)
EUE (MWh/Year)
EUE (%)
Base 1,173 300 450 164 1,145 167 0.00 0.00 0.00 0.00 0.000 Land-Constrained 1,173 300 450 0 0 54 0.00 0.00 0.01 0.00 0.000
Hybrid Solar Reliability Impacts
180 MW hybrid solar 1,173 0 180 0 0 167 13.58 24.47 72.44 9.74 0.140
450 MW hybrid solar 1,173 0 450 0 0 167 5.12 9.72 20.51 3.02 0.044
700 MW hybrid solar 1,173 0 450 0 250 167 1.73 3.32 6.43 0.95 0.014 958 MW hybrid solar 1,173 0 450 0 508 167 0.48 0.96 1.86 0.27 0.004
1,595 MW hybrid solar 1,173 0 450 0 1,145 167 0.02 0.07 0.10 0.02 0.000
Firm Generation Reliability Impacts
0 MW firm 1,173 0 450 0 0 167 5.12 9.72 20.51 3.02 0.044
100 MW firm 1,173 100 450 0 0 167 0.61 1.11 1.92 0.23 0.003
150 MW firm 1,173 150 450 0 0 167 0.16 0.22 0.35 0.03 0.000
200 MW firm 1,173 200 450 0 0 167 0.02 0.04 0.09 0.01 0.000 300 MW firm 1,173 300 450 0 0 167 0.00 0.00 0.00 0.00 0.000
Fossil Fuel Retirement Risk Assessment
Base, deactivation of 600 MW of firm gen. 567 300 450 164 1,145 167 0.04 0.08 0.22 0.04 0.001
Land-Constrained, deactivation of 170 MW of firm gen.
1,008 300 450 0 0 54 0.06 0.11 0.20 0.02 0.000
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Table 12-3. Probabilistic Analysis: Results Summary, Oʻahu 2035
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base 800 508 450 564 1,145 167 0.00 0.00 0.00 0.00 0.000
Land-Constrained 800 508 450 430 0 194 0.00 0.01 0.01 0.00 0.000
Base, high load 800 508 450 564 1,145 167 0.00 0.00 0.00 0.00 0.000
Land-Constrained, high load 800 508 450 430 0 194 0.65 1.42 3.28 0.60 0.007
Hybrid Solar Reliability Impacts
450 MW hybrid solar, high load 800 508 450 0 0 167 3.43 6.97 16.86 3.21 0.035
700 MW hybrid solar, high load 800 508 450 0 250 167 1.96 4.02 9.47 1.71 0.019
958 MW hybrid solar, high load 800 508 450 0 508 167 0.45 0.94 2.26 0.45 0.005
1,595 MW hybrid solar, high load 800 508 450 0 1,145 167 0.15 0.28 0.65 0.16 0.002
Firm Generation Reliability Impacts
508 MW firm, high load 800 508 450 0 0 167 3.43 6.97 16.86 3.21 0.035
558 MW firm, high load 800 558 450 0 0 167 1.72 3.46 8.30 1.46 0.016
658 MW firm, high load 800 658 450 0 0 167 0.37 0.83 1.66 0.25 0.003
808 MW firm, high load 800 808 450 0 0 167 0.00 0.01 0.01 0.00 0.000
Fossil Fuel Retirement Risk Assessment
Base, deactivation of 440 MW of firm gen. 359 508 450 564 1,145 167 0.01 0.03 0.04 0.00 0.000
Base, 300 MW new firm gen., deactivation of 170 MW of firm gen.
628 300 450 564 1,145 167 0.01 0.02 0.04 0.01 0.000
Base, 300 MW new firm gen., deactivation of 440 MW of firm gen.
359 300 450 564 1,145 167 0.72 1.60 3.11 0.52 0.007
Land-Constrained, deactivation of 170 MW of firm gen.
628 508 450 430 0 194 0.01 0.04 0.06 0.01 0.000
Land-Constrained, deactivation of 440 MW of firm gen.
359 508 450 430 0 194 0.44 0.95 2.29 0.37 0.005
Land-Constrained, 300 MW new firm gen., reactivation of 170 MW of firm gen.
965 300 450 430 0 194 0.05 0.10 0.21 0.04 0.001
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12.3.1.1 Hybrid Solar Reliability Impacts
As described earlier, if Oʻahu obtains 450 MW of hybrid solar and 300 MW of firm generation by 2030 through the Stage 3 procurement, the system should meet the loss of load expectation target of 0.1 day per year. However, if we do not obtain any new firm generation, the system may not meet the loss of load expectation target depending on how much variable renewable generation is procured and placed into service.
To determine the sensitivity of the loss of load expectation based on the amount of variable renewable
generation added in 2030 assuming the Base Load, we removed any new firm generation that we plan to
acquire through the Stage 3 procurement and varied the amount of future hybrid solar added in 2030.
As shown in Figure 12-6, in 2030, without any new firm generation, nearly 1,600 MW of hybrid solar is
needed to meet the 0.1 day/year target. Shown below is the relationship between the loss of load
expectation and future hybrid solar added in 2030. Figure 12-6 shows that as we incrementally add more
future hybrid solar in 2030, its contribution toward reliability improvements greatly diminishes (particularly after 600 MW of hybrid solar is integrated onto the system), highlighting the need for a diverse resource portfolio. We expect similar results if we replace large-scale solar with distributed, customer-sited hybrid solar.
Importantly, this chart demonstrates the sensitivity of reliability that O‘ahu has to small changes in capacity. For example, 200 MW of hybrid solar results in a significant swing (approximately 8.7 days per year) in reliability. We consider this point a significant consideration in how we plan and procure resources to meet our customers’ reliability expectations.
Figure 12-6. Oʻahu: relationship
between change in loss of load
and change in future paired PV
hybrid solar capacity (Base Load, 2030)
In Figure 12-7 below we present the unserved energy based on the month and hour of our existing system
in 2021 (left) and the scenario where we do not add any new firm generation but obtain 450 MW of hybrid
solar (right). With only the 450 MW hybrid solar resource (as targeted in Stage 3 procurement), we may
experience significant unserved energy during the morning and evening hours because of the weather-
dependent, energy-limited nature of wind, solar and energy storage.
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Figure 12-7. Oʻahu: 2021 existing system (left); no new firm, add 450 MW hybrid solar, Base Load, 2030 (right)
We performed the same analysis for 2035. Unlike the 2030 hybrid solar sensitivity, which assumed the Base
Load, this 2035 sensitivity assumed the High Load. With future uncertainties in EV adoption, we wanted to understand the reliability risks associated with load growth due to electrification of transportation.
In this sensitivity, we assume that we successfully acquire the 450 MW of hybrid solar and 300 MW in 2029 and 200 MW in 2032 of firm generation from the Stage 3 procurement. Additional hybrid solar was then added to determine its impact on reliability in 2035. Shown in Figure 12-8, below, is the relationship between the loss of load expectation and incremental additions of hybrid solar in 2035. Similar to 2030, the figure shows that as we add more hybrid solar in 2035, its contribution toward reliability improvements quickly diminishes. It is important to note that, even with resources procured through the Stage 3 procurement and an additional 1,145 MW of hybrid solar, the system may not meet the 0.1 day/year target under the High Load. Based on the relationship shown below, we would need approximately 1,225 MW of hybrid solar in addition to the Stage 3 procurement.
Figure 12-8. Oʻahu; relationship between change in loss of load and change in future hybrid solar
capacity (High Load, 2035)
In Figure 12-9, we present the unserved energy based on the month and hour of the scenario with and
without the additional 1,150 MW of hybrid solar and 500 MW of firm generation. As shown in the image on
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the right, under the High Load, even with 500 MW of new firm resources and nearly 1,600 MW of hybrid solar, we may still experience unserved energy.
Figure 12-9. Oʻahu: add 508 MW firm, add 450 MW hybrid solar, High Load, 2035 (left); add 508 MW firm, add 1,600 MW hybrid solar, High Load, 2035 (right)
12.3.1.2 Firm Generation Reliability Impacts
We performed an analysis to determine how reliability of the system changes based on the procurement or addition of firm generation. We assume the 450 MW of hybrid solar sought in the Stage 3 procurement and incremented firm generation to determine the impacts to reliability.
As shown in Figure 12-10, in 2030, assuming the Base Load, we may need approximately 200 MW of new firm generation to meet the 0.1 day/year loss of load expectation target. Shown below is the relationship between the 2030 loss of load expectation and varying amounts of firm generation. The figure shows that as more firm generation is added in 2030, the reliability improvements decrease; however, in contrast, significantly less capacity of firm generation is needed to improve reliability by the same measure compared to hybrid solar.
Figure 12-10. Oʻahu: relationship between change in loss of load and change in future firm
renewable capacity (Base Load,
2030)
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In Figure 12-11 below we present the unserved energy based on the month and hour of the scenario where we do not have new firm generation but have the 450 MW of hybrid solar sought in Stage 3 (left), and the scenario where we add 150 MW of new firm generation along with 450 MW of hybrid solar (right). As shown, the addition of 150 MW of firm generation may help significantly reduce the amount of unserved energy, though we still expect unserved energy during the morning and evening hours.
Figure 12-11. Oʻahu: no new firm, add 450 MW hybrid solar, Base Load, 2030 (left); add 150 MW firm, add 450 MW hybrid solar, Base Load, 2030 (right)
We also performed analysis to determine how reliability changes based on the procurement of additional
firm generation above the 508 MW targeted in the Stage 3 procurement. Similar to the 2035 hybrid solar
sensitivity performed, this 2035 firm generation sensitivity assumed the High Load to ensure that the
Integrated Grid Plan is capable of reliably serving load growth from accelerated adoption of electric vehicles. Similar to the 2035 analysis on hybrid solar, we assume that 450 MW of hybrid solar, and 500 MW of firm generation sought through the Stage 3 procurement are in service.
Shown below in Figure 12-12 is the relationship between the loss of load expectation and increments of new firm generation in 2035. Based on the results, we would need close to 200 MW of additional firm generation above the 500 MW of firm generation sought in the Stage 3 procurement to meet the 0.1 day/year target under High Load. We also observe the outsized impact the addition (or forced outage) that 100 MW of firm generation can have on reliability, with a change of approximately 4.6 days per year of loss of load.
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Figure 12-12. Oʻahu: relationship between change in loss of load and change in future firm capacity (High Load, 2035)
In Figure 12-13 below we present the unserved energy based on the month and hour of the scenario with and without an additional 150 MW of firm generation. As shown in the image on the right, under the High Load, we may still experience unserved energy even with 658 MW of new firm generation.
Figure 12-13. Oʻahu: add 508 MW firm, add 450 MW hybrid solar, High Load, 2035 (left); add 658 MW firm, add 450
MW hybrid solar, High Load, 2035 (right)
12.3.1.3 Fossil Fuel Retirement Risk Assessment
Given that both the Base and Land-Constrained scenario meet the loss of load expectation target in 2030, we completed analyses to determine whether we could deactivate additional fossil fuel–based generators while maintaining reliability. As shown in Table 12-4, with the Base Load and under the right system conditions, an additional 600 MW of existing fossil-fuel firm generation could be deactivated and still meet the 0.1 day/year loss of load expectation target. In the Land-Constrained scenario, we may be able to deactivate an additional 170 MW of existing fossil-fuel firm generation.
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Table 12-4. Probabilistic Analysis: Results Summary, Oʻahu, Base Load, 2030, Retirement Sensitivity
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base 1,173 300 450 164 1,145 167 0.00 0.00 0.00 0.00 0.000
Deactivation of 600 MW of firm gen. 567 300 450 164 1,145 167 0.04 0.08 0.22 0.04 0.001
Land-Constrained 1,173 300 450 0 0 54 0.00 0.00 0.01 0.00 0.000
Deactivation of 170 MW of firm gen. 1,008 300 450 0 0 54 0.06 0.11 0.20 0.02 0.000
Given that both the Base and Land-Constrained scenarios meet the loss of load expectation target in 2035, we completed analyses to determine whether we could deactivate additional generators while maintaining reliability. Table 12-5 focuses on the Base scenario. If we acquire 500 MW of new firm generation, 1,600 MW of hybrid solar along with 400 MW of offshore wind and 164 MW onshore wind, we may be able to deactivate an additional 440 MW of additional fossil-fuel firm generation. If we acquire only 300 MW of new firm generation
from the Stage 3 procurement, an additional 170 MW of fossil-fuel firm generation could be deactivated.
Table 12-5. Probabilistic Analysis: Results Summary, Oʻahu, Base Load, 2035, Retirement Sensitivity, Base Scenario
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base (incl. 400 MW offshore wind) 800 508 450 564 1,145 167 0.00 0.00 0.00 0.00 0.000
Deactivation of 440 MW firm gen. 359 508 450 564 1,145 167 0.01 0.03 0.04 0.00 0.000
Base (300 MW new firm gen.) 800 300 450 564 1,145 167 0.01 0.02 0.07 0.01 0.000
Deactivation of 170 MW firm gen. 628 300 450 564 1,145 167 0.01 0.02 0.04 0.01 0.000
Deactivation of 440 MW firm gen. 359 300 450 564 1,145 167 0.72 1.60 3.11 0.52 0.007
Table 12-6 focuses on the Land-Constrained scenario. If we acquire 500 MW of new firm generation, 450
MW of hybrid solar along with 400 MW of offshore wind and 30 MW onshore wind, we may be able to
deactivate an additional 170 MW of fossil fuel firm generation. If, however, we acquired only 300 MW of new
firm generation through the Stage 3 procurement, we may need to reactivate an additional 170 MW of fossil
fuel firm generation to meet our reliability target.
Table 12-6. Probabilistic Analysis: Results Summary, Oʻahu, Base Load, 2035, Retirement Sensitivity, Land-Constrained Scenario
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Land-Constrained (incl. 400 MW offshore wind)
800 508 450 430 0 194 0.00 0.01 0.01 0.00 0.000
Deactivation of 170 MW firm gen. 628 508 450 430 0 194 0.01 0.04 0.06 0.01 0.000
Deactivation of 440MW Firm Gen. 359 508 450 430 0 194 0.44 0.95 2.29 0.37 0.005
Land-Constrained (300 MW new firm gen.) 800 300 450 430 0 194 0.22 0.40 0.86 0.12 0.002
Reactivation of 170 MW existing firm gen. 965 300 450 430 0 194 0.05 0.10 0.21 0.04 0.001
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12.3.1.4 3-Day Energy Profile, High Unserved Energy Day
The reliability analyses are the average of the 250 simulation samples. Even though the loss of load expectation meets or exceeds 0.1 day per year, individual samples of weather and firm generation outage combinations may produce significant unserved energy. We show in Figure 12-14 a sample with significant unserved energy, even with 1,600 MW of future hybrid solar (this includes 450 MW acquired through the Stage 3 procurement along with the 1,145 MW of hybrid solar selected by RESOLVE).
Figure 12-14. Oʻahu: detailed
energy profile, 2030 high
unserved energy load day; Base
scenario, Base Load, no new firm, add 1,600 MW hybrid solar
Figure 12-15 shows another sample with significant unserved energy in the Land-Constrained scenario with 300 MW of new firm generation and the reactivation of 170 MW of firm generation.
Figure 12-15. Oʻahu: detailed energy profile, 2035 high unserved energy load day; Land-Constrained scenario, Base Load, add 300 MW firm, add 450 MW hybrid solar, add 400 MW offshore wind, add 170 MW existing firm
In both figures, we see the important role that a resource with the attributes like a firm generator play in the
reliability of the system. The significant duration and magnitude of the unserved energy on the system demonstrates the need for a resource with attributes similar to a firm generator.
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12.3.2 Hawaiʻi Island
Uncertainty in forecasted electricity demand is a large source of risk for Hawaiʻi Island. Section 8.3.2 shows how the planned Hawaiʻi Island system meets reliability targets in 2030 and 2035 but requires additional resources in a High Load scenario. This section analyzes how adding or removing resources from the Hawaiʻi Island system affects reliability metrics. Shown below in Table 12-7 and Table 12-8 is a summary of the resource adequacy results for different scenarios of future firm and variable plans. Further detailed discussion is presented in the subsequent sections. Volcanic activity is an environmental risk unique to Hawaiʻi Island. Volcanic ash can reduce the effectiveness of solar resources and lava flows can also impact resources in their path.
Table 12-7. Probabilistic Analysis: Results Summary, Hawaiʻi Island 2030
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base, no Stage 3 228 0 0 48 0 7 0.000 0.000 0.000 0.000 0.000
Base, (no HEP) 170 0 140 48 0 7 0.004 0.004 0.012 0.000 0.000
Hybrid Solar Reliability Impacts Base, no Stage 3 (no HEP)
170 0 0 48 0 7 0.092 0.132 0.264 0.003 0.000
60 MW hybrid solar, (no HEP) 170 0 60 48 0 7 0.008 0.008 0.016 0.000 0.000
Firm Generation Reliability Impacts
Remove 130 MW firm 97 0 140 48 0 7 4.49 9.56 19.2 0.390 0.037
Remove 100 MW firm 124 0 140 48 0 7 0.176 0.280 0.484 0.005 0.001
Remove 90 MW firm 143 0 140 48 0 7 0.024 0.032 0.072 0.001 0.000
Table 12-8. Probabilistic Analysis: Results Summary, Hawaiʻi Island 2035
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base 228 0 140 48 3 7 0.000 0.000 0.000 0.000 0.000
Base, no future RE 228 0 140 0 0 0 0.008 0.024 0.032 0.000 0.000
Base, high load 228 0 140 48 3 7 5.18 10.5 19.8 0.475 0.030
Base high load, no future RE
228 0 140 0 0 0 28.9 64.2 149 4.70 0.454
Hybrid Solar Reliability Impacts
200 MW hybrid solar, high load 228 0 140 0 200 0 3.18 7.75 14.2 0.384 0.037
420 MW hybrid solar, high load 228 0 140 0 420 0 0.176 0.312 0.548 0.008 0.001
600 MW hybrid solar, high load 228 0 140 0 600 0 0.012 0.024 0.064 0.001 0.000
Firm Generation Reliability Impacts
20 MW firm, high load 228 24 140 0 0 0/0 3.34 7.14 13.5 0.358 0.035
50 MW firm, high load 228 49 140 0 0 0/0 0.080 0.116 0.248 0.007 0.001
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12.3.2.1 Hybrid Solar Reliability Impacts
As described earlier, the Base scenario meets or exceeds the reliability target. Therefore, for the purposes of assessing the reliability risks of the Hawaiʻi Island system, the scenarios shown below assume the 2030 Base scenario and the removal of the HEP plant, whose PPA is set to expire at the end of 2030.
■ Even without the full Stage 3 procurement target of 140 MW of hybrid solar, the 2030 system’s loss of load expectation is less than 0.1 day per year.
If a system has a high loss of load expectation, even small amounts of added resources can dramatically
improve the system’s loss of load expectation. However, continually adding resources has diminishing
returns. The planned Base 2030 system already has a low loss of load expectation so additional resources
would have a minimal benefit to the system’s loss of load expectation. Though adding resources to an
already stable system may not impact loss of load expectation as much, the resources still act as a safety net
should other resources be unexpectedly brought offline (e.g., the 2018 Kilauea eruption that forced PGV out
of service for an extended period or recent extended outages experienced on Hawai‘i Island).
Once loss of load expectation exceeds 0.1 day per year it rises quickly if more resources are brought offline. Though the effects are not as dramatic as when removing comparable amounts of firm resources, there should be caution when removing resources because they have a growing impact on the system’s loss of load expectation as more resources are retired.
Figure 12-16 shows the relationship between change in loss of load and change in Stage 3 hybrid solar capacity for the Base Load scenario in 2030 on Hawaiʻi Island.
Figure 12-16. Hawaiʻi Island:
relationship between change in
loss of load and change in Stage 3 paired PV hybrid solar capacity (Base Load, 2030)
The heat map shown in Figure 12-17 below illustrates when we expect unserved energy to occur and at what quantities for the scenario shown in Figure 12-16 with a loss of load expectation around 0.1 day per year (Base scenario, remove 60 MW firm generation, add 0 MW hybrid solar). The quantities shown are an average of all 250 samples. When the PGV plant is offline for maintenance, we see much of the unserved energy occurring in March during the evening peak and early morning hours.
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Figure 12-17. Hawaiʻi Island: remove 60 MW firm, add 0 MW hybrid solar heat map (Base Load, 2030)
We performed the same analysis for 2035. Unlike the 2030 hybrid solar sensitivity, which assumed the Base Load, the 2035 sensitivity assumed the High Load. With future uncertainties in EV adoption, we wanted to understand the reliability risks associated with load growth due to electrification of transportation.
The 140 MW of hybrid solar from Stage 3 was assumed to be in service.
■ With the High Load, if no new resources are added, the loss of load expectation is above 28 days per
year.
We also observe that small changes in hybrid solar capacity can significantly change the reliability of the
system, though there are diminishing returns. For example, just 50 MW of hybrid solar at lower penetrations
reduces loss of load expectation by approximately 17 days per year and at higher penetrations 1 day per
year. The planned High Load 2035 system has a high loss of load expectation so if a project selected through a competitive procurement fails to reach commercial operations or an unexpected outage of the solar plant takes place, significant adverse impacts to reliability are expected in a High Load scenario. This trend is also evident in the firm resource reliability curves. Figure 12-18 shows the relationship between change in loss of load and change in future hybrid solar capacity on Hawaiʻi Island for the High Load scenario in 2035.
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Figure 12-18. Hawaiʻi Island: relationship between change in loss of load and change in future hybrid solar capacity (High Load, 2035)
The heat map in Figure 12-19 shows when we expect unserved energy to occur and at what quantities for
the scenario shown in Figure 12-18 above with a loss of load expectation around 0.1 day per year (High Load, no new firm generation, and 420 MW of hybrid solar). The quantities shown are an average of all 250 samples. With fewer firm resources, unserved energy is expected during the early morning hours when firm resources are down for maintenance and during bad solar condition months like December.
Figure 12-19. Hawaiʻi Island: add 0 MW firm, add 420 MW hybrid solar; EUE heat map (High Load, 2035)
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12.3.2.2 Firm Generation Reliability Impacts
For the purposes of assessing the reliability risks of the Hawaiʻi Island system, the scenarios shown below assume the 2030 Base Load and the incremental removal of existing firm resources, including the HEP plant, whose PPA is set to expire at the end of 2030, as well as PGV and utility-owned thermal generating units. Additional existing firm generators were removed to further decrement the total firm capacity on the system to show the reliability impact of firm generation. The 140 MW of hybrid solar from Stage 3 is assumed to be in service. In 2030, under the Base Load, a loss of load less than 0.1 day per year is expected even if HEP and some additional firm becomes unavailable.
We also observe that even small amounts of added resources can dramatically reduce the system’s reliability.
However, continually adding resources has diminishing returns on reliability improvements. Though adding
resources to an already stable system like the planned Base Load 2030 system may not impact loss of load
expectation as much, the resources still act as a safety net should other resources be unexpectedly brought
offline given the sensitivity the Hawaiʻi Island system has to changes in generation availability. Figure 12-20 shows the relationship between change in loss of load and change in cumulative firm capacity on Hawaiʻi Island for the Base Load in 2030.
Figure 12-20. Hawaiʻi Island: relationship between change in loss of load and change in cumulative firm capacity (Base Load, 2030)
The heat map in Figure 12-21 below shows when we expect unserved energy to occur and at what quantities for the scenario shown in Figure 12-20 above with a loss of load expectation around 0.1 day per year (High Load scenario, remove 100 MW firm generation, add 140 MW hybrid solar). The quantities shown are an average of all 250 samples. With fewer firm units online, unserved energy is expected to occur during the early morning hours when firm resources are down for maintenance and during poor solar condition months like December.
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Figure 12-21. Hawaiʻi Island: remove 100 MW firm, add 140 MW hybrid solar heat map, (Base Load, 2030)
Figure 12-22 assumes the 2035 High Load forecast and the planned resource retirements through 2035. The 140 MW of hybrid solar from Stage 3 is assumed to be in service.
■ In a High Load scenario, a loss of load expectation of 28 days per year is expected if no resources are
added to the system.
When comparing the firm capacity graphs with the hybrid solar capacity graphs in Section 12.3.2.1, it’s
notable that when applied to the same resource portfolio, firm resources have a much larger impact on
system reliability than a comparable amount of hybrid solar resources. The system is more sensitive to the
addition or removal of firm resources than of hybrid solar resources.
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Figure 12-22. Hawaiʻi Island; loss of load vs. future renewable firm capacity (High Load, 2035)
The heat map in Figure 12-23 shows when we expect unserved energy to occur and at what quantities for the scenario shown in Figure 12-22 above with a loss of load expectation around 0.1 day per year (High Load scenario, add 50 MW new firm generation, and no hybrid solar additions). The quantities shown are an average of all 250 samples. With fewer solar resources, unserved energy is expected to occur during the early morning and evening peak hours of hot weather, high load months like August.
Figure 12-23. Hawaiʻi Island: add 50 MW firm, add 0 MW hybrid solar; expected unserved energy heat map (High Load, 2035)
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12.3.2.3 3-Day Energy Profile, High Unserved Energy Day
The energy profiles shown in Figure 12-24 and Figure 12-25 show the day from all 250 samples with the greatest unserved energy for the hybrid solar and firm generation sensitivities with loss of load expectation of approximately 0.1 day per year. This shows that even though the reliability target is met, unserved energy may still occur. For both scenarios, loss of load starts around midnight and continues through the morning hours. The system recovers by midday.
Figure 12-24. Hawaiʻi Island:
detailed energy profile, 2030 high
unserved energy load day; Base
Load, remove 60 MW firm, add 0 MW hybrid solar heat map
Figure 12-25. Hawaiʻi Island: detailed energy profile, 2030 high unserved energy load day; Base Load, remove 100 MW firm, add 140 MW hybrid solar
The energy profiles shown in Figure 12-26 and Figure 12-27 show the day out of all 250 samples with the
greatest unserved energy for the hybrid solar and firm generation sensitivities in 2035 with loss of load
expectation of approximately 0.1 day per year.
When adding only hybrid solar to the system as shown in Figure 12-26, loss of load starts around midnight and continues through the morning hours. The system recovers by midday.
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When adding only firm generation resources to the system as shown in Figure 12-27, loss of load starts around midday and continues through the evening hours. The system recovers by midnight.
Figure 12-26. Hawaiʻi Island: detailed energy profile, 2035 high unserved energy load day; High Load, add 0 MW firm, add 420 MW hybrid solar
Figure 12-27. Hawaiʻi Island: detailed energy profile, 2035 high
unserved energy load day; High
Load, add 50 MW firm, add 0 MW hybrid solar
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12.3.3 Maui
Uncertainty in forecasted electricity demand is a large source of risk for Maui. Section 8.4.2 shows how the
planned Maui system meets reliability targets in 2030 and 2035 but requires additional resources in a High
Load scenario. This section shows how adding or removing resources from the Maui system affects reliability
metrics. Shown below in Table 12-9 and Table 12-10 is a summary of the resource adequacy results for
different scenarios of future firm and variable plans. Further detailed discussion is presented in the subsequent sections.
Table 12-9. Probabilistic Analysis: Results Summary, Maui 2030
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base 119 36 191 13 0 0 0.00 0.01 0.02 0.00 0.000
Hybrid Solar Reliability Impacts
20 MW hybrid solar 119 36 20 13 0 0 0.03 0.07 0.12 0.00 0.000 80 MW hybrid solar, high load 119 36 80 13 0 0 0.01 0.01 0.02 0.00 0.000
Firm Generation Reliability Impacts 0 MW firm 119 0 191 13 0 0 0.75 1.05 2.58 0.04 0.004
9 MW firm 119 9 191 13 0 0 0.18 0.31 0.66 0.01 0.001
18 MW firm 119 18 191 13 0 0 0.02 0.04 0.08 0.00 0.000
Table 12-10. Probabilistic Analysis: Results Summary, Maui 2035
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base, high load 119 40.7 191 66 37 0 3.47 6.43 13.56 0.32 0.030
Hybrid Solar Reliability Impacts
37 MW hybrid solar, high load 119 40.7 0 66 37 0 28.86 63.97 173.56 4.68 0.436
328 MW hybrid solar, high load 119 40.7 191 66 137 0 1.49 2.24 4.78 0.10 0.010
628 MW hybrid solar, high load 119 40.7 191 66 437 0 0.53 0.12 0.96 0.02 0.001
Firm Generation Reliability Impacts
24 MW firm, high load 119 24 191 66 37 0 9.25 22.90 58.28 1.90 0.177
57 MW firm, high load 119 57 191 66 37 0 0.52 0.73 1.38 0.03 0.002
73 MW firm, high load 119 73 191 66 37 0 0.11 0.06 0.15 0.00 0.000
81 MW firm, high load 119 81 191 66 37 0 0.02 0.00 0.02 0.00 0.000
12.3.3.1 Hybrid Solar Reliability Impacts
As described earlier, if Maui obtains 191 MW of hybrid solar and 40 MW of firm generation by 2030 through
the Stage 3 procurement, the system should meet the loss of load expectation target of 0.1 day per year.
However, if we do not obtain any new firm generation, the system may not meet the loss of load expectation
target depending on how much variable renewable generation is procured and placed into service.
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To determine the sensitivity of the loss of load expectation based on the amount of variable renewable generation added in 2030 assuming the Base Load, we included the installation of 36 MW of new firm generation that we plan to acquire through the Stage 3 procurement and varied the amount of future hybrid solar added in 2030. This is a different approach from the one taken for Oʻahu because a significant amount of thermal capacity was removed from service at Kahului and Māʻalaea Power Plant, more than half of the
existing firm thermal fleet for a combined 122 MW removed, and it was expected that the entire Stage 3
target for firm capacity would be needed as replacement.
As shown in Figure 12-28, in 2030, with the new firm generation, no additional hybrid solar is needed to
meet the 0.1 day/year target. Shown below is the relationship between the loss of load expectation and
future hybrid solar added in 2030. Figure 12-28 shows that as we incrementally add more future hybrid solar in 2030, its contribution toward reliability improvements greatly diminishes, partly because the starting resource portfolio before any hybrid solar is added already exceeds the reliability target.
Figure 12-28. Maui: relationship between change in loss of load and change in future hybrid solar capacity (Base Load, 2030)
In Figure 12-29 below we present the unserved energy based on the month and hour of the scenarios where we obtain 20 MW of hybrid solar (left) and 191 MW of hybrid solar (right). Because these scenarios included 36 MW of new firm generation from Stage 3, there is minimal unserved energy. However, the addition of 191 MW of hybrid solar benefits the system by reducing the times of day and months where unserved energy occurs.
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Figure 12-29. Maui: 20 MW Hybrid Solar, Base Load, 2030 (left); 191 MW Hybrid Solar, Base Load, 2030 (right)
We performed the same analysis for 2035. Unlike the 2030 hybrid solar sensitivity, which assumed the Base Load forecast, this 2035 sensitivity assumed the High Load forecast. With future uncertainties in EV adoption, we wanted to understand the reliability risks associated with load growth due to electrification of transportation.
In this sensitivity, we assume that we successfully acquire the 40 MW of firm generation from the Stage 3
procurement. Additional hybrid solar was then added to determine its impact on reliability in 2035. Shown in
Figure 12-30 below is the relationship between the loss of load expectation and incremental additions of
hybrid solar in 2035. Similar to 2030, the figure shows that as we add more hybrid solar in 2035, its
contribution toward reliability improvements quickly diminishes. It is important to note that, even with
resources procured through the Stage 3 procurement, the system may not meet the 0.1 day/year target under the High Load.
Figure 12-30. Maui: relationship between change in loss of load and change in future hybrid solar capacity (High Load, 2035)
In Figure 12-31, we present the unserved energy based on the month and hour of the scenario with up to
628 MW of hybrid solar and 40 MW of firm generation. As shown in the figure on the right, under the High
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Load, even with 40 MW of new firm resources and 628 MW of hybrid solar, we may still experience unserved energy.
Figure 12-31. Maui: 228 MW Hybrid Solar, High Load, 2035 (left); 628 MW Hybrid Solar, High Load, 2035 (right)
12.3.3.2 Firm Generation Reliability Impacts
We performed analysis to determine how reliability of the system changes based on the procurement or
addition of firm generation. We assume the 191 MW of hybrid solar sought in the Stage 3 procurement and
incremented firm generation to determine the impacts to reliability.
As shown in Figure 12-32, in 2030, assuming the Base Load, we may need approximately 18 MW of new firm
generation to meet the 0.1 day/year loss of load expectation target. Shown below is the relationship
between the 2030 loss of load expectation and varying amounts of firm generation. The figure shows that as more firm generation is added in 2030, the reliability improvements decrease; however, in contrast,
significantly less capacity of firm generation is needed to improve reliability by the same measure compared to hybrid solar.
Figure 12-32. Maui: relationship between change in loss of load and change in future firm capacity (Base Load, 2030)
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In Figure 12-33 below we present the unserved energy based on the month and hour of the scenario where we do not have new firm generation but have the 191 MW of hybrid solar sought in Stage 3 (left), and the scenario where we add 18 MW of new firm generation along with 191 MW of hybrid solar (right). As shown, the addition of 18 MW of firm generation may help significantly reduce the amount of unserved energy, though we still expect unserved energy during the morning and evening hours.
Figure 12-33. Maui: 0 MW Firm, Base Load, 2030 (left); 18 MW Firm, Base Load, 2030 (right)
We also performed analysis to determine how reliability changes based on the procurement of additional
firm generation above the 40 MW targeted in the Stage 3 procurement. Similar to the 2035 hybrid solar
sensitivity performed, this 2035 firm generation sensitivity assumed the High Load to ensure that the Integrated Grid Plan is capable of reliably serving load growth from accelerated adoption of electric vehicles.
Shown below in Figure 12-34 is the relationship between the loss of load expectation and increments of new firm generation in 2035. Based on the results, we would need close to 73 MW of new firm generation to meet the 0.1 day/year target under High Load.
Figure 12-34. Maui: relationship between change in loss of load and change in future firm capacity (High Load, 2035)
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In Figure 12-35 below we present the unserved energy based on the month and hour of the scenario with and without an additional 40 MW of firm generation. As shown in the figure on the right, under the High Load, we may still experience unserved energy even with 81 MW of new firm generation.
Figure 12-35. Maui: 40 MW Firm, High Load, 2035 (left); 81 MW Firm, High Load, 2035 (right)
12.3.3.3 3-Day Energy Profile, High Unserved Energy Day
Figure 12-36 shows that even in the Base scenario where 0.1 day/year reliability is met, unserved energy may still occur. The overall trend shows that the existing thermal units ramp up in the evening and ramp down in the morning following the solar resources.
Figure 12-36. Maui: detailed
energy profile, 2030 high
unserved energy load day; Base Load
Figure 12-37 shows how in the Base scenario with the High Load forecast, reliability is not met even with new resources being added. High amounts of unserved energy in the evening and morning hours still occur.
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Figure 12-37. Maui: detailed energy profile, 2035 high unserved energy load day; High Load
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12.3.4 Molokaʻi
Uncertainty in forecasted electricity demand is a large source of risk for Molokaʻi. Section 8.5.2 shows how the planned Molokaʻi system meets reliability targets in 2030 and 2035. This section shows how adding or removing resources from the Molokaʻi system affects reliability metrics. Shown below in Table 12-11 and Table 12-12 is a summary of the resource adequacy results for different scenarios of future firm and variable plans. Further detailed discussion is presented in the subsequent sections.
Table 12-11. Probabilistic Analysis: Results Summary, Moloka‘i 2030
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base 15.18 0 0 0 11.5 0.5 0 0 0 0 0%
Hybrid Solar Reliability Impacts
0 MW hybrid solar 4.4 0 0 0 0 0 19.244 42.32 198.66 0.28 0.9%
3 MW hybrid solar 4.4 0 0 0 3 0 9.092 22.29 44.78 0.07 0.2%
6 MW hybrid solar 4.4 0 0 0 6 0 1.436 3.09 6.90 0.01 0.0%
9 MW hybrid solar 4.4 0 0 0 9 0 0.436 0.87 1.92 0.00 0.0%
12 MW hybrid solar 4.4 0 0 0 12 0 0.164 0.30 0.71 0.00 0.0%
Firm Generation Reliability Impacts 2.2 MW firm 0 2.2 0 0 6 0 61.712 137.49 336.81 0.54 1.8%
4.4 MW firm 0 4.4 0 0 6 0 1.436 3.09 6.90 0.01 0.0%
6.6 MW firm 0 6.6 0 0 6 0 0.052 0.10 0.13 0.00 0.0%
Table 12-12. Probabilistic Analysis: Results Summary, Moloka‘i 2035
Scenario Existing Firm (MW)
New Firm (MW)
Stage 3 Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base 15.18 0 0 0 0.0 0 0 0 0 0 0%
Hybrid Solar Reliability Impacts 0 MW hybrid solar 4.4 0 0 0 0 0 40.728 72.94 256.36 0.36 1.1%
3 MW hybrid solar 4.4 0 0 0 3 0 5.056 12.03 23.16 0.03 0.1%
6 MW hybrid solar 4.4 0 0 0 6 0 1.796 4.14 9.30 0.02 0.0%
9 MW hybrid solar 4.4 0 0 0 9 0 0.988 2.54 5.38 0.01 0.0%
Firm Generation Reliability Impacts
2.2 MW firm 2.2 0 0 0 6 0 37.908 88.56 195.86 0.39 1.2%
4.4 MW firm 4.4 0 0 0 6 0 1.796 4.14 9.30 0.02 0.0%
6.6 MW firm 6.6 0 0 0 6 0 0.02 0.04 0.06 0.00 0.0%
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12.3.4.1 Hybrid Solar Reliability Impacts
We assessed the impact that hybrid solar has on reliability by assuming the Base scenario that includes 4.4 MW of firm generation. We added 3 MW increments of hybrid solar starting at 0 MW. Even with 12 MW of future hybrid solar, 4.4 MW of firm does not meet the loss of load target of 0.1 day per year. Figure 12-38 illustrates the difference in loss of load expectation benefit of 2 MW at different levels of hybrid solar. For example, going from 0 MW to 2 MW provides about 12 days/year loss of load expectation improvement versus a 0.6 day/year improvement going from 7 MW to 9 MW of hybrid solar. If we extrapolate the curve to hit a target of 0.1 day per year, it would take about 13 MW of hybrid solar capacity.
Figure 12-38. Moloka‘i: relationship between change in loss of load and change in future
hybrid solar capacity (Base Load,
2030)
The heat map in Figure 12-39 shows the expected unserved energy from 250 simulation samples. This shows
that out of the 250 samples, the beginning of the year shows no unserved energy but during the later
months, especially September, there is a higher possibility for unserved energy.
Figure 12-39. Moloka‘i: 4.4 MW firm, add 12 MW hybrid solar expected unserved energy heat map (Base Load, 2030)
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We also performed analysis in 2035 assuming a High Load forecast to understand the impacts of accelerated EV adoption. Similar to the 2030 scenario we assume 4.4 MW of firm generation and hybrid solar additions in 3 MW increments starting at 0 MW.
Figure 12-40 illustrates the difference in loss of load expectation benefit of 2 MW at different levels of hybrid solar capacity. For example, going from 0 MW to 2 MW provides about 12 days/year loss of load expectation
improvement versus a 0.9 day/year improvement going from 7 MW to 9 MW of hybrid solar. If we extrapolate the curve to hit a target of 0.1 day per year, it would take about 15 MW of hybrid solar capacity.
Figure 12-40. Moloka‘i: relationship between change in loss of load and change in future hybrid solar capacity (High Load,
2035)
Figure 12-41 shows the expected unserved energy from 250 simulation samples. This shows that out of the 250 samples, the beginning of the year shows no unserved energy but during the later months, especially December, there is a higher possibility for unserved energy.
Figure 12-41. Molokaʻi: 4.4 MW
firm, add 12 MW hybrid solar
expected unserved energy heat
map (High Load, 2035)
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12.3.4.2 Firm Generation Reliability Impacts
To assess the impacts of firm generation, we assume 6 MW of hybrid solar and additions of firm generation in 2.2 MW increments starting at 2.2 MW. We based the 2.2 MW increments on existing generator sizes on Moloka‘i.
Figure 12-42 illustrates the difference in reliability benefit of 1 MW at different levels of firm capacity. For example, going from 2.2 MW to 3.3 MW provides about 45 days/year loss of load expectation improvement versus a 2.5 day/year improvement going from 4 MW to 5 MW.
Figure 12-42. Moloka‘i: relationship between change in
loss of load and change in firm
capacity (Base Load, 2030)
Figure 12-43 shows the expected unserved energy from 250 simulation samples. This shows that for almost
all the hours, the system does not show any unserved energy within the 250 samples.
Figure 12-43. Moloka‘i: 6.6 MW firm, 6 MW hybrid solar expected unserved energy heat map (Base Load, 2030)
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To assess the firm generation impact on reliability, we assumed that 6 MW of hybrid solar is in service with additions of firm generation in 2.2 MW increments starting at 2.2 MW. We based the 2.2 MW increments on existing generator sizes.
Figure 12-44 illustrates the difference in reliability benefit of 1 MW at different levels of firm capacity. For example, going from 2.2 MW to 3.3 MW provides about 39 days/year loss of load expectation improvement
versus a 1.8 day/year improvement going from 4 MW to 5 MW of firm capacity.
Figure 12-44. Moloka‘i: relationship between change in loss of load and change in firm capacity (High Load, 2035)
Figure 12-45 shows the expected unserved energy from 250 simulation samples. This shows that for almost all the hours, the system does not show any unserved energy within the 250 samples.
Figure 12-45. Moloka‘i: 6.6 MW
firm, 6 MW hybrid solar expected
unserved energy heat map (High
Load, 2035)
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12.3.4.3 3-Day Energy Profile, High Unserved Energy Day
The energy profile shown in Figure 12-46 depicts the worst unserved energy day to illustrate what that day would look like. In this scenario, the firm generators are out of service and without them there is significant unserved energy in the late evening and early morning hours.
Figure 12-46. Moloka‘i: detailed
energy profile, 2030 high unserved energy load day; Base Load, 4.4 MW firm, add 12 MW hybrid solar
The energy profile shown in Figure 12-47 depicts the worst unserved energy day to illustrate what that day would look like. In this scenario, the firm generators are out of service and without them there is unserved energy in the late evening and early morning hours.
Figure 12-47. Moloka‘i: detailed energy profile, 2035 high unserved energy load day; High Load, 4.4 MW firm, add 12 MW hybrid solar
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12.3.5 Lānaʻi
Uncertainty in forecasted electricity demand is a large source of risk for Lānaʻi. Section 8.6.2 shows how the
planned Lānaʻi system meets reliability targets in 2030 and 2035. This section shows how adding or removing
resources from the Lānaʻi system affects reliability metrics. Shown below in Table 12-13 and Table 12-14 is a summary of the resource adequacy results for different scenarios of future firm and variable plans. Further detailed discussion is presented in the subsequent sections.
Table 12-13. Probabilistic Analysis: Results Summary, Lānaʻi 2030
Scenario Existing Firm (MW)
New Firm (MW)
CBRE RFP Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
Base 10 0 16 0 5.2 0.6 0.00 0.00 0.00 0.00 0.000
Hybrid Solar Reliability Impacts
8 MW firm, 4 MW hybrid solar 8 0 4 0 0 0 1.45 2.40 6.94 0.0051 0.013
8 MW firm, 7 MW hybrid solar 8 0 7 0 0 0 0.20 0.35 0.93 0.0008 0.002
8 MW firm, 10 MW hybrid solar 8 0 10 0 0 0 0.04 0.05 0.10 0.0001 0.000
8 MW firm, 13 MW hybrid solar 8 0 13 0 0 0 0.01 0.01 0.04 0.0001 0.000
Firm Generation Reliability Impacts 4 MW firm, 16 MW hybrid solar 4 0 16 0 0 0 4.62 8.66 22.82 0.0271 0.068
6 MW firm, 16 MW hybrid solar 6 0 16 0 0 0 0.09 0.15 0.34 0.0003 0.001
8 MW firm, 16 MW hybrid solar 8 0 16 0 0 0 0.00 0.00 0.00 0.0000 0.000
Table 12-14. Probabilistic Analysis: Results Summary, Lānaʻi 2035
Scenario Existing Firm (MW)
New Firm (MW)
CBRE RFP Hybrid Solar (MW)
Future Wind (MW)
Future Hybrid Solar (MW)
Future Standalone BESS (MW)
LOLE (Days/ Year)
LOLEv (Event/ Year)
LOLH (Hours/ Year)
EUE (MWh/ Year)
EUE (%)
High load bookend 10 0 16 0 7.2 0.6 0.00 0.00 0.00 0.00 0.000 Hybrid Solar Reliability Impacts
8 MW firm, 4 MW hybrid solar 8 0 4 0 0 0 3.54 5.86 18.22 0.0159 0.037
8 MW firm, 7 MW hybrid solar 8 0 7 0 0 0 0.59 1.02 2.51 0.0023 0.005
8 MW firm, 10 MW hybrid solar 8 0 10 0 0 0 0.09 0.16 0.40 0.0004 0.001
8 MW firm, 13 MW hybrid solar 8 0 13 0 0 0 0.01 0.03 0.08 0.0001 0.000
Firm Generation Reliability Impacts 4 MW firm, 16 MW hybrid solar 4 0 16 0 0 0 10.56 21.63 57.16 0.0735 0.171
6 MW firm, 16 MW hybrid solar 6 0 16 0 0 0 0.22 0.37 1.03 0.0013 0.003
8 MW firm, 16 MW hybrid solar 8 0 16 0 0 0 0.00 0.00 0.00 0.0000 0.000
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12.3.5.1 Hybrid Solar Reliability Impacts
We assessed reliability impacts to hybrid solar additions on Lānaʻi in 2030. To determine the sensitivity of the loss of load expectation based on the amount of variable renewable generation added in 2030, we removed future hybrid solar and 2 MW of existing firm generation. We then varied the amount of hybrid solar to see how reliability changed.
As shown in Figure 12-48, in 2030, with 8 MW of firm generation, we need approximately 10 MW of hybrid solar to meet the 0.1 day/year loss of load expectation target. Shown below is the relationship between loss
of load expectation and hybrid solar additions in 2030. The figure shows that as we add more hybrid solar,
the improvements to reliability diminish.
Figure 12-48. Lānaʻi: relationship between change in loss of load and change in hybrid solar (Base Load, 2030)
Figure 12-49 presents the unserved energy based on the month and hour of the system with 8 MW of firm
generation and 10 MW of hybrid solar. Unserved energy could be seen in the morning hours of October to
December.
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Figure 12-49. Lānaʻi: 8 MW firm 10 MW hybrid solar expected unserved energy heat map (Base Load, 2030)
To determine the sensitivity of the loss of load expectation based on the amount of hybrid solar added
under the 2035 High Load forecast, we removed the future hybrid solar and 2 MW of existing firm (see Figure 12-50). We then varied the amount of hybrid solar to see how reliability changed. The 2035 High Load forecast is not drastically higher than the 2030 Base Load forecast; therefore, the loss of load expectations between 2030 and 2035 are similar.
Figure 12-50. Lānaʻi: relationship between change in loss of load and change in hybrid solar (High Load, 2035)
Figure 12-51 presents the unserved energy based on the month and hour of the system with 8 MW of firm generation and 10 MW of hybrid solar. We observe unserved energy mostly from October to December.
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Figure 12-51. Lānaʻi: 8 MW firm, add 10 MW hybrid solar expected unserved energy heat map (High Load, 2035)
12.3.5.2 Firm Generation Reliability Impacts
We also performed analysis to analyze how the loss of load expectation changes based on the amount of
existing firm generation in 2030. In this sensitivity, we assume that 16 MW from the past CBRE RFP is in
service.
In 2030, 6 MW of firm generation is sufficient to meet the 0.1 day/year loss of load expectation target. Figure
12-52 shows the relationship between loss of load expectation and firm generation. The impact to loss of load expectation decreases as the amount of firm generation increases.
Figure 12-52. Lānaʻi: relationship between change in loss of load and change in firm capacity (Base Load, 2030)
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Figure 12-53 presents the unserved energy based on the month and hour. Most of the unserved energy is observed in the morning and evening hours.
Figure 12-53. Lānaʻi: 6 MW firm,
add 16 MW hybrid solar expected
unserved energy heat map (Base Load, 2030)
We also analyzed the relationship between loss of load expectation and the amount of existing firm generation in the 2035 High Load forecast. In this sensitivity, we assumed that 16 MW of hybrid solar is in service.
As shown in Figure 12-54, in 2035, we will need more than 6 MW of firm generation to meet the 0.1 day/year target. The figure shows the relationship between the loss of load expectation and firm generation.
Figure 12-55 presents the unserved energy based on the month and hour. Most of the unserved energy is observed in the morning and evening hours.
Figure 12-54. Lānaʻi: relationship
between change in loss of load and change in firm capacity (High Load, 2035)
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Figure 12-55. Lānaʻi: 6 MW firm, add 16 MW hybrid solar expected unserved energy heat map (High Load, 2035)
12.3.5.3 3-Day Energy Profile, High Unserved Energy Day
The results shown above are the average of the 250 simulation samples. Figure 12-56 shows a sample in the
2030 Base scenario where unserved energy is experienced in the early morning hours. Figure 12-57 shows a
sample in the 2035 High Load scenario where unserved energy is experienced in the early morning hours
and mid-afternoon.
Figure 12-56. Lānaʻi: detailed energy profile, 2030 high unserved energy load day; Base Load, 8 MW firm, add 10 MW hybrid solar
Figure 12-57. Lānaʻi: detailed energy profile, 2035 high unserved energy load day; High Load, 8 MW firm, add 10 MW hybrid solar
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APPENDICES
13 Appendices
A-1 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
Appendix A:
Stakeholder Feedback
and Public Input
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1 Stakeholder Feedback
and Public Input
1.1 Stakeholder Council
The Stakeholder Council met a total of 23 times between August 2018 and December 2022, discussing various topics on Integrated Grid Planning. The following table includes a list of meeting dates, links to presentation materials and notes. This information is also available within the Key Stakeholder Documents Library.
Meeting Date Materials Notes August 30, 2018 General Presentation Meeting Summary
November 8, 2018 General Presentation Meeting Summary
January 22, 2019 General Presentation Meeting Summary
February 20, 2019 General Presentation Meeting Summary
May 8, 2019 General Presentation Meeting Summary
August 23, 2019 General Presentation Meeting Summary
November 7, 2019 General Presentation Meeting Summary
January 16, 2020 General Presentation Meeting Summary
March 12, 2020 General Presentation Meeting Summary
June 1, 2020 General Presentation Meeting Summary
August 18, 2020 General Presentation NREL Solar and Wind Resource Final Study
NREL Solar and Wind Resource Potential Study Meeting Summary
March 9, 2021 General Presentation
Stakeholder Council Framework Pre-Read Stakeholder Council Meeting Docket 2018-0165 Meeting Summary
March 29, 2021 General Presentation Meeting Summary
April 27, 2021 General Presentation Meeting Summary
June 18, 2021 General Presentation SWITCH Analysis Presentation Meeting Summary
June 23, 2021 General Presentation NREL Assessment of Wind and Photovoltaic Technical Potential Report Preliminary Agenda for June 30, 2021 Island-Wide PSCAD Study Meeting Meeting Summary
October 28, 2021 General Presentation
Technical Advisory Panel Update Presentation Meeting Summary
Meeting Recording
November 9, 2021 General Presentation
Resilience Working Group Recap Stakeholder Council Pre-Read Meeting Summary
Meeting Recording
January 24, 2022 General Presentation Meeting Summary
Meeting Recording
May 18, 2022 General Presentation Progress Update Presentation Meeting Recording
September 29, 2022 General Presentation Meeting Recording
November 30, 2022 Joint Stakeholder Council and Technical Advisory Panel Meeting Presentation Meeting Recording
December 5, 2022 General Presentation Meeting Recording
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1.1.1 Stakeholder Toolkit
The purpose of the Stakeholder Toolkit is to provide public-friendly materials for Stakeholder Council
Members to use when discussing Hawaii Powered. The use of materials throughout engagement helps to
provide consistent branding and messaging. Two toolkits were provided to the Stakeholder Council
including in 2020 and 2022.
■ Toolkit – Overview Presentation with talking points (shown below)
■ Toolkit – Frequently Asked Questions
■ Toolkit – Hawaii Powered Handout
■ Toolkit – Engagement Opportunities Flier
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1.1.2 Stakeholder Toolkit Materials
The following pages show images of display boards, informational and frequently asked question handouts,
and presentations slides.
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1.2 Technical Advisory Panel
The Technical Advisory Panel, also referred to as the TAP, has been working together from September 2018 to December 2022, discussing various technical topics supporting the development of the Integrated Grid Plan. The following table includes a list of dates with links to meeting summaries and technical reports. This information along with additional presentations are available within the Key Stakeholder Documents Library.
Date Notes September 15, 2018 Meeting Summary
May 7, 2019 Meeting Summary
September 10, 2019 Meeting Summary
October 22, 2019 Meeting Summary November 19, 2019 Meeting Summary
December 17, 2020 Meeting Summary February 24, 2021 Meeting Summary
June 1, 2021 TAP Response to Order No. 37730 July 28, 2021 Workplan Update
October 1, 2021 TAP Feedback – Renewable Energy Zone Study
October 4, 2021 TAP Feedback – Transmission Planning Criteria TAP Feedback – System Security Methodology
October 11, 2021 TAP Feedback – Non-Wires Opportunity Evaluation Methodology
TAP Feedback – Distribution Planning Methodology
November 1, 2021 TAP Feedback – Proposed Energy Reserve Margin (ERM) Criteria
December 13, 2021 TAP Feedback – System Stability Study
January 20, 2022 TAP Feedback – Additional Evaluation of Hourly Dependable Capacity (HDC) Values
January 21, 2022 TAP Feedback – System Stability Study
February 25, 2022 TAP Feedback – Under Frequency Load Shed (UFLS) Study UFLS Study Discussion
March 10, 2022 TAP Feedback – Order 38253
March 11, 2022 TAP Feedback – Distribution Planning Methodology (Clarifications) Load Forecast Scenario Discussion April 28, 2022 TAP Feedback
June 2, 2022 TAP Feedback
July 7, 2022 TAP Feedback TAP Feedback Summary
July 12, 2022 TAP Feedback August 4, 2022 TAP Progress Update
August 11, 2022 TAP Feedback
September 14, 2022 TAP Progress Update
November 15, 2022 TAP Feedback
November 16, 2022 TAP Feedback
December 1, 2022 TAP Feedback
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1.3 Stakeholder Technical Working Group
The Stakeholder Technical Working Group, also referred to as STWG, met between June 2021 and February 2023, discussing various technical topics supporting the development of the Integrated Grid Plan. The following table includes a list of meeting dates and links to meeting notes. This information along with supporting documents are available within the Key Stakeholder Documents Library.
Date Notes June 2, 2021 Meeting Summary
June 17, 2021 Meeting Summary
July 14, 2021 Meeting Summary
July 16, 2021 Meeting Summary August 4, 2021 Meeting Recording
September 7, 2021 Meeting Summary September 23, 2021 Meeting Summary
October 6, 2021 Meeting Summary October 13, 2021 Meeting Summary
November 19, 2021 Meeting Summary September 14, 2022 Meeting Summary
November 29, 2022 Presentation
December 15, 2022 Presentation
January 19, 2023 Presentation
February 16, 2023 Presentation
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1.4 Public Engagement (2020)
A collection of public engagement notifications, materials and summary documents associated with Hawaiian Electric engagement opportunities.
■ Meeting Invites: postcard and fliers
■ Media advertisements and social media
■ Meeting materials
■ Survey questions and input forms
■ Virtual open house and statistics
■ Graphic summary
Island Link Hawaiʻi Meeting Recording
Oʻahu Meeting Recording
Maui Meeting Recording
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1.4.1 Public Engagement Materials
The following pages show images of display boards, advertisements, social media posts, comment cards,
maps and diagrams, and screenshots from a virtual open house.
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1.5 Plugged In
A blog called Plugged In, with monthly posts about Integrated Grid Planning milestones, features on customers and Hawaiian Electric team members, and “deeper dives” on technical subjects. A total of 12 blog posts have been posted and are available to read on Hawai‘i Powered.
Posting Date Link Views (as of 3/1/2023) Reads (as of 3/1/2023)
March 11, 2022 Announcing Hawaii Powered 124 47
March 11, 2022 Shared Solar 101 93 34
April 18, 2022 Aloha from Hawaiian Electric! 63 25
April 19, 2022 What You Need to Know: 2021-2022 Sustainability Report 43 13
May 31, 2022 Non-wires alternatives 31 10
June 1, 2022 Energy Efficiency: The power to change is in our hands 59 15
July 5, 2022 Molokai residents receive kits to help save energy at home 41 12
July 6, 2022 Distributed Energy Resources: A diverse grid is a strong grid 70 21
August 1, 2022 Building Resilience in North Kohala: A collaborative approach to strengthen our communities 57 24
August 2, 2022 Electrification of Transportation: Driving toward a renewable future 84 26
September 6, 2022 Inputs and Assumptions: What does the data really mean? 61 23
November 28, 2022 Renewable Energy Zone (REZ) Maps: You know your community best 45 14
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1.6 Newsletters
Monthly Hawai‘i Powered e-newsletters sharing Integrated Grid Planning updates and blog post links with all project subscribers. A total of 8 e-newsletters have been released and are available to read on Hawai‘i Powered.
■ March 17, 2022
■ April 21, 2022
■ June 2, 2022
■ July 12, 2022
■ August 4, 2022
■ September 12, 2022
■ November 29, 2022
■ February 28, 2023
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1.7 Inputs & Assumptions
The inputs and assumptions data dashboard (hawaiipowered.com/iadashboard), provides interactive learning modules and graphs tied to the data sets we used to model future energy scenarios.
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1.8 Activity Book
Hawai‘i Powered activity book with energy exercises, power-up puzzles, creative coloring, and more for learners of all ages. We distributed this activity book at community events on Hawai‘i Island, O‘ahu, and Maui. Parents and teachers could also download the activity book at Hawai‘i Powered.
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1.9 ETIPP
Summary of O‘ahu microgrid planning which was an outcome of Hawaiian Electric’s involvement in DOE's Energy Transitions Initiative Partnership Project (ETIPP) to improve energy resilience and combat climate change.
SUMMARY REPORT
Resilient and Renewable Energy
Community Workshops
Oʻahu, Hawaiʻi
October/November 2022
RESILIENT AND RENEWABLE ENERGY COMMUNITY WORKSHOPS
EXECUTIVE SUMMARY
EXECUTIVE SUMMARY
Hawaiian Electric is seeking community input regarding long-term efforts to increase resilience and
decarbonize the electrical grid for the island of Oʻahu. The recent destruction caused by hurricanes in
Florida and Puerto Rico underscores the need to improve energy resilience as climate change fuels more
severe weather events. Hawaiian Electric is working with the U.S. Department of Energy, National
Renewable Energy Laboratory, and Hawaiʻi Natural Energy Institute to develop a map that identifies
opportunities for development of microgrids across Oʻahu. Microgrids allow grid-connected facilities to
operate independent of the grid during a power outage using electricity from local energy resources.
In parallel with efforts to improve resilience, Hawaiian Electric is also working toward decarbonization of
the energy system, consistent with their Climate Change Action Plan and the State of Hawaiʻi’s goal of 100
percent renewable energy and net-zero carbon emissions economywide by 2045. As an initial step in the
long-term planning process, Hawaiian Electric engaged National Renewable Energy Laboratory to conduct
a data-based analysis of potential areas on Oʻahu that may be suitable for future grid-scale renewable
energy projects. With community input, this analysis will be used to inform developers of potential site
suitability as well as to guide planning efforts for the transmission infrastructure needed to support future
renewable resource development.
Hawaiian Electric hosted six hybrid community workshops across Oʻahu to share information and solicit
community input regarding the microgrid mapping and renewable energy zone analysis. Specifically, the
workshops were designed to collect community insight on specific facilities that should be prioritized for
microgrid development, as well as factors that should be considered in siting renewable energy resources.
The community workshops were held in each of the six moku (districts) across Oʻahu, as listed below.
Notices regarding the workshops were sent to elected officials, neighborhood boards, and energy-related
groups and organizations. In addition, a news release was sent to various media outlets and promotional
news stories ran in the Star Advertiser and Pacific Business News (see Attachment A). Each workshop
included an open house (in-person only) followed by a hybrid community workshop (in-person and via
Zoom). The workshops were also livestreamed and recorded by ʻŌlelo Community Media.
• Ko‘olauloa Moku (Waimea – Ka‘a‘awa): Monday, October 24 at Kahuku Elementary School
• Waiʻanae Moku (Nānākuli – Keawaʻula): Wednesday, October 26 at Agnes Kalanihoʻokahā Community
Learning Center
• Kona Moku (Moanalua – East Honolulu): Tuesday, November 1 at Kapiʻolani Community College
• Waialua Moku (Ka‘ena – Kapaeloa): Thursday, November 3 at Waialua Elementary School
• Ko‘olaupoko Moku (Waimānalo – Kualoa): Tuesday, November 15 at Windward Community College
• ʻEwa Moku (Honouliuli – Hālawa): Thursday, November 17 at Leeward Community College
Community members were able to provide feedback at each of the workshops in various formats,
including verbal comments (both in-person and via Zoom), online through the Zoom chat function, as
RESILIENT AND RENEWABLE ENERGY COMMUNITY WORKSHOPS
EXECUTIVE SUMMARY
well as through Menti. Additional options for submitting input following the workshops were also
provided, including via an interactive website (www.hawaiipowered.com) and email
(igp@hawaiianelectric.com).
Overall, community members voiced an interest in increased resilience and energy equity. Key messages
related to the following topics:
• Development of microgrids and renewable energy projects must factor in energy equity;
• Siting renewable generation only in locations where resource and land are available will not support
energy resilience;
• Grid-scale renewable generation should be hosted in a variety of communities, not just those in rural
areas;
• Cost to develop microgrids and renewable energy must be factored into the decision-making process;
and
• The concept of hybrid microgrids requires careful explanation to facilitate understanding.
This report includes a synopsis of the technical information shared by Hawaiian Electric at each of the
workshops followed by a detailed summary of the community input received.
TECHNICAL PRESENTATION
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1
Introduction
Hawaiian Electric hosted Renewable and Resilient Energy Community Workshops across the island of
Oʻahu, one in each of the six moku (districts). Following is a summary of the introductory remarks and
technical presentation provided at each workshop; a copy of the presentation slides is contained in
Attachment B. Community feedback received at each meeting is summarized in subsequent sections of
this report.
Overview
Opening remarks were provided by Kurt Tsue, Director of Community Affairs at Hawaiian Electric. He
explained that the purpose of the workshops is to address two separate but related topics relating to
increasing resilience and decarbonization of the electric grid: (1) hybrid microgrids and (2) renewable
energy zones. The workshops are structured to provide presentation of technical information for these
two topics, each followed by an opportunity
for community members to ask questions
and provide input. He stated that the
workshop format is intended to increase
accessibility and community participation by
allowing for attendance either in-person or
online through Zoom, as well as via a live
broadcast and recording provided by ʻŌlelo
Community Media. He noted that all of the
information shared at the open house is also
part of the workshop presentation; the
benefit of the open house is the opportunity
for community members to talk story with subject matter experts. He also emphasized that these are
long-range planning efforts and there will be ongoing opportunities to provide input in the future.
He introduced the speakers and others available for questions throughout the workshop, including Ken
Aramaki (Director of Transmission, Distribution and Interconnection Planning at Hawaiian Electric), Marc
Asano (Director of Integrated Grid Planning at Hawaiian Electric), Katy Waechter (Geospatial Science
Researcher at the National Renewable Energy Laboratory), and Colton Ching (Senior Vice President of
Planning and Technology at Hawaiian Electric). In addition, he introduced Alani Apio (Kamau LLC) as the
workshop facilitator. He also recognized the Center for Resilient Neighborhoods (CERENE) as a partner
organization that is engaging with communities at the grassroots level to increase resilience through
development of resilience hubs, which dovetails with the concept of microgrids.
Kurt explained that Hawaiian Electric has an obligation to provide reliable electrical service, as well as
stabilize energy costs by transitioning off fossil fuels. He acknowledged that this is a very challenging
time in terms of electricity costs and stated that Hawaiian Electric is open to continuing conversations
on this topic if desired. He explained that the purpose of the Renewable and Resilient Energy Workshops
is to address the transition to renewable energy as well as the need for increased resilience in light of
RESILIENT AND RENEWABLE ENERGY COMMUNITY WORKSHOPS
TECHNICAL PRESENTATION
2
climate change. Recent events in Puerto Rico and Florida underscore the importance of addressing these
issues as soon as possible, especially given Hawaiʻi’s vulnerability as an island state in the middle of the
Pacific Ocean. The first portion of the workshop relates to microgrids; there are different types of
microgrids, but the workshop is focused on hybrid microgrids to support disaster and emergency
preparedness. Hybrid microgrids improve energy resilience by ensuring backup power to critical facilities
(such as medical facilities, community gathering places, food storage facilities) during a grid outage.
Implementation of a hybrid microgrid involves islanding (sectioning off) facilities which are typically
energized through the island-wide electric grid, allowing for continued power during a grid outage from
local energy resources. Hawaiian Electric is seeking input from the community regarding whether
microgrids should be considered in their community, and if so, what facilities should be included. The
second portion of the workshop relates to efforts to decarbonize Oʻahu’s energy system by
incorporating grid-scale renewable energy generation. He emphasized that a lot of changes will need to
be made to fully transition to renewable energy and current efforts are focused on how best to bring
renewable energy projects online to achieve decarbonization goals in a manner that meets the
community’s needs. Hawaiian Electric is seeking community input regarding the factors that should be
considered in siting these types of large-scale renewable energy projects.
Kurt acknowledged that these are difficult concepts to navigate but are extremely important to address
in planning Hawaiʻi’s energy future. He stated that Hawaiian Electric has traditionally focused on
providing technical engineering solutions that ensure a safe and reliable electrical grid but has come to
understand the importance of balancing these technical requirements with community priorities and
needs. In particular, he acknowledged the importance of understanding how communities may be
affected by efforts to improve resilience and decarbonize the energy system, and the need to
incorporate community input proactively rather than after the fact. He specifically acknowledged recent
efforts by the West Oʻahu/Kalaeloa Clean Energy ʻOhana, which involved aligning community interests
and filing specific recommendations with the Public Utilities Commission (PUC) to allow for better
community involvement in the renewable energy planning and development process. Building on these
efforts, he explained that Hawaiian Electric is committed to further improving existing processes to
facilitate community engagement. As part of this commitment, Hawaiian Electric is trying to level the
playing field by sharing the same information that is used by utility engineers and developers in a format
that is more accessible to the community; this information is being shared as part of this workshop with
more detail provided at www.hawaiipowered.com. The goal is to make it easier for the community to
participate in renewable energy and resilience planning efforts. Input received from the community will
be documented in a report that will be submitted to the PUC on behalf of the community and
incorporated into the planning process. In addition, the information will be visible to others involved in
the planning process including developers and state agencies such as the Hawaiʻi State Energy Office.
Kurt emphasized that this is a long-term effort and there will be continuing opportunities for community
input and participation moving forward.
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Hybrid Microgrid Mapping Project
Ken Aramaki, Director of Transmission, Distribution and Interconnection Planning at Hawaiian Electric,
presented information regarding the hybrid microgrid mapping project, which is a current initiative to
improve resilience of Hawaiian Electric’s island-wide electrical grid. Grid resilience is critical to
maintaining community lifelines, which are those services essential for human health and safety as well
as economic security. Community lifelines include things such as energy, communications, health and
medical, transportation, food, water and shelter. Community lifelines are generally interdependent;
however, energy is central to all community lifelines. As such, Hawaiian Electric is trying to identify
opportunities to improve resilience of the electrical grid so that energy availability may be more reliable
to maintain community lifelines during emergency situations.
Basic knowledge of the electrical grid structure is helpful for understanding the concept of microgrids.
Hawaiian Electric’s electrical grid was originally built to provide a one-way flow of energy to customers,
originating with bulk generation at various power generation plants. The high voltage energy from these
generators is transported through a transmission network with the voltage incrementally stepped down
through a series of substations, then is ultimately delivered as low voltage electricity to individual
customers. The system has been modified in recent years to accommodate the addition of new energy
resources from independent power producers, including solar photovoltaic, wind farms, and energy
storage systems; although not originally designed for these additions, the grid has been modified to
allow for interconnection at various voltage levels and at different points throughout the system. In
addition, customers have also added distributed energy resources (such as rooftop solar, batteries, and
diesel generators) to their individual properties through various programs, in many cases to offset
electricity costs.
Recent technological advancements have allowed for distributed energy resources to function as a
microgrid, which allows customers to continue receiving electricity in the event of a broader grid outage.
For example, it is possible for customers with rooftop solar photovoltaic panels and batteries to
configure the system behind their electrical meter in a manner that allows for power to be maintained
at their individual home or business in the event of an emergency. Other examples include commercial
customers that use diesel generation to provide power independent of the grid. These types of
microgrids generally serve a single customer and are referred to as customer microgrids. Hawaiian
Electric recently created a microgrid services tariff that allows for both customer microgrids as well as
larger microgrids involving multiple customers (referred to as hybrid microgrids). A hybrid microgrid
consists of a cluster of customers located proximate to one another, each of which is individually served
by the utility on a normal day-to-day basis. To develop a hybrid microgrid, the utility infrastructure (e.g.,
poles and lines) connecting these customers is hardened and electrically sectioned off from the broader
electrical grid. During a grid outage, the customers within the hybrid microgrid may be powered using
the aggregate of those customers’ localized generation resources, delivered across the microgrid via
utility infrastructure.
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Upon launching the microgrid services tariff, Hawaiian Electric realized that customers may not be able
to easily identify opportunities where microgrids are feasible as they are technically complex systems
and require an understanding of the electrical grid. Around that same time, Hawaiian Electric applied
and was selected to participate in a new program funded by the Department of Energy (DOE), referred
to as the Energy Transitions Initiative Partnership Program (ETIPP). The program provides technical
assistance to remote and island communities seeking to transform their energy systems and increase
energy resilience through strategic energy planning. Through this program, Hawaiian Electric is working
with National Renewable Energy Laboratory (NREL), Sandia National Laboratories, and Hawaiʻi Natural
Energy Institute (HNEI) to identify specific locations on Oʻahu that may be well suited for a hybrid
microgrid based on technical, reliability, and resilience-related characteristics. The results of this analysis
will be presented on community-based maps that can be used by customers to understand if a hybrid
microgrid is a viable solution for their community and specific locations where microgrids could be used
to improve the electrical infrastructure resilience.
Katy Waechter, Geospatial Science Researcher III at NREL, presented additional detail regarding the
hybrid microgrid mapping process. She explained that the goal of the mapping effort is to identify
potential microgrid locations at the parcel level. Three categories of criteria were initially identified to
evaluate site suitability, as described below. She stressed that although potential microgrid sites may be
determined based on a single criterion, the goal of the analysis is to identify areas where the criteria
overlap as these are locations where microgrids would be expected to have the greatest impact.
• Criticality incorporates critical loads, facilities, and services within a given community, particularly
those that directly impact human health and safety during an emergency. Specifically, this category
includes emergency facilities and services (such as emergency shelters, fire stations, and emergency
option centers), medical facilities and services (such as hospitals, surgical centers, and nursing
homes), and critical infrastructure (such as water sources, transmission towers, bridges, ports, and
airports).
• Vulnerability addresses those parts of the grid currently and projected to endure the longest or most
frequent outages based on factors including natural hazard risk (such as tsunami evacuation zones,
flood hazard zones, and sea-level rise inundation areas), remoteness and accessibility (based on the
relative density of transportation and electrical transmission infrastructure in any given area), and grid
reliability (based on Hawaiian Electric data regarding grid outages over a 10-year period [2011-2021]).
• Societal Impact focuses on locations that would significantly impact communities if they lost power.
This category includes residential care facilities, community homes, schools, daycare facilities, and
libraries. To ensure equity and accessibility to microgrid opportunities, this category also focuses on
populations that may be disproportionately affected by outages including customers receiving
assistance (such as the Asset-Limited, Income-Constrained, Employed [ALICE] program),
disadvantaged communities (in accordance with DOE’s definition which follows the Biden
Administration’s Justice40 Initiative and incorporates 36 different metrics of burden), as well as
Hawaiian homelands, IRS Opportunity Zones and other similar metrics.
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The mapping exercise, which covers the entire island of Oʻahu, includes dozens of spatial datasets for
these three categories of criteria as well as information specific to Hawaiian Electric’s distribution
network. In addition, the mapping incorporates a model used to determine where electricity demand is
balanced with grid-connected customer energy resources (e.g., rooftop solar panels, batteries, etc.), as
these may be locations where microgrids could be most easily developed with minimal upgrades. The
maps resulting from this initial effort were
shared in the presentation and are available
online at www.hawaiipowered.com\etipp;
however, the maps are considered
incomplete as they do not yet reflect
community-based knowledge. As such,
Hawaiian Electric is seeking community
input regarding additional criteria that
should be included in the analysis as well as
any specific facilities that should be
considered for a hybrid microgrid. Of
particular interest are facilities that may not
be included in public datasets but are
important to the community, such as those locations where people gather during and following
emergency events. There are multiple options for providing input including in-person and virtual tools
offered during the Renewable and Resilient Energy Workshops as well as online at
www.hawaiipowered.com\etipp; details for contributing input are provided below. All input received
will be considered and incorporated into the analysis as appropriate. The resulting site-specific maps,
which will ideally show where the various criteria and community resources meet, will be shared with
the community as a resource for evaluating potential locations for hybrid microgrids.
Renewable Energy Zones
The workshop also included a presentation regarding long-term planning to meet Hawaiʻi’s
decarbonization goals; this information was presented by Ken Aramaki and Marc Asano, Director of
Integrated Grid Planning at Hawaiian Electric. They started by explaining that decarbonization of the
energy system is a critical component of mitigating climate change, the effects of which are being
increasingly realized in Hawaiʻi and elsewhere around the world. The State of Hawaiʻi has established
goals of achieving net zero carbon emissions and 100 percent renewable energy by the year 2045 (with
interim targets by 2030). Hawaiian Electric’s Climate Change Action Plan includes commitments
consistent with these goals to reduce carbon emissions by 70 percent compared to 2005 levels by 2030.
Achieving these commitments will require significant changes over the next 20 years, including
development of the necessary renewable energy resources as well as the transmission infrastructure
needed to deliver those resources. As energy infrastructure typically takes at least 10-15 years to
develop, near-term action is needed to work toward these commitments.
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Long-term planning to support the transition to a decarbonized electrical system is being addressed as
part of Hawaiian Electric’s Integrated Grid Planning (IGP) process. The goal of these efforts is to develop
and implement a plan for a clean energy grid that meets the established timelines (accounting for the
time needed to build the supporting transmission infrastructure to support renewable resource
development), stabilizes customer costs, balances competing land uses (including affordable housing
and agriculture), minimizes community impacts, and improves overall energy resilience. Given the range
of planning considerations and technical complexities, this will require a focused and coordinated effort
across the board, including the community.
Currently, Hawaiian Electric has an as-available renewable capacity of approximately 1,143 megawatts
on the island of Oʻahu. This capacity includes the various existing renewable energy projects (e.g., solar
photovoltaic and wind energy) and is considered as-available because the energy availability is
dependent on weather conditions and/or time of day (e.g., when the sun is shining or wind is blowing);
the majority of this as-available renewable capacity (763 megawatts) is associated with customer-sited
resources such as rooftop solar. An additional 384 megawatts of solar energy resources is currently in
development; these are generally large, grid-scale projects that were selected as part of Hawaiian
Electric’s Stage 1 and 2 competitive procurement processes and are in the process of being brought
online. In addition to providing additional renewable energy resources, these projects also include a
storage component (e.g., batteries) which allows for the energy to be used during periods with the
greatest demand. Despite all of these renewable resources, Hawaiian Electric still heavily relies on firm
generation sources to maintain grid reliability; the total firm capacity is approximately 1,614 megawatts,
of which only about 126 megawatts is from renewable sources. The goal is to phase out the non-
renewable firm capacity, which will need to be offset with either renewable firm capacity or larger
amounts of as-available capacity.
To adequately displace existing firm non-renewable resources in order to achieve 100 percent
renewable energy by 2045, both distributed energy resources as well as grid-scale resources must
substantially increase. To better understand the potential for distributed energy resources, Hawaiian
Electric worked with NREL to map opportunities for rooftop solar across Oʻahu. This mapping exercise
indicated that there is significant potential for rooftop solar and Hawaiian Electric recognizes that this
component is critical to Hawaiʻi’s clean energy future. Regardless, it is not possible to achieve a fully
decarbonized energy system without grid-scale renewable resources.
Grid-scale renewable energy projects are currently developed through a competitive bidding process in
which Hawaiian Electric identifies capacity on their system to receive renewable energy resources and
issues a Request for Proposal (RFP). Developers work directly with individual landowners to identify
locations for energy resource projects, then submit proposals to Hawaiian Electric in response to the
RFP. It is important to understand that for projects to be interconnected with the Hawaiian Electric grid,
they can only be sited in areas that have transmission infrastructure with adequate capacity;
furthermore, projects are typically sited in close proximity to existing transmission infrastructure to
minimize the need for extensive transmission lines.
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To better understand the potential for future development of grid-scale renewable resources and to
plan for the transmission infrastructure needed to support these resources, Hawaiian Electric conducted
a Renewable Energy Zones analysis, which is an industry-standard approach to identify areas where
there may be opportunity to site potential renewable resources. In this case, the analysis evaluated the
potential for development of solar or land-
based and offshore wind energy resources,
as these are currently the most affordable
and feasible resources for which data are
currently available; however, the analysis
does not preclude the integration of other
types of renewable resources as they
become more readily available in the future.
To help address known conflicts, areas with
certain characteristics or land uses were
excluded from the analysis including tsunami
inundation and flood hazard zones,
productive agricultural lands,1 urban zones,
conservation lands, and areas with slopes greater than 30 percent, among others. The results of the
analysis identify areas of technical potential (i.e., areas that may be suitable for renewable energy
generation projects); these areas are geographically delineated into specific zones based on potential
interconnection points with the existing electrical grid. The preliminary results of the Renewable Energy
Zones analysis were shared in the presentation and are available online at
www.hawaiipowered.com\oahu. However, the results are entirely based on technical data and do not
reflect community priorities. As such, Hawaiian Electric is seeking community input regarding suitability
of areas within the Renewable Energy Zones, both in terms of specific locations that may be desirable
for development of renewable energy resources as well as those that are not preferred. There are
multiple options for providing input including in-person and virtual tools offered during the Renewable
and Resilient Energy Workshops as well as online at www.hawaiipowered.com\oahu; the online map
includes the ability to drop a pin and add comments identifying those places that may be suitable as well
as areas that are undesirable for development of renewable energy projects. The input gathered
through this process will be used to refine the Renewable Energy Zones analysis, which will be used to
guide planning efforts for transmission infrastructure needed to support future renewable resource
development, as well as to inform developers regarding potential site suitability for specific renewable
energy projects through the RFP process.
1 Identification of productive agricultural lands was based on the University of Hawaiʻi’s Land Study Bureau (LSB)
soil classification system, which rates the productivity of soils throughout the state based on characteristics
including texture, slope, salinity, erodibility, and rainfall, and designates areas in categories ranging from A to E (with Class A representing the most productive soils and Class E representing the least productive soils). The
analysis excludes all areas with LSB Class A soils and 90 percent of areas with Class B and C soils.
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Opportunities for Community Input
Kurt outlined the various options for providing input during the workshops, as listed below. He stated
that all comments would be documented in a summary report.
• Verbal comments by participants attending in person and online (via the Zoom hand-raising function)
• Written comments on comment forms (for in-person participants) or via the Zoom chat function (for
online participants)
• Menti (online service accessed via personal computer or mobile device, which aggregates and allows
meeting participants to see all comments)
He also explained that the following tools are and will remain available, allowing the community
adequate time to review and provide input following the workshops. Recordings of the workshops by
ʻŌlelo Community Media will also be available on Hawaiian Electric’s website.
• Website for hybrid microgrid mapping project (www.hawaiipowered.com\etipp)
• Website for Renewable Energy Zones analysis (www.hawaiipowered.com\oahu)
• Workshop Recordings (https://www.hawaiianelectric.com/clean-energy-hawaii/community-
meetings)
In addition to the tools outlined above, comments may also be submitted directly to Hawaiian Electric
via email (igp@hawaiianelectric.com).
COMMUNITY FEEDBACK
KOʻOLAULOA MOKU (WAIMEA – KA‘A‘AWA)
OCTOBER 24, 2022
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Introduction
The first of six Renewable and Resilient Energy Workshops hosted by Hawaiian Electric was held in the
Koʻolauloa moku of Oʻahu, which spans from Waimea to Kaʻaʻawa. The workshop was held on October
24, 2022 at Kahuku Elementary School. There were approximately 13 attendees, as well as Hawaiian
Electric staff; a list of attendees is included in Attachment C.
At the request of the community, a follow-up discussion was held on December 1, 2022 at Hauʻula
Community Center. The follow-up discussion included approximately 22 attendees, as well as Hawaiian
Electric staff; a list of attendees is included in Attachment C.
Hybrid Microgrids: Community Feedback
Based on the presentation of technical information regarding hybrid microgrids (as summarized
previously in this report), Kurt reiterated that Hawaiian Electric is looking for input regarding siting hybrid
microgrids in Koʻolauloa, including other
criteria that should be included in the
analysis as well as specific facilities that
should be considered because they are
important to the community. He highlighted
the work that the Koʻolauloa community has
done relative to emergency planning and
preparedness, emphasizing that Hawaiian
Electric wants to learn from these efforts.
He explained that Alani would be facilitating
the discussion and reminded participants of
the various ways that they can ask questions
and provide input. Alani stressed that the
purpose of the workshop is to gather the community’s input to ensure the analysis is aligned with the
community’s priorities. The questions and input provided by workshop participants is summarized below.
• A workshop participant explained that each community within the Koʻolauloa moku is quite different.
For example, she stated that she is from Hauʻula which differs from Kahuku in terms of
demographics, community feelings and interests, as well as the physical terrain. She noted that there
were no residents of Kahuku in attendance, but that their input should also be obtained. Hauʻula is
very close to both the ocean and mountains, without much space between, which means that a lot of
the community is within the tsunami inundation zone. The community is accustomed to heading
mauka out of the inundation zone during emergency events. There is also a lot of concern about
shoreline erosion, which is resulting in loss of beaches, vegetation and eventually homes. Hauʻula
residents have been focused on emergency preparedness for a long time, as this community
experiences a lot of power outages. The cause of the outages is not always known and the
community is often uncertain of how long the outages will last. These types of uncertainties, whether
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associated with road closures or power outages, takes a toll on the community. Given these
concerns, Hui o Hauʻula has been planning a resilience hub for the larger Koʻolauloa community. It is
an ongoing effort, but there is a strong desire for the work to be completed. Similar to Hawaiian
Electric, they also have a technical assistance grant from ETIPP and have been receiving technical
assistance regarding microgrids. She expressed support for microgrids throughout the Koʻolauloa
moku and stressed the importance of working together to determine where they should be located.
Microgrids would help to maintain energy during emergency situations, which would allow the
community to feel more secure. She expressed appreciation for Hawaiian Electric taking time to work
through the information with the community and requested more information about the microgrid
maps.
• Another workshop participant reiterated that the various communities within Koʻolauloa are slightly
different. In general, everyone in Koʻolauloa knows to head mauka during emergency events,
although specific gathering locations and individual plans have been refined over time. The
community has gotten better about preparing with the proper equipment (batteries, coolers, etc.),
but access to power is critical. The other key issue in Koʻolauloa is road access; currently the most
vulnerable location is near the school in Kaʻaʻawa. The ocean comes right up to the road in this area,
and will be over the road within the next one to two years. He also noted another location with a
similar issue at Kukuna Road near Kualoa. He stated that he does not know how the State of Hawaiʻi
Department of Transportation (DOT) is planning to address this issue, but noted that Hawaiian
Electric’s lines run along the road. He emphasized that all of the partners need to be thinking about
how to address these issues now. Residents are aware and are alarmed, but nobody is addressing the
issues. He expressed the desire for Hawaiian Electric, DOT, and other partners to come together and
work with the community to solve problems, and acknowledged Hawaiian Electric’s efforts. Alani
noted that Hawaiian Electric can help to share these messages with other agencies and organizations.
Kurt explained that while Hawaiian Electric is focused on energy, there is a lot of other work
occurring in parallel. Hawaiian Electric is directly coordinating with other agencies and organizations,
including the City and County of Honolulu Office of Climate Change, Sustainability and Resiliency,
Centers for Resilient Neighborhoods (CERENE), and Hawaiʻi Emergency Management Agency
(HiEMA); the goal is to elevate concerns, connect the dots, and bring partners together.
• It was stated that critical infrastructure in this area includes the fire station, Kahuku hospital, internet
service, and stores. As such, the critical infrastructure is limited but it is important that each
community in Koʻolauloa has a microgrid. In terms of siting the microgrids, they should be in central
locations where the community typically gathers in the event of an emergency such as a tsunami.
• It was emphasized that although there is limited infrastructure in Koʻolauloa, those few facilities are
very important to the community. In addition to the hospital in Kahuku, there is also an Emegency
Medical Services (EMS) station and new fire station in Hauʻula. One concern is that the police and fire
personnel have not been part of the local emergency planning efforts. The community has an
emergency response team that has been actively planning and training for over ten years. In addition
to having an identified tsunami evacuation site, they are also working to develop a resilience hub.
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However, they have not been successful in their efforts to coordinate with police and fire personnel;
it was speculated that the local police and fire crews have been instructed not to talk with the
community emergency response team. The community thinks this coordination is critical, because in
the event of an emergency, they will need to be their own boots on the ground. Koʻolauloa is far
removed from Honolulu and emergency response agencies will likely be overwhelmed, such that the
community anticipates needing to be self-sufficient for 30 days for more. In this type of situation, it
will take everyone working together; with coordination, the local emergency response team can help
support police and fire crews (and vice versa). Alani noted that Hawaiian Electric can help deliver this
message to the relevant agencies.
• A workshop participant reinforced the need for microgrids in Koʻolauloa, specifically as part of
community resilience hubs; she stated that these planning efforts should be coordinated. She
explained that the resilience hub being planned by Hui o Hauʻula will be located on a hillside at an
elevation of approximately 60-90 feet (outside of the tsunami and flood inundation zone). Hui o
Hauʻula is working with medical partners and plan to include a medical clinic, dialysis capabilities, and
other similar services as part of the resilience hub. She requested that the Hauʻula resilience hub and
any other similar facilities planned in Koʻolauloa be specifically considered in Hawaiian Electric’s
microgrid planning efforts. Other facilities that should be included are the hospital and fire stations.
She also noted that without power, there is limited access to fresh water; it is critical that microgrids
also help to maintain access to water.
• When asked about specific locations where the community gathers during emergency events, one of
the workshop participants explained that people go to places located in mauka areas as lowland
areas are not likely to be accessible. Specific locations include the Mormon Church in Hauʻula and the
area around the dam in Kahana, which is a big open space where families from Kaʻaʻawa and
Punaluʻu gather to barbeque/picnic. He stated that others in the community have their own places
and things that they do during emergencies, and it is important that there is help for people during
the emergency event as well as afterwards during the transition and recovery effort.
• Kurt explained that microgrids require local energy resources to provide power during emergency
events (e.g., solar photovoltaics and battery storage, mobile generators, etc.) and asked about the
community’s priorities for powering microgrids. In response, one of the workshop participants stated
that in the event of an emergency involving a major grid outage (such as in Puerto Rico), the
community doesn’t necessarily care about the source of the power but rather with restoring
electricity as quickly as possible. There may be an increased focus on renewable or more efficient
energy source moving forward, but during an emergency, people want any form of power.
• As part of planning for the resilience hub, Hui o Hauʻula is considering solar photovoltaics as well as
other renewable energy technologies including wind turbines, geothermal, biomass, and possibly
hydrogen. They are currently reviewing various opportunities as part of their ETIPP grant. Based on
available information, biomass appears to be a promising concept. The particular strategy being
considered produces no emissions and is able to use greenwaste (which is abundant in Koʻolauloa).
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In addition to the comments discussed during the workshop, additional comments were received via
Menti and in writing. Specifically, in response to the prompting question posed via Menti – “Is the
proposed criteria aligned with the community’s resilience priorities (if not, what’s missing?)” – the only
comment received stated “yes.” A copy of the Menti response is contained in Attachment D.
Questions and comments that were received in writing on the response cards regarding the microgrid
mapping and related resilience issues are listed below. Copies of the written response cards are
contained in Attachment E.
• What kind of new poles for our erosive highway?
• Punaluʻu contains a large amount of agricultural land. Can those areas still qualify for a microgrid?
• Cost is a big issue for community. How is a microgrid going to impact electric bills?
• Do you start where the hub will be and work out or do you have another method of making the grid?
• We’ve been asking to have mango tree branches now hanging over our lines cut for months and
nothing has been done. It was stressful to think about it during hurricane season.
Comments provided by participants at the follow-up discussion held on December 1, 2022 at Hauʻula
Community Center are listed below:
• Impressed with Babcock Florida, they have a resilient community that was not affected during
Hurricane Ian. https://babcockranch.com/. Built to highest standards in FL. No houses were
damaged, and they had a huge microgrid in place.
• Oakland, CA are pushing their EVs to also charge back the grid (learned through Zoom mtg)
• BYU has done a good job with their solar layout
• We need more than just solar, we need backup.
• RE: Power frequent power outages - The community feels ignored. The community doesn’t have
much faith. Community has given up. We have an outage at least 1x/wk.
Renewable Energy Zones: Community Feedback
Based on the presentation of technical information regarding the renewable energy zones analysis (as
summarized previously in this report), Alani reiterated that Hawaiian Electric is looking for input
regarding siting of renewable energy resource development. He acknowledged the previous issues
related to siting of wind turbines in Kahuku and emphasized that Hawaiian Electric is trying to improve
the renewable energy planning process to avoid similar issues in the future. The questions and input
provided by workshop participants is summarized below.
• In response to the previous comment that Hui o Hauʻula is considering wind turbines as part of their
resilience hub, Alani noted that wind turbines are controversial and asked if this is something that is
being discussed with the community. One of the workshop participants stated that he doesn’t think
there is anything wrong with turbines, but they must be properly sited. In the case of Kahuku, the
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turbines were placed too close to the community. Based on research of other wind energy projects, it
is understood that wind turbines in Germany are located at least one mile from the nearest residence
or farm. We should be learning from others to incorporate the best technology and information
regarding health impacts. The people who sited the turbines so close to the school are incompetent,
just like those involved in the rail project. He stated that he would like to see wind turbines at the
State Capital, Department of Health, and City Hall; they should have to live with the wind turbines as
that is what the Kahuku community has to live with 24/7. He noted that he was one of the first
people to be arrested when the wind turbines were brought to Kahuku; although he lives in Kahana,
this is part of all of our communities. If people aren’t willing to put the wind turbines next to a high
school in Hawaiʻi Kai, they shouldn’t put them in Kahuku.
Kurt acknowledged these concerns and the need for improvements in the renewable energy
development process; previous efforts did not adequately include the community and there have
been many lessons learned. He explained that these workshops are part of an effort to improve the
renewable energy development process, particularly engaging the community earlier in the process.
Hawaiian Electric is seeking input from the community to help inform future Requests For Proposals
(RFPs), which is the process by which the grid-scale renewable energy projects are identified and
selected for development. He stated that Hawaiian Electric has learned a lot from talking to the
community, including Hui o Hauʻula and Kukea Kahuku, and recognizes the need for improvements.
He explained that significant improvements have resulted from recent efforts by the West Oʻahu
community based on their concerns with renewable energy development. In response to an RFP for a
shared solar program, community leaders came together and aligned their interests, then submitted
a letter to the Public Utilities Commission (PUC) requesting changes to the RFP process. The PUC
granted most of the community’s requests, which will be incorporated into all RFPs moving forward.
Kurt emphasized that this is the type of work that Hawaiian Electric hopes to facilitate with other
communities around the island.
• A workshop participant stated that there has always been a lot of wind in the back of the valleys. He
emphasized that there is wind in the valleys on both sides of the island but acknowledged that it will
be difficult to get transmission lines across the mountains. However, he stated that he thinks wind
turbines could be sited in the middle between the mountains, as there are no residents in this area
and the turbines could serve the populations on either side. He acknowledged that investors might
not like this arrangement, but he thinks this is the best long-term solution for wind and even solar
energy projects. He also noted that all houses should be required to have solar photovoltaic systems,
with lease programs or other arrangements that are user-friendly and affordable enough to allow for
system upgrades.
• A question was asked about the timing of the peak power demand on Oʻahu. Colton explained that
the greatest demand for electricity on a daily basis is typically around 7:00pm. Although fairly
consistent throughout the year, usage typically peaks in September or October (as this is when it
starts getting dark earlier, but is still fairly warm so air conditioning units are still being used). The
peak power demand on Oʻahu (around 7:00pm in the September to October timeframe) is
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approximately 1,200 megawatts, which far exceeds that of the neighbor islands but is much lower
than other states.
• A workshop participant emphasized that there will continue to be development which will occupy a
lot of the open areas shown on the map. As such, renewable energy projects should be sited as far
back as possible from these areas, in the middle area between the mountains, away from schools and
other development.
• A workshop participant stated that she recently attended a presentation hosted by the Board of
Water Supply about the Canary Islands, an archipelago similar to Hawaiʻi. She stated that there is an
impressive amount of work being done to research and collect data on a wide variety of issues
related to water supply as well as renewable energy. She encouraged others to learn more about this
work as the Canary Islands are ahead of many other locations and are willing to share information.
• A workshop participant noted that she previously lived on Pacific Heights and that this area was very
windy. She stated that she isn’t sure how to best capture that wind but emphasized that it funnels
through the valleys. She agreed with the approach of talking with communities to figure out how to
best approach renewable energy solutions and stressed the need to amplify the voice of
communities that feel invisible. She stated that she hopes community members will join these
conversations, as it is important to capture their input. She also discussed the value of community
centers, such as the community center in Hauʻula which serves everyone in Koʻolauloa. She explained
that community centers engage people, day and night; it is a comfortable place where people feel
safe and can spend time with their friends. She stated that she hopes Hawaiian Electric will continue
trying to engage with the community as it is an important step and she believes that people want to
give input.
Alani noted that although it may not be Hawaiian Electric’s kuleana to build a community center, it is
important to consider the human element that makes community centers so valuable. If people don’t
have places to come together and talk about issues, such as these discussions about microgrids and
renewable energy, then they won’t know what is going on or the appropriate steps to take. The
workshop participant explained that the community center in Hauʻula has been there for a long time.
It was mothballed but has since been turned into a great facility; unfortunately, it is located in the
flood inundation and tsunami evacuation zone. As soon as the resilience hub is built, everything from
the community center will be relocated to this location as it will be in a mauka location. She noted
that the Federal Emergency Management Agency (FEMA) helps to replace buildings that are located
in the flood inundation and tsunami evacuation zone, so Hui o Hauʻula is trying to get their help. She
stated that similar efforts are needed to relocate these types of facilities around the island. She also
noted the importance of getting input from the community so that the culture can be incorporated
and make people feel at home. People who are engaged and spend time together, build social
capital, which is the most important thing in the time of emergencies.
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In addition to the questions and comments discussed during the workshop, additional questions and
comments were received in writing, as listed below. Copies of the written response cards are contained
in Attachment E.
• No windmills should be as close to homes, schools and farms as the monster turbines in Kahuku are.
• Kurt was a very informed and informing speaker. Excellent, thank you. Learned a lot. Will be more
informed in future to have more meaningful input. Appreciate early community involvement.
• Are horizontal wind turbines less expensive than vertical? How well do they tolerate salt air? No solar
farms on agricultural land! No vertical wind turbines!
• No vertical wind turbines! Horizontal turbines are okay.
• Good to know what’s going on and all of the changes that affect our electric utilities and how it
trickles down to us.
Comments provided by participants at the follow-up discussion held on December 1, 2022 at Hauʻula
Community Center are listed below:
• Supportive of horizontal turbines
• Completely against wind turbines
Shellee Kimura, Chief Executive Officer of Hawaiian Electric, provided closing remarks. She expressed her
appreciation for community members joining the workshop and engaging with Hawaiian Electric. She
emphasized the importance of the community’s perspective and encouraged others to participate in the
future. She noted that Hawaiian Electric understands that these are complicated topics and it is difficult
for many people to engage; however, community knowledge and experience is critical to developing
real solutions for Hawaiʻi. Recognizing that the work being discussed may not be built for ten or more
years, she stressed that the process is starting now; input obtained through these types of discussions
result in decisions that get baked into the plans, which ultimately result in infrastructure being built in
people’s communities. Therefore, it is important that the community is part of the conversation as the
plans are developed. The goal is to create a system that serves the community in alignment with
community values. She explained that we all have important work to do to achieve 100 percent
renewable energy while ensuring affordability and equitability, both in terms of economics as well as
geography. She acknowledged that transforming the entire energy ecosystem is challenging,
underscoring the importance of working with the community. Because energy intersects with so many
aspects of peoples’ lives, changes to the energy ecosystem can both positively and negatively affect the
community. The goal is to work with the community to design the system in a way that results in the
most positive impacts as possible. She reiterated the importance of the community’s input and thanked
the participants for their time and interest in the process.
Kurt also acknowledged CERENE and explained that they are engaging with the community at the
grassroots level to develop resilience hubs, such as the work being done by Hui o Hauʻula. Miku
Lenentine explained that CERENE is based out of Kapiʻolani Community College and works with both the
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University of Hawaiʻi Department of Urban and Regional Planning and the City and County of Honolulu
Office of Climate Change, Sustainability and Resiliency. She stated that CERENE is working with
neighborhood groups and community centers to identify potential locations for resilience hubs across
the island. She emphasized the comments shared by one of the community participants about the
importance of community centers and the human element of resilience during emergencies. She stated
that CERENE would be holding a meeting in Koʻolauloa on November 16, 2022 at which time they would
share more details and have follow-up discussions regarding reslience hubs.
COMMUNITY FEEDBACK
WAIʻANAE MOKU (NĀNĀKULI – KEAWAʻULA)
OCTOBER 26, 2022
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Introduction
The second of six Renewable and Resilient Energy Workshops hosted by Hawaiian Electric was held in
the Waiʻanae moku of Oʻahu, which spans from Nānākuli to Keawaʻula. The workshop was held on
October 26, 2022 at Agnes Kalanihoʻokahā Community Learning Center. There were approximately 19
attendees, as well as Hawaiian Electric staff; a list of attendees is included in Attachment C.
Hybrid Microgrids: Community Feedback
Based on the presentation of technical information regarding hybrid microgrids (as summarized
previously in this report), Kurt reiterated that Hawaiian Electric is looking for input regarding siting
hybrid microgrids in the Waiʻanae moku, including other criteria that should be included in the analysis
as well as specific facilities that should be considered because they are important to the community.
He explained that Alani would be facilitating the discussion and reminded participants of the various
ways that they can ask questions and provide input. Alani acknowledged the past history of
environmental justice and inequity issues experienced along the Waiʻanae coast and stressed the
importance of community input to the energy planning process. The questions and input provided by
workshop participants is summarized below.
• One of the workshop participants expressed frustration that Hawaiian Electric is addressing the three
communities that are currently hosting the majority of the renewable energy projects on O’ahu. She
stated that as a member of a community that has been heavily affected, she would rather point to
other communities than to identify locations in her community. She emphasized the need to address
the injustices associated with all of the existing facilities hosted on the Waiʻanae coast and stated
that she doesn’t want to offer up places for more facilities that the community doesn’t want. She
stated that the community understands the need for renewable energy but thinks that the rest of the
island should share the burden of hosting these facilities.
Alani clarified that workshop are being held to solicit input from each of the six moku around the
entire island of Oʻahu; he emphasized that the feedback received from each workshop would be
documented and made available for all stakeholders to review. He also noted that the intent of the
microgrids is to provide a benefit to the community by maintaining power at critical facilities during
emergency conditions. For example, he suggested that the Waiʻanae Coast Comprehensive Health
Center is an important facility that may benefit from a microgrid (but noted that specific facilities
should be identified by the local community). The participant acknowledged the potential benefit of
microgrids to the community, but emphasized that the rest of the island needs to share the burden –
if not in terms of renewable energy projects then in other ways that can improve resilience (such as
access roads). If other communities don’t have adequate space or the land is too expensive to site
renewable energy facilities, they can instead help with funding to improve resilience in areas that are
hosting those facilities. She emphasized that social justice crosses a multitude of community lifelines
and the discussion shouldn’t be limited to only energy systems; other issues that should be
addressed include transportation systems, food sustainability, and support for the few remaining
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farms. In summary, she stated that she appreciates the information being requested but instead of
identifying where projects should go, she would like to focus on support for Waiʻanae.
• Another workshop participant expressed concern about the resilience of existing infrastructure in the
event of a major hurricane. She stated that all infrastructure, including Hawaiian Electric’s
transmission system along Farrington Highway, needs to be bolstered. Several poles in Nānākuli have
been replaced, but there are other locations along the Waiʻanae coast where the system needs to be
strengthened. There is no value in establishing microgrids if there isn’t a way to transmit power to
them. As such, there needs to be a focus on improving the infrastructure to ensure that power can be
delivered to microgrids, wherever they might be. She noted that there were previously discussions
about undergrounding the transmission lines along Farrington Highway and acknowledged the
concerns with cost, degree of disruption, as well as sea level rise. She stressed the need for action to
be taken before another disaster strikes, noting that too often progress is not made due to cost or
lack of consensus. Action is needed now to provide adequate infrastructure to support microgrids. In
terms of specific facilities, she agreed with the need for a microgrid that serves Waiʻanae Coast
Comprehensive Health Center as well as the dialysis center in Waiʻanae.
Colton acknowledged the comments regarding the need for further hardening of the infrastructure.
He noted that Hawaiian Electric recently filed an application with the Public Utilities Commission
(PUC) for this very purpose. He emphasized that there is no single solution that will address all issues.
Although microgrids are the focus of the current discussion, they are only one of piece of the larger
puzzle that Hawaiian Electric is trying to solve. Kurt added that this is the exact type of feedback that
Hawaiian Electric is seeking. He reiterated that microgrid analysis is just one part of the overall
solution, and agreed that other efforts such as hardening existing infrastructure also needs to happen
in parallel. He explained that hybrid microgrids are a new concept and this is one of the first times
that Hawaiian Electric is discussing this topic with the community. He emphasized that the effort is
still in the early stages and the information is incomplete as community input is still needed.
• Alani highlighted one of the comments received via Menti, which states “the concept is fantastic and
relevant to the current situation of our energy crisis, but one criteria that I wonder is if cultural sites
were included in consideration that may lay in scientifically ideal locations for renewable energy.”
Kurt responded that the analysis to date has not included this type of information, but that it will be
critical to the process moving forward. Specifically, Hawaiian Electric is looking for site-specific
information from the community that neither Hawaiian Electric nor potential developers may be
aware of. Alani noted that any project that requires PUC approval will need to undergo some level of
review by the State Historic Preservation Division (SHPD). However, he provided an example
illustrating that SHPD is not always aware of all cultural resource issues that may be important to the
community, and thus it is critical to obtain the community’s cultural knowledge.
• Kurt also acknowledged another comment received via Menti regarding cost: “Who will pay to
develop or construct a microgrid.” He explained that the microgrid mapping is part of a larger effort
associated with a PUC docket for a microgrid service tariff. As part of this effort, all of the microgrid
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mapping information including community feedback will be used to develop a Request for Proposal
(RFP) for developers to submit bids for construction of microgrids on Oʻahu. Ken clarified that the
genesis of the microgrid mapping effort was to support a program in which customers (or a group of
customers) could self-fund the development of a microgrid. The data that is generated through the
mapping process can also be used to identify opportunities for Hawaiian Electric to improve
reliability. For example, Hawaiian Electric could pursue a microgrid as an alternative to building a new
transmission line to meet reliability metrics. As such, there are different funding mechanisms that
can be used for development of microgrids.
• Alani asked if there are specific locations, particularly in mauka areas, where the community gathers
during emergency events. A workshop participant noted that an important mauka area especially for
the Nānākuli and Māʻili community is the Lualualei Naval Magazine as it is relatively accessible and is
one of the higher spots in the region.
• A workshop participant asked if there is a specific size for microgrids. For example, if a microgrid
were developed for the Waiʻanae Coast Comprehensive Health Center, would surrounding areas also
be included in the microgrid? Ken responded that under the hybrid microgrid program, the maximum
size would be approximately 3 megawatts (which roughly equates to the capacity of a distribution
feeder line); microgrids can also be smaller in size. He explained that the size of a microgrid is
dependent on the circuit capacity and architecture, as well as the various criteria considered in the
mapping analysis. Alani asked Ken to provide an example of an area that could be served by a 3-
megawatt microgrid. Ken responded that the circuit that feeds the area between the elementary
school in Waiʻanae up to Kaʻena Point is generally about the maximum size of a hybrid microgrid.
Another example is illustrated on the map contained in the technical presentation showing two
potential hybrid microgrids in Hauʻula, both of which include various homes and businesses. Alani
suggested that Hawaiian Electric could compile maps showing potential microgrid locations in the
Waiʻanae moku.
• A workshop participant stated that it is possible to identify locations that serve as community
gathering areas, but it is also important to have trained community volunteers to receive people that
would be coming to these locations. She noted that she lives right down the street from Kaupuni
Park; a lot of community members come to this location but it is not always managed in an orderly
manner (e.g., vehicle parking, tent placement, etc.). If sites are identified on a map as gathering
locations, there needs to be some sort of organization or command so that they can temporarily
welcome as many people as possible. Alani noted that Hawaiian Electric directly coordinates with
disaster management agencies and other similar groups, and emphasized that this should be part of
the discussion moving forward.
Kurt explained that because microgrids can be isolated from the grid, they require a backup power
source. Therefore, he asked the community to think about what types of technologies should be
considered in powering microgrids in the Waiʻanae moku. He explained that the community can provide
feedback on this question moving forward.
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In addition to the comments that were raised during the workshop, additional questions and comments
were received via Menti. These comments are summarized below; copies of the responses are
contained in Attachment D.
The following questions and comments were received via Menti in response to the question: Is the
proposed criteria aligned with the community’s resilience priorities (if not, what's missing)?
• You have done a good job but it needs to remain open for unforeseen scenarios. Also, the Veterans
centers need to be included.
• In looking at how and where do we keep the Waiʻanae Moku powered during outages be of man or
natural disasters, our distribution points/places - which are still being identified, and could be
"Resilience Hubs."
• Which is the most ideal / powerful renewable source of energy you guys are looking at currently that
still "works" for the community? Or just the source you have researched the most that works for
Hawai’ʻi?
• The concept is fantastic and relevant to the current situation of our energy crisis, but one criteria that
I wonder is if cultural sites were included in consideration that may lay in scientifically ideal locations
for renewable energy.
• Identified mauka "safe havens" locations in each ahupuaʻa
• What’s smallest grid possible? Does it make sense functionally, operationally and financially to try to
create small compact ones - to address transmission vulnerability?
• How much of a financial impact would it be to create microgrids in Waiʻanae? Can we afford it? Who
pays for it?
• Areas directly around our schools that are emergency and/or hurricane, tsunami shelters
• ʻAe, HECO must consider both oral history not documented by cultural organizations as well as
documented written history cultural sites. Many ʻohana have stories and significant places not made
public or stories passed down that makes sites kapu.
• Influence the military facilities to become sites
• Military sites (2)
The following questions and comments were received via Menti in response to the question: What other
community facilities are missing or should be included in the analysis?
• Kaupuni Park in Waianae Valley Homestead
• Community Learning Center in Māʻili
• Military sites indeed
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The following questions and comments were received via Menti in response to the question: How
should these microgrids be powered?
• Firm power sources vs intermittent. Things that don't add environmental disposal hazards.
• Firm power not intermittent. Environmentally safe resources.
Renewable Energy Zones: Community Feedback
Based on the presentation of technical information regarding the Renewable Energy Zones analysis (as
summarized previously in this report), Kurt reiterated that Hawaiian Electric is looking for input
regarding siting of renewable energy resource development. He acknowledged there are improvements
that need to be made to the planning process and this is part of an effort to better include community in
that process. The questions and input provided by workshop participants is summarized below.
• A workshop participant referenced the 138kV substations shown on the Renewable Energy Zones
maps and noted that these are locations where electrical voltage is increased to allow for
transmission across further distances. He asked whether the electricity used for the microgrids could
be transmitted at lower voltages, such that it would not need to be increased to the 138kV level. In
this case, microgrids could be used to
provide electricity for the local
community (i.e. more distributed rather
than centralized). Colton confirmed that
this is the approach being considered for
microgrids. Given the anticipated size
(up to approximately 3 megawatts), the
microgrids would be localized and
interconnected at the distribution level
(via lower voltage lines). In contrast, the
Renewable Energy Zones analysis is
looking at opportunities for large-scale
renewable energy generation projects that would serve the island-wide grid. As such, the map is
intended to show areas with technical resource potential that may be suitable for development. The
analysis will help Hawaiian Electric to identify how much renewable energy generation could be
developed in any given region to help meet the renewable energy goals for the island. To allow for
safe and efficient use of the electricity, these larger-scale projects would need to interconnect at the
138kV level.
• The participant also noted that the analysis is focused on wind and solar photovoltaic technology and
asked if geothermal is also being considered. Ken responded that although geothermal power may be
possible, there currently is no data available specific to geothermal potential. He explained that the
Renewable Energy Zones analysis will help to determine how much energy Hawaiian Electric should
plan for in different regions around Oʻahu so they can develop the necessary transmission
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infrastructure to interconnect future projects. Colton added that there may be potential for
geothermal energy, but there is no data regarding specific locations or quantities for the island of
Oʻahu. Currently, the only data available relates to wind and solar potential; if and when data
regarding geothermal (or other types of renewable energy resources) become available, these can be
included in the analysis. Katy noted that the National Renewable Energy Laboratory (NREL) is currently
working to incorporate geothermal into their renewable energy potential tool and hopes this will be
available for widespread use by 2024. She noted that there are some datasets for other renewable
energy technologies such as hydrokinetic marine. The workshop participant asked if there is data
available for hydrogen technology; Katy responded that NREL is also working on this information.
• A workshop participant referenced the Renewable Energy Zones map and emphasized that it does
not show any resource potential for areas such as Honolulu and Pearl Harbor. She asked about the
potential for rooftop solar in these areas, including high-rise buildings. Although rooftop solar
involves planning in smaller increments, she stated that there is significant potential especially given
recent discussions about allowing for solar panels to exceed maximum building height limits. By
excluding this information, she stated that a significant amount of resource potential is being
ignored. She emphasized that the community’s desire to maximize potential on existing structures
rather than focusing on raw land was previously raised by the West Oʻahu/Kalaeloa Clean Energy
ʻOhana, and she is disappointed that this input is not reflected in the Renewable Energy Zones
analysis. Colton acknowledged the previous input provided by the West Oʻahu/Kalaeloa Clean Energy
ʻOhana; he explained that this is being addressed as part of a separate effort and apologized that it is
not reflected on the Renewable Energy Zones maps. He committed to sharing this information the
next time Hawaiian Electric meets with the community. He explained that the Renewable Energy
Zones analysis excludes certain areas (for example, high quality agricultural lands, urban areas,
conservation lands, etc.) as a way to limit the potential for conflicting land uses; this is the reason
why there is no potential shown for certain parts of the island. Katy also noted that the analysis is
based on a 90-meter scale. Another workshop participant emphasized that even if the analysis
indicates there is no potential for large-scale projects, it should still indicate that there is potential for
rooftop solar; this is critical to help address equity across geographic regions and to encourage
rooftop solar and other small-scale projects.
• A workshop participant shared information regarding the Energize Waiʻanae program, which is part
of Solarize 808. This program will be rolled out in the Waiʻanae moku starting next month.
• Another workshop participant explained that they are part of the Renew, Rebuild Hawaiʻi committee.
On November 17, the committee is hosting a webinar regarding geothermal energy, including
representatives from Puna Geothermal, the University of Hawaiʻi, and other similar entities. He
stated that this may be a good opportunity to get information and other resources (and can be
shared with those who are not able to attend). He noted they recently hosted a webinar regarding
ocean thermal conversion technology (OTEC), which is another alternative form of firm power.
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• A workshop participant noted that the presentation showed that Oʻahu currently has 1,614
megawatts of firm capacity and 126 megawatts of renewable firm capacity. She indicated that these
resources together total approximately 1,700 megawatts and asked if this is the target capacity once
other renewable energy resources are brought online. Marc indicated that as other renewable
energy projects are integrated into the system, especially projects that include battery storage,
Hawaiian Electric will start retiring existing fossil fuel generation units which will decrease the total
firm capacity. For example, the recent retirement of the AES coal plant reduced firm capacity by
about 180 megawatts. The workshop participant asked what will happen in 20+ years when the
system is operating entirely on renewable energy resources, but existing solar panels reach the end
of their useful life. Colton explained that when a large fossil fuel generator such as the AES coal plant
is taken offline, it does not necessarily need to be replaced with exactly the same amount of
generation or energy storage. However, it is critical that the replacement energy is available on a
consistent basis to ensure reliability; various ways of addressing this issue include using a mix of
different technologies, as well as staggering the onboarding (and associated lifespans) of the various
generation sources.
• A workshop participant referenced the increase in electrical prices when the AES coal plant was taken
offline and asked how the transition to 100 percent renewable energy will affect prices. Colton
explained that although the coal plant produced extremely high levels of greenhouse gas emissions,
it also generated relatively cheap electricity. Therefore, increased price is one of the tradeoffs of no
longer buying power from the coal plant as part of the effort to comply with state laws and policies.
He explained that there have also been unforeseen events (including supply chain issues, economic
downturn, and the Russian invasion of Ukraine) that have driven oil prices significantly higher than
when the decision was made to retire the AES coal plant. However, he stressed that the goal is to
select the right mix of renewable energy technologies to be brought online at a deliberate and
efficient pace. Although it may not be possible to bring prices below their previous levels, they will be
stabilized such that ratepayers can be protected from external events such as a destabilized oil
market.
• A workshop participant asked about measures to protect the electrical grid from terrorist or
cyberattacks and whether spare parts are maintained to facilitate system recovery. Colton explained
that Hawaiian Electric has an entire team that is dedicated to protecting against terrorist and
cyberattacks. He emphasized that this effort is tightly coordinated with multiple agencies at the
federal and state level. He explained that although Hawaiian Electric is a small utility, the risk
exposure is high because Hawaiian Electric is the only entity that provides power for the entire U.S.
Indo-Pacific Command (PACOM); all other commands on the mainland are served by multiple
utilities. He confirmed that Hawaiian Electric also maintains various spare parts for its system,
including those needed to respond to attacks as well as hurricanes and other types of natural
hazards.
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In addition to the comments discussed during the workshop, additional questions and comments were
received via Menti and in writing. These comments are summarized below; copies of the responses are
contained in Attachments D and E (respectively).
The following questions and comments were received via Menti in response to the question: What are
the most important factors to consider for the siting of renewable energy on O'ahu?
• Diversifying the kinds of renewable energy and not just place such a huge focus on solar
• Finding technology that takes up less land space and has a smaller footprint
• Fair, not necessarily just equal, and pono distribution across ALL communities
• Designing tech and systems for high rises and town areas
• Concentration and permeation of projects within a defined geographic area (identify threshold to
manage number of projects, whether large or small)
• Physical security, cyber security, and accessibility for repairs such as large transformers.
The following questions and comments were received via the written comment cards:
• Are the areas of highest potential to host large renewable development be given highest priority
usage of that resource? Or will it be sent to the higher usage sites? Example: Will Waiʻanae and North
Shore side who have high land potential be given higher priority usage over Waikīkī (who is a high
energy user)?
• Do you see your prime prospective locations for large renewable development and microgrids
competing with sustainable agriculture plots and prime farming locations? Will you be willing to
relinquish prime energy development locations and allow diversified sustainable agriculture to take
the spot?
• I appreciate that the meetings are hybrid, that makes it more accessible.
COMMUNITY FEEDBACK
KONA MOKU (MOANALUA – EAST HONOLULU)
NOVEMBER 1, 2022
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Introduction
The third of six Renewable and Resilient Energy Workshops hosted by Hawaiian Electric was held in
the Kona moku of Oʻahu, which spans from Moanalua to East Honolulu. The workshop was held on
November 1, 2022 at Kapiʻolani Community College. There were approximately 36 attendees, as well
as Hawaiian Electric staff; a list of attendees is included in Attachment C.
Hybrid Microgrids: Community Feedback
Based on the presentation of technical information regarding hybrid microgrids (as summarized
previously in this report), Kurt reiterated that Hawaiian Electric is looking for input regarding siting hybrid
microgrids, including other criteria that should be included in the analysis as well as specific facilities that
should be considered because they are important to the community. He explained that Alani would be
facilitating the discussion and reminded participants of the various ways that they can ask questions and
provide input. Alani stressed the important of community-based knowledge and stated that the purpose
of the workshop is to gather feedback to ensure the analysis is aligned with the community’s priorities.
The questions and input provided by workshop participants is summarized below.
• A workshop participant stated that he recently completed a survey from the University of Hawaiʻi
Department of Urban and Regional Planning; a key question was about where residents would like to
get energy for their specific community. Similarly, he emphasized that the Center for Resilient
Neighborhoods has a similar place-based focus on issues such as energy, water, and other resources.
The survey included questions similar to those being posed by Hawaiian Electric and led him to think
about health-related facilities. He explained that he lives in an area dependent on Kalanianaʻole and
Kamehameha highways for access; if those roads are inaccessible, there would be limited options for
health care services. As such, he thinks it would be valuable for a microgrid to include the Straub
urgent care facility (located in the Hawaiʻi Kai shopping center). He emphasized that local facilities
such as urgent care centers may have to handle any medical issues until roads can be safely opened.
• Another workshop participant referenced a City and County of Honolulu initiative to convert their
entire fleet to electric vehicles. She stated that based on this initiative, theoretically all emergency
response vehicles will be electric vehicles. She asked if the analysis has considered baseyards or other
locations where the City and County of Honolulu’s vehicle fleets are charged and stated that these are
locations that will require energy. Ken responded that vehicle charging stations were not included in
the analysis and stated that this is valuable input.
• A workshop participant asked for further definition of microgrids and how these would benefit the
community. Alani offered an example based on his neighborhood, located in Kailua near Castle
Hospital. He stated that the hospital is a critical facility as it will provide key medical services during an
emergency; other critical facilities in this area include Kailua High School (which can serve as an
emergency shelter), Olomana Fire Station, and a Hawaiian Electric substation. All of these facilities are
located proximate to one another and are interconnected with the Hawaiian Electric grid. Installation
of a microgrid would involve reconfiguration and hardening of the electrical system to allow these
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facilities to be islanded (or sectioned off) during an emergency. If the island-wide grid were to lose
power, local energy resources (e.g., backup generators located at Castle Hospital) could be used to
power the various facilities within the microgrid.
Kurt asked representatives from the Center for Resilient Neighborhoods (CERENE) to also summarize
the work being done in the Kona moku. Bob Franco explained that CERENE received an Action 15
grant from the City and County of Honolulu Office of Climate Change, Sustainability and Resiliency,
and is partnering with the University of
Hawaiʻi Department of Urban and
Regional Planning to identify resilience
hubs in each moku across Oʻahu. CERENE
thinks of a resilience hub as a structure as
well as services that can be provided at
that structure. In addition to the types of
services that Alani referred to in his
example (i.e., medical services, emergency
shelter, fire station), other critical services
relate to food, water, and
communications. CERENE is conducting
community engagement workshops in each moku and preparing similar maps using data from the
University of Hawaiʻi Department of Urban and Regional Planning. He noted that this work is being
done with support from Hawaiian Electric, who provided funding for their resilience core leaders, and
CERENE is trying to get this to be part of student’s learning experience at Kapiʻolani Community
College. He highlighted the synergies between Hawaiian Electric and CERENE’s efforts, emphasizing
that the microgrids could provide the energy lifeline for the resilience hubs. He stated that the power
for the microgrid might not be located at the resilience hub as it could come from another nearby
source, utilizing solar or other generation resources. He emphasized that CERENE has also spent a lot
of time focusing on vulnerable populations, including kūpuna. He noted they also recently had a
workshop with Pacific Islander pastors to discuss their response to the COVID epidemic.
• A workshop participant asked for clarification regarding whether microgrids are only for emergencies
or whether they are also used for day-to-day conditions. Ken responded that the primary objective of
a hybrid microgrid is to provide back-up power in the event of an emergency, which is why the focus is
on siting them around critical facilities and/or in areas that are prone to outages. The workshop
participant stated that it seems important to have microgrids available in rural areas at all times, not
just in emergencies. Alani clarified that once installed, a microgrid is available for use at any time. Bob
Franco emphasized that it is important to also remember that a long-term purpose is also to
decarbonize the energy system.
• An online participant stated that she recently joined the resilience hub workshop at Waikīkī
Community Center. She explained that during the resilience hub workshop, they discussed gathering
areas that can be used by the community during an emergency; she stated that these gathering areas
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should be considered for microgrids. She noted that her group identified Kapiʻolani Community
College as an ideal gathering area.
Another workshop participant subsequently stated that he works at the Chancellor’s Office and
wanted to clarify that Kapiʻolani Community College is not a designated evacuation center; the
nearest evacuation center is Kaimukī Middle School. He also stated that Kapiʻolani Community College
is working with Kaimukī Middle School to develop a solar energy backup system across the street. He
noted that there are several emergency responders and other entities in the immediate area
(including the Red Cross, Department of Defense, Hawaiʻi Emergency Management Agency, Diamond
Head State Park, and Department of Accounting and General Services [DAGS]) that can be involved in
the discussion of energy needs; he stated that it is important to consider where the emergency
responders are located and what type of energy they need.
• An online participant submitted a question via the chat function, asking if there are any plans in place
for mobile microgrids to assist emergency response teams or organizations and emergency shelters
during natural disasters during times of crisis. Ken responded that there are plans in development that
would generally allow this type of response. For example, in the Koʻolaupoko region, Hawaiian Electric
worked with the community to conceptually identify areas that could be isolated from the grid in an
emergency and could host a mobile generator to provide power to certain critical facilities. He
explained that this ability exists, but it takes a lot of planning and engineering to implement. Colton
clarified that the generator is the mobile component; the facilities that are part of the microgrid are
fixed in place and the electrical components must be modified and hardened to support the microgrid.
• Another online participant asked about the type of power that can be used for a microgrid. Ken
responded that hybrid microgrids are designed to aggregate whatever energy generation resources
are available for the various customers within the microgrid. As many customers already have rooftop
solar and battery storage, this could provide a significant portion of the energy generation for a hybrid
microgrid; however, this may be augmented by other types of energy generation resources.
• A workshop participant asked if vacant land is being considered for microgrids. She also asked if
microgrids must be configured in a certain way, such as through triangulation. Ken responded that
microgrids are generally developed for customers that receive electricity from the utility.
Furthermore, a hybrid microgrid would generally include facilities that are served by the same
electrical distribution line. To develop a microgrid, isolation points are added to the system to allow
for those facilities within the microgrid to be isolated from the grid during an emergency.
The participant asked whether an area with open land could be used to develop facilities to create a
hybrid microgrid. Kurt referenced the work that CERENE is doing to identify resilience hubs; these may
have their own source of power or may be connected to a microgrid with other critical facilities.
Structures that are hardened and can accommodate people as a gathering place can also be
considered; however, facilities such as hospitals should be prioritized for their primary purpose.
• Another workshop participant stated he lives in the Makiki neighborhood and during emergency
events, most people shelter in place. He stated that he lives in Kalana Hale on Beretania Street; the
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surrounding area includes many buildings with a lot of kūpuna (over 60 or 70 years old) as well as a
food distribution center. He explained that there is a Foodland that has been vacant for 12-18 months;
he is not sure about the commercial viability but stated that it may be appropriate as a community
gathering location (without overwhelming other facilities such as medical centers). He also asked
about public utility-private partnerships with commercial kitchens or similar sites (such as Kapiʻolani
Community College). These are facilities where chefs can organize, with logistical support from other
organizations that may have excess food, to help feed people; he emphasized that power is critical for
these types of services.
Alani asked Hawaiian Electric staff to clarify the process for identifying locations for microgrids. Colton
explained that existing information in databases and reports has been used to identify institutional
facilities that provide various public functions, such as schools, state buildings, and emergency
shelters. He emphasized the need for community-based knowledge such as underutilized facilities that
may be modified to provide emergency services; he noted the importance of providing specificity to
help inform the microgrid development process. In terms of the process moving forward, Colton
explained that Hawaiian Electric has started identifying locations for potential microgrids; for example,
a microgrid was developed in Hana several years ago and another microgrid is currently being
proposed for the North Kohala district of Hawaiʻi Island. The intent is to expand the effort from these
singular opportunities addressing infrastructural needs to more broadly address community priorities.
The process to identify community priorities for microgrids is just starting; it will take several years to
sort through, prioritize, and refine the opportunities based on the available data and community
feedback. He also stressed that the need to figure out how individual microgrids will be funded.
However, he stated that he believes that microgrids will become an inherent part of Hawaiʻi’s energy
system in the future as the opportunities are better understood.
• An online participant stated that she is an associate professor at University of Hawaiʻi Department of
Urban and Regional Planning, and is working with CERENE and the City and County of Honolulu Office
of Climate Change, Sustainability and Resiliency on resilience hub planning projects. She explained
that they conducted a community survey in April and gathered community input regarding frequently
used community facilities that could be used as resilience hubs. She stated that it is an ongoing effort
but they would be happy to share the findings to date. She explained that their effort includes a
similar suitability analysis but because the resilience hubs would be community facilities, there is more
focus on factors such as hazard vulnerability, transportation accessibility, social vulnerability, and
community support; however, there is overlap and opportunities for collaboration.
She also asked for clarification regarding the microgrid analysis in terms of whether Hawaiian Electric
is seeking to identify facilities where microgrid equipment could be sited or facilities that a microgrid
could serve; she noted that these could be one in the same or they could be different, depending on
the scale. For example, is Hawaiian Electric trying to find sites to put solar panels to serve a microgrid,
or the facilities that could be served by those panels? Alani confirmed that the goal is to identify the
specific facilities that could be served by a microgrid based on the community’s specific priorities and
needs. Katy added that it is easier to move around the technology (for example, the customer-sited
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5
energy resources such as solar panels or batteries) than it is to move around essential facilities (for
example, a community gathering place).
A workshop participant stated that a relatively new issue that should be considered is ransomware or
hijacking facilities and asked how Hawaiian Electric would harden the grid to address those situations.
She also asked whether a microgrid would decentralize the grid operationally. Colton explained that
hardening serves to make the system more resilient; microgrids are only one component of this effort.
Ultimately, for a microgrid to function after a major storm or disaster, all components of that
microgrid (including the energy resource generation, as well as all of the wires that connect the
energy resource generation to the critical facilities) must be able to withstand the disaster. As such,
the electrical wires and lines forming the microgrid need to be hardened. He emphasized that it is also
important to harden other lines comprising the rest of the grid to help improve overall reliability, as it
isn’t possible to build a microgrid for every customer. Regarding cyberattacks, Colton explained that
this is an ever-growing challenge that many industries face, not just the energy sector. However, he
stated that Hawaiian Electric is particularly at risk because electricity is such an important part of our
society; in addition, Hawaiian Electric is the sole utility serving the entire U.S. Indo-Pacific Command
(PACOM). As such, he emphasized that Hawaiian Electric spends an enormous amount of their
resources and works directly with multiple federal and state agencies to ensure the energy system is
resilient and resistance to cyber threats.
With respect to the question about whether microgrids will result in a more distributed electrical
system, Colton indicated that it is yet to be determined what the future electric system will look like;
however, it is fairly certain that it will be more decentralized and microgrids are needed to make this
possible. It is unclear whether the system will be completely decentralized as there are certain aspects
of a resilient grid that requires larger, centralized resources.
In addition to the comments discussed during the workshop, additional questions and comments were
received via Menti and in writing. These comments are summarized below; copies of the responses are
contained in Attachments D and E (respectively).
The following questions and comments were received via Menti in response to the question: What other
community facilities are missing or should be included in the analysis?
• Multi-family homes and large walk-ups with multiple owners that can technically have renewable
energy sited and storage but there are implementation barriers to installation.
• Community gardens (2)
• Hawaiian cultural sites
• Homeless shelters and food pantries
• Can you help us understand why microgrids are good for communities? How can this new solution
speak to energy justice?
• Large landowners
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• Confused why schools were not included when there are so many unused/open parking lots and
rooftops that could (should) be generating clean energy which are spread across all communities and
are already public resources (not always year-round)
• Open space/parks such as Ala Moana Beach Park or Kapiʻolani Park
• Major grocery/retail stores for medicine and emergency supplies
• Narrow valley neighborhoods with only a few roads (and sub-trans/distribution lines) that lead to
entire load centers
• Sites with EV chargers
• Will you be able to explain microgrids again?
• Vulnerable utility lines
• Community centers, both public and private (i.e., within subdivisions)
• Multigenerational homes with elderly
• Domestic violence/women's shelters
• KCC + Leahi + Kaimuki Fire Station + Diamond Head Theatre + Diamond Head movie studio could be
resilience hub
• Critical shopping malls and nearby gas stations
• Don't forget about the community parks and pools
• Red Cross Headquarters is also nearby
• Grocery stores and large warehouses
• Language barriers
• Community Centers, Queen Theatre, National Guard Facility
• Security, including cameras to deter looting, which would probably happen in Waikīkī
• Entire school campuses - including student housing
• Convention center, after converted to an emergency shelter, and nearby shops
• Pumps for water treatment facilities and flood control; telecommunication towers
• Is this a way to bring nuclear or other dangerous power systems here?
• What is the span of a microgrid? How large or small of an area can a microgrid support?
• Major food distribution warehouses and non-restaurant kitchens
• Water pumping stations, sewage treatment, and hydroelectric facilities
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• Mobile microgrids to support emergency response teams, disaster resilience/response shelters,
medical device charging stations, and personal electronic needs
• Facility management centers
• Homeowners associations
• Energy efficiency within the selected grids
• Indigenous sites, areas of cultural importance, churches
• What happening to the energy wheeling law?
• What about allowing for off-grid ecovillage communities that would be less reliant on County services?
• Traffic control center, emergency management center, telecommunication hubs
• What about creating planning department guidelines to allow for ecovillage communities so people
can live off-grid, or at least less reliant on county services?
• FED/DOD must pitch in too ....
• Schools, community centers, community health centers, non-profits, areas where community
members already gather
The following questions and comments were received via the written comment cards:
• Could a personal microgrid be built so they are moveable (away from lava) or protected (from
hurricanes)?
• How will these projects be funded? Will the cost be put on customers?
• How is accountability and transparency built into this process, aside from gathering community input?
• What are additional outreach efforts the team is making to gather community input? Many people
from low income or working class backgrounds aren’t able to attend due to competing priorities (e.g.,
work, family, etc.).
• Great discussion! Glad that the community is being involved. Looking forward to more.
• Are there instances or examples that a microgrid can fail post-disaster?
• How do we pay for the microgrid?
• How long does it take to install a microgrid?
• What about broadband expansion?
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Renewable Energy Zones: Community Feedback
Based on the presentation of technical information regarding the Renewable Energy Zones analysis (as
summarized previously in this report), Kurt reiterated that Hawaiian Electric is looking for input
regarding siting of large-scale renewable energy resource development to decarbonize the energy
system. He emphasized that the results are preliminary but are being shared as part of an effort to
better include community in the energy planning process. Alani referenced concerns that have been
raised with respect to equity and social justice and stated that this is an opportunity for community
members to voice their opinion regarding specific factors and site suitability. The questions and input
provided by workshop participants is summarized below.
• A workshop participant asked if there is any consideration as part of the competitive bidding process
to require cost benefits or other community benefits for the communities hosting the projects. She
emphasized that so many communities are having bear the burden with no real recognition or reward.
Kurt responded that this is an excellent point and stated that there is important work to be done as
part of future procurement processes. He explained that the next Request for Proposal (RFP) will be
the Stage 3 RFP for Hawaiʻi Island, followed by the Stage 3 RFP for Maui and Oʻahu; these are currently
in the final Public Utilities Commission (PUC) review process. He stated that for the first time, these
RFPs include requirements for community benefits; these requirements are largely the result of input
received from communities such as West Oʻahu, which have had to bear the burden of much of the
infrastructure to date. He explained that this is a relatively new process and isn’t likely to be perfect,
but the goal is to ensure that the benefits are going directly to the host communities, with the
investment addressing needs identified by the community. He also emphasized that there is still work
to be done at the community level and there is ongoing discussion about other elements that can be
incorporated to make the process as equitable as possible moving forward.
• A workshop participant stated that there is a lot of open space between Kapiʻolani Community College
and 22nd Avenue; much of this area is associated with the Department of Defense and could be a good
place to site solar energy facilities. He noted that the neighborhood board tends to be concerned
about siting anything on Diamond Head, so it would be important to have discussions with that group.
He also stated that another location to consider relative to ensuring food availability is the area
around the airport, as a way to keep food moving either to supermarkets or other key sites.
• A workshop participant noted that the Renewable Energy Zones analysis is focused on solar and wind,
which are currently the main technologies. She asked how Hawaiian Electric’s Integrated Grid Planning
(IGP) process would incorporate new technologies (such as geothermal, offshore wind, hydrogen as
those technologies become more viable in the future. Colton confirmed that the Renewable Energy
Zones maps are based on solar and wind potential, because those are the resources for which data is
currently available. However, as part of the IGP planning process, the goal is to develop an energy
portfolio for the future; other technologies (such as geothermal, biomass, hydrogen) are candidate
resources being evaluated as part of that effort. Colton stressed that they are doing their best to
factor in advancements and cost of future technologies into the selection portfolio. As the process
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moves forward toward development, those technologies will be considered. He noted that the IGP
plan is intended to inform decision-making for the future, but what is actually developed in the future
will likely differ from the plan as there are many non-technical aspects (such as land use policy) that
will also factor into the final implementation plans. The workshop participant stated that there are
some technologies that are ready for implementation that haven’t necessarily been considered, such
as micro-hydropower with dams and pumped storage hydro facilities.
• A question from Menti was discussed: “Will nuclear power or other dangerous technologies be
considered as part of this process?” Colton stated that nuclear power is constitutionally banned in the
State of Hawaiʻi. As such, planning for the future energy system is not currently considering nuclear
power as an option.
In addition to the comments discussed during the workshop, additional questions and comments were
received via Menti. These comments are summarized below; copies of the responses are contained in
Attachment D.
The following questions and comments were received in response to the question: What are the most
important factors to consider for the siting of renewable energy on O'ahu?
• Current land cover
• Work in tandem with newer Customer Distributed Customer Energy Resource programs, including
aggregators, and Smart DER BYOD
• Will the sites that have highest potential for large renewable development be given high priority
access to those resources? (In other words, will they be used for their land but it all goes to high users
like Waikīkī/Urban Honolulu?)
• Cost
• Effectiveness of the location
• Community burden
• Cold beer!
• Native Hawaiian lands, no desecration
• Taking into account areas of historical/cultural/indigenous importance and preventing further mistrust
• Areas that lack their own generation
• Proximity to energy use
• The cost especially HOA groups with multi building complexes. How can those communities go solar
and be self-sufficient with a reasonable cost to owners?
• Geographic energy balance
• What about allowing for off-grid ecovillage communities that are less reliant on County services?
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• Impact on native species and whether the sites will cause a negative impact on indigenous flora/fauna
• Ecological factors
• Vacant lands but close to existing electric infrastructure
• While Honolulu doesn't have space for large development, they are the largest users of energy on the
island and waste it haphazardly for aesthetics. Will we charge them more to use the renewable energy
farmed in Waiʻanae / North Shore?
• Multiple uses (e.g., agrivoltaics)
• Community residents in that ahupuaʻa have had a chance to express their preferences for siting or the
aspects of a clean energy project. Placed on already developed land? Placed out of view? Allow the
community to shape the project, to inform location.
• Will this project compete with probable prospective agriculture plots? Will sustainable food planning
have to compete with your company striving for renewable energy? In other words, will you be willing
to relinquish prime location for agriculture?
• Intersect of cost, renewable project resilience, and environmental impact
• Financial incentives, "Energy Cash Back" incentives
• Locations with wind, wave, and solar resources but avoid negatively impacting cultural, historic,
natural and human resources
• Soil health
• Environmental impact and sustainability
• Existing infrastructure
• Community (includes ecological health) benefits
• Thoughts on vertical farming powered by renewable energy?
• Diverse portfolio
• Large scale utility sites should be kept in areas away from the general public
• Not losing efficiency because of a site that is far from the population that is using the energy; more
distance often times can lead less efficiency
• Renewable energy is actually clean
• The trade-offs should be well understood. For example, if we use vacant land for renewable energy,
that same land will not be available for affordable housing, or for more agricultural activities, etc.
• As we all just saw, an emergency proclamation could mean that dangerous technologies could be
implemented without public input.
COMMUNITY FEEDBACK
WAIALUA MOKU (KA‘ENA – KAPAELOA)
NOVEMBER 3, 2022
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Introduction
The fourth of six Renewable and Resilient Energy Workshops hosted by Hawaiian Electric was held in the
Waialua moku of Oʻahu, which spans from Ka‘ena to Kapaeloa. The workshop was held on November 3,
2022 at Waialua Elementary School. There were approximately 10 attendees, as well as Hawaiian
Electric staff; a list of attendees is included in Attachment C.
Hybrid Microgrids: Community Feedback
Based on the presentation of technical information regarding hybrid microgrids (as summarized
previously in this report), Kurt reiterated that Hawaiian Electric is looking for input regarding siting
hybrid microgrids, including other criteria that should be included in the analysis as well as specific
facilities that should be considered because they are important to the community. He explained that
Alani would be facilitating the discussion and reminded participants of the various ways that they can
ask questions and provide input. The questions and input provided by workshop participants is
summarized below.
• A workshop participant stated that it is possible for residents be off grid if they have adequate
resource generation (for example, solar photovoltaic panels and battery storage). To the extent that
residents are connected to the grid and have adequate resource generation, it is possible to create a
microgrid; however, this costs a lot of money. He stated that when people initially started installing
rooftop solar, Hawaiian Electric used to a formula to determine how much power they would buy but
this changed over time. He acknowledged that Hawaiian Electric needs to collect enough money to
cover their overhead costs but emphasized that consumers don’t want to pay any more than
necessary; he asked what Hawaiian Electric’s formula will be to balance these needs. Ken explained
that microgrids can be developed at different scales. For individual customers (such as a single
residence), he stated that Hawaiian Electric has programs in place that provide compensation to
customers for exporting electricity to the grid at certain times of the day; this also allows customers
to use their battery system for backup power. He noted that there is another program currently in
place (called “Battery Bonus”) which provides extra compensation to customers that add battery
systems. The purpose of the microgrid mapping effort discussed in the technical presentation is to
identify potentially suitable areas where multiple customers can create a microgrid using their
aggregated generation resources. Based on the current approach, this is a customer-based program
such that the microgrid would be set up and paid for by the customer; this could be a single resident,
a cluster of residents/businesses working together, or agencies that are trying to increase resilience
of their system. The participant noted that if the customer is a fire department or hospital (or
similar), the cost would come back to the taxpayers.
• A workshop participant stated that she works for the Board of Water Supply (BWS) and asked if
Hawaiian Electric has coordinated with BWS or other agencies such as the Department of Education
(DOE). She stated that it will be difficult to find a location on the North Shore that the community is
comfortable with, depending on the visual impacts associated with the infrastructure. She stated that
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it would be beneficial to collocate the infrastructure with other agency facilities that need to be
connected with the Hawaiian Electric grid. For example, depending on the size of the infrastructure,
it could possibly be collocated near the BWS reservoirs in Pūpūkea. She emphasized that the agencies
are typically very supportive of any efforts to assist with disaster preparedness. As a second point,
she also highlighted the fact that much of the available land along the North Shore is within the
tsunami evacuation zone. For example, Waialua Elementary School is within the tsunami inundation
evacuation zone; the only school that is not within the tsunami evacuation zone is the high school.
Therefore, any proposed infrastructure should be sited in mauka areas. Specific facilities that should
be considered for a microgrid include the hospitals in Kahuku and Wahiawa. Marc responded that
Hawaiian Electric has been working with BWS as well as other state agencies such as Hawaiʻi
Emergency Management Agency through their resilience working group. He also noted that Hawaiian
Electric’s Integrated Grid Planning process includes a stakeholder council, and BWS is represented
there as well. The workshop participant suggested bringing those entities together with the
community as this could make the process more efficient.
In response to the inquiry about the visual impacts, Kurt explained that microgrids typically do not
involve highly visible infrastructure. The primary components involve hardening the system, such as
replacement of existing wooden poles with new steel poles, to make it more able to withstand a
disaster event, as well as electric switching units allow that portion of the grid to be isolated. He
explained that they also require an interconnection point for some form of energy generation,
whether it is renewable energy resources or a mobile generator. Together, these components allow a
portion of the grid to be sectionalized and powered using backup energy in the case of an
emergency. He noted that Hawaiian Electric would like input regarding the types of backup power
the community would like to use for microgrids. He emphasized that there are no projects designed
yet, so this is still a conceptual discussion.
• A participant asked if the microgrids would require a lot of agricultural land. He emphasized that
much of the available land on the North Shore is agricultural land, including the land above the
pumping station and water tank along Kamehameha Highway. He asked if microgrid infrastructure is
allowed on agricultural land. Kurt responded that infrastructure would not be sited on the highest
quality (Zone 1) agricultural land, but possibly on lower quality (Zone 2) agricultural land.
The participant asked more specifically about the need for energy storage as part of microgrids and if
needed, whether this would occur on agricultural lands. Kurt explained that the need for energy
storage would be based on the generation source. He reiterated that no specific projects have been
designed yet, but if the community would like a microgrid powered by solar photovoltaics, then it
would likely need to include battery storage. He emphasized that determining the appropriate place
for siting energy generation is another part of the microgrid discussion for which Hawaiian Electric
would like to get community input.
Ken clarified that the genesis of the hybrid microgrid mapping effort was to enable customers to
identify whether a microgrid makes sense in any given location based on certain factors; however,
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the data can also be used to site microgrids. Colton explained that there are a number of reasons
that microgrids may be developed. In some cases, microgrids are developed by Hawaiian Electric to
improve grid reliability in certain service areas. For example, Hawaiian Electric uses the generators
that were built at Schofield Barracks to serve a microgrid for surrounding areas. However, Hawaiian
microgrids can serve other purposes to meet the needs of customers – either individually or working
together, perhaps in combination with a third party. As such, Hawaiian Electric is trying to facilitate
that process by creating maps that provide relevant information; he emphasized that community
input is needed to inform the analysis. He noted the previous questions regarding use of agricultural
lands and types of energy generation, stating that these questions are ripe for discussion if the
community is looking to develop a hybrid microgrid. He emphasized that these are decisions that
should be made by those who have an interest in developing a microgrid. To further clarify, he
explained that if an individual customer that wants to use rooftop solar and battery storage to run
their home or business off-grid, this type of microgrid would be implemented and funded by the
customer. In cases where Hawaiian Electric believes a microgrid is needed to improve grid resilience,
such as in a remote service area, this could be implemented as a utility project (assuming that it is
demonstrated to be cost effective in comparison to other alternatives as required by the Public
Utilities Commission [PUC]). Hybrid microgrids, in which utility infrastructure is used to connect
multiple customers, would be implemented and funded by that group of customers and/or a
developer; he emphasized that Hawaiian Electric is trying to provide these opportunities for
customers and has a tariff in place to help, but ultimately these actions would be customer-driven.
• An online participant noted that Hawaiian Electric is referring to “customers” but is also referring to a
public function for microgrids in terms of disaster preparedness. She asked whether these microgrids
would be publicly funded (for example, using federal or state funds) or whether the community
would need to pool their resources to provide the necessary funding. Kurt explained that the term
“customer” refers to individual residences as well as any other entity that receives electrical service
from Hawaiian Electric. In terms of funding, he explained that in addition to customer microgrids,
there could be some form of collaboration for larger scale microgrids such that they aren’t solely paid
for by the community. For example, there could be opportunities for funding to come from the rate
base or by issuing a Request for Proposal (RFP) for low-cost microgrid construction based on a
competitive bidding process. Alani emphasized that the focus of the current discussion are hybrid
microgrids that would support disaster preparedness for the community and would be publicly
funded.
The participant also explained that there are community groups working across the state as part of
the Hawaiʻi Hazard Awareness and Resilience Program. She explained that the group in Wahiawa
spent approximately a year and a half identifying areas of strengths/weakness and developing a plan
for their community. She suggested that Hawaiian Electric review those plans as they provide
detailed information from the community about specific structures requiring protection and areas
where infrastructure should be hardened. Kurt stated that this will be a valuable resource moving
forward; he requested help getting access to the reports. He explained that Hawaiian Electric has
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been working with Hawaiʻi Emergency Management Agency and other state and local agencies, but
that this level of specificity from the community will help to further inform the planning efforts. Both
Kurt and Katy emphasized that the goal is to identify specific facilities that are important to the
community but may not be in official datasets.
• A workshop participant expressed support for building microgrids in the community. He
recommended that the effort include an analysis of areas that may have existing asphalt (especially
asphalt in need of repair), as this would provide an additional community benefit. He emphasized
that infrastructure maintenance is a major issue on the North Shore, so solutions that incorporate
microgrid opportunities with reinforcing existing infrastructure will be well received by the
community. He noted that there could be opportunities if the community has plans to reuse the
sugar mill, or at shopping centers, or possibly by looking at historic land uses (for example,
agricultural land with disposal pits or old structures that may not be suitable for growing food); he
noted that these may be small areas but could provide infill opportunities for energy infrastructure
with minimal disruption to agriculture.
• A workshop participant stated that the microgrid concept is confusing, as she tends to think of a self-
contained power generating unit. If the desire is to have customers work together to form hybrid
microgrids, it would be good to identify and connect customers with grant programs and other
funding opportunities. For example, Hawaiian Electric’s stakeholder group could help to identify
these types of resources for the community. She added that definitions are important and
encouraged Hawaiian Electric to develop a list of key terms with the specific meaning as a way to
improve communications.
• An online participant submitted a question via the chat function, asking if microgrids are a resource
that would support emergency management in the event of an emergency. The participant stated
that there aren’t emergency shelters in the Waialua moku so any effective facility would have to be
up the hill towards Wahiawa; however, shelters and emergency facilities are needed before they can
be powered. Kurt confirmed that hybrid microgrids would be for critical facilities; in addition to the
type of facilities identified in the technical presentation, he also emphasized that it also should
include facilities that the community feels are important to have access to emergency power in the
event of an emergency. The intent is for microgrids to make the grid more resilient by addressing
specific vulnerabilities, thus contributing to emergency preparedness.
Kurt also explained that the Center for Resilient Neighborhoods (CERENE) is working on efforts
related to these community needs. For example, based on a need identified by Hui o Hauʻula, they
are currently working to build a resilience hub with the Hauʻula community. Ultimately, CERENE is
working toward identifying opportunities for resilience hubs for communities across the island. In
looking at the big picture, these two efforts dovetail in that if a community builds a resilience hub, it
could be integrated with a microgrid for backup emergency power. He acknowledged that it is a
lengthy and complex process but explained that there are a lot of efforts happening in parallel.
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• A workshop participant stated that it is not good to ask people what they think and put the cart
before the horse. He also stated the microgrid schematic in the technical presentation is pretty
conceptual, so he is trying to better understand the design of a microgrid. He also stated that it
would be nice if the design could be cookie-cutter and asked about the approximate footprint. He
understands that it is early in the process but emphasized that it would be helpful to have more
visuals. Alani acknowledged the input and stated that the team would work on providing more
concrete information. Marc added that an example of a hybrid microgrid serving multiple critical
facilities in the community could include a fire station, hospital, and emergency shelter all located
within approximately one-half mile of each other.
In addition to the comments discussed during the workshop, additional questions and comments were
received via Menti and in writing. These comments are summarized below; copies of the responses are
contained in Attachments D and E (respectively).
The following questions and comments were received via Menti in response to the question: What other
community facilities are missing or should be included in the analysis?
• Didn't see anything
• What will these micro grids look like?
• No more wind on north shore
• Visual impact on the landscape
• How big will they be?
• No offshore wind
• Looks fairly complete
• Social and economic justice
The following questions and comments were received in writing on the response cards and the online
chat function in Zoom:
• Like to see complete emergency kit to store with long shelf life (years)
• Like to see education of real disaster (film); i.e., tsunami, hurricane, etc.
• Politicians need to prioritize the dollars to prepare (i.e., evacuation centers and supplies)
• What would make a microgrid…a poor investment?
• Water is #1 – make sure Department of Water can get water out of the ground (i.e., energy for
pumps)
• Need stronger visuals that show footprint
• Microgrid is kind of confusing
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• Grants etc. to help customers
• Definition of terms
• Information regarding Hawaiʻi Hazard Awareness and Resilience Program:
https://www.representativeamyperruso.com/hharp
• Wahiawā is ready for and needs such support - as we will be a clear evacuation site, and the military
has told us many times that they will serve their own purposes first
• The Schofield-Wahiawā resiliency hub raises questions, for me, about that partnership, because we
have been told many times that Schofield resources will be used for Schofield first. Can you come to
Wahiawa and do a public presentation on that particular grid, please? Waialua definitely needs
separate and more geographically accessible resilience support.
Renewable Energy Zones: Community Feedback
Based on the presentation of technical information regarding the Renewable Energy Zones analysis (as
summarized previously in this report), Kurt reiterated that Hawaiian Electric is looking for input
regarding siting of large-scale renewable energy resource development to decarbonize Oʻahu’s energy
system. He emphasized that the results are preliminary but are being shared as part of an effort to
better include community in the energy planning process. He acknowledged that the North Shore is
carrying a heavy load with respect to renewable energy, noting that future RFP processes will
incorporate requirements for community benefits as part of a broader effort to improve energy equity.
The questions and input provided by workshop participants is summarized below.
• A workshop participant stated that the North Shore Sustainable Communities Plan is currently being
updated; this area (including Kahuku) currently has the greatest amount of renewable energy on the
island. She stressed that the community does not support wind turbines, particularly offshore wind
turbines. Alani noted this same comment on Menti and noted that community members can also add
similar comments to the mapping tool at www.hawaiipowered.com/oahu.
• A workshop participant stated that future RFPs should include legal language to ensure that
developers are compliant with the specific requirements so that the community doesn’t need to hire
their own lawyers. He emphasized that Hawaiian Electric should be in a position to make sure these
issues are addressed so it doesn’t fall to the community. Kurt stated that moving forward, the RFPs
will include stronger language that holds developers more accountable. He explained that there will
be a requirement for developers to document their dialogue with the community, the needs
identified by the community, and the commitments made to the community; these documents will
be made public as part of the RFP process and developers will need to comply with their
commitments over the full contract term for the project.
• A workshop participant stated that based on discussions at neighborhood board meetings, her
understanding is that rooftop solar programs are no longer available for the North Shore, in part
because Hawaiian Electric’s system cannot handle any more solar energy in this area. She indicated
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that this is something that Hawaiian Electric needs to consider if they want to move forward with
plans that include rooftop solar for resiliency. She also stated that other locations such as in East
Honolulu should be considered for future wind projects. In addition, she emphasized the value of
grant programs to help residents fund rooftop solar projects. Kurt acknowledged the comments and
referenced the Solarize 808 program, which is a collaboration between Hawaiʻi Energy and Hawaiʻi
Green Infrastructure Authority (HGIA). Through this program, community members that want to
install rooftop solar can work together and issue an RFP for developers or installers as a way to lower
costs. The program is starting in Kahuku and elsewhere in Koʻolauloa but will also be offered to the
North Shore and Waianae communities as well. He noted that there is an opportunity to incorporate
GEMS funding for people who qualify; in addition, Hawaiʻi Energy will work with homeowners to
lower their consumption in parallel with installing rooftop solar. He also highlighted another program
for shared solar (also referred to as community based renewable energy [CBRE]) which provides an
opportunity for those without the ability for rooftop solar to still get access to solar energy. He noted
that there has been a lot of improvements to the RFP process for shared solar based on community
input; for example, if a project were to be constructed in the Waialua moku, the community that lives
closest to the project would be given the first chance to subscribe such that they would directly
benefit from the project. He explained that the shared solar program is still in the RFP process, but
Hawaiian Electric will share more information with the community as the process moves forward.
• A workshop participant stated that microgrids seem fairly complex and require a lot of engineering.
He suggested that it may be possible to incorporate some of the legacy infrastructure on the North
Shore, specifically referencing the network of former plantation irrigation infrastructure (such as
reservoirs, canals, and channels) for hydropower. He noted that Dole is in the process of unloading
much of this infrastructure, but that water supply is critical to the agricultural community on the
North Shore. If there are federal funds and other partners involved, use of this infrastructure as part
of microhydro project (for example, a system that pumps water uphill at night with hydro power
when it rains while solar isn’t generating) could leverage resources and provide benefits in terms of
both energy generation and food sustainability. Marc emphasized that other technologies beyond
solar and wind are being considered and explained that the RFPs are structured in a way that allow
developers to propose projects using these other technologies.
• An online participant submitted a question via the chat function, stating that they heard offshore
wind is being planned off Ka’ena Point and asking if this is just a rumor as they don’t see any offshore
wind projects shown on Hawaiian Electric’s map. Colton responded that several developers
previously approached Hawaiian Electric regarding their interest in developing offshore wind. He
stated that currently there are no proposals being considered by Hawaiian Electric. He noted that he
is aware of at least one developer that has been discussing offshore wind with different
neighborhood boards, but his understanding is that this would not involve Ka’ena Point.
• A workshop participant noted that solar developers prefer to site solar project in flat areas, which is
typically agricultural land. He also noted that in terms of cost efficiency, projects that are proximate
to major overhead lines do not require the cost of constructing new transmission infrastructure. He
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offered the idea of suspending solar panels under the 46kV transmission lines, as this would solve for
issues related to topography and proximity to existing infrastructure.
• A workshop participant asked if Hawaiian Electric stays apprised of housing and other types of
development occurring in certain areas. He stated that there is a plan to add a large number of
affordable rental housing units in Waialua; he suggested that it would be good for Hawaiian Electric
to coordinate with the developers so they can incorporate elements into their development that
allow it to be part of the microgrid and other similar planning efforts (rather than something that just
gets added on later). Kurt explained that land use and plans for development typically depend on
landowner preference. The purpose of these discussions is to capture the community’s voice before
landowners come forward and agreements are put in place. He explained that for any type of
development, whether it is for renewable energy or housing, the developer and landowner would
need to address land use as part of the permitting and regulatory process. He also noted that prior to
the RFP process, Hawaiian Electric issues a Request for Interest (RFI) to solicit landowners that are
interested in developing renewable energy on their land. In terms of adding electric loads as part of a
new housing development, Colton explained that Hawaiian Electric works to integrate these into the
planning process as much as possible. He explained that they have an entire team focused on
providing electrical service to customers, and they proactively work with landowners and
development teams to educate them on Hawaiian Electric’s processes and to incorporate
requirements for electrical service into their development plans.
In addition to the comments discussed during the workshop, additional questions and comments were
received via Menti and in writing. These comments are summarized below; copies of the responses are
contained in Attachments D and E (respectively).
The following questions and comments were received via Menti in response to the question: What are
the most important factors to consider for the siting of renewable energy on Oʻahu?
• No more wind on north shore
• Visual impact on landscape
• Solar on rooftops
• Sea level rise and concurrent environmental issues (cesspools, tsunami zone, etc.)
• Equity
• Make sure electricity generated in community stays in community
• Social and economic justice
• Cost effectiveness
The following questions and comments were received in writing on the response cards:
• Like HECO to ensure subcontractors and supplies are legally compliant so community does not need
to hire lawyers
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• Can HECO help the community fight BOEM plan to develop offshore energy; not a popular idea
• Is there a plan to get energy infrastructure in the ground?
• In 10 years if electrical cars equal 90 percent of vehicles with no gas, how much increase in electrical
energy must be developed?
• Regarding agricultural land, we need an island-wide plan for energy land use
• Can land under the existing 46kV powerlines be used for solar? Note: If suspended or cables, the
topography will not be so significant.
• North Shore has most amount of renewables
• Solar on rooftops
• Put wind in East Honolulu next
COMMUNITY FEEDBACK
KO‘OLAUPOKO MOKU (WAIMĀNALO – KUALOA)
NOVEMBER 15, 2022
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Introduction
The fifth of six Renewable and Resilient Energy Workshops hosted by Hawaiian Electric was held in the
Ko‘olaupoko moku of Oʻahu, which spans from Waimānalo to Kualoa. The workshop was held on
November 15, 2022 at Windward Community College. There were approximately 16 attendees, as well
as Hawaiian Electric staff; a list of attendees is included in Attachment C.
Hybrid Microgrids: Community Feedback
As part of the presentation of technical information regarding hybrid microgrids (as summarized
previously in this report), Ken described a specific type of microgrid being pursued in the Koʻolaupoko
moku based on work done through the Koʻolaupoko Resilience Initiative working group over the last
several years. Through that process, certain areas within Koʻolaupoko were identified as critical
customer hubs (CCHs). These CCHs include areas with critical facilities that serve multiple community
lifelines; by adding switching equipment and other related components, these areas can be isolated
from the grid and powered using mobile diesel generators during an emergency event. He explained
that the CCHs identified through the Koʻolaupoko Resilience Initiative include multiple locations such as
Olomana, Waimānalo, and the Windward Mall area in Kāneʻohe. These CCHs were proposed as part of a
FEMA grant (Building Resilient Infrastructure and Communities [BRIC]), which would provide federal
funds for construction of the CCHs; although not selected for the original grant, the same CCHs will be
re-proposed as part of another upcoming grant opportunity.
Kurt explained that the energy system in Koʻolaupoko is particularly vulnerable because there is no
generation in the region and electricity is delivered via three transmission lines that traverse the Koʻolau
Mountains. Although Hawaiian Electric is working to harden this infrastructure, it is still possible that it
may not withstand a severe hurricane. He
stated that a lot of input was previously
provided by community leaders as part of the
Koʻolaupoko Resilience Initiative. He
explained that Hawaiian Electric is looking to
continue these discussions by getting
additional input on other criteria that should
be included in the microgrid mapping analysis
as well as specific facilities that should be
considered for a hybrid microgrid because
they are important to the community. He
explained that Alani would be facilitating the
discussion and reminded participants of the various ways that they can ask questions and provide input.
Alani stressed that the purpose of the workshop is to gather the community’s input to ensure the analysis
is aligned with the community’s priorities. The questions and input provided by workshop participants is
summarized below.
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• A workshop participant asked how large of an area a microgrid can serve. Ken responded that hybrid
microgrids can generally serve an area equal to the area served by one distribution feeder. At the
neighborhood level, this would be about one hundred homes (plus or minus); if considering a large
facility (such as Windward Mall), a hybrid microgrid could also include some surrounding areas. He
noted that microgrids can also cover smaller areas.
• An online participant asked if there is a timeframe for providing input on the hybrid microgrid
mapping effort. Ken explained that this initial effort conducted by the National Renewable Energy
Laboratory is scheduled to be complete by approximately March 2023; any input received by early
January will be incorporated into the first set of hybrid microgrid maps. Kurt emphasized that this
initial effort is just the beginning of the process and will provide a snapshot in time. He explained that
the planning process will continue into the future and potentially will be followed by a procurement
and development process, all of which would include additional opportunities for community input.
• A workshop participant referenced the parking lots at Windward Community College as being
covered with solar photovoltaic panels, noting that France just recently committed to covering all of
their parking areas with solar panels. He asked if school facilities with solar panels have been
included in the microgrid mapping, noting that solutions for energy storage also need to be
considered. Ken responded that the mapping effort identifies both the existing customer energy
resources (such as existing solar panels on schools) as well as the energy load in any given area, as
locations where resources and loads are balanced are good candidates for a hybrid microgrid.
However, he explained that additional energy generation can be added to augment existing
resources to support a microgrid, if necessary. The participant noted the value of a microgrid to
provide backup power to an emergency shelter during a disaster event, but also emphasized the
importance of energy storage for facilities with kitchens and refrigeration; these services are critical
for community resilience during an emergency (much more so than individual homes). Ken agreed
with the need for energy storage to augment solar photovoltaic energy produced during daylight
hours. He explained that the analysis is focused on identifying suitable locations for microgrids based
on the full range of criteria to help customers better understand potential opportunities for microgrid
development. It is not intended to provide a detailed inventory of energy storage capabilities based
on the load profile, but rather to provide an indication of the existing resources relative to the load.
Alani stated that one of the prevailing questions is what technology will be used to provide power
and storage for the microgrids, explaining that these are questions that require community input.
Ken explained that the options to provide power and storage can be customized to fit a given area,
such as mobile diesel generators (in the case of the Koʻolaupoko CCHs) which may or may not be
augmented with solar photovoltaics and battery storage.
• A workshop participant asked if the microgrid size limit of approximately one distribution circuit is
based on an analysis requirement of the ETIPP program or a specific technological or financial
constraint. Ken explained that the mapping project originated with the microgrid services tariff,
which enables customers to develop hybrid microgrids. Hybrid microgrids are intended to serve at or
below the substation distribution feeder level; incorporating substations would significantly increase
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microgrid complexity. As the distribution feeders generally serve up to 3 megawatts of load, this is
the maximum size of potential microgrids (which aligns with the mapping project).
• Kurt referenced a question posted on Menti regarding what new infrastructure is needed in a
neighborhood for a microgrid. Ken explained that development of a microgrid requires addition of
switching equipment to allow the designated area to be isolated from the grid, as well as generating
resources to provide the backup energy. In addition to these components, it is also important to
harden overhead infrastructure within the microgrid (for example, replacing old wooden poles with
new steel poles, or possibly undergrounding electrical lines) to maximize the resiliency of the system.
• A workshop participant asked about the scale of electronic infrastructure needed for a microgrid. He
asked if it requires build-out of new facilities or if it is as simple as adding switching equipment to
existing structures. Ken explained that microgrids are generally not simple systems. Customer
microgrids are implemented behind the meter of a single customer using their own infrastructure;
customer microgrids can include large facilities such as schools, which may include multiple buildings,
but all behind a single meter. In contrast, a hybrid microgrid creates an electrical boundary around
multiple customers by adding switches at various points on the surrounding electrical lines. Alani
emphasized that every microgrid will be unique, based on the existing infrastructure and resources,
and will require its own engineering solution. Ken agreed and explained that the microgrid mapping
is just the initial step in a much larger process. The mapping is intended to provide an indication of
whether a site is suitable for a microgrid; much more detailed engineering will be needed once the
decision is made to pursue a project.
• A workshop participant asked whether the nearby residences would be included in the potential
CCHs identified for Koʻolaupoko. For example, she referenced the CCH for Windward Mall and asked
whether the houses along the CCH boundaries would also be connected. Ken responded that he does
not think that this particular CCH would include houses, but that it is technically possible for homes
to be included. Colton reiterated that from an engineering perspective, it is possible to design a
microgrid around any combination of commercial structures, community facilities, and private
residences. However, the CCHs focus on providing backup power specifically to facilities that provide
community services (such as the mall, schools, and medical facilities). Alani noted that if there were
to be a publicly funded microgrid that happened to include certain residences, this could benefit
those property owners; he asked whether there would be any restrictions for publicly funded
microgrids to only include critical facilities or if they could also include residences (for example, if it is
not technically possible to add a certain critical facility without also including adjacent residences).
Colton responded that there is flexibility and that it is possible for residences to be included. He
emphasized that microgrids should be designed specifically around objectives based on the funding
sources. For example, the BRIC grant uses FEMA funding, so the focus of the microgrid is to provide
backup power for emergency services. If the objective is to provide a microgrid to serve a remote
community (such as Hana on Maui), it would be designed to service all of the customers in that area.
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• An online participant asked how many microgrids Hawaiian Electric is looking to establish in
Windward Oʻahu. Ken explained that the BRIC grant submitted for the CCHs identified through the
Koʻolaupoko Resilience Initiative included three proposed sites. There were additional sites that were
identified, but those three were prioritized for the grant application.
• Another online participant referenced diesel generators as a storage option and asked for a visual
representation of the energy storage associated with a microgrid designed to incorporate resources
from approximately 100 residences. Ken referenced the technical presentation, which includes
concept photographs of the mobile diesel generators envisioned for use as part of the Koʻolaupoko
CCHs. In this case, the mobile generators would be stored elsewhere; in the event of an emergency,
the generators (along with a transformer and other electrical equipment) would be transported on
trailers and staged in a parking lot near the CCH.
• A workshop participant emphasized that the CCHs identified to date include Waimānalo, Olomana,
and Kāneʻohe but do not include any locations in northern Koʻolaupoko. He asked that additional
locations be considered in Kahaluʻu, Waiheʻe, and ʻĀhuimanu; critical facilities include a utility
baseyard, fire station, a boat ramp, helicopter landing zones, as well as Key Project and other
community gathering locations. He noted that there is adequate space for parking trailers, noting the
need for adequate diesel supply. He also explained that the housing branch of the state is looking at a
new water system in the area between Waiāhole and Kualoa. The community is proposing a water
system that is not electrically dependent and would flow from the Waiāhole Ditch tunnel (which is at
an elevation of about 750 feet). Every day, water flows from Kahana Valley to Waiāhole, where it
then gets allocated to either the leeward or windward side of the island. He emphasized that there is
constant kinetic energy in the tunnel and could be used to produce hydroelectric power, which would
be like having a diesel generator that doesn’t run out of diesel. He stated that this energy could be
used to support a microgrid for the surrounding community, including facilities with kitchens,
refrigeration, and food distribution.
In addition to the comments discussed during the workshop, additional questions and comments were
received via Menti and in writing. These comments are summarized below; copies of the responses are
contained in Attachments D and E (respectively).
The following questions and comments were received via Menti in response to the question: What other
community facilities are missing or should be included in the analysis?
• Supermarkets
• Farms, community kitchens
• Schools as community gathering places
• Food and supplies
• National Guard facilities
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• Community Civic centers such as KEY Project (Waiheʻe/Kahaluʻu); Waiāhole Elementary School (high
ground, centered in farm area)
• Key Project
• Perhaps Castle High School - its cafeteria has provided shelter during several storms, has a kitchen if
needed, and can reduce strain on other shelters
• HiEMA storage facilities
• Correctional facilities
• Military facilities
• Hawaiʻi State Hospital
• In an emergency situation, shelters such as schools, should be included in potential microgrids
• What new infrastructure is needed in a neighborhood for a microgrid
• Due to the inclement weather in Koʻolaupoko, flooding and other negative impacts have to be taken
into account
• Wastewater treatment plant
• Windward Community College with kitchen facilities
• Agriculture water reservoirs
• Is there a strategy for linking solar photovoltaic arrays (public and private) as a microgrid energy
source?
• Potential hydropower from Waiāhole ditch
• Will microgrids be controlled at the customer level or will the utility company have control? Will they
be for emergency use only or can they be used to reduce grid reliance?
• Hydropower
The following questions and comments were received via the written comment cards:
• Recommended resilience hub: 20-acre former Navy landfill in Haiku Valley (naturally protected site;
Hawaiian homeland impact area; natural distribution point to the community)
• Why do you use the low emission scenario for sea-level rise vulnerability?
• Remind the presenters that the state’s greenhouse gas goal is net negative (not net zero) carbon
emissions
Renewable Energy Zones: Community Feedback
Based on the presentation of technical information regarding the Renewable Energy Zones analysis (as
summarized previously in this report), Kurt reiterated that Hawaiian Electric is looking for input
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regarding siting of large-scale renewable energy resource development to decarbonize Oʻahu’s energy
system. He emphasized that this is just the early stages of a long-range planning effort but the goal is to
make information more accessible so the community can more easily provide input. The questions and
input provided by workshop participants is summarized below.
• A workshop participant asked if it possible to supply 100 percent of Oʻahu’s energy from renewable
sources. Marc responded that the analysis to date show that it is possible but emphasized that it is
going to take everyone working together as there are a lot of pieces needed to accomplish that goal.
He noted that if we rely on solar and wind energy, it will require a lot of land to support those types
of projects. He also reiterated that there are also other technologies that may be available for use in
the future, depending on the price of those technologies. In addition, biodiesel is also considered a
renewable energy source and is used at one of Hawaiian Electric’s power plants. As such, there are
various ways to achieve 100 percent renewable energy, with each option having a different cost. In
any case, it will take coordination and partnership at all levels to achieve this goal.
• A workshop participant acknowledged that the Renewable Energy Zones analysis considered impacts
to farmland and other areas that people might be concerned about. He asked whether the analysis
has considered the use of urban and other built spaces, such as Windward City Shopping Center or
Castle Hospital, and suggested the addition of parking lots covered with solar photovoltaics and other
similar projects that ideally would not obstruct viewplanes. Marc explained that Hawaiian Electric has
tried to spur this type of activity in several ways, including customer energy programs that enable
solar photovoltaics on parking canopies and similar rooftop structures. He also described the shared
solar (or community based renewable energy [CBRE] program), through which developers build
projects and community members can subscribe to the energy produced by the project. In addition,
Hawaiian Electric issues Requests for Interest (RFIs) to solicit landowners that are interested in
building parking structure or larger rooftop solar photovoltaic systems. Alani noted that these are
solutions that Hawaiian Electric can encourage but they cannot require landowners to construct
these types of facilities.
• Alani referenced a comment received via Menti regarding the location of geothermal resources in
Koʻolaupoko. Marc stated that there are known geothermal resources on Hawaiʻi Island and studies
in the past tried to identify geothermal resources on the other islands. He explained that researchers
at University of Hawaiʻi are further investigating geothermal potential and are currently considering
more exploratory drilling. However, drilling is expensive and funding needs to be put in place.
Although there are ways to guess at where there may be geothermal potential, drilling is the only
way to confirm whether there is a viable resource.
• A workshop participant asked if Hawaiian Electric has revisited the hosting capacity limits for larger
customers that are behind a meter and are looking to develop more renewable resources. Marc
confirmed that Hawaiian Electric updates the capacity analysis each time it issues a Request for
Proposal (RFP) and information regarding the remaining capacity on the various transmission lines is
made available to developers through the RFP process.
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Kurt closed the meeting by acknowledging the work being done by the Center for Resilient
Neighborhoods (CERENE). He explained that they are working at the grassroots level with communities
to identify locations for resilience hubs. These are structures that can be used as community gathering
places and provide key services to the community during an emergency event. These efforts dovetail
together, as it would be ideal for the resilience hubs to be connected to other critical facilities as part of
a microgrid.
In addition to the comments discussed during the workshop, the following questions and comments
were received via Menti in response to the question: What are the most important factors to consider
for the siting of renewable energy on Oʻahu? Copies of the responses are contained in Attachment D.
• Amount of land needed
• Creating a safe distance from schools and other community facilities
• Every community should have renewable energy to support themselves. Some communities are
taking too much of the load. This should also help Hawai'i be more resilient.
• Lifecycle cost to customers
• Where possible build in already disturbed areas as opposed to undeveloped areas.
• Location of geothermal resources in Koʻolaupoko
• Visual obstruction to landscape
• Survivable/resilient
• Agreed on the visual obstruction to landscape.
• Does the amount of renewable energy a community can generate determine its ability to host a
microgrid?
• Explore hydro options
• Proximity to Koʻolau Substation so that the resource can flexibly support the most electrical circuits
possible at the lowest cost and complexity
• Good idea, building upon already developed areas
• Ecological impact that it will have throughout the entire ahupuaʻa. One small change will have a
cascade effect on all components (loʻi, mala, loko iʻa, etc.).
• Acceptable site for nuclear SMR
• Kāneʻohe Bay is a unique natural and cultural resource so should not become used to site any
generation sources
• How the state can contribute to siting options – e.g., state buildings, state housing projects - the
ability for the state and county to use their existing buildings for energy projects. And fast track
them?
COMMUNITY FEEDBACK
ʻEWA MOKU (HONOULIULI - HALAWA)
NOVEMBER 17, 2022
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Introduction
The last of six Renewable and Resilient Energy Workshops hosted by Hawaiian Electric was held in the
‘Ewa moku of Oʻahu, which spans from Honouliuli to Halawa. The workshop was held on November 17,
2022 at Leeward Community College. There were approximately 11 attendees, as well as Hawaiian
Electric staff; a list of attendees is included in Attachment C.
Hybrid Microgrids: Community Feedback
Based on the presentation of technical information regarding hybrid microgrids (as summarized
previously in this report), Kurt reiterated that Hawaiian Electric is looking for input regarding siting
hybrid microgrids, including other criteria that should be included in the analysis as well as specific
facilities that should be considered because they are important to the community. He also noted that
the microgrid mapping process considers existing sources of resource generation that can be used for
backup power (e.g., rooftop solar panels), but noted that Hawaiian Electric would also like community
input on the type of technologies that should be explored if additional generation is needed to power
the microgrids. He explained that Alani would be facilitating the discussion and reminded participants of
the various ways that they can ask questions and provide input. Alani stressed the important of
community-based knowledge and stated that the purpose of the workshop is to gather feedback to
ensure the analysis is aligned with the community’s priorities. The questions and input provided by
workshop participants is summarized below.
• A workshop participant stated that he thinks various places to recharge electric cars should be
included and that these locations should be widely distributed.
• A workshop participant asked how Hawaiian Electric will prioritize locations based on the community
input that is received. Katy responded that the criteria are currently equally weighted in the analysis.
However, the team recognizes that not everything is equally important to the community in the
event of an emegency, and emphasized that the goal of these discussions is to identify the criteria as
well as specific facilities that are most important to the community. She stated that the team is open
to suggestions, but they are thinking that the frequency of responses from the community (for
example, around concepts such as food distribution centers, schools, etc.) indicates relative
importance for that moku, and thus would be used as the basis for assigning weights. Alani
emphasized the importance of community input to determine the highest need.
• Alani referenced a question received via Menti: “Can Waiau Power Plant be repurposed into a
microgrid?” Marc explained that Waiau Power Plant is one of Hawaiian Electric’s main centralized
power plants that serves the island of Oʻahu and has blackstart capability in the event of a
widespread blackout. In other words, if Hawaiian Electric needs to restore power to the island-wide
grid, Waiau Power Plant would help with this process. Therefore, this power plant would not be used
for microgrid purposes as it is used to help maintain the island-wide grid.
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Kurt acknowledged the work being done by the Center for Resilient Neighborhoods (CERENE) at the
grassroots level, explaining that they are partnering with communities at the neighborhood level to
identify locations for resilience hubs. He
stated that their work has been informed by
lessons learned from disaster incidents
around the world and focuses on facilities
that can serve as a gathering place and
provide key services to the community
during emergency events (including food
distribution, refrigeration, medical services,
etc.). He explained that resilience hubs can
be designed to have their own power
source, but also are good candidates for
microgrids. In addition to partnering with Hawaiian Electric, CERENE is also working with the City and
County of Honolulu Office of Climate Change, Sustainability and Resiliency and Hawaiʻi Emergency
Management Agency.
In addition to the comments discussed during the workshop, additional questions and comments were
received via Menti in response to the question: What community facilities are missing or should be
included in the analysis? These comments are summarized below; copies of the responses are contained
in Attachment D.
• Shopping centers and grocery stores
• Need to add grocery stores to critical facilities
• UHWO and LCC
• Schools
• HART rail transit stations, ROCs, MSFs
• Central Oʻahu Regional Park
• Key military bases
• Filipino community center in Waipahu
• Kroc Center
• Mililani Town Center
• Walmart Kunia Pearl City
• Costco Kapolei and Waipio
• ʻEwa Foodland, Safeway, Longs
• Waipio Costco/Kaiser Waipio/EMS Waipio
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• Pearl City High School
• ʻEwa and Kapolei Library
• Campbell, Kapolei, Mililani, Waipahu High School
• Gas stations
• Don Quijote and Seafood City Waipahu
• Coast Guard Air Station
• Mililani High Tech Park
• Pacific Palisades Community Center
• Can Waiau power plant be repurposed into a micro grid?
• Department of Health on Waimano Home Road
• Sam’s Club Pearl City
• Suggest looking at gaps in existing facilities map to fill in spots so microgrids are well distributed
• Target Kapolei Salt Lake
Renewable Energy Zones: Community Feedback
Based on the presentation of technical information regarding the Renewable Energy Zones analysis (as
summarized previously in this report), Kurt reiterated that Hawaiian Electric is looking for input
regarding siting of large-scale renewable energy resource development to decarbonize Oʻahu’s energy
system. He acknowledged that there are already renewable energy projects sited in the ʻEwa moku and
emphasized the need for community input moving forward. The questions and input provided by
workshop participants is summarized below.
• A workshop participant asked if there are still discussions about wind power, particularly offshore
projects. Marc explained that Hawaiian Electric’s process to acquire renewable projects involves
issuing a Request for Proposals (RFP) which allows developers to submit proposals for projects; these
projects may involve a range of different technologies including offshore wind. There are currently no
proposals for offshore wind projects in Hawaiʻi but Hawaiian Electric is aware of offshore wind
developers that are talking with certain communities about potential projects. Hawaiian Electric has
not taken any technologies off the table but is working to determine which technologies would be
acceptable in different communities. Alani asked Marc to confirm that Hawaiian Electric cannot
restrict the proposals that are submitted as the parameters of the RFP process are set by the Public
Utilities Commission (PUC); Marc confirmed these points.
• Alani referenced a question submitted via Menti: “How can nearby residents see direct benefits from
energy projects.” Kurt explained that there has recently been community input relative to this topic
and relates to the purpose of these workshops. Specifically, Hawaiian Electric has been working with
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the West Oʻahu community in response to input shared about the energy burden associated with
projects sited in this region. Through this process, various community leaders and organizations
aligned their interests and submitted a letter to the PUC with input regarding the Hawaiian Electric
RFP process for shared solar (also referred to as community based renewable energy [CBRE])
projects. The shared solar projects allow community members to subscribe and achieve the same
benefits as customers with rooftop solar photovoltaic systems. The PUC adopted most of the
recommendations submitted by the West Oʻahu community, resulting in requirements for both for
the shared solar RFP as well as all other RFPs moving forward. In particular, community members
that live closest to a shared solar project will be given access to an energy subscription before other
residents around the island. Other requirements include incentives related to hiring local staff and
workforce development. Furthermore, based on this input and the support of the PUC and other
collaborating agencies, the next round of RFPs will require projects to provide a community benefits
package, with a minimum dollar amount based on the size of the project. The RFPs include language
requiring developers to work directly with the community to identify specific needs and ensure that
the community benefits or funding directly support those needs. He stated that there is more
information that can be shared, but these are examples of improvements that have been made to
the procurement process to provide direct benefits to the community and illustrate the value of
community input. Alani emphasized that when projects are selected through the RFP process, there
will be specific opportunities for the community to provide input to the developers regarding
community needs and allocation of community benefits.
• A workshop participant asked if there is expected to be any mandates for solar photovoltaics on state
and county facilities. More specifically, he stated that he spoke with the branch manager at the
Molokaʻi public library who was wondering about the process for getting solar installed on a building
such as a library. In terms of the requirements, Marc stated that this is not something that Hawaiian
Electric can mandate and would instead require legislative action. There have previously been bills
contemplated that would require solar photovoltaics to be added on state and county buildings.
There are also policies such as the University of Hawaiʻi’s net zero goal, based on which Hawaiian
Electric has been working with University of Hawaiʻi to add solar photovoltaic systems at their various
campuses around the state. Regarding the question about the Molokaʻi public library, Marc explained
that customers typically work with a contractor/installer to enroll in one of Hawaiian Electric’s
programs.
• Alani referenced a question received via Menti: “Can the site selection be part of the microgrid
design and community resiliency?” Ken responded that the Renewable Energy Zones analysis is
intended to identify opportunities for larger grid-scale projects to provide energy for the island-wide
grid. He noted that these projects could include elements that help to improve community resilience,
but these would add layers of complexity and cost.
• Alani identified another question received via Menti: “What kind of community benefits are offered
or available?” Kurt explained that based on language currently included in the RFP, there are no
specific limitations; it will be up to the community to identify their specific needs and the type of
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benefits that would address those needs. The intent is to not be prescriptive and rather to encourage
developers to engage meaningfully with communities to develop a community benefits package. The
developers will be required to provide a minimum dollar amount for the community benefits, which
is currently set at $3,000 per megawatt per year over the full contract term for the project (20+
years). Based on engagement with the community, the developer will be required to document the
community input; this information will be made publicly available and used to hold the developers
accountable.
• A workshop participant asked how small a microgrid can be to catch Hawaiian Electric’s interest. Ken
responded that customer microgrids can be as small as a single home, while hybrid microgrids can be
as large as 3 megawatts. He explained that Hawaiian Electric is not necessarily seeking microgrids as
part of the procurement of larger renewable energy projects, as these are intended to provide
energy for the island-wide grid. As such, the larger grid-scale projects do not necessarily need to
include microgrid functionality.
• A workshop participant asked about the total consumption or load for the Hawaiian Electric system.
He asked about the progress toward reaching the goal of 100 percent renewable energy and asked
how much more renewable energy will be needed as the climate gets hotter. Marc explained that
Hawaiian Electric’s Renewable Portfolio Standard (RPS) for the multiple islands it serves is
approximately 38 percent as of 2021. The RPS for Oʻahu is just over 30 percent, while Maui and
Hawaiʻi Island are higher (40+ percent and 60 percent, respectively). He noted that the law was
recently changed, with a new formula used to calculate the RPS, such that these estimates will be
slightly lower at the end of this year. He emphasized that there is still a lot of work needed and that
the Renewable Energy Zones analysis is intended to help determine how best to reach 100 percent
renewable energy.
• A workshop participant asked how the transition to 100 percent renewable energy will change the
cost of energy. Colton explained that the transition started with the most cost-effective resources,
which included wind and solar projects; at certain times, the price of these resources has been much
lower than the cost of fossil fuel generation while other times it has been more expensive.
Nevertheless, the transition to renewable energy provides both environmental benefits as well as
price stability. For example, as oil prices are currently much higher than what they were a year ago,
the renewable resources purchased five years ago (at a rate that was more expensive than the price
of oil) are now cost effective. Moving forward, as more renewable resources are developed, lower
cost projects will be exhausted and higher cost projects will need to be developed. Hawaiian Electric
is working hard to make sure future renewable energy projects are as cost effective as possible; for
example, the Renewable Energy Zones analysis will help inform planning for cost effective
infrastructure for interconnection. In addition, it will be important to stay abreast and consider use of
new and improved technologies. Moving forward, it is likely that the cost of renewable energy will
increase as more is added to the system. However, it is important to recognize that costs will not
automatically go up as they will be relative to the price of oil (which can be highly unpredictable). For
the renewable energy projects that are being added to the system, Hawaiian Electric is working with
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independent power producers and entering into contracts with fixed prices for the 20-25 year
contract term; this price stability will be very valuable in the future.
• Alani referenced a question received via Menti: “How can private landowners (shopping centers with
big parking lots) be incentivized to get solar, potentially CBRE?” Marc explained that the CBRE
program involves issuance of an RFP seeking proposals for procurement; individual landowners work
with a developer to prepare and submit a proposal for a project on their land. He explained that an
RFP was recently issued and Hawaiian Electric is currently in the process of evaluating those
proposals. Colton added that Hawaiian Electric also issues Requests for Interest (RFIs) to identify
landowners that may be interested in leasing or selling property for development of renewable
energy project. The list of landowners that respond to the RFI is made available to developers and
can improve the chance of connecting with a developer.
• Alani highlighted another question received via Menti: “Are there any shared solar projects available
today for communities in the ʻEwa moku?” Kurt responded that there are currently no shared solar
projects available in the ʻEwa moku. However, Hawaiian Electric will actively promote and offer
shared solar subscriptions to the community when available in the future. An announcement is
expected soon on the selections for the low and moderate income shared solar program, followed by
selections for the shared solar RFP issued earlier this year. He clarified that the proposals that are
submitted to Hawaiian Electric are based on a partnership between a willing landowner and willing
developer, and that Hawaiian Electric does not have any control over the location of the proposed
projects.
• Another question submitted view Menti: “How can Hawaiian Electric involve more community
members in these kinds of discussions besides these kinds of meetings?” Kurt explained that these
workshops are just the beginning of the process and Hawaiian Electric is willing to have additional
conversations with community in whatever form is preferred. He also referenced resource tools
available at www.hawaiipowered.com/oahu, including a map of Oʻahu where community members
can drop pins and add comments regarding suitable and unsuitable locations for potential renewable
energy projects. He reiterated that all input will be documented and considered in the planning
process.
• A workshop participant asked how the workshops were promoted. Kurt explained that Hawaiian
Electric provided notification regarding the current workshops to the neighborhood boards, Hawaiʻi
Energy Policy Forum, Star Advertiser, Pacific Business News, and social media channels as well as
requested that various elected officials share the information through their channels. He emphasized
that much of the success in getting community members to attend is via word of mouth, so asked
participants to share the information with their respective circles and offered to have follow-up
meetings with the community if desired.
• Alani highlighted another question via Menti: “Can we prioritize selecting projects that are being
developed by local organizations and businesses rather than those that are based outside of
Hawaiʻi?” Kurt explained that the RFPs currently do not include language to this effect and all
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developers are evaluated equally. However, he stated that he thinks this is an important concept to
consider; Hawaiian Electric cannot make this decision but it could be recommended to the PUC by
the community.
• Kurt referenced a question received via Menti: “How can communities be part of the selection
process?” He stated that this is a good question but one for which Hawaiian Electric does not have an
answer. He emphasized that this is another concept that can be discussed with the community and
stakeholders in terms of how best to capture community sentiment as part of the RFP process. He
explained that Hawaiian Electric has been reviewing how this issue is handled by utilities on the
mainland but has not yet identified a good model. As of now, the best approach is to continue having
open discussions and working through issues together.
Alani asked for clarification regarding how projects are selected. Kurt explained that selection is
based on criteria set forth in the RFP – that is, the extent to which a developer can demonstrate that
their project meets the written criteria in the RFP (e.g., ability to interconnect to the grid, reasonable
cost per kilowatt hour). Alani asked for clarification regarding who sets the criteria. Kurt explained
that are opportunities for public input on the RFPs before they are finalized, noting that this was the
way that the West Oʻahu community submitted their recommendations. This work is done in
partnership with the PUC, and Kurt emphasized that they are trying to make this a more inclusive
process.
• A workshop participant asked if there will be other future workshops on these topics. Kurt responded
that there will certainly be future opportunities to provide input relative to both the hybrid microgrid
and Renewable Energy Zones analyses. He explained that the hybrid microgrid map is meant to be a
snapshot in time and will serve as the foundation for future efforts that will dive deeper into the
details of whether microgrids are a good fit in specific locations; there will be continued community
engagement as this process moves forward. Similarly, the Renewable Energy Zones analysis is also a
preliminary analysis that is being shared to engage the community early in the planning process.
Additional information will be shared as it becomes available (for example, inclusion of other
renewable energy technologies). He referenced www.hawaiipowered.com/oahu, which includes an
interactive map where community members can add pins and comments regarding the suitability of
specific sites for renewable energy projects. In addition, there will be continuing discussions with the
community moving forward. All input received will be documented and incorporated into the long-
term planning process.
In addition to the comments discussed during the workshop, the following questions and comments
were received via Menti in response to the question: What are the most important factors to consider
for the siting of renewable energy on Oʻahu? Copies of the responses are contained in Attachment D.
• How can nearby residents see direct benefits from energy projects?
• Cost-effective and reliable
• Improving reliability
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• Multi use land, all parking lots, warehouses, state and county facilities
• Environmental equity and impact on the community
• Minimize overhead wires
• Projects should be sited close to users
• Minimize impact to landscapes, mountain slopes, etc.
• Local jobs and technical education programs
• Can we prioritize selecting projects that are being developed by local organizations and businesses
rather than those that are based outside of Hawaiʻi?
• Siting commitments to create public benefits to host communities - plus large-scale storage (CO2,
water/mass lifting, etc.)
• What kind of community benefits are offered or available?
• Good community engagement
• How can the community be part of the selection of sites and projects?
• Can the site selection be part of the microgrid design and community resiliency?
• Help community with resiliency
• Those communities where solar is not ideal (i.e. homes bordering golf courses)
• How can private landowners (shopping centers with big parking lots) be incentivized to get solar,
potentially CBRE?
• Are there any shared solar projects available today for communities in ʻEwa Moku?
• Appreciate seeing this on ʻOlelo!
• Make sure some women are involved!
• Utilize brown fields. Partner w/public-private surface parking lots. DO NOT TAKE AWAY ag land or
commercial mix use lots.
• How can HECO involve more community members in these kinds of discussions? Besides these kine
meetings.
• Diverse sources
ATTACHMENT A
NOTICE OF WORKSHOP
ATTACHMENT B
TECHNICAL PRESENTATION
ATTACHMENT C
WORKSHOP ATTENDEES
Koʻolauloa Moku (Waimea – Kaʻaʻawa)
Monday, October 24, 2022
Kahuku Elementary School
Name Organization (if any)
In-Person Participants
Dotty Kelly-Paddock Hauʻula Community Association
Kendal Leonard Hawaiʻi Natural Energy Institute
Ben Shafer Friends of Kahana Community
Stephany Vaioleti Koʻolauloa Neighborhood Board
On-Line (Zoom) Participants
Jin US
Ali Andrews Shake Energy
Yvonne Hunter Hunter Communications Inc.
Bob Kagamida Hitachi
Parker Kushima Hawaiʻi State Energy Office
Jae-Hyup Lee South Korean Company (partner w/ HNEI on microgrids for
Hawaiʻi Island)
Andrew Okabe Public Utilities Commission (PUC)
Nick Sinchek Hawaiʻi State Energy Office
James Vaughn
Koʻolauloa Moku (Waimea – Kaʻaʻawa)
Thursday, December 1, 2022
Hauʻula Community Center
Name (In-Person) Organization (if any)
Ginny Alatasi
Steve Cheney
Raynae Fonoimoana
Amanda Ho Hawaiʻi State Energy Office
Ronnie Huddy HCA / CERT
Linda Iongi
Wanda Kamauoha
Dotty Kelly-Paddock Hauʻula Community Association
Parker Kushima Hawaiʻi State Energy Office
Lorraine Matagi Hauʻula Community Association
Carlos Mozo
Wade Nakashima
Debra Parr
Barbara R
Dan R
Dave Siroskey
Ella Siroskey
Ailene Sproat
Barbara Tatsuguchi
Miriam Young
On-Line Participants (Zoom) Organization (if any)
Kathy Boyle
Gregory Weiss
Waiʻanae Moku (Nānākuli – Keawaʻula)
Wednesday, October 26, 2022
Agnes Kalanihoʻokaha Community Learning Center
Name Organization (if any)
In-Person Participants
Chris Fujimoto University of Hawaiʻi – Kapiʻolani
Sidney Higa Hooulu Holdings
Kapua Keliikoa-Kamai Waiʻanae Valley Homestead Community Association
Parker Kushima Hawaiʻi State Energy Office
Roland Lee Nānākuli-Māʻili Neighborhood Board
Miku Lenentine University of Hawaiʻi – Kapiʻolani
Helen Reddy Center for Resilient Neighborhoods (CERENE)
Cynthia Rezentes Nānākuli-Māʻili Neighborhood Board
Nicole Shintani Hawaiʻi State Energy Office
Georgette Stevens ʻŌlelo Community Media
On-Line (Zoom) Participants
JMA
NJUNG
Ali Andrews Shake Energy
Amanda Ho
Yvonne Hunter Hunter Communications Inc.
Jo Jordan
Chad Miura
Andrew Okabe Public Utilities Commission (PUC)
Sharlette Poe Waiʻanae Neighborhood Board
Kona Moku (Moanalua - East Honolulu)
Tuesday, November 1, 2022
Kapiʻolani Community College
Name Organization (if any)
In-Person Participants
Ali Andrews Shake Energy
Leo Asuncion Public Utilities Commission (PUC)
Andrew Calise Honeywell
Winifred Canney Center for Resilient Neighborhoods (CERENE)
Stephanie Chang Stephanie Chang Design Ink
Michele David
Tristan David Center for Resilient Neighborhoods (CERENE)
Michael Flores
Dr. Robert Franco Center for Resilient Neighborhoods (CERENE)
Sarah Harris Office of Climate Change, Sustainability & Resiliency
Carol Hoshiko Kapiʻolani Community College, Office of Continuing Education &
Training
Parker Kushima Hawaiʻi State Energy Office
Miku Lenentine University of Hawaiʻi – Kapiʻolani
James McCay DHA Coop
Mary Janell Murro University of Hawaiʻi, Public Administration
Dean Nishina Division of Consumer Advocacy
Andrew Okabe Public Utilities Commission (PUC)
Monique Schafer Hawaiʻi State Energy Office
Eric Teeples University of Hawaiʻi at Manoa School of Architecture
Cuong Tran University of Hawaiʻi, National Disaster Preparedness Training Center
Jose Andres Zavala Center for Resilient Neighborhoods (CERENE)
On-Line (Zoom) Participants
Anand
Marta
Kodi Benoza-Tabion
Jenny Brown Center for Resilient Neighborhoods (CERENE)
Iwalani Clayton Center for Resilient Neighborhoods (CERENE)
Valarie Cleopas
Leila Jaffuel
Yun-Su Kim
Luke Lenentine
Chad Miura
Kelsey Nakagawa
Jenn Lieu Nickel
Denise Pierson Kapiʻolani Community College, Civic & Community Engagement
Suwan Shen Urban & Regional Planning, UH Manoa
Angela Soto Balmores Center for Resilient Neighborhoods (CERENE)
Waialua Moku (Kaʻena - Kapaeloa)
Thursday, November 3, 2022
Waialua Elementary School
Name Organization (if any)
In-Person Participants
Andrew Calise Honeywell
Richard Figliuzzi North Shore Resident
Alex Kahl Ala Mai Farmstead
Agnes Leinau Resident
Bob Leinau Resident
Reed Matsuura City Council, Staff
Kathleen Pahinui North Shore Neighborhood Board On-Line (Zoom) Participants
Raquel Hill-Achiu
Andrew Okabe Public Utilities Commission (PUC)
Amy Peruso Representative (Wahiawa, Whitmore Village, Launani Valley)
Koʻolaupoko Moku (Waimānalo - Kualoa)
Tuesday, November 15, 2022
Windward Community College
Name Organization (if any)
In-Person Participants
Amra Brightbill Marine Corps Base Hawaiʻi - Kāneʻohe Bay
Noah Doerr Coffman Engineers
Malia Hagmann University of Hawaiʻi at Manoa
Naomi Kuwaye Public Utilities Commission (PUC)
Adriel Lam Kāneʻohe Neighborhood Board
Miku Lenentine University of Hawaiʻi – Kapiʻolani
Amy Luersen N/A
Paul Luersen N/A
Jacob Milanczuk Kalakaua Middle School
Corinne Nishina N/A
Dean Nishina Division of Consumer Advocacy
John Reppun KEY / Waiāhole Neighborhood Board
Jack Shriver Power Engineers
Maria Tome Hawaiʻi State Energy Office
Kirsten Baumgart Turner Hawaiʻi State Energy Office
He Xu-Sadri Marine Corps Base Hawai'i (MCBH) On-Line (Zoom) Participants
Anand
Demaney
Lora
Lisa Kitagawa Representative (Kāneʻohe, Kahaluʻu, Waiāhole)
Andrew Okabe Public Utilities Commission (PUC)
Meagan Ostrem Marine Corps Base Hawaiʻi (MCBH)
iMo Radke
Nick Sinchek Hawaiʻi State Energy Office
Matthew Sutton
Claudine Tomasa
David Warner
ʻEwa Moku (Honouliuli - Halawa)
Thursday, November 17, 2022
Leeward Community College
Name Organization (if any)
In-Person Participants
Macklin Burnham N/A
Marcey Chang Division of Consumer Advocacy
Mark Glick Hawaiʻi Natural Energy Institute (HNEI)
Amanda Ho Hawaiʻi State Energy Office
Leila Jaffuel Ember Media
Parker Kushima Hawaiʻi State Energy Office
Miku Lenentine University of Hawaiʻi – Kapiʻolani
Kendal Leonard Hawaiʻi Natural Energy Institute
Nathan Muramatsu N/A On-Line (Zoom) Participants
Kat K
Andrew Okabe Public Utilities Commission (PUC)
ATTACHMENT D
COMMUNITY INPUT RECEIVED VIA MENTI
ATTACHMENT E
COMMUNITY INPUT RECEIVED VIA RESPONSE CARDS
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
1.10 Power Up
Materials used for the “Powered Up” media campaign from January 17 to February 12, 2023, to promote the REZ website and public input opportunity.
Platform Total Clicks Total Impressions Facebook 3, 257 111,245 Instagram 199 67,608 Meta Story Placement 1,908 348,667
A-204 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
1.11 Renewable Energy Zone (REZ) Map Comments
REZ map comments were gathered both in-person and virtually from September 2022 through February 2023.
1.11.1 REZ Comment Categorization Guidelines
All REZ comments were categorized by Integrated Grid Planning (IGP) consideration -- time, affordability,
land use, community, resilience and reliability -- using the following guidelines:
IGP Consideration Related Topics Time Goal of 100% clean energy by 2045 Political administrations (state and federal)
Affordability Customer bills/rates Financial incentives or credits for clean energy programs (e.g. shared solar)
Cost to build new infrastructure and/or expand existing infrastructure Land Use Potential placement of grid-scale projects and/or electric vehicle charging stations
Support for making rooftop solar required in certain cases Community Benefits for communities hosting renewable projects
Cultural and historical sensitivities
Animal and vegetation sensitivities
Concerns and/or requests from landowners, renters, tenants, etc.
Individual actions and behavior changes
Resilience and Reliability Renewable energy generation methods other than solar and wind (e.g. hydro, nuclear, geothermal, etc.)
Microgrids and battery storage
Optimal and/or challenging geographic and weather conditions
Outages and isolation
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
1.11.2 REZ Comment Takeaways
After categorizing the REZ comments, Hawaiian Electric synthesized takeaways that are specific to each
island. Takeaways are specific to each island to acknowledge distinctive community needs and desires, which
aligns with Hawaiian Electric’s ongoing outreach strategy.
1.11.2.1 Hawaii Island
IGP Consideration Takeaways Time Concerns regarding existing and future battery storage as it ages Affordability Support for decisions that result in lower customer rates
Explore subsidized rooftop solar programs for businesses Support for affordable home battery storage programs
More likely to install rooftop solar and/or using electrical vehicles if: Rooftop solar materials and installation were affordable The power credit system was clarified and improved
Incentives were provided by Hawaii County
Land Use Support for expanding rooftop solar efforts for both residential and business buildings
Support for expanding electrical vehicle charging stations
Support for using existing infrastructure Unused golf course on the mauka side of Ali'i (was part of Kona Country Club) Solar canopies over parking lots
Community Support for partnerships with landowners, Homeowner Associations, property management companies, renters, farmers, etc. to expand rooftop solar
Support for partnering with Kamehameha Schools Trust to place renewable energy projects on unused land Avoid placing renewable energy projects in residential areas
Resilience and Reliability Interest in other generation methods like hydrothermal, geothermal, nuclear, biofuel, etc. Avoid volcanic areas that could destroy potential projects
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
1.11.2.2 Oahu
IGP Consideration Takeaways Time Dissatisfaction with the recent retirement of coal plants due to higher bills
Requested assistance and support from Hawaiian Electric to replace and/or refurbish roofs and solar panels as they age Concerns that government (state and federal) and internal Hawaiian Electric structure will be too slow to achieve 100% clean energy by 2045
Affordability Support for decisions that result in lower customer rates
Support for rooftop solar incentives Community buy-back programs Grant programs Programs for lower-income residents Subsidized re-roofing/re-paneling
Support for electric vehicle incentives
Better rates for electric vehicle owners who charge during non-peak hours at home Benefit for businesses who install charging stations for employees
Land Use Avoid placing renewable energy projects near significant cultural and environmental sites Diamond Head Waipio Manalua Maunaloa Kāneʻohe Bay Support for discussing and collaborating with communities regarding potential wind turbine placement
Support for using existing infrastructure
Solar canopies over parking lots (ex. Kaiser High School and Hawaii Kai Golf Course)
Solar panels on Rail Guide Way
Retrofit retired fossil fuel generation plants for long duration energy storage
Support for expanding the amount of electric vehicle charging stations available and plug types
Community Support for making participation in rooftop solar more accessible Partnerships with landowners, Homeowner Associations, property management companies, renters, farmers, etc.
Responsible and responsive management by Hawaiian Electric for incentive programs
Concerns that lower-income communities will be most burdened Support for community benefits packages for project-hosting communities
Resilience and Reliability Interest in other generation methods like nuclear, steam, hydro, offshore wind, geothermal, waste-to-energy (trash), hydrogen, and small modular reactors Concerns that a grid reliant on solar and wind generation will be at risk in times of unideal weather
Concerns regarding the physical and cyber security of potential micro and grid-scale projects
Dissatisfaction with the recent retirement of coal plants due to outages and inconsistent reliability
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
1.11.2.3 Maui
IGP Consideration Takeaways Time Concerns regarding the plan for aging battery storage
Affordability Support for decisions that result in lower customer rates Support for incentives for clean energy choices Tax credits for energy efficient windows and doors Option to buy back electricity from individuals and businesses with solar panels and battery storage Programs for homeowner/homestead sized windmills
Concerns that rooftop solar systems are too expensive for the average person/household
Land Use Support for potentially new or expanded infrastructure in Central Maui to preserve other land
Support for expanding electric vehicle charging stations
Support for using existing infrastructure Community Support for a partnership between the agriculture community and Hawaiian Electric to produce mutually beneficial projects
Avoid placing renewable energy projects near significant cultural and environmental sites East Maui, specifically fishing grounds Hana through Kaupo Haleakala down to Hi-Performance Center South Maui Waihe'e Honua'ula
Mauka
Waiehu
Makena
Nu'u
Resilience and Reliability Interest in other generation methods like harvesting methane, wave/tidal/ocean technology, hydro, and nuclear
Concerns of isolation and outages, especially in times of emergency
A-208 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
1.11.3 REZ Comments Collected
REZ Comments Collected Maybe South (or East) Big Island are good options for future large-scale investment because land is still relatively cheap and there's lots of sunshine. Oahu island is fast becoming urbanized everywhere as well as Kauai and Maui. Many lower-income residents on Hawaii island move out to the Hilo-Ocean View side because costs are now too high in Kona, Kohala, Waimea, and Hamakua. I don't think there'd be as much pushback for new projects as this is one of the last places in Hawaii that have yet to see any kind of major development. If future large energy projects were brought there, it could be a great economic boon for the people in that area. I know the Big Island well because I grew up in Kohala and we own homes in Kohala, Hilo, Kamuela.
Away from population but closer to the load growth. Try to find areas that won't disrupt anyone.
Away from population but closer to the load growth. Try to find areas that won't disrupt anyone. So much rain on hilo side
If area can actually work with should develop; at elevation but flat and no one will see it
Away from residential areas. Open areas in general, not specific
Picked zone 2 because high potential (360 mw) and lots of space for solar
Land available. Open range to put solar or wind good wind coming down from mountain
Open land, not big need for pasture land
Put more windmills Avoid residential areas in general
Avoid residential areas - like Kahuku Wind Farms
Avoid volcano areas because eruption would destroy the solar farms
Hakalua waimea area. Land availability avoid areas where lava has flowed
Puako and Waikalo good places f/solar
Puako and Waikoloa good places f/solar Everyone should pitch in if it benefits community need more solar because my bill doubled I like in Honoka'a, build more there
good area for solar
Avoid Waipio for large scale - cultural, mana'o + avoid Manalua and Maunaloa
O'okala? Okay More wind in Waikoloa + happy to see more solar
Kohala good wind zone won't bother anyone Good resource to have solar. Thought there were [WORD] about developing project in the area
Not healthy with all noise + Kapuna so put proj. away from them
Solar in Puako, want the proj that dropped out - land is dry can't be used for other things
Born + raised Honokaia - community solar or wind ks land
Open land + sunny. Can't do much else w/land. low cattle carrying capacity Should have never shut down a coal fired power plant without something inplace first. I guess the general public shouldn't expect anything less from a Biden administration.
Nothing is wrong with turbines, but they must be properly sited; in Kahuku, the turbines were placed too close to the community. Based on research of other wind energy projects (Germany), it’s understood that wind turbines are located at least one mile from the nearest residence or farm. Should be learning from others to incorporate the best technology and information regarding health impacts. Would like to see wind turbines at the State Capital, Department of Health, and City Hall; they should have to live with the wind turbines as that is what the Kahuku community has to live with 24/7. If people aren’t willing to put the wind turbines next to a high school in Hawaiʻi Kai, they shouldn’t put them in Kahuku A lot of wind in the back of the valleys. Wind in the valleys on both sides of the island, may be difficult to get transmission lines across the mountains. Wind turbines could be sited in the middle between the mountains, as there are no residents in this area and the turbines could serve the populations on either side. Investors may not like that but may be a long‐term solution for wind and even solar energy projects
Houses should be required to have solar photovoltaic systems with lease programs or other arrangements that are user‐friendly and affordable enough to allow for system upgrades
Development will continue which will occupy a lot of open areas shown on the REZ map, so renewable energy projects should be sited as far back as possible from these areas, in the middle area between the mountains, away from schools and other development
Pacific Heights area is very windy, not sure how to capture that but it funnels through the valleys
Communities need to be engaged for renewable energy solutions, especially those underserved/underrepresented
Supportive of horizontal turbines Potential for rooftop solar in Honolulu and Pearl Harbor areas, especially on high-rise buildings based on discussions about allowing solar panels to exceed max building height limits. Desire to maximize potential on existing structures, rather than raw land (discussed at West Oʻahu/Kalaeloa Clean Energy ʻOhana)
REZ not including Honolulu and Pearl Harbor is excluding a significant amount of resource potential
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected REZ should show potential for rooftop solar in addition to large-scale projects, so equity across geographic regions can be taken into consideration. Could also encourage rooftop solar and other small-scale projects
Energize Waiʻanae program (part of Solarize 808) will be rolled out in the Waiʻanae moku starting Nov 2022 Fair, not necessarily just equal, and pono distribution across ALL communities
Designing tech and systems for high rises and town areas
There is a lot of open space between Kapiʻolani Community College and 22nd Avenue; much of this area is associated with the Dept. of Defense and could be a good place to site solar energy facilities
Area around the airport is worth considering relative to ensuring food availability
Consider including technologies like micro-hydropower with dams and pumped storage hydro facilities, which are ready for implementation
East Honolulu should be considered for future wind projects Grant programs to help residents fund rooftop solar projects are valuable
Incorporate legacy infrastructure on the North Shore, specifically the network of former plantation irrigation infrastructure (such as reservoirs, canals, and channels) for hydropower Dole is currently unloading much of their infrastructure, which is critical to the water supply for North Shore’s agricultural community. This could also be used for micro-hydro power Hawaiian Electric could coordinate with the developers who’re planning to add multiple affordable rental housing units in Waialua. This collaboration could encourage developers to incorporate elements that’re beneficial to microgrids for example
Put wind in East Honolulu next To address impacts to farmland, solar panels could be added to urban and other built spaces like Windward City Shopping Center and Castle Hospital
There may be geothermal resources in Koʻolaupoko
Proximity to Koʻolau Substation so that the resource can flexibly support the most electrical circuits possible at the lowest cost and complexity
Solar photovoltaics on state and county facilities like the Molokai public library
Multi use land, all parking lots, warehouses, state and county facilities Utilize brown fields. Partner w/public‐private surface parking lots. DO NOT TAKE AWAY ag land or commercial mix use lots.
Wind turbines are controversial and should be discussed with the community
No windmills should be as close to homes, schools and farms as the monster turbines in Kahuku are. Appreciate early community involvement.
Are horizontal wind turbines less expensive than vertical? How well do they tolerate salt air? No solar farms on agricultural land! No vertical wind turbines!
No vertical wind turbines! Horizontal turbines are okay
Completely against wind turbines Diversifying the kinds of renewable energy and not just place such a huge focus on solar
Finding technology that takes up less land space and has a smaller footprint
Concentration and permeation of projects within a defined geographic area (identify threshold to manage number of projects, whether large or small)
Physical security, cyber security, and accessibility for repairs such as large transformers
Are the areas of highest potential to host large renewable development be given highest priority usage of that resource? Or will it be sent to the higher usage sites? Example: Will Waiʻanae and North Shore side who have high land potential be given higher priority usage over Waikīkī (who is a high energy user)?
Do you see your prime prospective locations for large renewable development and microgrids competing with sustainable agriculture plots and prime farming locations? Will you be willing to relinquish prime energy development locations and allow diversified sustainable agriculture to take the spot?
Many communities have to bear the burden of hosting new infrastructure without real recognition or reward
The neighborhood board tends to be concerned about siting anything on Diamond Head North Shore Sustainable Communities Plan is currently being updated; the community does not support wind turbines, especially offshore wind turbines
No more wind on north shore
Kāneʻohe Bay is a unique natural and cultural resource so should not become used to site any generation sources
No solar farm at Nankuli Ranch
No wind farms at Palehua Put near landfill. Harvest methane and utilize it instead of just burning it off. Is there enough, though? More solar and battery projects. D.O.T. will be needing to charge buses down the road. Looking for areas with a lot of wind. Have you considered wave and ocean technology?
Been in Lahaina during fire, storms. Water can be a good source of electricity. Green on Haleakala Hwy near truck off-ramp, opportunity for wind power. State DOT owns property there. Look at battery power opportunity at Kahului.
West Maui – solar; more generation there… North Side – wind
Harness methane gas at the landfill to create power; not sure about the sustainability of a project like that.
Curious about wave technology.
Focused on central valley area because of the population density there; best bang for your buck
Near Maalaea Power Plant – close to infrastructure and serve as fire break. Potential for every area to be isolated during outages, especially west side and Hana, so distributing the energy would be ideal
Experience with west side being isolated during emergencies and agree with having power out there
Lands that are able being developed or have been disturbed by former ag use
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected There are hydro opportunities. There are families who have worked really hard to get water back, so I would urge caution. Not the kind of hydro you’re thinking about, there are new opportunities. Honokohau is one of the most powerful hydro opportunities. There are community members who have their own personal hydro, need to consult with the families there.
Put green dot by the dump.
Potential in the 700 acres of Hawaiian Homes Lands upcountry. Ukumehame – the land has been decimated; maybe solar could be used but as long as it doesn’t add to the negative affects already being seen in that area.
Hana has two generators to keep power on. We can convert them to biofuel.
Are we considering other resources like ocean/wave tech
High wind potential in the Kaupo area, near the existing windfarm
East Maui – in terms of resiliency, would make sense to have a resource there Mokulele Hwy – East of the highway, above DHHL lands and heavy industrial zone, may not be usable for anything else and possibly high potential for solar
Behind the Kihei Baseyard, not highly visible
Central Valley, already developed and centrally located
Launiupoko, possibility for wind
Near Kaheawa Wind farms, already disturbed Above Olinda, downslope of Haleakala
With the seabird work that I do, there is an important pathway for uaʻu. Put the green dots in central Maui where thereʻs already a lot of infrastructure.
Green dots in West Maui, good potential for wind and solar.
Putting up turbines or solar in Central Maui wouldnʻt bother me, but beyond that should stay untouched.
Central Maui has a lot of potential for development or re-development.
Hydroelectric, wave, ocean technology It has to be many approaches, it canʻt be just one technology. Met an ocean/wave technology person on a plane 20 years ago and he had me convinced that ocean technology could be a good thing. A lot cultural sensitivity, but also not a lot of transmission going out there. Itʻs an opportunity there, though, because there’s a lot of land available.
We can see where people are okay with projects, in the Central Maui area.
Iao Valley/Wailuku – Rural area right next to the center hub of government
Central area, so much potential for development/re-development, especially in places that are sitting vacant
Ocean/wave technology potential
South Maui - since the study identified it as a good potential, it may be worth looking at Green dot in Waikapū, North Kihei, and other site in Central.
Large agricultural land owner has plenty land. Need a partnership with MECO to build projects that Large agricultural land owner can monetize. There are beneficial partnerships that could happen, but thatʻs above our heads (those in the room). There are lands that were excluded in NREL’s study. A lot of land in Lahaina wonʻt be farmed again because of water, so those ag lands are opportunities. Cost-prohibitive to farm in Lahaina. Some Class A ag lands are worth re-visiting to see if they can be included in future RE plans.
Need to go to County Council with a plan, prove that the ag land in Lahaina is not farmable, no water, too expensive. Tell them that energy is a form of ag. HECO is allowing the PUC to cause energy sprawl. Ag designation needs to be changed. The powers that be donʻt always know about the issues. Sugar was grown where it was because it was crap land. Would never grow anything in North Kihei except for kiawe. Waikapū Town planned development wants to build a new wastewater treatment plan, add Māʻalaea. Can pump the millions of gallons of water uphill and then create energy when it goes back downhill?
Methane gas from pig manure; should be capturing methane from landfill Wave technology, needs to be scaled
Waikapu, North Kihei (Large agricultural land owner) why wasn’t that land used before Kuihelani Hwy
A lot of ag lands in Lahaina will never be farmed again because there’s no water – Large West Maui lnd owners: This needs to be taken to the council and prove the unfarmable lands so the classification can be changed
Major sewage plant in Maalaea - Pump the water uphill, install hydro, create a lake, if enough water you can supply Large agricultural land owner, or the water from the lake can replenish the Iao aquifer
Kaupō has great wind and solar potential, but itʻs far from transmission lines.
Put green dot where Mokulele Highway where Humane Society is, there is a heavy industrial area near above where Hawaiian Homes wants to develop. Itʻs dry, no water, thereʻs nothing around there.
Put green dot in waiheʻe, waiehu area. Lots of wind potential.
East Maui is very cloudy, also high in cultural resources. Thereʻs wind there in certain areas.
Potential for every area to be isolated during outages, especially west side and Hana, so distributing the energy would be ideal
Concern would be for Hana, lot of sensitivity there, don’t recommend putting anything there. Have had a lot of issues with wind and snow, power has gone down there. It would be difficult to bury cables there.
Cultural and jurisdictional sensitivities from Haleakala down to Hi-Performance center.
Avoid Pali due to fires.
Kapalua airport area due to aircraft approaches, FAA requirements. FAA put a six-mile radius around the airport for them to monitor.
Hana has culturally sensitive sites.
Summit – lots of jurisdictions operating up there.
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected Ranch lands. Whatever happens up mauka affects the ocean, that would be my concern. A lot of birds travel makai to mauka in that location. There are a lot of birds going makai from mauka in the morning.
South Maui has one of the densest cultural resources. Waihe’e because of cultural significance.
Honua’ula – worried about the desecration.
Maui Lani area because of ʻiwi kūpuna.
Central area due to a lot of conservation area, same thing with Hana. Need to protect those areas. Lahaina already has a solar farm.
East Maui/Haleakala – Franco: protection of our natural environment East Maui – density in Hana is very low so its hard to envision large projects in that area
West Maui Mountain area – should protect watersheds and natural environment
Haleakala – caution because of historical significance
Haiku, road to east, probably not suitable for solar
Avoid airport Avoid Mauka areas due to cultural significance, terrain, and protected habitats
Avoid East Maui
Avoid vistas of Mauna Kahalawai
Kahakuloa/Waihee coastlines should be avoided because of sea level rise and possible iwi
Kipahulu Biologic Reserve and Haleakala Wilderness Area Waihee/Waiehu, very windy but also lots of cultural significance
Makena – lots of archeological sites
Hana thru Kaupo – last untouched place on the island
Anything on the coastline is going to be difficult, shoreline/beach access.
The central area, along Veteran’s Highway, is prone to wildlfire. Look at what happened in Kahoma Valley, Lahaina, during Hurricane Lane. I didnʻt see or hear vulnerability mentioned, is that a factor?
There is a lot of unused land up mauka that catches a lot of sun. As long as weʻre being respectful of future housing sites, cultural features, etc.
North Kihei area has had a lot of negative impacts already. Upcountry/Makawao, grew up there when it was still paniolo days
Top of Mount Kahalawai; wind farms are an eyesore, dirt roads created sediment into Maalaea Bay. Did the benefits outweigh the cons. We should avoid mauka development Haleakalā as a caution area.
Cannot put any resources near the airport.
Fire caution, conservation land, wet terrain. Mostly mauka-oriented comments.
Whenever anything goes up behind the mountain, it’s never a good thing. Cuts off access to fishermen, becomes a place for tourists, impacting sacred land.
Grew up in Lahaina where there was a lot of ag. Have a lot of challenges there, it’s an island by itself. Kula, historical area for ag
All of East Maui. – Fishing ground, no transmission lines out there, aesthetics
Too much cloud cover, not good for solar.
Nu’u – large boulders from ancient times.
Waiauku’u (Waihee) – familial generations of taro patches/farming The input of the solar farms are a great idea- one major item to consider for all of solar is how is it going to be maintained to keep the system making the energy it is supposed to be making the whole time. There are a few companies dedicated to doing such work on the islands but this should be supported further and for open discussion.
If you drive the cost of electricity so high that it becomes unsustainable, all effort toward clean energy will be useless. Yes, pursue clean energy options, but do it in a way that puts the burden on HECO and the state of Hawaii, not on customers who are already stretched too thin paying energy bills.
I love the idea of more solar panels. I would like to see incentives given to businesses and homeowners (including condominium buildings) to add these to their structures.
Alternative energy sources are not reliable and are more expensive. In addition to causing more harm than natural gas. The last few days in Kaneohe and windward side cloudy and rain so good luck if you are dependent on solar. Wind energy is not efficient in producing and transfering electriicy to the grid.
We have a large solar system. Because of our conservation efforts, last year we generated $1,900 more electricity than we used. We were not rebated any of this amount. When I called your office I was told since we are a residence, not a power generator, no refund was available. They suggested we USE MORE electricity if we were concerned about gifting energy to Maui Electric. This seems counter productive if you need the resource.
I love this idea! It's called the WINDWARD side for a reason! Let's use it! A lot of homes in Diamond Head/Kapahulu/Kaimuki are serviced by underground power lines, and HECO's requirement that homes be upgraded to 200 amp service in order to install residential PV makes installation cost prohibitive due to the cost of digging etc for this upgrade. If 200 amp service wasn't required for residential PV, then less space is needed for utility solar projects due to decreased demand
It would be amazing to have large gyms in HPP, Fern Acres and Hawaiian Acres/Beaches,Pahoa where the equipment is powered by the people using the equipment that would be attached to battery sources that Hawaiian Electric could capture to distribute to the area homes to help cost containment. Gym would be equipped with solar power as well.
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REZ Comments Collected There is a lot of untapped potential for solar panel placement on residential roofs. Not just in Pearl City but statewide. HECO should develop strategies to make use of this resource, possibly using partnerships with homeowners where their out-of-pocket costs are minimal but the energy generated by a distributed network of installations helps the surrounding community.
I have a recently installed rooftop PV system with battery storage. On very sunny days, my batteries will be full by noon and the system will stop storing energy. The system then stops producing electricity, even though there is plenty of opportunity. I would be happy to donate the additional energy that could be generated back into the grid to help reduce the demand on the grid, but that doesn't seem to be an option. I understand this is because of the limitations HECO places on PV systems.
As a renter, I feel felt out of this process and at the whim of my landlord. The cost of my power bill has jumped $300 a month I don't have A/C I put in brand new water heater got rid of my extra fridge and cut everything else back as much as possible and I am paying $700+ every month
Continue to turn trash into power by expanding the power project to burn the thousands of pounds of trash produced on Oahu into energy. This not only produces energy but also reduces the incredible trash problems and landfills taking up space.
We need more EV charging stations operational on Maui There should be operating stations at shopping malls Too many of the stations are closed Mill house. Ma’alea harbour. Kulamalo. None at Maui mall
We have solar panels on our roof and I challenge my neighbors to do the same.
Solar on roofing in Kailua represents a huge potential opportunity given the high amount of sunny days and the lack of large trees or mountains close. The biggest challenge is affordability for most people should consider Hawaiian Electric renting roof space, etc
We are installing 30 panels and 2 batteries to help shoulder the load. Hawaii Kai Golf Course has a large, flat parking lot that could accommodate solar panels. The panels would shade cars and keep them cool while golfers are using the course. The parking lot paving is old and crumbling. Perhaps a partnership could be made: new paving in exchange for using the space over the parking lot for solar PV?
Hydrothermal utilization and wind is important as alternative forms of energy.
Sun most days We have solar PV, it would be good for all to be able to add tesla batteries to stabilize the grid and provide for power outages. A recent quote requires additional panels added to use batteries, or I can add batteries, but they aren't part of the grid, so no environmental benefits for all. Would be good to be able to add battery storage to our home.
Can the interior area of the crater be used for PV panels?
Palehua Community the large amount of vacant land above the Pulehunui industrial area (southeast of the Maui Humane society) would be a supreme site for a large solar farm. It would be near power lines, near to the location where the State and Hawaiian Homelands are planning to put in a large number of facilities, and most importantly it is an area that receives a very high level of solar radiation with limited cloud cover.
Website that shows power outages as well as updates. Calling in during outages doesn't work. A single website linked to social media would help all. Could be automated as well. With power outages, most customers have cell service for sometime, so this would help all.
PLEASE stop the ridiculous activities that are RAISING our electric bills
There is an unused 18 hole golf course on the mauka side of Ali'i that could make a great solar farm. Was/is part of Kona Country Club courses - now going to waste & overgrown. Connectable to the grid.
The anti-solar rooftops attitude and practices of Hawaiian Power is an insult to the utilities approach to solving social challenges. When I fly over Oahu and Hawaii islands I'm flabbergasted about the lack of rooftop solar. I have tried to expand my current investment in our energy challenge and there is more resistance from Hawaiian Power than the County. I have not heard one word on how we can improve this number but many reasons why we cannot. You work a sheltered market. Live up to it's mission.
Allow rooftop solar with net metering. Don’t force us to use a third party like sunrun and stop putting solar farms on arable land.
These clean energy initiatives are not only costing us more in electric bills, but are also horribly misguided and poorly implemented. We won't even dream of building a nuclear power plant (The cleanest form of energy technology available currently) or even building an infrastructure to recycle solar panels.
Water Generator. Think about it. Water flows from Kahanua Valley through tunnels built in the 1890s by mccandless brothers to feed water to sugar fields on the leeward side. But, water flow to Waiahole valley provide taro fields, tenant’s, etc. can generate electricity with Down flow instead of pumps. I’m not an electrical engineer. But a system can be created Hawaiian Electric engineers. Electricity from created by water generators can feed to our grid. Thank you. A feedback is requested.
Why do we have the windmills so close to schools in the city of Kahuku Why do we have the windmills so close to schools in the city of Kahuku
Re-establish energy buy-back programs to foster more solar development, and encourage existing solar customers to participate. This might discourage the practice to “go off-grid” once a home’s batteries are fully charged if excess solar power is being produced, because the current compensation structure offered by Hawaiian Electric does not sufficiently benefit the homeowners, who have invested significantly in clean energy. Energy companies on other regions offer much fairer opportunities — why can’t HECO?
How can residences who live in condos and townhouses, who share roof space, take advantage of solar/PV energy savings? With all the current renewable energy resources where is the savings going, to the residents or HECO? Can fuel cell technology create electricity?
Energy storage is critical. While batteries at individual homes are important (I already have a Powerwall), infrastructure storage is necessary. With all the land available and water from rain, a water fed gravity energy storage system could make a lot of sense. There may be better places on the island.
Don't put solar in natural areas, only on buildings and parking areas. Otherwise the solar will ruin Hawaii's natural beauty and wildlife. Also many areas are already saturated with solar. They produce too much energy during the day and none at night. We need large scale energy storage otherwise we will never
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REZ Comments Collected reach the 2045 goal. Also stop making goals that are so far into the future that all current politicians will not have to be held accountable for them. Have realistic short term goals instead. Not just in Hilo, but over the entire island, parking lots should have solar covers. As we need more electric car charging, this can help facilitate the powering of the chargers.
Net Metering. Pay the same rate for electricity from private PV systems that you charge and the need for larger projects will be less. Given the volcanic activity on the island, is there any way we can use the geothermal energy to steam water to spin turbines to produce power?
Need to upgrade the grid to return power credits produced by solar homes to the homeowners in a more equal way. I understand cost verses credit, but it is hard to get behind a company that doesn't provide much back to the people that pay for it. Excellent Choice for solar!
Where are all the depleated batteries going? Are children being used to mine Lithuim in Africa to provide this means of "clean energy"? We also know its cause fires. Its a lie. Have a good day.
There are medical offices in Hilo with solar panel installations installed in parking lots to provide covered parking spots for the staff and patients and electric power for the grid. If this makes economic sense for their businesses, it should make sense for our entire community. One of the smallest benefits would be a public relations win for Hawaiian Electric. Please investigate this option before using precious agricultural land that most local residents can no-longer afford.
Clean energy i Is no more than a talking point right now and climate change is just a hoax and a way for Hawaiian Electric to raise rates and local governments to increase taxes
I have a PV with a NEM agreement. I want to expand as I have more space on my rooftop, but the process is difficult and I am limited to how much I can add. If a homeowner has a NEM, we should be able to expand to the rooftop limit to be able to contribute to the grid.
We installed a Tesla wall so we could take advantage of the money back.program. it has been almost a year, now, and we still gave not received any monies back from this program which HECO endorsed, advertised and encouraged the public to be a part of. Please, 1) explain why you have taken so long and do not say there was a long list of applicants. That is not an excuse. And, please, remit and honor your promise. You can call me at 808 292 8903. Installation of level 1 chargers to allow for EV charging during peak solar production hours at work sites as people are unable to take advantage of lower rates or solar production. Instead of utilizing so much limited land for additional solar structures and wind farms, partner with property owners to utilize their unused solar footprint on their home's roof would be a more ideal way to use space. Yes, there are plenty of challenges with adding solar to homes, but if the state wants to really be proactive in improving going renewable, they will make the process easy, available and not a money grab opportunity. Fiscally it is difficult for most home owners to get solar, but if there is incentive of co-sharing costs such as renting the space from then in the form of payment in electricity, etc. It's a win for the community and a win for the home owner. There's more to be said about this than this little space, but developing on green land for wind and solar farms seems to be an unnecessary use of limited space resources. Maximize the use of the space already developed and show the world how it's done right by working as a community.
Ideology is not good policy! 100% renewable in Hawai'i is not going to make a dent in "saving the planet." There are clean solutions that are affordable, available, and can meet demand. Solar and wind are none of these! They work to an extent, but cannot be the only solution. Use actual science and engineering to help Hawai'i residents enjoy living here. That is your job! This has become a tourist state, but the residents are still paying for it!
I would love to have renewable energy options Limited number of EV charging available within this commercial zone
There should be an incentive for those with solar to save electricity usage, because as it stands, users are actually encouraged to use more in order to reap monetary benefit. There is no financial gain or savings when we produce extra electricity. The only way to reap any benefits of the credits we earn is by going over what we produce. When I first moved into my home with solar, I asked around other users to understand how it works. The advice I was given is that if I’m used to using very little electricity and always produce extra, then I need to crank it up sometimes, like leave the a/c on, so that I’d go over what I produce, use up my credits, and pay even less then the service fee. I don’t understand how come we don’t get anything whatsoever for the energy that we produce for HECO. Even if we get a small percentage of the profit from what we’re making for HECO, at least it would be an incentive to use as little electricity as we can, even with solar, which equates to producing even more.
100% renewable is not feasible and will cost more than you believe you will save. It is unattainable for the majority of people. You are placing a huge burden on the bottom of the income bracket
Regarding large solar projects on former Ag land; If ground mounted (bifacial) solar arrays are raised 6 to 8 off the ground, they can provide shade or partial shade for new Ag opportunities that could be very efficiently drip irrigated and provide low water use and very low evaporation for suitable crops such as strawberries, many lettuces and herbs such as; Shade-Tolerant Vegetables and Herbs: arugula, endive, lettuce, sorrel, spinach. collards, kale, mustard greens, swiss chard. beets, carrots, potatoes, radishes, rutabaga, turnips. Broccoli and cauliflower, brussels sprouts, cabbage. mint, chervil, chives, coriander/cilantro, oregano, parsley.
Residential townhomes have a limited access to PV/EV amenities. Shared roofline limits the amount of EV panels per occupant. Not sure about available options through HECO. Residential customers should have opportunity to add, expand, or modify solar panels on their homes with ongoing incentives and without adverse consequences like having to modify their customer agreements that negatively affect them. Battery systems are neat, but not the solution to help the whole community or help the grid. The grid needs to be updated to support more solar and allow those who want to add enable them to. New construction or remodeling also should mandate solar with incentives.
The solar farm you are installing at the base of makakilo is a giant destruction of plant life and waste of our precious land. You should be installing them in parking lots and areas that are already paved over. What is the point of renewable energy if you are killing acres of plant life to install it? This would not be a good location. Major power production equipment should not be located within the limits of the Sunset Ridge community as indicated by the placement of this marker.
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REZ Comments Collected Additionally, solar pannels and wind turbines should be located where they will not negitively impact ocean views or unique locational values of ajacent residential properties. Wind turbines should NOT be near schools or residential areas. These are highly undesirable in Kahuku and have negatively affected the community around there. Would strongly oppose more turbines on windward side unless in remote areas
Frankly, I agree that the coal/oil fired plant in Campbell should never have been shut down. Solar and wind are fine when it works but it's not 24/7 reliable. HECO should've invested in building a nuclear power plant in Campbell as it would allow all other plants to be shut down and have ZERO carbon footprint. Nuclear is VERY SAFE today as it's been 2 decades since the U.S. built a new nuclear plant. Hey, if the City can spend $12 BILLION on a stupid rail, it costs less than that for a nuclear plant that will fill the needs for all Oahu's electrical demands for decades to come. Even the smallest plant has more available capacity than Oahu currently demands (even without solar & wind supplements).
Wind farms are run by electricity. I thought the purpose of wind farms was to use the wind we get naturally to help provide power. Wind farms barely pay for themselves. They are expensive, interfere with birds, and barely contribute. If you want wind power, let the "wind" power the mills, not electric. They don't make sense.
Good idea
Why is the price per KW different everywhere? Is Hawaii's electricity so much better that it costs more? Is the price per KW for electricity in Ohio less because the "quality" of the electricity produced is not as good? Noooo! Electric is electric. It should cost the same across the board. Power companies stop being greedy!
Please stop taking away agricultural land! Get Monsanto out of Hawaii!
Quit taking away agricultural land and we will be able to have plenty of food! We need to bring back a few dairy farms so we can produce our own products here on the islands.
Good idea. Do not take away people's freedom of choice in the process. If people want to be off the grid let them.
Noooo! It isn't worth it! If you want to use wind power, let the wind that naturally happens power it. Why are the "wind" mills powered by electricity? Makes no sense, they barely pay for themselves, take away from the natural beauty, and birds are dying because of them.
In my view it is important to stop wasting green energy which is already produced: I have a photovoltaic system with batteries, but when the batteries are full the photovoltaic system must stop producing energy because HECO does not allow my system to output that excess production to the grid! I would not even expect to be compensated for that energy, I would just want to stop the waste, and I am sure that many new photovoltaic systems are in my same situation.
Please stop destroying Maui’s beautiful landscape in the name of climate change. You will destroy one of the most beautiful spots on the planet with ugly wind turbines and solar panels, and the climate will continue on its path.
Kamehameha Schools Trust (KST) has thousands of acres of property tied up in low revenue, methane emitting cattle leases all over the Big Island. What about long term KST leases for renewable energy production that would benefit KST, Hawaiian's education and the public at large? Ag land use and renewable energy use are not always mutually exclusive. Does KST --given that they are fundamentally a product of co opted land use --have any desire or obligation to give back to the planet and indigenous peoples who have no access to their schools ? Until you can Figure out a way to Lower my bill this is Useless. My KWH have been the same for years, and my bill has been The same, Now that the Coal plant has been shut down, My Monthly Bill For the SAME KWH has Almost Doubled, And For what? Heco Made Millions in Profit, and yet we the People who made you Wealthy Suffer.
Wind turbines destroy the beauty of Maui’s natural landscape.
Land South of and surrounding Community College has ample empty space and access to electric grid from existing power plant accross the Queen K highway from the airport. Looks like some development directly North of the college is in early stages, perhaps could be a coordinated development opportunity for solar power facilities.
While I’m not in favor of wind energy, especially anywhere near populated areas, I believe solar panels should be placed on every single public building possible (schools, government buildings, etc) and over parking lots (covered parking).
Solar/wind generated electricity should only be backup sources. Since Hawaii/Pearl Harbor/Hicham are home to the Pacific Fleet ALL ENERGY resources should be available for our strategic defense. My KWH have been the same for Many Many Years. Now My KWH are still the Same and My Monthly Bill has almost Doubled, Yet Heco has the Nerve to Post it's Millions of Dollars in Profit. Seems like this is only helping Heco Geothermal should be pursued on this island as it is the least intrusive on the environment and requires less outside inputs.
There are abundant opportunities for renewable energy projects in Puna—only each project will need security alarm systems and cameras to deter criminal activity. Susidized Solar on business roofs for a start. Methane gas burn off from our refineries is energy going to waste. Hawaiian Electric has been stubbornly concerned with the bottom line than with customers. Until all the refinery burn off is used to fire our boilers to create steam and hence electricity you are wasting energy. The product of burning methane is O2 and H2O. Compare that to the carbon foot print of just one windmill.
Closed loop pumped storage hydro power can be a great solution for storage of intermittent renewable energy production (wind/solar) and a more cost effective and environmentally friendly alternative to battery systems. With the natural slopes on Hawaii Island, it seems that these systems would be possible storage solutions and reduce the need to rapidly switch on/off power generators at the fuel oil plants to balance inconsistent renewable power supplies (wind/solar).
In 20 years you expect to go completely green? Impossible, schools are billions of dollars behind in updates and renovations, now they have to go green. How are millions of homes, condos, and business going to go green. Who is going to pay. Will Matson and airlines who bring in all our essentials going to solar and wind power? Will new rail system be updated to run green? Who will pay? Will all our truckers and delivery people going green? Who pays, etc. etc????
Apparently no solar company wants to help off grid areas such as those in Nahiku because they are most interested in making money off of selling electricity they make off your roof back to the grid.
Start looking into putting power lines underground, at least in areas affected by wildfires often, wind and cause mass outages like down veterans highway to kihei Why did our electric bill go way up after the so called smart meter installation?
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected Subdivisions along Hwy 137 (i.e. Kehena, Puna Palasades and Seaview) are on the sunny coastline with ample homes that can and do offer rooftop solar PV. Please improve the ability for residents to have grid-tied solar PV systems by upgrading the grid infrastructure for these subdivisions. Many residents in this area have resiliency practices already, so may choose to have onsite battery storage for their solar PV setup. Hence, there are opportunities for distributed energy storage as well as excess solar PV feeding into grid to contribute to upper Puna residents who have less solar opportunities (e.g it is more cloudy along the east rift zone than in the Kalapana coastal area.) Kihei, Pukalani and Wailuku are full of developments, start working with Hawaiiana and other developers for solar roofs and green roofs with subsidies or incentives so that these complexes become more self sufficient.
I agree with an existing comment that panels over the parking at the Hawaii Kai Golf Course has great potential Geothermal done "right". When our oil supply becomes compromised, as one day it surely will be! Out of luck!!
Work with animal farmers and keepers for solar panels on ground - generate energy and provide cooled areas for animals to rest. This can be taken to bus rest stops as well. Many bus stops on maui are uncomfortable, hot and sunny. Work with the county to beautify and functionalize rest stops to improve use of public transport and generate power.
Incentive HOAs to install “community” solar on building …. Rebates to individual residents or HOA to encourage solar installations. Offshore wind!
How can our Haiku Point condo(200 apts) have Electric Vehicle recharging stations installed within our grounds, to each carport and parking space? Is there a pilot project we can volunteer for?
It's unfortunate our city council did not think this out better. Rather than eliminate the Kahi plant, but do so in phases, must people cannot afford the alternative initiated by the progressives who have most of the discretionary funds. But, enact a process that doesn't bite most of the population of Hawaii. However, I do appreciate the Hawaiian Electric initiative to help the population with solar power initiative. Mahalo HEC.
I’m in favor of a well planned electric power supply system that takes into account reliability and the cost to electric customers AND taking into account of the consequential cost impact of your electrical customers, business and government which could increase the cost of living for anyone or organizations that uses electricity. Lately, there has been a lot of outrages in my neighborhood. I was really surprised when HECO seemed to be NOT aware when AES Coal Plant shut down and the consequential increase of the electric rates. In the past, HECO tract cost of fuel and the impact of electrical rates in its Long Range Generation Planning. Isn’t HECO still doing this study as new electric generation units are added or subtracted from its system? The cost Electric energy affects all of us so Plan and implement WISELY!
Back up power is needed for renewable solar/wind. In the next several decades it will be impossible to eliminate the need for fossil fuel powered back up generation. It’s that or get ready for an increasingly unreliable grid.
the kula ag farm ( a maui county project) has vacant land between the current farms as well as rough terrain areas that could support wind turbines as well as photovoltaic pannels Many Hawaii residents have bought into solar energy. The time is approaching where roofs with solar panels will need to be replaced or refurbished. The cost of moving panels to replace a roof is crazy expensive. I think subsidizing re-roofing is more than warranted, especially as reroofing is not something a homeowner does but once every 15-20+ years. I am nearing that point when reroofing will be necessary. With my fixed income I will need all the help I can get to make it happen. Anything HEI can do to assist residents with solar panels will be greatly appreciated.
As with most of Hawaii, this area is good for Solar, not as good as the West side of the Island but still pretty good. Geothermal test plant is probably a great option but the location must be perfectly picked. Previous site in Pahoa was damaged 6~8 years ago.
Wind is an excellent renewable energy source—however the latest weatherproof turbines and the latest Plastic bird screened blades or vibration towers must be used to decrease salt damage repairs and harm to birds and bats. Solar power companies act like its free but their contracts should all be reviewed carefully. They have some fairly nefarious clauses. If in doubt, have them reviewed by somebody, preferably contract attorney before signing! We should do more air dry/ hang dry our laundries and use our natural sun power! It is difficult for apartment/ condo residents as most condos allow hanging laundries in lanais. Condo AOAOs should allow hang dry even the limited basis. Can HECO voice up?
Please continue to add wind, solar and battery storage as fast as possible to try and help preserve the power supply on our beautiful islands instead of relying on petroleum that has to be shipped in and can easily be interrupted at any time. Think about what would happen to our economy if the oil stopped flowing to the islands unexpectedly.
Honua Ola is a proposed wood-burning plant located in Pepeekeo. The proposed plant wants to cut eucalyptus trees, burn them to generate electricity. The rate Honua Ola plans to charge HELCO. is more than 2x what solar would cost. They're claiming this is renewable but this is a lie. The trees will not be replanted because the major landholder KSBE wants the trees permanently removed. This is a challenge because community members do not want this plant and Honua Ola keeps pushing to open the plant. WE can do WAY better than burning trees in 2023!
Increase grid-tied systems to provide excess power to the system for storage/later use. Net-metering is a good incentive to motivate users to invest in solar systems.
Expand geothermal to ensure lower energy costs for the consumer. These wasteful pet projects for various solar, wind, tree burning fiascos are doing nothing to lower the cost of energy to the consumer and do nothing to help attract true manufacturing jobs which are desperately needed.
Develop micro-grid landscape for rural and remote neighborhoods. Whereby HECO facilitates installation of PV panels n residential properties and battery storage in centralized location (subsidized through grants and public/private partnerships). This would help achieve the renewables goal, along with creating resilience for the community by hardening certain infrastructure and creating redundant sources; if one neighbourhood were to be adversely impacted by an event, the neighbouring communities could divert some electricity.
Grid-tie solar systems. Net-metering was a good motivator for the homeowner/farmer to invest in solar systems.
Are you nuts? Look what has happened to other locations that have tried to go 100% renewable. Utility costs have gone through the roof. How are you going to stop that? How are you going to ensure utility costs are kept down. How are you addressing environmental impact - like killing birds with windmills and the society impact - like child labor in Africa mining rare earth minerals?
I think there is opportunity to seek other companies to compete with HECO to offer energy solutions to Oahu's residents. The poor planning and decision making of HECO and our state representatives has clearly proven, especially in the past twelve months, how detrimental the consequences of poor decisions and planning can have on locals. We need more choices when it comes to such a serious matter such as energy demands required by the state.
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REZ Comments Collected battery storage facilities needed to stabilize the grid. More roof top solar panels will help reduce demand but must be coupled with battery storage for load management. In North America, every electric vehicle manufacturer (except Tesla) uses the SAE J1772 connector, also known as the J-plug, for Level 2 (240 volt) charging. None of the HECO fast charging locations support the SAE J1772 connector thus limiting their usefulness. Additionally, for those that can use the HECO DC fast charging stations, it’s not recommended to use them more than once or twice a week, because the high rate of recharging can adversely affect the lifespan of an electric car’s battery if done too often. I never see these fast charging stations in use because of these facts.
Military Installations need reduced carbon (ie renewable) electric reliability and resilience. Increased reliability for military installations offers benefits to neighboring communities when transmission & distribution is disrupted (eg lines down during a major storm). Communities should seek to partner with Installations who seek to host Generation resources to improve reliability and resilience for everyone.
How much will the taxpayers be fleeced for this? How much will the taxpayers be fleeced for this?
I would like to install solar panels on one of my two houses in Volcano but I am not sure it would pay for itself. Volcano is often cloudy and rainy which would eliminate the solar generation of electric power. Still, since electricity is so expensive maybe it is worth the installation. Do you have some potential generation figures for Volcano?
This is the community lot for Fern Forest. This is a ever growing community that could use more infrastructure This is the entrance for Fern Forest. This is a ever growing community that could use more infrastructure
This is Hirano Store. They used to have a gas station there perhaps they would be open to a charging station and the community nearby would benefit greatly
Could the unused land at the airport provide space for solar panels in addition to the parking areas (covered parking results).
The only way to people completely green is to be off the grid. Let people be off the grid.
The only way to people completely green is to be off the grid. Let people be off the grid. This whole renewable energy thing is a big farce. I'm not blaming you at Hawaiian electric because it's probably being forced down your throat. In fact, I'm sure it is. This thing is never going to work plain and simple. They're just isn't enough energy in Hawaii at present to accommodate what needs to happen. Like most government programs, it will end up costing more and being of little benefit to the taxpayers
The park here has a decent sized parking lot that could be an excellent site for solar covered parking. It also is in an open area so shade is not a problem.
Nuclear fusion generator that produces power like the sun will be the best option for 100% renewable energy, but so far there are only a few start up companies working on this technology and no government funding provided to them even though they are clean and green. No radioactive waste will be produced like with nuclear fission generators, so there won't be any Toxic Avenger or 3 eyed fish incidents.
Would be possible to get more of the condo buildings in this area to have roof mounted solar panels?
For almost 40 years my comment is: NOT environmentally friendly next to a neighborhood, too near lava eruptions, Loud noise, no working monitors for emissions, no alarm and evacuation plan for emergencies but I’m sure you have plans to build more plants all the way to the ocean and destroy the peace and beauty of Kapoho. I’m also pretty certain that you will ignore my input. Please alert me for public meetings. Thank you for the opportunity to give input.
Residential rooftop solar. Hydrothermal as long as it can be done at a reasonable cost. Forget Wind, as it seems to do nothing but disrupt that eco system and kill whales.
Based on the proposed idea of a solar farm on an unused 18 hole golf course I'm in support of this kind of local project and encourage it to move forward.
We are building a self storage facility along the canal. Over 750kw of pv can be installed. We are willing to look at battery storage as needed for grid purposes. I am the principal investor for the LLC. I am familiar with moderate sized pv systems.
Solar panels are not allowed in Hali i Kai condos.
Electric vehicles using batteries are NOT a good option...Where are folks that use batteries going to put them when they no longer work? How will they be recycled? We are on a small island. Furthermore, where does the electricity come from when you are charging those batteries? From the oil fired plants we have in Hawaii.
I installed a new PV system on my house in November 2022 but HECO still has not approved coverage for my ADU which is on a separate meter. My PV system is sized to cover both dwellings but my ADU continues to pull from the grid because HECO takes months and months to approve a simple thing like a meter consolidation. If HECO could speed up their processes a lot more people would stop pulling from the grid.
HECO needs to speed up their approval PV approval process if they want to get people off the grid. It literally takes months to get approvals through HECO. Could add solar panels in the large undeveloped grounds of the boys prison
Could add solar panels in the large undeveloped grounds of the boys prison
Could add a small solar farm on the undeveloped grounds of the boys prison
In case of hurricane, which will destroy most solar panels and deprive families of electricity until they rebuild, Hawaiian Electric should maintain coal burning plant as backup.
The wind project that powers the water department's pumps looks to be curtailing a lot of potential generation, but apparently there is no PPA in place to allow the export of power to the grid. This project seems like it would benefit from storage, so the pumps could be powered whether or not the wind is blowing, and so that the project could provide peak power to the grid. I know that the ownership and existing operating agreements complicate matters, but amending agreements must be simpler than building a new wind facility.
Hawaii island sits on one of the most active geo-thermal resources in the world. It's stupid not to take advantage of it. Between its solar resources and geo-thermal resources, the island could be energy independent forever; it would never have to worry about running out of electricity; it could wean itself of its dependence on fossil fuels! As a home owner, I look forward to a day when Hawaii is a no longer dependent on fossil fuels.
The challenge is this strange tool. The "Solar Potential" tool shows no data for the Miloli'i area, yet NREL has LOTS of data.
We would LOVE to have solar panels. But they’re ridiculously expensive. Looking to buy a RAV 4 plug in hybrid. But don’t know if it’s feasible since electricity is so high
Stop ripping us off with the smart meters than make our bills double You put in the wind towers that havent done much good because the customers had to pay for that and you stop using them to charge us more
A-217 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected Had solar added and bill dropped from xx to 26. Two years later, solar is still working and it is 2x higher than before solar without AC.
Not enough electric car charging stations in or near densely populated residential areas.
Park and ride rail with EV charging would increase green transport into town, avoiding congestion. Win-win
Why are condos categorized as commercial and takes over a year for solar approval from DPP. The state wants renewable energy but puts roadblocks to people who try to do better. Let's streamline the process and make it easier so people can save money and preserve our island.
Hickam AFB doesn't have a single public EV charger on the whole base except maybe on the HANG side. Further, the base is full of large hangars, building and large parking lots that should all be covered in solar panels to power new EV charging stations and facilities. It's time to get people excited, make it easier to switch to EVs sooner, lower utility bills and help keep our island air clean. The large parking lots of the Hawaii Kai Shopping Center, Hawaii Kai Towne Center, and Koto Marina Center rather than land could be covered with solar modules. I understand that on some days, more solar energy is produced than HECo can use to satisfy demand, so energy storage would also be needed. Still concerns about bird interactions with wind generator blades.
Are there opportunities here for a solar farm?
ro have solar on the roof. To sell back energe that I have left over so you can sell to Co. that need it
I agree that the abandoned golf course has potential for a smaller solar farm.
Idea is great and an important component of island sustainability. However, HECO's processing and bureaucratic hassle to initiate.new pv.system is absolutely problermatic and new user initiation and rebates is terrible and unfriendly to new adopters
Idea is great and an important component of island sustainability. However, HECO's processing and bureaucratic hassle to initiate.new pv.system is absolutely problermatic and new user initiation and rebates is terrible and unfriendly to new adopters
Let's not charge a pv solar owning customer $300 for "generation" and "fuel" in a month where they receive from HELCO 22kWh, but send to HELCO 25 kWh.
It still concerns me to have wind generators near the coastline where they endanger birds.
Good opportunity for solar farms We want to be part of the solution. Our roof gets a lot of sunlight and currently have solar panels for water heating, but we would be interested in setting up an affordable solar system for our other electricity needs. Allow the Leilani Estates Community to invest in photovlatic cells on building tops and two of its 10 community acres to power the common areas (clubhouse, pavilion, ev charge station). This to be paid for by a partial grant and community members who invest in the infrastructure with payback of savings realized VS the existing power grid.
Big steam engine use old telescope lenses to make the heat to a turbine produce electric
There is abundant open rooftop and parking lot space all over Honolulu. It is south-facing so should get optimal solar generation. Let's harness the ocean! Unlike wind and solar the ocean has 2 tides every day. The tides could power turbines that would power the entire ocean and it is a clean source of energy. Keep it simple. https://www.irena.org/Energy-Transition/Technology/Ocean-energy#:~:text=Tides%2C%20waves%20and%20currents%20can,use%20it%20to%20generate%20electricity. This comment applies to all green energy development, be it wind, solar or whatever comes down the road. Please don't use virgin undeveloped land for any green energy production. Use only existing structures, preferably in already developed areas ie, existing building roofs, walls, express way medians, road beds and adjacent rights of way. All structures are disfiguring to the landscape and take a toll on wildlife. Giant wind and solar farms are a massive eyesore. I'd rather have compact scrubbed coal, hydrogen or oil than untold acres of energy infrastructure. If worse comes to worse teach people how to cut down on energy use so we need less infrastructure rather than more. Why not install PV panels on top of condominium parking structures, they’re everywhere like schools did in their parking lots. Do condo owners and renters want to contribute to this, lower their bills, of course This entire state is prime for solar (photovoltaic) energy creation (and this isn't even considering newer tech including transparent photovoltaics) where a lot of home rooftops are still devoid of PV due to the challenge of not enough storage capacity for excess power to be fed back into our island/state locked power grid. IMHO, HECO and its subsidiaries should be prioritizing this (excess storage capacity). Why? Because more off-grid solutions are coming and economies of scale will inevitably make them feasible. I've been following RV/camping car off-grid solutions both in the US and Japan for awhile now. Ecoflow has several turnkey solutions including a modular solar generator system (you can link two Delta Pro's together along with appropriate PV panels) that I've been pricing out to see if it made sense to implement in order to just power home AC units and the refrigerators (the largest kWh consumers besides powering up the oven, dryer, microwave). Each Delta Pro is 3.6kWh that can have an additional 3.6kWh battery added; thus linking two of them together, can yield close to 11kWh of usable power generation; overkill for most situations unless also taking into account emergencies). The pricing has dropped dramatically in the past year to the point where I may pull the trigger for one unit as a starter (since the cost of one unit with additional battery plus say 1.2kW of PV), could pay for itself in 2 years if running a bunch of wall AC's or split AC units for most of the day/humid evenings as well as two refrigerator/freezers). And while I don't own an EV (the pricing and lack of infrastructure never made sense), the fact that I can use this as a charger, would make moving to EV finally attractive as more auto options are now becoming available. HECO should be making it far easier for residents to get onboard (rooftop PV) before the company starts finding itself losing to actual feasible turnkey (mostly plug-and-play) off-grid solutions that don't require a technical background to setup.
It’s not reasonable! Please use common sense! We are already having issues switching from 3 different power sources. It’s not a seamless transition, I do appliance repair and have never replaced so many computer boards as I have in the last few years. Thanks Dave
All new C&C construction and public projects should be required to use solar energy. The new Civic center will lay down lots of new concrete and asphalt. The roofs could be for solar and green space.
Looks like good location however, please make it un-viewable from the driving road unlike the Palm Springs California Area that has wind farms that absolutely destroy the natural scenery as well as highway to Las Vegas from Los Angeles - gigantic solar farm that is viewable from the freeway. I own 19 Solar panels and have a back up battery. I have been told that HECO takes a percentage of my stored battery power and sells it. Is this true? I hope this is just bad information. Please clarify. James
A-218 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected Wind is not a sensible energy solution, especially compared to solar. The turbines are extremely large and costly to produce and maintain, especially near Big Island the water is deep to install, and they are an awful eyesore to coastal residents and ocean users.
Great open lava lands for a solar farm! I think a small nuclear reactor located on Schofield could provide clean power to the entire island.
When is this so called green energy going to lower our rates? Go back to coal and lower our rates. What good is renewable energy if our rates keep going up?
Electric prices are way to high
Electric prices are way to high
Get the Home Owners Associations under control. They are denying homeowners’ requests to install new solar panels for arbitrary reasons. These requests were developed by professional companies and were approved in the past.
At this point, “affordability” is the most common concern. Maybe 100% renewable energy is not the future your customers are looking for, unless you can show that it will not negatively impact affordability.
Please have a counter that shows how much more Hawaiians are paying now that the coal plant was shut down. This should be a running total.
In Orkney, they generate power using tidal energy. The tide is rising or falling 24 hours a day, spinning the turbine. They generate 104% of what they need! Have we looked into these turbines to see how to apply this technology in our island state? Orbital Marine Power in Orkney
I think it's a big mistake to go green without having a backup. Solar is a joke and only works during the day with clean panels. Look at how much dirt are on the panels just installed In Kapolei, they are covered in red dirt, last time I checked the panels don't work very well when covered in red dirt. The windmills are a whole other story, built close to residential areas, killing wildlife, environmental unfriendly. Don't get me started with the closing of our only coal powered, what was the problem with clean coal? China is building a new coal plant every week, and they aren't even near as clean as ours was. Hawaii's whole energy direction is political driven by the tree huggers and are forcing the rest of us to pay for their political agenda.
Would like to have a commitment to have the electric vehicle charging stations a high priority to have them working. The one next to Tommy Bahamas in Mauana Lani has not been operational for some time. I drive a Tesla but my next car will be a gas car due to frustrations in charging. This is especially true on Hawaii where distances are great and may need a charge before driving home.
Placing charging stations in park areas would help to serve the local communities and keep traffic away from commercial stores
Placing charging stations in park areas would help to serve the local communities and keep traffic away from commercial stores
I don’t see any comments or considerations regarding the best energy source—- nuclear power.
Bring back the NEM program, and create more free EV charging stations. There are not enough on this island! I concur with so many other commenters that there is great opportunity to increase solar use and to add battery power, but that there needs to be additional incentives to install new solar plants or improve existing ones. This would have the added impact of preparing the neighborhood for the days when electric cars are the norm and not an expensive novelty.
Pacific Paradise Mountain View Manor off of Oshiro road is a fast growing community. There are more sunny days than before and the potential for solar seems to be increasing.
Forget green. Rely on nat gas
Affordability should be a top priority for HECo as the Islands people are already suffering financially. Too many other economic issues making it hard for residents to afford to stay here and live. Everyday basic needs should not be hard for everyone to afford.
Place solar panels on the RAIL guide way. That will use available space, it will be non-obtrusive, it will be near the primary user, the maintenance will be easier and excess power can be stored under the rail where space is available. Alternate wind (small scale) and (vibration) power generators could provide power at night. As it become successful, freeways and viaducts will also become an options. We'd love the opportunity to install roof top solar panels to help with home electrical cost and to help save our planet. What are the Hawaii county incentives to help us achieve this with our home and electric vehicles? Co-locating solar and/or storage with the new water well infrastructure that is going in would make sense. The pumps are high-demand loads that could be mitigated by having generating capacity close by. The large electrical feeders also make for a good conduit to feed power back into the grid. The area is largely out of view from other areas, which helps to minimize visual disturbance.
Ideal location for offshore wind power farm
Ideal location for offshore wind farm. Offshore wind installations have an added benefit as a fish aggregator. Offshore wind power is good for energy and food sovereignty.
Good location for deep geothermal power plant.
How about you quit the bulls bit and recognize you have geothermal like Iceland quit trashing the islands with solar and wind turbines and support nuclear/fossil fuels while getting the real research done. This is crap buying into “climate change” the height or arrogance and at worst the decimation of our freedoms and our islands.
Please stop forcing this on everyone! Your rates are already insane and without the coal plant, doubt they will ever go down. This will do nothing except raise rates more, our grid cant handle it and will make any power outage increase. This isnt a way to reduce costs to residents, thats a lie. If people want to be more green, let them but stop forcing this until you can make it cost effective for all and the grid can manage. Ag Zoning not specifically approved for BESS battery storage. Could be legal challenges. Naalehu Solar Project not in line with Kau CDP. Site infrastructure (connection to roadway, paving, left turn lane off highway, could cause significant cost to project. Panels will reflect a significant amount of light towards residences in Waiohinu and Kiolaka'a. Surrounding property owners do not support this project.
I want you to provide the least expensive energy you can, regardless of the source. Don't push what you call "clean" energy before it's time. When "clean" energy sources become less expensive (without subsidies) than conventional sources, they will automatically become the norm. Your job should be to provide the best service possible at the best price. So many people can only afford the cost of townhomes. We aren't able to get fiber and obviously cannot get solar with shared roofs because of HOA rules. Let's get the HOA on board and it's unfair that people in townhomes have to pay higher costs for electricity and internet because of something they cannot control
We need Hydrogen as a power source and part of our infastructure
A-219 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected To encourage more roof top solar, Helco needs to allow the solar credits generated to be applied to the entire electric bill, specifically the minimum charge. If I generate more KWH than I use in a year, I should not have to pay a minimum charge every month. Hello is getting the benefit of free KWHs, they should not be greedy and still billl a minimum charge on top of receiving free electricity from the consumer.
have studies been done for hydro pumped storage to better store excess wind and solar energy?
Big hurricane, solar panel wiped out, wind turbines destroyed. Where does power come from? Big hurricane, solar panel wiped out, wind turbines destroyed. Where does power come from?
Seems like a few SMRs (Small Modular Reactors) could take care of Oahu's energy needs with minimal footprint and almost zero cost for fuel transportation and no carbon footprint. Is this possibility being examined? Lots of vacant or little used land here for a solar farm. It would be hidden from the road by trees. Those who want to go back to coal are fooling themselves about what coal does to our island. We need to get off of coal completely. Also there are quite a few opportunities for geothermal production that should be explored.
Please continue to do all that you are doing, setting and reaching goals within as reasonable time of as possible. Battery storage is good, but can the average household afford it and, if not, what then is the answer.
Include geothermal in the forefront of discussino.
Partner with DOE to install solar canopies over existing parking lot which is located near the street for easy connection to HECO grid. I recently got an email about a new meter, which I greatly appreciate this advancement I wonder if there has been a discussion of installing "smart meters." This would greatly aid power management, a key component of a grid based on renewable sources.
Kaiser High School has a huge parking lot and adjacent field which could be used for solar canopies or a small-scale solar farm. Close proximity to the street for HECO grid connection and nearby fire station for added security and safety.
Parking lot solar canopy which has been done at other DOE campuses. Win-win! Provides shade for vehicles and generates solar power to help lower rates for the community. Close proximity to street provides convenient and unimpeded connection to HECO grid.
Parking lot solar canopy which has been done at other DOE campuses. Win-win! Provides shade for vehicles and generates solar power to help lower rates for the community. Close proximity to street provides convenient and unimpeded connection to HECO grid.
Parking lot solar canopy which has been done at other DOE campuses. Win-win! Provides shade for vehicles and generates solar power to help lower rates for the community. Close proximity to street provides convenient and unimpeded connection to HECO grid.
Parking lot solar canopy which has been done at other DOE campuses. Win-win! Provides shade for vehicles and generates solar power to help lower rates for the community. Close proximity to street provides convenient and unimpeded connection to HECO grid.
Parking lot solar canopy which has been done at other DOE campuses. Win-win! Provides shade for vehicles and generates solar power to help lower rates for the community. Close proximity to street provides convenient and unimpeded connection to HECO grid. Parking lot solar canopy which has been done at other DOE campuses. Win-win! Provides shade for vehicles and generates solar power to help lower rates for the community. Close proximity to street provides convenient and unimpeded connection to HECO grid. Install more EV chargers! There are NO public chargers from temple valley all the way to turtle bay. Yet, there are plenty of people that commit along this route and more and more are switching to electric vehicles. Incentivize at home charging with better rates for EV owners to charge during off peak hours!
Install more wind turbines in highly productive areas. Install a traffic circle right here for all the people that like to turn left in the evenings. 😓😓
Do many of the warehouses/businesses have solar panels on the roof?
I know there are going to be electric vehicle charging stations in the new parking garage. Is there a plan to put car port structures with solar panels on the top floor? Keeps the cars cooler, and provides electricity at the same time.
If feasible, erecting micro-grids with solar PV panels and battery storage.
I commissioned electric solar panels in October 2023. They are installed and sitting on my roof NOT connected due to lack of movement on the part of MECO and HI Electric. When will we ever get our government and utility officials to become efficient and effective in their jobs?
I have lots of room on my roof (in addition to my 28 PV panels) to make a micro grid.
I have lots of room on my roof (in addition to my 28 PV panels) to make a micro grid.
I have first hand experience in alaska with all aspects of power generation. The only good reliable power is hydro and thermo. You have a resource that could power all of hawaii with thermo from your valcano. Solar and wind have been a waste of time and money. and are very expensive to own operate and it takes 12 times the minerals that need to be mined to build. Hawaii is being lied to. Its a money makin scam. you don t build anything here you don t mine anything. so you don t see the fact that all you are doing is changing where you burn diesel. So I don t support your effert to lie about the truth. Go back to the old power station. HECO was not ready to transition yet. You’re putting the cart before the horse. Like anything else in this world you don’t get rid of something until you know it is working. This is plain idiocy and childish. You’re letting a bunch of people decide for you what is best to transition. Transition is slowly moving from one condition to the other not abrupt change. You didn’t really transition did you? Because you don’t have any full resources to back up power in the event of an island power shut down do you?
Bring back the original net metering like in the past. So many homes could feed our grid the energy needed if HECO develops storage solutions for the energy being fed back to the grid. Then during peak periods, the grid could draw from the HECO batteries.
Solar is only for the wealthy, as panels with battery are unreasonable for the poor. Tax breaks and energy savings do not payback debt, so the poor must incur greater debt, that is in addition to their mortgages and higher taxes. If the energy savings and tax breaks were SO big, then all these solar companies would NOT be sprouting out of the woodwork like mold and thriving in a million dollar median house market. Higher taxes will punish the poor, who cannot buy solar; but the rich can take advantage of the tax cuts.
Solar is only for the wealthy, as panels with battery are unreasonable for the poor. Tax breaks and energy savings do not payback debt, so the poor must incur greater debt, that is in addition to their mortgages and higher taxes. If the energy savings and tax breaks were SO big, then all these solar companies would NOT be sprouting out of the woodwork like mold and thriving in a million dollar median house market. Higher taxes will punish the poor, who cannot buy solar; but the rich can take advantage of the tax cuts.
A-220 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected I believe it is too much to ask that the island of Oahu be totally reliant on renewable energy by 2050. I think there needs to be a compromise at some point. There need to be more consideration to unintended consequences. Mark James 3025 Wailani Rd Hon HI 96813
Good place for high speed EV charger. High speed EV chargers will make EV rental fleet practical. Good place for fast EV charging stations. A network of fast EV chargers in several popular locations on the island will make EV rental viable.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc. All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc. All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc. All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc. All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc. If solar powered (not just solar charged) vehicles are developed, using the sun to propel the vehicles, motor fuel consumption will drop to almost nothing. potentially saving billions of barrels per year.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc. All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
All public & private surface parking lots could be utilized for PV & energy storage. Reduce heat island effect, selective trees/green spaces. PPA or UESC etc.
Very poor decision making from the leadership of HECO monopoly in Oahu has brought increased electricity prices to residents. The recent closure of major coal powered plant generating cheaper electricity here in Oahu, and replacing it with buying expensive oil, hence passing the increased bill to residents is not representative of a leadership that looks after their own people but instead puts political motives as priority. Change in leadership is the real opportunity. We shut down the coal-fired plant TOO SOON!
Stop taking all my solar credits when you "reconcile" my account every July. It's bad and it's why I have a hard time really supporting anything HECO does aside from becoming a CO-OP. Your grumbles about maintaining the grid and how homeowners with P.V. don't maintain the grid......Where does all the money go from the kW's I give you and you sell at 100% mark up but come December you have no problem when you take $600 of wholesale electricity value from me
Stop taking all my solar credits when you "reconcile" my account every July. It's bad and it's why I have a hard time really supporting anything HECO does aside from becoming a CO-OP. Your grumbles about maintaining the grid and how homeowners with P.V. don't maintain the grid......Where does all the money go from the kW's I give you and you sell at 100% mark up but come December you have no problem when you take $600 of wholesale electricity value from me
I had recently contacted you about getting an energy audit. You informed me you don't do it, but I can do it myself. Today I found out there is $150 tax credit, rebate, for getting one. I cannot do that for myself. We are in Makaha Valley and really want to lesson our carbon foot print. Very disappointed in how you do things. I bought better surge protectors, but don't know if I am using it right. I am 65 years old and didn't grow up with technology so having new items doesn't register with my abilities. I need someone who can teach me how to use my smart plugs and new surge protectors correctly. The jealousy windows should be outlawed as so much air conditioner cooled air leaks out. People need incentives to change. We are so progressive in many ways but we are so behind in others. I purchased my home for the calming, panoramic ocean view and beautiful, relaxing natural surroundings & have resided in it for over 35 years. I do not want the gigantic, unsightly wind turbines or large-scale mass of solar panels to negatively impact my daily life. Put nuclear power plants on 2-3 islands and stop wasting our money on unreliable “renewables”. Provide tax credits for energy efficient windows and doors. Windmills kill birds. Solar panels and batteries use toxic metals and enrich China. And bring back cheap coal energy. Wake up to real science and stop believing the climate change narrative.
Power magazine reports that fossil fuel plants like AES Kalaeloa were available 90% of the time; for wind & solar, it's 17%. So to replace Kalaeloa would require 180MW x 90%/17% = 964 MW. When does HECO plan to have that much? Also how long can all plants run 24/7 without overhaul ?
A-221 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected Once every 20 years, we should reenact the battle of Nu'uanu. This would pay tribute to the cultural heritage and history of our aina and reduce carbon emissions by 50% every generation.
Tidal energy, please Renewable energy must not come at the expense of native habitat and species. Use previously developed land and areas that are already covered with non-permeable surfaces. older apt building has roof-top solar but benefits only the owner of the solar panels not the apt owners. Would like to see a direct benefit to the apt owners by a discounted diverter installation device.
older apt building has roof-top solar; solar panels' credit belongs to/benefits roof-top solar panel owner; unable to divert credit to apt owners who really need the break to high electricity bills. Building already installed LED lighting on premise, and not much savings to the apt owners. Would like to see some type of relief to the apt owners.
I like the idea of owning an EV, however living in a condo, at home charging is not an option. It would be nice to see more super charger availability, powered by renewable sources.
Make PV panels available for homes. Rotating panels in open pasture.
All new housing to include townhouses, not just in Ocean Point but all of Oahu, should have mandatory minimum solar installation. If the purchaser wants more solar, the developer can add it to the price of the home but at a minimum the home will have solar. For example, a 1700sq ft home should have a minimum of 7KwH system.
I concur with having a Nuclear Power Plant. For all that say it is too dangerous, we have floating Nuclear Power Plant (aka Navy Ships and submarines) docked in Pearl Harbor all the time. Oahu emergency power plan is based on connecting those nuclear ship or submarine to the power grid. A lot of these comments, the way they are written and the context used, are not from local people, get real. All those charges on our bill is the problem. The only thing that change is the rate, and do cable companies pay the electric co to use their poles etc... if so why can't we the customer of electric get a discount since we are the ones who paid for the poles etc.. in our bill
Every home could be nearly 100% self sufficient with subsidized solar systems. Currently, an on-grid solar system is quite expensive and people cannot afford this among other bills.
Not sure why the dot on the map is out where there is currently no infrastructure.
Resilience would be my best choice because the project will need that to meet and address all of the projects planned in a way to meet everyone's needs which I feel will need lot of give and take.
It's good that you are pursuing purchasing power from homes with battery back up to cover peak power surges, but if you really want to save life on Earth, bring back net metering. Incentivising the purchase of solar panels/battery packs by buying electricity from individuals and businesses is the fastest way to get to net zero. Many states do it successfully and we have optimal conditions. Don't develop land, disperse not centralize. It should be embarrassing that HELCO cannot keep a Level 3 charger working ON ITS OWN SITE! This charger is frequently (as in every time I've ever been there) not working. If we want to encourage EV use then adequate charging needs to be available. Keeping this charger up and working should be a project given to a team of people who check on it daily.
I do not subscribe to the eminent disaster rhetoric of "climate change", nor is there any data to suggest that humans contribute to or can change climate. If people want to generate their own power to get off the grid, I would encourage them to do so; however forcing everyone to do so is costly, unnecessary and just another tool to control people who are not harming anyone. The components of batteries that are needed to store the various alternatives create toxic waste and contribute to the enslavement of the poor in the countries where they are mined.
I do not want to live with chainsaws, logging trucks, increased degradation of our neighborhoods, towns, and highways, clearcuts, polluted air and water, higher electric bills, and corrupt political back-room deals, and entitled - arrogant billionaire investors. I want HawIi Electric to wake up to reality and tell Hu Honua to bugger-off.
There is space to plant trees for shade and reduce the heat from the road.
Solar is currently supplying full house power and do not need to connect to the grid, however the incentive to give solar back to the grid is small. Getting a 4 to 1 ratio of solar kWh in credit seems to be inadequate to incentivize trying to help us. I am pretty sure the electric company would prefer no solar as they are losing money with every house becoming self-sustaining. I agree that you do need to be able to initially come up with a good sum of money to pay for the solar installation and the interest rates are ridiculous for solar loans. The tax breaks are pretty good though. For a 10 kWh system you can claim $10,000.00 in tax credits for state and depending on the cost of the complete system, 30% of that can be claimed in tax credits for federal. Lets get together on this solar plan and make sure the customers are #1 if they choose to go with solar and really make it worth while. Otherwise we are talkiing out of both sides of our mouth. We are long overdue to start thinking long-term and begin development of generation 3 nuclear power. We are not going to meet our needs with windmills and solar panels. The future is nuclear and we must begin making up for lost time. An energy poor island is simply poor. The situation on Oahu is already untenable. Add to that premature decommissioning of power plants without replacement energy is foolish. Bad decisions all around!
I like the community solar farm concept like the one being built in Makakilo. These need to be done with adequate battery backup. I would like to hear about plans to recycle old solar panels and storage batteries too as this is important to truly consider these systems green. I would also like to see more hydrogen infrastructure. Hydrogen should be used initially to power commercial and municipal vehicles that return to a central facility.
solar and pumped hydro storage on koko headlands
Look into retrofitting old fossil fuel facilities for long duration energy storage. Can do either retrofit or build new. Look at "cryostorage" or "compressed air storage" as that technology looks very useful and easily implemented for long duration energy storage!
At a minimum solar canopies over the parking lot of the planned stadium. The maximum is build a mini SoFi stadium and install solar panels and batteries. Contract full retail net metering for 25 years as a incentive. Install solar canopy over whole Hikimoe Street making it the first solar street. Being a bus hub connecting to the rail station makes perfect sense to provide cover for commuters. It also perfect for charging stations for electric buses. This part of Waikele Center parking lot has become a food truck hub and has a blood donation truck. Put a solar canopy here to soak up the sun instead of the asphalt. Bring out nearby charging station from hiding by the trash area and install several charging stations here.
A-222 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected All new build construction, (commercial or residential) should be required to install solar panels to help mitigate general fuel usage. All residential areas should also be encouraged to plant a tree or two within the property to keep the environment clean and green, a very small way but attainable. Government policy inquiry/commentary. Please consider the future of energy production in Hawaii. A diversity of power generation resources is critical. Committing to a "renewable-only" strategy could leaves us vulnerable when weather isn't optimal, eg, storm conditions and storm related damage to panels, prolonged cloudy conditions (has happened a few times over the years), etc. Can a non-fossil fuel grid handle the load when every vehicle is required to charge? If every electrical demand is reliant on solar panels and wind turbines, what is the current capacity of those renewables and what is the current demand including vehicles that currently don't rely on electric charging? It's understandable that HECO is subject to government policy and regulation. The PR of converting to renewables is a good strategy given the one-sided conversation of energy future. Is the discussion about fuel elimination, or emission reduction, or developing an solar/wind industry over fossil fuel? Cost benefit analysis has to be more transparent beyond "we should do this because we'er saving the planet". It's understandable for HECO's business future to relent to government dictate, but is that the best future not just for perceived world saving, but for cost saving? Hawaii's COL is the highest in the US. A single option solution is never good for preparation or for efficiency. Plus most people can't afford extra energy cost when everything else is already costly. If the goal is to weed out those who can't afford to live here, that goal is well underway. And it's understandable how HECO and Hawaii's government would think that less people here is the goal. That is not sustainable. I'm a retired oil company engineer and my stake in Oahu's energy future is much the same as yours - seeking practical, non-polluting, long-term energy solutions. That said, it is a very good bet that HECO will NEED spinning turbine-power to provide a reliable 24/7 power grid well past 2045 (in other words, HCEI's "bold goal" of 100% renewables by '45 will NOT be met). If we (You) don't plan for that eventuality, the good people of Hawaii will continue to burn expensive / polluting liquid hydrocarbons while much of the world flares (see link below) unwanted natural gas (methane) because they do not have a "local" market. Liquified Natural Gas (LNG) regassification on Oahu is already done on a tiny scale. "Regas" is the easy part, making the Oahu-based infrastructure small in comparison to the LNG cryo facilities that put LNG into special LNG tankers & ship it to us. This is a very-well understood technology and HECO is well-positioned to be the champion of large-scale LNG. IMHO HECO was foolish not to continue its 2016 LNG project with Hawaii Gas. Every day not spent developing large-scale LNG for Oahu is a day that we burn dirty oil instead of much-cleaner natural gas. Be the leader. https://thedocs.worldbank.org/en/doc/1692f2ba2bd6408db82db9eb3894a789-0400072022/original/2022-Global-Gas-Flaring-Tracker-Report.pdf
1. Use former fuel tanks at Red HIll for pumped hydro storage. 2. Lease roof space on warehouses, state and county buildings, for HECO solar panels. 3. When building solar panels on ag land, make them high enough for shade-tolerant crops to be grown underneath, and for animals to graze to keep the foliage down.
Aloha Hawaiian Electric, Thank you for asking for our input. When I was younger I watched computing transition from “really big machines” (mainframes) to “Massively Distributed Processing” (servers). I believe the future of Renewable Energy will follow a similar path, and we will soon see the birth of Massively Distributed Energy Farms. These farms will be owned, operated and managed by local public utility companies, but the collection of energy will take place throughout the community. Below are a couple of ideas I’ve been thinking about. 1) Work with the County to modify the existing, or create new, public utility easements to allow Hawaiian Electric to install Energy Collection Devices (i.e. solar, wind, rain) as well as Storage Capacity (batteries) and Energy Distribution Devices (EV and/or other battery charging mechanisms.) Collection devices and charging stations could be placed a) along certain County roadways b) County recreation facilities c) County, State and Federal public parking areas d) Privately owned parking lots over a certain size (Residential, retail, hospitality) 2) Reach out and work with landlords/owners of Large Paved Parking lots. a) Most landlords/property owners don’t want to become “Solar Experts” b) Storage capacity and distribution capacity could also be included c) How many landlords, owners, tenants and customers would love: i) high-shade over their parking lot ii) EV (and other) charging capacity in their parking lot iii) Reliable, safe, worry-free Renewable energy 3) For the Off Grid community: Replace propane canisters with battery capacity a) Build out community charging stations, similar to transfer stations and water stations. b) Customer can plug-in their battery and wait for it to charge; or c) Customer can “swap” drained battery for fully charged battery i)HECO could charge batteries off-site and transport 4) Residential Off grid or On: Offer a “carport” configured as a Renewable Energy Collection System a) Homeowners want solar; b) Homeowners don’t want to become solar experts; or get stuck with a product that might not be supported in the future. c) Homeowners want to TRUST their energy supply! d) Charge a flat monthly rate (off grid) and/or standard electric rate (on grid) e) HECO would Own, Manage and Maintain all of the equipment f) Customer gets a carport : HECO grows it’s Massively Distributed Energy Farm
A-223 Integrated Grid Planning Report
APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected Provide method to encourage rental homeowners to install solar panels on their rental units. Could set it up as HECO owns the panels and "rents" roof space or provide the homeowner a monthly stipend based on the power utilized from those panels. Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes.
Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes.
Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes. Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes.
Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes. Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes.
Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes.
Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes. Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes.
Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source. Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes.
Maximized surplus energy. Citizens as partners. Durable neighborhood energy and conservation. Minimize battery cost. Maximize clean fuel production for short and long term energy storage, stable ship and air fuels, hydrogen and gas turbines and fuel cell power. Waste to energy adapted, collocated for thermal efficiency, potable water, mining land fills, conversion sewage and wastewater, Geothermal high and low temperature , floating wind, tidal, ground source.
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APPENDIX A – STAKEHOLDER FEEDBACK AND PUBLIC INPUT
REZ Comments Collected Multifamily charging and offsite energy. Micro turbine CCHP incentives. Delivery vehicle electrification. Highest efficiency solar. Merge or partner with experienced company like Engie for rapid evolution of Electric company into clean generation, fuels, and waste conversion, high efficiency clean power generation, and export potential of energy and byproducts of processes.
Invest a community solar in this long undeveloped land that has no claimed ownership. The lure of cheap electric will hopefully give landowners around this land incentive to give up their potential stake in the land. Installing a large solar canopy over this land and batteries for each landowner and offering the community an opportunity to invest and benefit from lower electric bills will give this barren land a purpose. It is my hope these landowners follow their neighbor across the street, Highway Inn in their investment of solar and batteries on their business.
Put large solar canopies, batteries and EV charging stations in this large parking lot. Want to vote for the fast EV charging stations, especially at locations that are centrally walkable to destination attractions (like the Azeka marketplaces, and the major beach parks in this area, and grocery stores). Incentivize large businesses to host charging stations /more charging stations and keep them running. (Maui Brewing is a good example of a success story there. ) There are some charging stations that are not operable and haven't been for months - how to ensure that they stay running?
Consider viability of ocean-based reneweable energy. This bay specifically gets very high wind and wind-wave action because of the funneling effect between the west maui mountains and Haleakala - can we harness some of that energy via wind mills (like in the northern seas around the UK and scandinavia?) or via wave power bouys? Understand that these options might not be worth the additional environmental effects on the ocean... but not sure? Put windmills on Mauna Loa and/or Pala'au plains. Previous efforts to this effect were very badly planned and communicated because all the power was going to get shipped off-island with no benefit for Molokai residents. Ensure all Molokai residents get this power FIRST and pitch the idea of selling power to the neighboring islands for the benefit of Molokai residents (i.e. residents get free power paid for by the sale of power to neighboring island grids, which are more power-hungry/consume more power. Neighboring islands get more sustainable power to help bring their costs down, and the Molokai community will be incentivized to support the plan for their own benefit.) Consider incentive programs for homeowner/homestead sized windmills. Like this: https://www.energy.gov/energysaver/small-wind-electric-systems Need the county/state planning departments to make permitting for installing these windmills simpler and easier, or make blanket exceptions or something. Is it possible to have these in dense neighborhoods like Kahului/Wailuku/Kihei, or do you need bigger homesteads like < 1 acre, or what? There are very small ones that are designed for home use applications, and larger horizontal access ones that might be good for farms/ranches that have more space. Even the small ones can generate a significant amount of power for the average home consumer, and just add reliability/redundancy to the grid.
B-1 Integrated Grid Planning Report
APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Appendix B:
Forecasts, Assumptions and
Modeling Methods
B-2 Integrated Grid Planning Report
APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Contents
1 Forecasts and Assumptions .................................................................................................................................................. B-3 1.1 Load Forecast and Methodology ......................................................................................................................................................................... B-3 1.2 DER Forecasts ............................................................................................................................................................................................................... B-5 1.3 Time-of-Use Rates .................................................................................................................................................................................................. B-10 1.3.1 Literature Review ......................................................................................................................................................................................... B-11 1.4 Energy Efficiency ...................................................................................................................................................................................................... B-13 1.4.1 Energy Efficiency Supply Curve Bundles ........................................................................................................................................... B-14 1.5 Electrification of Transportation ........................................................................................................................................................................ B-21 1.5.1 Light Duty Electric Vehicles ..................................................................................................................................................................... B-21 1.5.2 Electric Buses ................................................................................................................................................................................................ B-23 1.5.3 Electric Vehicle Forecast Sensitivities.................................................................................................................................................. B-23 1.6 Sales Forecast ............................................................................................................................................................................................................ B-25 1.7 Peak Forecast ............................................................................................................................................................................................................ B-28 2 IGP Modeling Methodology ............................................................................................................................................... B-31 2.1 Modeling Objectives .............................................................................................................................................................................................. B-31 2.1.1 Renewable Portfolio Standards (RPS) ................................................................................................................................................. B-31 2.1.2 System Reliability ........................................................................................................................................................................................ B-32 2.1.3 Affordability ................................................................................................................................................................................................... B-32 2.1.4 Environmental Carbon Impact Reduction ........................................................................................................................................ B-32 2.1.5 Grid Resilience .............................................................................................................................................................................................. B-32 2.1.6 Community Impacts and Land Use ..................................................................................................................................................... B-33 2.2 Overview & Purpose of Modeling Tools ....................................................................................................................................................... B-33 2.2.1 Modeling Framework ................................................................................................................................................................................ B-35 2.2.2 Capacity Expansion (RESOLVE) overview .......................................................................................................................................... B-36 2.2.3 Resource Adequacy (PLEXOS) overview ............................................................................................................................................ B-36 2.2.4 Production Cost and Operational Flexibility (PLEXOS) overview ............................................................................................ B-37 2.2.5 System Security (PSSS/E and PSCAD) overview ............................................................................................................................. B-38 2.2.6 Synergi and LoadSEER overview ........................................................................................................................................................... B-40 3 Reliability Criteria ................................................................................................................................................................ B-43 3.1 Resource Adequacy Criteria ................................................................................................................................................................................ B-43 3.2 Operating Reserves (Reg Reserve) ............................................................................................................................................................................. B-44 3.3 Transmission Criteria ................................................................................................................................................................................................. B-44 3.3.1 Thermal limits ............................................................................................................................................................................................... B-45 3.3.2 Voltage levels ............................................................................................................................................................................................... B-45 3.3.3 System stability ............................................................................................................................................................................................ B-46 3.4 Distribution Criteria ................................................................................................................................................................................................ B-46 3.4.1 Normal Conditions ..................................................................................................................................................................................... B-46 3.4.2 Contingency Conditions ........................................................................................................................................................................... B-46 3.4.3 Normal and Contingency Overloads .................................................................................................................................................. B-46 3.4.4 Overload and Voltage Issues ................................................................................................................................................................. B-47 4 Resource Portfolio ............................................................................................................................................................... B-48 4.1 Existing Customer energy resource programs ............................................................................................................................................ B-48 4.2 Existing generation portfolio .............................................................................................................................................................................. B-51 4.2.1 O‘ahu ................................................................................................................................................................................................................ B-51 4.2.2 Hawai‘i Island ................................................................................................................................................................................................ B-52 4.2.3 Maui County .................................................................................................................................................................................................. B-53
B-3 Integrated Grid Planning Report
APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
1 Forecasts and
Assumptions
1.1 Load Forecast and Methodology
The load forecast is one of the many assumptions that the resource planners use in their models to
stress test the various plans under varying conditions. Multiple scenarios and sensitivities were developed to plan around uncertainties surrounding adoption of behind-the-meter technologies, which ultimately drive the load forecast and peak demand. Additional sensitivities were also identified in the resource planning stage.
Forecasts were developed for the five islands beginning with the development of the energy forecast
(i.e., sales forecast) by rate class (residential, small, medium, and large commercial and street lighting) and by layer (underlying sales forecast and adjusting layers – energy efficiency, distributed energy resources, and electrification of transportation, and time-of-use rate load shift).
The underlying sales forecast is driven by the economy, weather, electricity price, and known
adjustments to large customer loads and is informed by historical data, structural changes1, and
historical and future disruptions. The impacts of energy efficiency (EE), distributed energy resources (DER), primarily photovoltaic systems with and without storage (i.e., batteries), and electrification of transportation (light duty electric vehicles (LDEV) and electric buses (eBus), collectively “EoT”) were layered onto the underlying sales outlook to develop the sales forecast at the customer level. Load
shifting in response to time-of-use rates (TOU) was also included as a forecast layer. Since the load
shift was assumed to be net zero (i.e. load reductions during the peak period are offset by load increases during other time periods), there is impact to the peak forecasts, but no impact to the sales forecasts. An illustration of the components that contribute to the customer sales forecast is shown in
Figure B-1.
1 Structural changes include the addition of new resort loads or new air conditioning loads that have a persistent impact on the forecast.
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Figure B-1. 2030 O‘ahu Customer Sales Forecast by Layers2
The residential and commercial sectors are forecasted separately as each sector’s electricity usage has been found to be related to a different set of drivers as described in the approved March 2022 Inputs and Assumptions filing. To summarize, historical recorded sales used in econometric models are
adjusted to remove sales impact of DER, EE and EoT, which are treated as separate layers. Input data
sources for developing the underlying sales forecast include economic drivers, weather variables,
electricity price and historical data from the Company, as shown in Table B-1 below.
Table B-1. Input Data Sources for Underlying Forecast
Source Data
University of Hawaii Economic Research Organization
Real personal income Resident population Non-farm jobs Visitor arrivals
NOAA – Honolulu, Kahului, Hilo and Kona Airports Cooling degree days Dewpoint Temperature Rainfall
Itron, Inc. Commercial energy intensity trend for Pacific Region for non-heating/cooling end uses.
Hawaiian Electric
Recorded kWh sales
Recorded customer counts
Large load adjustments
Real electricity price
2 Time-of-Use layer is not shown due to the assumption that customer sales [kWh] during peak load hours we shifted to other hours of the day resulting in net-zero change to sales.
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
The underlying sales forecast was based on a combination of multiple models and methods (i.e., certain
models/methods are more appropriate for near-term time horizons and others for long-term trends).
Methods for the underlying layer include:
• Market analysis: A ground up forecast evaluating individual customers (particularly large commercial customers), projects, and events that may merit a specific carve out if significant, i.e., new large projects or loss of large loads.
• Customer service: An analysis of recent trends in customer counts, sales and use per customer and applies knowledge of local conditions such as construction activity, state of the visitor industry, trends in weather including impacts of storms and volcanic eruptions.
• Trending models: Uses historical data series to project future sales or customer counts. Works well when historical data series has identifiable patterns and future trends aren’t expected to vary from the past.
• Econometric models: Relates sales or customers’ use of electricity to macroeconomic variables such as personal income, jobs, population, and visitor arrivals as well as other variables such as temperature, humidity or electricity price. Econometric models may also incorporate time series parameters such as lagged dependent variables or an autoregressive term. The quantification of the impact of changes in the economic and other variables on use is the strength of these models. The econometric model is specified in the following form: 𝑌𝑌= 𝛽𝛽0 + �(𝛽𝛽𝛽𝛽 𝑥𝑥 𝑋𝑋𝛽𝛽) 𝑛𝑛𝑖𝑖=1
where the dependent variable, Y, is kWh sales or use per customer and is related to the
independent (explanatory) variables, Xi, which represent economic or other variables. Variables βi
represent the regression model coefficients. The constant variable β0 represents the Y-intercept.
1.2 DER Forecasts
The DER layer includes impacts of behind the meter PV and battery energy storage systems as well as
known projects for other technologies (e.g., wind). This forecast adjustment estimated new additions
of DER capacity in each month by island, rate class and program, and projected the resulting monthly
sales impact from these additions. The DER adoption forecasts included stakeholder suggestions to
develop several sensitivities including a high and low forecast for the bookend scenarios.
Future DER capacity modeling considered two time horizons:
■ Near term (approximately next three years) reflects the current pace of incoming applications and
executed agreements, existing program (NEM, NEM+, SIA, CGS, GSP, CSS and ISE)3 subscription level
and caps, feedback from the Companies’ program administrators, PV system installers, customer input
3 Existing programs include Net Energy Metering, Net Energy Metering Plus, Standard Interconnection Agreement, Customer Grid Supply, Customer Grid Supply Plus, Customer Self Supply, and Interim Smart Export.
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
and any studies or upgrades being done to address short-term hurdles (e.g. circuit study, equipment upgrades) that affect the installation pace; and
■ Longer term forecast, which is model-based as the detailed application information is not available.
To extend the DER forecast from the short-term through the full planning period, an economic choice model using payback considers a set of assumptions such as the installed cost of PV and battery,
incentives, electricity price, program structure that affect the economic benefit to the customer which is
the primary driver of their decision to adopt the system.
Storage size assumptions for each island and rate class were optimized based on return on investment for an average customer. By modeling average customer’s optimal pairing size, the amount of forecasted storage was appropriately captured for the overall rate class as customers with larger storage
requirements offset those with smaller or no storage requirements. DER customers store excess
generation during the midday that is then used to reduce their load (and additionally export to the grid in the case of future export programs such as Scheduled Dispatch) during the peak period daily. As a result, DER customers are shifting their load in a manner consistent with proposed TOU rates and no
additional load shift would be expected in response to TOU rates.
Monthly DER capacity factors for each island were used to convert installed capacity to customer
energy reductions. The monthly capacity factors recognize the variations in solar irradiance throughout the year rather than using a single average annual capacity factor to reflect monthly variations more accurately in the energy production of DER systems. A degradation factor of 0.5% per year4 was applied
to the sales impacts to recognize that the DER system’s performance degrades over time.
To develop a high and low DER forecast, a number of factors were considered based on stakeholder feedback. As a result, Table B-2 summarizes the assumptions used to develop the DER forecasts.
Table B-2. Summary of assumptions used to develop DER forecast sensitivities
Input No State ITC Low Base High
Synopsis Revised lower DER uptake below market forecast
Market Forecast based on self-consumption
Revised uptake based on DER docket proposals (The Company), include EDRP (Oahu, Maui), expanded addressable market
Revised uptake based on DER docket proposals (DER Parties), include EDRP, updated resource costs, expanded addressable market
Cost Projections NREL ATB - Moderate NREL ATB - Moderate NREL ATB - Moderate NREL ATB Advanced
Federal Tax Credits Dec 2020 COVID-19 Relief Dec 2020 COVID-19 Relief Dec 2020 COVID-19 Relief 10-year extension
State Tax Credits 0% Increased 2021 to 35% Increased 2021 to 35% Increased 2021 to 35%
Includes EDR Program No No Yes (Oahu, Maui) Yes
4 Median degradation rate from NREL “Photovoltaic Degradation Rates – An Analytical Review”, D.C. Jordan and S.R. Kurz, 2012, http://www.nrel.gov/docs/fy12osti/51664.pdf
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Input No State ITC Low Base High Long Term Upfront Incentives None None $250/kW (Oahu, Maui) $500/kW
Long Term Export Program NA NA Standard DER Tariff (All Islands) with Scheduled Dispatch (Oahu, Maui)
Smart Export+ with Scheduled Dispatch
Addressable Residential Market
Single Family/2-4 Unit Multi- Family/Owner Occupied/Consumption Threshold
Single Family/2-4 Unit Multi- Family/Owner Occupied/Consumption Threshold
Single Family/2-4 Unit Multi- Family/Owner Occupied/Consumption Threshold
Single Family/2-49 Unit Multi- Family/Consumption Threshold
Addressable Commercial Market
Public or Private Owned/<6 stories/Consumption Thresholds
Public or Private Owned/<6 stories/Consumption Thresholds
Public or Private Owned/<6 stories/Consumption Thresholds
Public or Private Owned/<6 stories/Consumption Thresholds/Expand Sch-P Customer Pool to 100%
Add-Ons NEM+ NEM+
Sch-R NEM above minimum bill customers from 2021-2023 (Oahu, Maui), NEM+5
Sch-R NEM customers from 2021-forward
For incentives, the Base forecast assumed the following for Federal and State investment tax credits
shown in Table B-3 and Table B-4.
Table B-3. Federal Tax Incentive Rate Schedule
Class 2019 2020 2021 2022 2023 2024+ Residential 30% 26% 26% 26% 22% 0%
Commercial 30% 26% 26% 26% 22% 10%
Table B-4. State Tax Incentive Rate Schedule
2019 2020 2021 2022 2023 2024 2025 2026 2027+ 35% 35% 35% 25% 25% 20% 20% 20% 15%
• State cap on residential PV-only systems: $5,000 in all years
• State cap on residential PV+storage systems: $5,000 in 2019-2021, $10,000 in 2022-forward
One of the key drivers in the long-term DER forecast is the addressable market, including customers that can add-on to existing systems. The addressable market for residential customers included single family and multi-family homes with a maximum of four units that were owner occupied and with a high
enough energy consumption to utilize at least a 3 kW PV system, as shown in Table B-5. Historically,
only 15-20% of residential PV installations have been below 3 kW. From a practical perspective, customers with low consumption are less likely to make an investment in rooftop PV. Smaller systems
5 Customers participating in NEM+ is included in the Base case scenario for all islands, but only from 2024-forward for Oahu and Maui because Schedule-R NEM customers were re-introduced in the customer pool for 2021-2023.
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
are also less cost-effective due to fixed portions of the installation and material costs being spread out
over smaller total capacity and savings potential.
Existing NEM customers who were not reaching a minimum bill were added to the addressable market from 2021 through 2023 for O‘ahu and Maui, as shown in Table B-6. In addition, comments from stakeholders indicated that there might be DER customers who only install a battery. However, others may increase their PV capacity to capture the total value of tax credits. Considering these comments,
future retrofits for NEM customers assumed both an addition of a battery system, 5 kW/13.5 kWh, and
an increase in PV capacity, 5kW6.
Table B-5. Addressable Market for Residential Customers
Island Percent of Schedule R Customers Average PV System Size (KW) Average Storage Size (KWH) O‘ahu 37% 7.0 15.5
Hawai‘i Island 41% 6.0 11.0
Maui 43% 7.0 15.0
Lāna‘i 24% 4.0 9.0
Moloka‘i 30% 4.0 12.0
Table B-6. NEM Customers Added to Residential Addressable Market
Island Percent of Schedule-R NEM Customers Average PV System Size (KW) Average Storage Size (KWH) O‘ahu 85% 5 13.5 Maui 71% 5 13.5
For commercial customers, public and private building ownership was considered in defining the addressable market and structures greater than six stories were excluded. Similar to residential
customers, small and medium commercial consumption needed to be above a set energy usage
threshold. Commercial thresholds were established using rate class customers’ previous 12-months
usage, historical PV installation data, and business types. PV and non-PV customer segmentation by business type. Distributions for total energy usage7 were created for PV customers. Usage at the lower 1/8th quantile was used as the threshold for business types that had five or more customers who
already installed PV. The default thresholds of 500kWh for Schedule G and 5,000 kWh for Schedule J are
used for business types with less than five existing customers with PV already installed. The resulting addressable market for the commercial sector can be seen in Table B-7 through Table B-10.
6 Order No. 37816 permits existing PV customers to add up to 5 kW of additional PV generation capacity.
7 Total usage is the sum of the previous 12-months sales plus the sum of the previous 12-months estimated PV generation.
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Table B-7. Addressable Market for Commercial Customers
Island Percent of Schedule G Customers Percent of Schedule J Customers Percent of Schedule P Customers O‘ahu 37% 53% 78%
Hawai‘i 35% 68% 44% Maui 41% 63% 68%
Table B-8. Addressable Market, Average PV System Size, and Average Storage Size for Schedule G Customers
Island Percent of Schedule G Customers Average PV System Size (KW) Average Storage Size (KWH) O‘ahu 37% 7.0 12.5
Hawai‘i 35% 5.5 9.5
Maui 41% 7.0 14.5
Table B-9. Addressable Market, Average PV System Size, and Average Storage Size for Schedule J Customers
Island Percent of Schedule J Customers Average PV System Size (KW) Average Storage Size (KWH) O‘ahu 53% 76.0 40.0 Hawai‘i 68% 64.0 15.0
Maui 63% 59.0 45.0
Table B-10. Addressable Market, Average PV System Size, and Average Storage Size for Schedule P Customers
Island Percent of Schedule P Customers Average PV System Size (KW) Average Storage Size (KWH) O‘ahu 78% 330.0 0.0
Hawai‘i 44% 64.0 0.0
Maui 68% 330.0 0.0
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
1.3 Time-of-Use Rates
We evaluated and included Time-of-Use (TOU) load shifting impact for non-DER customers and non-EV
load into the load forecast. Generally, TOU rates are thought to be a mechanism to encourage customers to modify their consumption patterns (e.g. shift evening peak usage to other hours of the day) by reacting to different energy price signals. Stakeholders stated that residential TOU load shift scenarios should be included in the IGP base forecast and bookend forecasts even if impacts are
relatively small because it is likely that TOU rates will be implemented. Based on the proposal presented
and stakeholder input, assumptions in Table B-11 were used to develop TOU load shift scenarios for residential customers.
Table B-11. Summary of assumptions used to develop residential TOU load shift sensitivities
Input Low Base High
Rates Hawaiian Electric Final ARD Proposal Hawaiian Electric Final ARD Proposal DER Parties Final ARD Proposal
Residential Customer Pool
All Non-DER Residential Customers = Residential Forecast Minus High DER Sch-R Forecast
All Non-DER Residential Customers = Residential Forecast Minus Base DER Sch-R Forecast
All Non-DER Residential Customers = Residential Forecast Minus Base DER Sch-R Forecast
AMI Rollout 100% by 2025, Straight line from current deployment to 2025
100% by 2025, Straight line from current deployment to 2025
100% by 2025, Straight line from current deployment to 2025
TOU Rollout Default rate for AMI meters ramps up from 2022 to 2026 Default rate for AMI meters ramps up from 2022 to 2026 Default rate for AMI meters ramps up from 2022 to 2026
Load Shift Method Net Zero Load Shift Net Zero Load Shift Net Zero Load Shift
TOU Opt-Out Rate [%] 25% 10% 10%
Price Elasticity -0.045 -0.070 -0.070
One of the key components of the Advanced Rate Design (“ARD”) discussed in the DER docket includes
the implementation of TOU rates, including mandatory TOU for DER customers. Consistent with
Advanced Rate Design (“ARD”) discussions, each customer that adopts DER (solar paired with storage) and/or electric vehicles under managed charging scenarios is effectively shaping their consumption to operate consistent with a TOU rate. For example, DER customers would charge their energy storage
system with rooftop solar during the day and discharge the system in the evening. This load shifting is
captured in the DER forecasts battery storage profiles. Since these DER customers are shifting their load
in a manner consistent with proposed TOU rates, no additional load shift would be expected in response to TOU rates. The managed charging forecast profiles reflect customers charging electric vehicles during the day in response to TOU rates. On October 31, 2022, the Commission issued PUC
Order No. 38680 established future TOU rates will include three daily time periods with a 1:2:3 price
ratio. While specific rates, charges, and timing may deviate from the Base assumptions, the forecast
sensitivities adequately capture the potential load shift due to TOU rates.
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
We assumed new DER customers would be defaulted into a Three-Part TOU rate that includes a $3/kW
monthly demand charge. Referencing the Company’s Bill Comparison of 2017 TY and Proposed Three-
Part TOU Rates under the ARD Track Initial Proposal,8 a 300 kWh monthly usage and 3.336 kW peak residential customer’s monthly bill, including the demand charge, would be an estimated $5.86 higher under the proposed TOU rate compared to the 2017 TY rates. For a 600 kWh monthly usage and 3.336 kW peak residential customer, their estimated monthly bill would be $3.69 lower under the ARD rates
compared to 2017 TY rates. This small difference would not affect the economic choice model DER
uptake forecast in either direction for the average customer with the assumed average PV and battery system size. Stakeholders commented that prospective DER customers looking toward purchasing a future EV may be dissuaded from adopting DER because of the potential impact of a large demand
charge from vehicle charging. While a demand increase would lead to a higher demand charge under
the Company’s proposed ARD rates, DER uptake would not necessarily be decreased under this
scenario. The DER uptake model assumes a system size for PV and storage based on average customer usage. Introduction of an EV load would require adjusting the assumed PV and storage system size to account for the planned load increase, which ultimately adjusts the payback period.
1.3.1 Literature Review
Key takeaways from our literature review, including California studies,9 and estimated load shift for residential customers were presented to the STWG on September 23, 2021.
On October 1, 2021, the Consumer Advocate (“CA”) submitted comments on the TOU analysis
presented in the September 23, 2021 STWG. The CA made suggestions as potential input to development of commercial TOU forecasts.
■ Review three commercial TOU studies sited by the CA for consideration that may provide relevant information to estimate commercial TOU impacts.
■ Review historical data for the Companies’ commercial customers enrolled in TOU.
■ If no “reasonable Hawaii-based or comparable studies” provide sufficient data to support a forecast,
consider a pilot to provide understanding of the potential impacts.
■ The CA notes that they do not suggest delay or suspension of the IGP process to pursue this path.
In response to the CA’s comments, we investigated additional studies on TOU and customer response summarized below.
8 See Hawaiian Electric's Advanced Rate Design Initial Proposal filed on December 17, 2020 in Docket No. 2019-0323, Instituting a Proceeding to Investigate Distributed Energy Resource Policies pertaining to the Hawaiian Electric Companies.
9 Sacramento Municipal Utility District (2014), SmartPricing Options for Final Evaluation, research-SmartPricing-options-final-evaluation.ashx (smud.org)
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In Aigner and Hirschberg (1985),10 the summer period time-of-use energy (kWh) pricing subsection of
the study may be comparable to the ARD proposals, although considered with caution due to changes
in customer loads and efficiency that have occurred since the time of the study. The authors’ conclusion from their analysis of covariance is, “For the time-of-use energy rates, no perceptible shifting behavior is predicted in either season.”11 The elasticity for the TOU energy rates in both seasons resulting from
their econometric analysis also suggests there is no price responsive load shifting because the result
“indicates that an increase in peak-to-off peak price ratio will cause an increase in the proportion of
peak kWh consumption.”12 The authors note several limitations of the study that may have impacted the results and speculate that customers will shift load if the price signal is large enough. However, the actual statistical results of the study support the conclusion that the IGP load forecasts are reasonable
as proposed without a commercial TOU load shift layer.
The Qui et al. (2018)13 study was conducted in the summer in Phoenix, Arizona. It is characterized by the
authors as a study that “reveals how business customers respond to TOU pricing under relatively extreme weather conditions – summer in the Phoenix metropolitan area, where the average high temperature is above 100 degrees and air conditioner (AC) usage in the summer peak hours is a major
portion of the system load.”14 The conditions of the study are not comparable to conditions in Hawaii.
The California Statewide Pricing Pilot (SPP)15 studied small commercial and industrial (C&I) customers’ demand response to time variant rates in the Southern California Edison service territory. The C&I peak period was from noon to 6pm on weekdays. The observed peak period reductions were highly dependent upon smart thermostats as an enabling technology for customers with central air
conditioning.16 The results for the two-part TOU treatment group varied significantly across the two
years of the study and the authors state that results of that treatment group, “should be viewed cautiously, however, in light of the small sample size and significant variation in the underlying model coefficients across summers.”17 The peak period in the Companies’ final ARD proposal is 5pm-10pm and the lowest rates would be during the proposed midday period of 9am-5pm. Because of the differences
in the time periods of when the highest (and lowest) rates occur and the significant dependence of the
California SPP results on enabling technology, the California SPP results are not directly applicable to commercial customers under ARD rate proposals in the Companies’ service territory.
10 Aigner, D. and Hirschberg, J. (1985). Commercial/Industrial Customer Response to Time-of-Use Electricity Prices: Some Experimental Results. RAND Journal of Economics, 16(3), 341-355.
11 Id. at 349
12 Id. at 352
13 Qiu, Y., Kirkeide, L., and Wang, Yi. (2018). Effects of Voluntary Time-of-Use Pricing on Summer Electricity Usage of Business Customers. Environ Resource Econ 69, 417-440.
14 Id. at 418
15 Charles River Associates (2005). Impact Evaluation of the California Statewide Pricing Pilot. See https://www.smartgrid.gov/document/impact_evaluation_california_statewide_pricing_pilot
16 Id. at 119-120
17 Id. at 13
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Current participation rates in commercial TOU rates is extremely low: 16 customers on O‘ahu, 2
customers on Maui island, 2 customers on Hawai‘i island, all on either Schedule TOU-G or Schedule
TOU-J. There is insufficient customer data to guide or project the response from commercial TOU customers. In addition, the existing commercial TOU rates, as with all existing TOU rate options, are voluntary, while the proposed TOU rates in Advanced Rate Design are opt-out default rates. Based on commercial customers’ historically low participation in TOU rates in the Companies’ service territory and
the results of referenced studies, it is unlikely that implementing an opt-out commercial TOU rate in
and of itself will result in load shifting.
The Company will evaluate the response of residential and commercial customers that are assigned in the ARD TOU Roll Out Period study.18 This information will be used to inform forecasts in future IGP
cycles.
1.4 Energy Efficiency
The energy efficiency layer is based on forecast projections and hourly shapes from the July 2020 State of Hawaii Market Potential Study prepared by Applied Energy Group (AEG) and sponsored by the Hawai‘i Public Utilities Commission.19 The market potential study considered customer segmentation,
technologies and measures, building codes and appliance standards as well as the progress towards
achieving the Energy Efficiency Portfolio Standards. The study included technical, economic, and
achievable energy efficiency potentials which allowed the development of different EE forecast sensitivities.
An achievable Business As Usual (BAU) energy efficiency potential forecast by island and sector
represented savings from realistic customer adoption of energy efficiency measures through future
interventions that were similar in nature to existing interventions. In addition to the BAU forecast, AEG provided a Codes and Standards (C&S) forecast and an Achievable – High forecast. The C&S forecast included the impacts of new codes and standards set to take effect in future years that were known and
codified by June 2020. The Achievable - High potential forecast assumed higher levels of savings and
participation through expanded programs, new codes and standards, and market transformation.
For the High Load Bookend scenario, the EE Low sensitivity forecasts were updated to include C&S savings for all islands. To represent the potential for lower EE savings, the EE Low sensitivity reduced the programmatic Business-As-Usual component by 25%. Additionally, the EE Freeze sensitivity was
updated to include future C&S savings, aligning with the EE Base, Low, and High sensitivities. No
modifications were made to Business-As-Usual component of the EE Freeze sensitivity. Shown in Table B-12 is a revised summary of the EE forecast sensitivities.
18 PUC Order No. 38680 issued October 31, 2022 under Docket 2019-0323, Instituting a Proceeding to Investigate Distributed Energy Resource Policies Pertaining to The Hawaiian Electric Companies
19See https://puc.hawaii.gov/wp-content/uploads/2021/02/Hawaii-2020-Market-Potential-Study-Final-Report.pdf
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The impacts from AEG were derived at an annualized level and included free riders which reflected
savings for all measures as if they were all installed in January and provided savings for the whole year.
The annualized impacts were adjusted to reflect ramping in of measures throughout the year to arrive at energy efficiency impacts by month for each forecasted year. For simplicity, the installations were assumed to be evenly distributed throughout the year.
Table B-12. Summary of Energy Efficiency Forecast Sensitivities
Low Base High Freeze
BAU (Reduced by 25%) + C&S BAU + C&S Achievable High + C&S BAU capacity fixed at 2021 levels + C&S
1.4.1 Energy Efficiency Supply Curve Bundles
Energy efficiency supply curve bundles were developed to determine the optimal amount of energy
efficiency measures compared to the assumed forecasted energy efficiency using the results of the
Hawaii Statewide market potential study (“MPS”) that AEG performed on behalf of the Public Utilities Commission. In the modeling, energy efficiency was treated either as a reduction to load within the energy efficiency sales layer, or included in the supply curve bundles as a supply side resource.
1.4.1.1 Energy Efficiency Supply Curve Development Methodology
The supply curves were developed to treat energy efficiency as an available resource to be selected based on its cost and value. This required creating a new level of energy efficiency potential, referred to as “achievable technical,” before applying any screens for cost-effectiveness.
Developing Achievable Technical Potential
Achievable technical potential is a subset of technical potential, accounting for likely customer adoption of energy efficiency measures without consideration of cost-effectiveness. To develop the achievable technical potential, the customer participation rates from the “Future Achievable – High” case from the MPS, which account for market barriers, customer awareness and attitudes, program maturity, and
other factors that may affect market penetration of energy efficiency measures.
Differences from the Hawaii statewide potential study
Figure B-2 illustrates the levels of potential assessed in the MPS. Striped layers show impacts that are contained in the baseline forecast and therefore not part of the energy efficiency supply curves. These categories include naturally occurring efficiency, codes & standards impacts, and the lingering effects of
past program achievement.
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Figure B-2. Cumulative Persistent Energy Savings through 2030, EEPS Perspective20
Because the achievable technical potential used to develop the supply curves does not consider cost-effectiveness, it is not the same as any of the levels of potential shown in Figure B-2. Rather, the amount of available achievable technical potential would fall between the “Future Technical” and “Future Achievable – High” potentials.
Peak Impacts
Each energy efficiency measure has an island-specific load shape, which was created during the potential study process. By taking the annual savings calculated from the MPS and distributing it across this shape, impacts in each hour of the year can be calculated for each measure shape. The relative “peakiness” of each measure was considered by comparing its impacts during peak hours to a flat
shape. Peak impacts refer to impacts on the average weekday evening peak hour (between 6:00 PM and
8:00 PM) and are calculated as the average impacts during such hours.
Figure B-3 shows the average impacts of all measures within each classification using Oahu as an example, based on cumulative potential in 2030. As expected, peak-focused measure impacts are strongly concentrated in the weekday evening hours, whereas “other” measure impacts are much flatter.
20 See State of Hawaii Market Potential Study, Executive Summary page iv, Figure ES-3 (https://puc.hawaii.gov/wp-content/uploads/2021/02/Hawaii-2020-Market-Potential-Study-Final-Report.pdf)
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Figure B-3. Averaged Weekday Impacts by Measure Classification, Cumulative in 2030 (Peak vs Other, Oahu)
Cost-Effectiveness
The next consideration for bundling measures was the cost of savings. Although the levelized cost of
conserved energy ($/MWh), which annualizes costs across each measure’s lifetime, is one means of understanding resource costs, grouping solely based on energy saved may not allow the model to efficiently target measures with higher benefits due to contributions to peak reduction. Because the benefit-cost ratios (using the Total Resource Cost test perspective) from the MPS captured both energy
and capacity benefits, these ratios represent a convenient metric for bundling measures considering
both cost and value. Table B-13 shows the ranges used for bundle classification, which serve to separate measures that are highly cost effective (A) from borderline cost effective and not cost effective measures (B and C) to very non-cost-effective measures (D) to avoid them skewing the overall cost of
the more attractive groups.
Table B-13. Benefit-Cost Ratio Ranges Assigned to Bundle Groups
Bundle Benefit-Cost Ratio Range A >1.2
B 1.0 - <1.2
C 0.8 - <1.0 D < 0.8
It is important to note that many of the measures in group A could have absolute costs ($/MWh) that are higher than measures in group B or C. In those cases, the greater benefit of peak-focused resources
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
offsets the costs in the MPS methodology. Depending on how the shape of bundles meets the RESOLVE
model’s needs, it might choose lower absolute costs first, which could produce differences between the
RESOLVE model selections and the MPS. This flexibility is an expected feature of the chosen methodology.
Bundle Costs
To allow energy efficiency resources to compete against other supply side resources, the model is
provided a levelized cost of conserved energy (LCOE) for each model based on the measure-level costs
from the Statewide MPS, in $ per MWh. This is a Total Resource Cost net value which includes not only the installed cost of the measure, but net effects from non-energy impacts, O&M costs or savings, and possible avoided replacement costs, annualized over the life of the measure. Because non-energy impacts are netted out of the cost, it is possible for a measure to have a negative LCOE if the benefits
are greater than the cost of the measure. Each bundle’s LCOE is calculated as the savings-weighted
average of the LCOEs of the measures within the bundle. To further inform the planning process, the peak MW impact of each bundle was also noted (as calculated from the annual energy and load shape) and a value of $/MW was derived by multiplying the levelized cost of energy ($/MWh) by the annual savings (MWh) and dividing by the associated peak savings (MW).
Additional information on the bundle costs can be found in the Key Stakeholder Documents under the
Energy Efficiency Supply Curves category.21
1.4.1.2 Analysis Results
Figure B-4 below shows the incremental energy savings potential for each bundle over the forecast period. The sharp increase in savings in 2025 coincides with an increase in commercial linear lighting
installations, due to equipment turnover in the potential study modeling. Note that these annual
savings values do not include re-installation of measures that were previously incentivized and may have expired. While these measures will need to be reacquired in later years, they will not increase the total cumulative potential, so those reacquisition savings are excluded from this perspective.
There could be marginal additional savings at the time of re-acquisition, such as if technology standards
have improved in the intervening years, however such savings would be difficult to quantify directly
using the outputs of the MPS. The modeled potential without re-acquisitions is a conservative estimate to avoid overstating potential.
21 See https://www.hawaiianelectric.com/clean-energy-hawaii/integrated-grid-planning/stakeholder-and-community-engagement/key-stakeholder-documents
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Figure B-4. Incremental Annual Energy Savings Potential (Achievable Technical) by Measure Bundle (All Islands
Combined)
Table B-14 and Figure B-5 below show the cumulative energy savings by end use for each bundle. The
savings here represent the total Achievable Technical Potential in 2045 from the MPS.22
The Peak bundles are dominated by the cooling end use. The Peak A bundle, which includes the most cost-effective measures from the potential study, gets 77% of its savings from the cooling end use. The Other bundles are made up mainly of water heating, lighting, and appliance measures, which tend to have flatter or even morning-focused shapes.
Table B-14. Technical Potential Energy Savings (GWh) by Measure Grouping and End Use (All Islands Combined)
Peak Other End Use A B C D A B C D Cooling 17.5 2.3 0.5 2.9 5.3 0.1 0.2 1.2 Ventilation 2.0 0.2 0.3 0.4 2.8 0.1 0.3 0.8 Water Heating 2.1 0.2 0.1 0.2 11.5 2.2 0.0 0.4 Interior Lighting 0.2 1.1 0.1 0.4 11.2 0.0 0.0 0.2 Exterior Lighting 0.1 0.1 0.0 0.0 1.0 0.0 0.0 0.3 Res Appliances 0.1 0.0 0.2 1.0 0.5 0.5 0.1 2.6 Com Refrigeration 0.2 0.0 0.0 0.2 1.9 0.0 0.2 1.0 Electronics 0.2 0.0 0.0 0.0 0.1 0.0 0.0 0.0 Food Preparation 0.0 0.0 - - 0.2 0.0 - 0.0 Miscellaneous 0.2 0.0 0.1 0.0 5.0 0.1 0.2 0.3 Total 22.7 3.9 1.3 5.2 39.4 3.0 0.9 6.7
22 The Statewide MPS study period only ran to 2045. Annual potential from 2046-2050 was calculated based on the year-over-year trend from 2040-2045.
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Figure B-5. Achievable Technical Energy Savings (GWh) by Measure Grouping and End Use (All Islands Combined)
As noted in Order No. 38482, the energy efficiency supply curves must be revisited to adjust the peak
window used in the bundling process to 5-10 p.m. Also, clear explanation of the bundling process and
rationale must be provided to clarify for peak bundles, whether the majority of savings are coincident with system peak or the measure’s maximum savings occur during peak hours.
In the Oʻahu charts below, there is some shifting of the supply curve shapes for the adjusted peak window but generally, the shapes are the same.
■ Peak bundles retain the same profiles where their savings steadily increase and concentrate impacts at or near the peak window
■ Other bundles do not have a concentrated impact at the peak window and instead have oscillating savings above and below the flat shape (black reference line).
■ During the peak period, the Other bundles also have a smaller peak savings contribution compared to the Peak bundles.
■ The clear difference in shape observed between the measures bundled as Peak and Other was a factor in assessing the appropriateness of the bundles because it is more informative to the resource plan
development to know if certain energy efficiency shapes are preferred by the models.
Based on these results, it does not appear that the adjusted peak window makes a material impact on the bundle shape and the energy efficiency supply curves do not need to be revised.
-
5
10
15
20
25
30
35
40
45
A B C D A B C D
Peak Other
GWh
Cooling
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Res Appliances
Com Refrigeration
Electronics
Food Preparation
Miscellaneous
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
Figure B-6. Before (Left) and After (Right) Peak Window Adjustment for Peak Bundles
Figure B-7. Before (Left) and After (Right) Peak Window Adjustment for Other Bundles
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1.5 Electrification of Transportation
The electrification of transportation layer consists of impacts from the charging of light duty electric
vehicles (LDEV) and electric buses (eBus).
1.5.1 Light Duty Electric Vehicles
The light duty electric vehicle forecast was based on an adoption model developed by Integral
Analytics, Inc. as described in Appendix E of the EoT Roadmap23 to arrive at EV saturations of total light duty vehicles (LDV) by year for each island. Historical data for light duty vehicle registrations were provided by the Department of Business, Economic Development, and Tourism (DBEDT) and reported at the county level. The total light duty vehicle forecast for each county was estimated using a regression
model driven by population and jobs based on UHERO’s October 2019 economic forecast. The
development of the LDEV forecast utilized the EV saturation by island as shown on tab “EV Saturation” in Attachment 8 of PUC-HECO-IR-1 and applied the saturation to the light duty vehicle forecast for each island to arrive at the number of LDEVs.24 Although EV saturations were not specifically consistent with
carbon neutrality in Hawaii by 2045 in the Base LDEV forecast, they are consistent with County goals for
2035.
To estimate the sales impact from EV charging for each island, the annual kWh used per vehicle was calculated based on the following equation:
𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑘𝑘𝑘𝑘ℎ 𝑝𝑝𝑝𝑝𝑝𝑝 𝑣𝑣𝑝𝑝ℎ𝛽𝛽𝑖𝑖𝐴𝐴𝑝𝑝 = �𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑉𝑉𝑉𝑉𝑉𝑉∗(𝑘𝑘𝑘𝑘ℎ 𝑝𝑝𝑝𝑝𝑝𝑝 𝑚𝑚𝛽𝛽𝐴𝐴𝑝𝑝)�∗106𝑉𝑉𝑇𝑇𝑇𝑇𝐴𝐴𝐴𝐴 𝐿𝐿𝐿𝐿𝑉𝑉 𝐹𝐹𝑇𝑇𝑝𝑝𝑝𝑝𝑖𝑖𝐴𝐴𝐹𝐹𝑇𝑇
where
• Annual VMT is the annual vehicle miles travelled
• kWh per mile is a weighted average of fuel economies of electric vehicles registered
Annual VMT is forecasted by applying the baseline economic growth rate developed by the Federal
Highway Administration for light duty vehicles to DBEDT’s reported vehicle miles travelled for each
county.25 For Lānaʻi and Molokaʻi, vehicle miles travelled were developed based on information from
DBEDT and on-island sources.
23 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/electrification_of_transportation/201803_eot_roadmap.pdf
24 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/forecast_assumptions/PUC-HECO-IR-1_att_8_electric_vehicles.xlsx
25 See https://www.fhwa.dot.gov/policyinformation/tables/vmt/vmt_forecast_sum.pdf
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Historical kWh per mile was obtained using the weighted average fuel economy of registered electric
vehicles by island. For Lānaʻi and Molokaʻi, the fuel economy from the Nissan Leaf represented each
island’s average. Fuel economy and vehicle registration by type data were obtained from the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy and Electric Power Research Institute (EPRI), respectively.26 Annual kWh per vehicle was forecasted by applying a reference growth
rate developed using the U.S. Energy Information Administration’s (EIA) Annual Energy Outlook to the
historical weighted average fuel economies.27 The reference fuel economy growth rate expected battery
technology will improve and more larger vehicles will be produced.
Car registration data at the ownership level was not available to determine whether a car was a personally or commercially owned vehicle. Therefore, a ratio between residential and commercial PV installations in historical years was used to allocate the number of EVs between residential and
commercial customers for each island. Within the commercial EVs, a percentage based on PV capacity
installed by commercial rate Schedules G, J, and P was applied to the total commercial EV count to calculate the number of EVs at the commercial rate schedule level. The sales impact by rate schedule was calculated by multiplying the number of EVs by sales impact per vehicle for each island.
1.5.1.1 Light Duty Electric Vehicles Charging Profiles
Previous unmanaged charging profiles were developed using third party and public charging station
telemetry, load research conducted by several utilities in California, as well as Hawaiian Electric specific advanced metering infrastructure (AMI) data. The unmanaged residential and commercial light duty electric vehicle charging profiles were updated by leveraging data from the Company’s DC fast charging
network and a case study28 conducted through the deployment of EnelX’s Level 2 chargers in Hawai‘i.
Figure B-8 below highlights the revised residential and commercial charging profiles compared to the previous IGP profiles, including a demand reduction during the evening peak hours in the residential charging profile.
26 See http://www.fueleconomy.gov
27 See https://www.eia.gov/outlooks/aeo/data/browser/#/?id=113-AEO2019&cases=ref2019&sourcekey=0
28 See Smart Charge Hawai‘i Case Study, In partnership with Hawaiian Electric & Elemental Excelerator, EnelX
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Figure B-8. O‘ahu Light Duty Electric Vehicle Charging Profiles29
1.5.2 Electric Buses
The electric bus forecast was based on discussions with several bus operators throughout Honolulu,
Hawai‘i and Maui counties. Route information and schedules for weekdays, weekends and holidays were
used to estimate the miles traveled for each bus operator. Since specific information on the buses were
not available for most operators, we used the average bus efficiency (kWh per mile) for two different Proterra models. For each island, the total sales impact for each bus operator was applied to the rate schedule on which each bus operator was serviced.
1.5.3 Electric Vehicle Forecast Sensitivities
Three additional light duty electric vehicle forecast sensitivities (Low, High, and Freeze) were developed using varying adoption saturation curves. A Low Sensitivity forecast was developed using a slower and
lower adoption rate forecast from Integral Analytics, Inc’s adoption model. The High Sensitivity forecast
used the Transcending Oil Report, prepared by the Rhodium Group in 2018, which considered vehicle scrappage rates and the transition rate of vehicle sales to fully electric. The report estimated all vehicle
29 Charging profiles reflect a representative day in 2026
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sales by 2030 would need to be electric to reach 100% electric vehicle stock by 2045.30 A freeze
sensitivity was also developed, assuming no new additional electric vehicles above the Base forecast
after 2021. Table B-15 summarizes the light duty electric vehicle sensitivities.
Table B-15. Electric Vehicle Forecast Sensitivities
Low Base High Freeze
Low Adoption Saturation Market Forecast 100% of ZEV by 2045 Forecasted EV counts fixed at 2021 Base forecast
The following summarizes the light duty electric vehicle forecasts for the Base, Low, and High
sensitivities31.
Table B-16. Light Duty Electric Vehicle Count Forecast – Base
Year O‘ahu Hawai‘i Island Maui Molokaʻi Lānaʻi 2025 24,116 3,650 5,228 79 87
2030 54,881 13,231 18,999 176 158
2035 108,927 29,367 45,967 352 315
2040 198,017 54,171 77,031 690 611
2045 350,243 92,090 105,860 1,280 1,094
2050 504,068 141,362 131,219 1,930 1,637
Table B-17. Light Duty Electric Vehicle Count Forecast - Low
Year O‘ahu Hawaiʻi Island Maui Molokaʻi Lānaʻi 2025 15,408 2,176 3,786 62 57
2030 31,948 6,462 11,033 92 102
2035 66,229 16,986 24,902 171 191 2040 137,804 36,440 43,282 344 389
2045 257,340 66,645 69,579 721 843 2050 389,576 110,996 90,285 1,128 1,330
Table B-18. Light Duty Electric Vehicle Count Forecast - High
Year O‘ahu Hawaiʻi Island Maui Molokaʻi Lānaʻi
2025 116,253 36,501 29,345 470 739 2030 317,359 102,236 80,966 1,289 2,015
2035 516,970 171,097 133,243 2,111 3,278 2040 644,841 217,506 167,970 2,645 4,082
2045 679,383 232,787 178,516 2,804 4,300 2050 684,610 237,731 180,894 2,853 4,349
30 See Transcending Oil Report by Rhodium Group available at: https://rhg.com/wp-content/uploads/2018/04/rhodium_transcendingoil_final_report_4-18-2018-final.pdf
31 Additional light duty electric vehicle forecast detail can be found in Hawaiian Electric Reply to Consumer Advocate Comments CA-1, Attachment 1, Companies Reply to Party Comments (hawaiianelectric.com). Reference IGP Inputs Workbook 3 and 4 for forecasted electrification of transportation sales [kWh].
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1.6 Sales Forecast
Shown below in Figure B-10 through Figure B-14 is the sales forecast for the base scenario and
bookend sensitivities for the five islands.
Figure B-9. O‘ahu Sales Forecast Bookend Sensitivities
Figure B-10. Hawaiʻi Island Sales Forecast Bookend Sensitivities
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Figure B-11. Maui Sales Forecast Bookend Sensitivities
Figure B-12. Molokaʻi Sales Forecast Bookend Sensitivities
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Figure B-13. Lānaʻi Sales Forecast Bookend Sensitivities
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1.7 Peak Forecast
Shown below in Figure B-15 through Figure B-19 is the peak forecast for the base scenario and
bookend sensitivities for the five islands.
Figure B-14. O‘ahu Peak Forecast Bookend Sensitivities
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Figure B-15. Hawaiʻi Island Peak Forecast Bookend Sensitivities
Figure B-16. Maui Peak Forecast Bookend Sensitivities
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Figure B-17. Molokaʻi Peak Forecast Bookend Sensitivities
Figure B-18. Lānaʻi Peak Forecast Bookend Sensitivities
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2 IGP Modeling
Methodology
This section describes the analytical methodology used to identify the needs of the future grid to meet
various policy objectives. We used a suite of modeling tools to assess the grid needs, which set out to:
1. Identify the near-term quantity and timing of Grid Needs that will drive future program development
and procurement in each IGP cycle over the planning horizon; 2. Develop resource plans to identify potential pathways to solve for near-term needs and long-term objectives such as achieving 100% renewable energy and net zero carbon emissions by 2045; and 3. Evaluate proposed solutions through the creation of an energy marketplace in Hawaii.
We worked extensively with the Solution Evaluation Optimization Working Group (“SEOWG”), the
Stakeholder Technical Working Group (“STWG”), the Technical Advisory Panel (“TAP”), and the
Stakeholder Council to develop the methodologies. The following sections describe the overall process flow and modeling framework to derive the Grid Needs to inform solution sourcing and to evaluate or select solutions.
2.1 Modeling Objectives
We considered six overarching objectives to deliver reliable, clean, and cost-effective service to
customers.
■ Renewable Portfolio Standards
■ System Reliability
■ Affordability
■ Environmental Carbon Impact Reduction
■ Grid Resilience
■ Community Impacts and Land Use
2.1.1 Renewable Portfolio Standards (RPS)
The Grid Needs Assessment will seek to achieve and accelerate the State of Hawai‘i’s Renewable
Portfolio Standards (“RPS”) mandate of achieving 100% renewable energy by year 2045, with breakout
targets shown in Figure B-20.
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Figure B-19. State of Hawai‘i Renewable Portfolio Standard (RPS) Targets by Year
Under performance based regulation, we are incentivized to accelerate renewable energy achievement through annual renewable energy targets. As recommended by the Stakeholder Council, the Grid Needs Assessment should seek a portfolio that recognizes the RPS-A performance incentive mechanism. RPS
achievement simultaneously meets our carbon reduction goals.
2.1.2 System Reliability
The Grid Needs Assessment will account for multiple factors that assure system reliability; for example,
system balancing, system security, and T&D reliability. Additionally, we are accountable for Adequacy of
Supply, which is the ability of the electric system to supply the aggregate electrical demand and energy requirements of our customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements. Aspects of reliability will be evaluated through the Grid
Needs Assessment for adherence to various reliability related planning criteria and guidelines.
2.1.3 Affordability
The capacity expansion modeling tool will develop a resource portfolio to solve for RPS and system
reliability objectives in a least-cost manner. In the development of the resource plans, the model will
also consider the costs of installing new resources as well as the costs of operating existing resources. The resource plan will provide insight into resource procurement and system investment decisions needed to achieve 100% renewable energy over the next 25 years.
2.1.4 Environmental Carbon Impact Reduction
With increasing renewable generation on the grid and the retirement of fossil fuel generating units, the expectation is that greenhouse gas (“GHG”) emissions will significantly decline. Long-term plans can be
qualitatively and quantitatively assessed for GHG reduction. Quantitative GHG reduction assessments of
resource plans may also incorporate achievement of certain GHG reduction targets or estimated
reductions from an energy ecosystem perspective to include estimated reductions gained through electrification of other sectors, including transportation, buildings, etc.
2.1.5 Grid Resilience
There are two primary ways of looking at grid resilience. The first involves hardening of existing grid infrastructure (e.g., upgrades to utility poles, transmission and distribution line monitoring, transformers, etc.) and the second includes the ability of the system to return to service in a major outage event (e.g.,
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hurricane, tsunami, flooding, etc.). As outlined in the Resilience Working Group Report for Integrated Grid
Planning,32 comments from first responders, other infrastructure owners, and other RWG participants
will be used to inform transmission and distribution planning needs, priorities for resilience improvements, and options to achieve those identified planning needs and priorities. Notably, this
includes consideration of resilience enhancing microgrids to provide local, emergency power
generation when parts of the system’s transmission and/or distribution system are out of service due to
emergency conditions.
2.1.6 Community Impacts and Land Use
The viability of a long-term plan will depend on an assessment of community impacts and land use in Hawaii. It is imperative that any long-term plans balance multiple state policy objectives, such as housing, energy, and food sustainability.
Stakeholder Council feedback on community impacts and land was used to inform a key model input.
As an example, the resource potential for land-based resources that define the maximum capacity of
each resource that can be developed on each island. As part of the modeling input development, we engaged NREL to perform a solar and wind resource potential study. The Stakeholder Council provided specific parameters such as land slope and exclusions of certain type of land that could be developed
for grid-scale solar.
2.2 Overview & Purpose of Modeling Tools
We use several modeling tools to identify the grid needs across our generation, transmission, and distribution systems, and worked with the Hawaii Natural Energy Institute (“HNEI”) and the Technical Advisory Panel to establish a modeling framework, as shown in Figure B-21, for the Grid Needs
Assessment methodology that will be used throughout the various phases of the IGP process.
32 See https://www.hawaiianelectric.com/clean-energy-hawaii/integrated-grid-planning/stakeholder-engagement/working-groups/resilience-documents
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Figure B-20. Grid Needs Assessment Modeling Framework (Adapted from HNEI)
Two computer models that layout the pathways to identify the Grid Needs are the RESOLVE model and
the PLEXOS model. RESOLVE produces an optimized resource plan of proxy resources that can fulfill the
Grid Needs. The primary objective of this phase of the process is to identify Grid Needs using proxy resources; the actual technologies and solutions are determined during the solution sourcing which could consist of projects, procurements, or programs. In other words, the Grid Needs Assessment is not
intended to select or express a preference for a technology; rather identify what is needed for the
system and allow the market to propose solutions to meet those needs. In addition to the RESOLVE
base case that is developed using a base set of planning assumptions, further sensitivities are run in RESOLVE to better understand how certain assumptions influence outcomes that informs a robust action plan.
The resource adequacy of a resource plan is then evaluated in PLEXOS. The operations and cost to
operate the system are simulated through an hourly production simulation to ensure that the Grid Needs continue to be met on an 8760 hourly basis through year 2050. The results of the production simulation in PLEXOS are then used as inputs into the System Security analysis. The System Security analysis will be completed in PSS/E, PSCAD, and/or ASPEN Oneliner to evaluate needs for short circuit
current, inertia, frequency response, voltage support, and assess inverter control interactions, weak
grid/system strength issues. If the System Security step (or any of the other steps) identifies any shortfalls in the Grid Needs, the resource plan may be iterated upon to meet those residual needs. To address shortfalls in the Grid Needs, the proxy resources identified in the resource plan may be increased or accelerated from future years. It should be noted that the Capacity Expansion model and
Resource Adequacy step is initially run unconstrained, which means there are no system security or
operational rules assumed. With this approach, iteration of these steps are likely needed given the dynamic environment of a high-inverter based resource portfolio.
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2.2.1 Modeling Framework
Each step in the modeling framework has a different objective. The TAP advised that the full suite of modeling tools should be utilized in assessing the Grid Needs. For example, in its independent review,
the TAP stated:33
RESOLVE provides limited fidelity and should be used only as a technology screening tool. Subsequent determination of reliability, analysis of multi-year weather data, retirements, and avoided costs, etc. requires the use of other modeling tools. It was emphasized more than once that the other models should be an integral part of the overall process, NOT just a check on the output from RESOLVE.
Figure B-22 describes an overview of the objectives, key inputs, and outputs of each modeling step and tool. Each modeling software tool is described in the following sections, including a discussion of when adjustments or iterations may be made in each step. These decisions cannot be quantified solely by a set of criteria. Engineering judgment is needed when making decisions to adjust or iterate a modeling
step. Adjustments or iterations could include a decision on whether a shortfall in capacity to meet
reliability criteria is needed. On this issue, we posed the following questions to the TAP: What is the level of tolerance to decide when to go back and iterate and is it necessary to always rerun the full process or can estimations serve to backfill shortfalls? The TAP’s response is summarized below.
TAP did not provide a hard and fast answer to these questions, noting the need for ‘engineering judgment’ and ‘experience’ to determine what needs to be done. While TAP recognizes that engineering judgment can reduce the requirement for the full process to be used for all iterations, TAP recommends that solutions be vetted by the full process before proceeding to the procurement phase.34
33 See Grid Services and Planning Criteria Feedback filed in Docket No. 2018-1065 on June 1, 2021 at 4.
34 Id. at 4.
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Figure B-21. Key Inputs and Outputs of Modeling Steps
2.2.2 Capacity Expansion (RESOLVE) overview
The grid needs assessment uses the planning assumptions from the approved March 2022 Inputs and Assumptions. The primary objective of this phase of the process was to identify the optimal mix of
proxy resources that are built to represent the system’s grid needs. RESOLVE is intended to provide
directional guidance as to the optimal mix of resources; it is not intended to be a prescriptive pathway that must be strictly followed during solution sourcing activities.
2.2.3 Resource Adequacy (PLEXOS) overview
The Resource Adequacy step includes a probabilistic analysis consistent with industry best practices, including recommendations we adopted from the TAP. The resource adequacy analysis is probabilistic and evaluates the reliability of the system using 5 weather years based on meteorological data and 50
randomized generator outages for a total of 250 iterations. Specifically, PV reliability was based on five
years of NREL data, from 2015 through 2019, which was provided as part of the NREL Resource
Potential study. Wind reliability was based on historical measured data from existing wind plants for the same five years. DER used historical monthly capacity factor measurements also from the same five years. Thermal generators had 50 random outage samples with each sample modeled as an
independent production simulation. A total of 250 (50 outage samples per year for five weather years)
samples were modeled.
The results are then used to calculate various reliability metrics including loss of load expectation (LOLE), loss of load events (LOLEv), loss of load hours (LOLH) and expected unserved energy (EUE) to
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assess reliability. If a portfolio is found to be short of capacity, specifically in the near-term, adjustments
to the resource portfolio may be made during this step.
Loss of Load Expectation (LOLE) is the number of days per year where there is unserved energy. The unserved energy within the day is quantified as Loss of Load Events (LOLEv) defined as the number of unserved energy events per year. The difference between LOLE and LOLEv is that multiple unserved energy events can occur in a single day. Loss of Load Hours (LOLH) is the number of hours of unserved energy. One unserved energy event can last for one or more hours, and therefore, an LOLE of 0.1 days/year is not necessarily the same result as an LOLH of 2.4 hours/year.35 Expected Unserved Energy (EUE) is the amount of unserved energy. Examples of the various metrics and their interrelationship were shared in the Stakeholder Technical Working Group meeting on June 9, 202236 and recapped below in Figure B-23. As shown, while the day has unserved energy, the magnitude, duration, and frequency of that unserved energy affects the various metrics.
Figure B-22. Probabilistic resource adequacy metrics examples
2.2.4 Production Cost and Operational Flexibility (PLEXOS) overview
The PLEXOS modeling software is used to perform production cost simulations. The objective of the
production cost simulation is to confirm operability of the portfolios by modeling the operation of the electric system, accounting for regulating reserves, ramp rates, unit commitment, and storage charging and discharging through economic dispatch. This provides insight into how the new resources will be
35 See https://ieeexplore.ieee.org/abstract/document/9810615
36 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/stakeholder_technical/20220609_stwg_meeting_presentation_materials.pdf
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operated and dispatched in future years. More accurate costs of long-term plans will be developed as
part of the solution sourcing process when actual market solutions are proposed with current market
pricing. Total production costs and avoided costs are quantitative outputs of the production cost simulations.
2.2.5 System Security (PSSS/E and PSCAD) overview
Transmission Needs will be analyzed by the applicable system models. Identified needs, as described in this section, include the following transmission grid services:
■ Inertia
■ Voltage support
■ Fast frequency response (FFR)
■ Primary frequency response (PFR)
■ Short-circuit current
■ Transmission Capacity
There are two major components to inform transmission needs – system security analysis and steady-state analysis which builds upon the Renewable Energy Zone (REZ) study. These analyses are guided by the transmission planning criteria for each island. The TAP conducted a review of the transmission planning criteria and the system security process. The incorporation of their recommendations and feedback is included in the September 2022 GNA Methodology Report.
Steady-state analysis is performed in PSS/E, which analyzes system steady state voltages and transmission line loading. For each island, transmission networks, including trasmission lines, generation, substation transformers and loads, are modeled in PSS/E. Selected system generation dispatches with system load scenarios are represented in PSS/E, by modifying generation parameters (i.e., MW and MVar). The distribution system (distribution circuits, customer loads, and DER) is not modeled in detail in this steady state analysis, but represented as aggregated load and generation in each distribution bus of distribution substation transformers (for Hawaiʻi island system and Maui system) and each substransmission bus of transmission substation transformers (for Oʻahu system). Modeling of the full transmission network allows us to identify any equipment overloads or voltage violations per the transmission planning criteria.
The other component of system security study evaluates system dynamic stability conditions and determines related grid needs. Traditionally, the dynamic stabilty can be studied in the PSS/E as well. However, PSS/E dynamic stability simulation capability is more suitable for traditional synchronous machine dominated power systems in which electric-mechanical dynamics are the core component of system dynamic stability. Because our power system today and in the future is increasingly dominated by inverter-based systems (for solar, wind and battery energy storage), instead of synchronous machine based generation, a different type of software, PSCAD/EMTDC, is used to perform system dynamic stabilty. The PSCAD/EMTDC is one of few commercial avaiable utility grade software specifically designed for performing electromagnectic transient (“EMT”) simulation. This is the most popular EMT
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software currently among utilities, equipment manufactureres and research institutes in North America. A PSCAD simulation normally represents one system planning event (e.g., a generator trip) in one pre-defined system dispatch (e.g., daytime peak load high DER generation dispatch). We normally simulate 30 seconds of real time of an event like a storm causing a transmission line to unexpectedly trip offline. 10-14 hours are some times needed to complete these highly complex simulations.
The analysis will produce the following key deliverables:
■ Strategies and mitigations required for safe and reliable operation of the grid based on resource portfolio(s)
■ Typical and/or boundary dispatch and operational requirements for grid operation based on resource portfolio(s)
■ Frequency stability, voltage stability, control stability and rotor angle stability (if applicable) performance of the future grid
■ Evaluation of the need for grid forming technology and demonstration of system performance with this
technology when and if needed for the future grid
■ Evaluation of weak grid issues and development of a “weak grid” definition for each of the island grids,
which includes investments or mitigation strategies to operate a grid with limited to no synchronous
generation. Weak grid conditions could include low short circuit current availability, low inertia, and
limited reactive power support.
■ Identification of additional transmission grid services needed over the near-term 5-year planning horizon
2.2.5.1 Renewable energy zones
The second component in assessing transmission needs is the development of renewable energy zones (REZ), which includes development of transmission capacity needs to integrate higher levels of renewable energy. The transmission needs assessment leverages the July 2021 Assessment of Wind and
Photovoltaic Technical Potential Report to identify long term transmission capacity needs to harness
renewable energy potential on each island.
The REZ concept37 will require an extensive planning process centered around community and
stakeholder engagement; however, the intent of the renewable energy zone analysis is to identify the
cost of potential transmission upgrades that will allow RESOLVE to determine whether generation in various areas on each island and transmission buildout decisions are least-cost compared to other alternatives or alternate sites and resources. If determined to be directionally cost-effective then
developing renewable energy zones may be pursued further.
37 See NREL’s renewable energy zone guidebook, https://www.nrel.gov/docs/fy17osti/69043.pdf and the process undertaken at AEMO,
https://aemo.com.au/-/media/files/major-publications/isp/2020/appendix--5.pdf?la=en
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2.2.6 Synergi and LoadSEER overview
The distribution system analysis step will primarily use two different modeling tools: (1) LoadSEER, an agent-based forecasting engine, and (2) Synergi software, a steady-state distribution power flow
modeling tool.
LoadSEER creates local, distribution level forecast by distribution substation and circuit. This electric load forecasting software incorporates our corporate load forecasts and a multitude of other inputs to create forecasts at the circuit and substation transformer level.
The objective of LoadSEER is to statistically represent the geographic, economic, and weather diversity
across our service territory, and to use that information to forecast how circuit- and transformer-level
hourly load profiles will change over the next 30 years. Because of the complexity of the forecasting challenge, LoadSEER employs multiple statistical methods, including hourly load modeling, macro-economic modeling, customer-level economic modeling, and geospatial agent-based modeling, which
taken together increase the validity and reduce uncertainty associated with the forecasts.
The bottom-up parcel level methodology used by LoadSEER aligns with corporate-level forecasts, such that stakeholders are assured that these scenarios are grounded in a shared vision of the service territory, in aggregate.
Hourly customer class and feeder load shapes, distribution energy resource (“DER”) shapes, and DER
forecasts are jointly overlaid within the base load, agent model growth, and known new load service
requests to derive the overall forecast load profile for each circuit, such that all resource and load factors contributing to the circuit’s load at risk can be accurately assessed.
These bottom-up simulations provide circuit-by-circuit forecast. The circuit level data is then readily aggregated up to the transformer and substation levels, and input from local knowledge to fine tune
the model. This helps improve the scenario forecast’s quality and usability.
The Synergi modeling tool is a steady-state power flow software that is able to model each distribution substation and circuit. The tool is used to assess circuit-level loading and hosting capacity utilizing the circuit-level forecasts generated by LoadSEER. Synergi then determines if a distribution planning capacity or voltage criterion is violated. Then mitigations can be identified to allow integration of the
forecasted amount of load and DER. Although the secondary wires are not included in the model,
behind the meter customer assets such as rooftop solar and battery energy storage are modeled and aggregated at the distribution service transformer.
2.2.6.1 Distribution Planning Process and Methodology
As the power supply and electrical distribution systems transition to an integrated system, the planning processes must also transition. Hence today’s distribution planning methodology must ensure the orderly expansion of the distribution system and fulfill the following core functions:
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■ Plan the distribution system’s capability to serve new and future electrical load growth, including electric vehicle (EV) growth
■ Safely interconnect DER, such as photovoltaic (PV) systems and energy storage systems that transmit power across the system in a two-way flow, while maintaining power quality and reliability for all customers
■ Incorporate the locational benefits of DER in the evaluation of grid needs and system upgrades
We engaged with customers and stakeholders to seek input and feedback on the distribution planning methodology as part of the Distribution Planning Working Group. This has afforded opportunities for stakeholders to collaborate and co-develop the distribution planning methodology for identifying grid needs, as described in the September 2022 GNA Methodology Report.
The distribution grid needs will be the foundation that drives solution options, including non-wires alternative (NWA) opportunities.
Overview
The distribution planning process occurs annually and includes four stages: Forecast, Analysis, Solution
Options, and Evaluation (see Figure B-23).
Figure B-23. Stages of the Distribution Planning Process
Stages
The forecast stage begins at the start of the calendar year when the prior year’s circuit and transformer load data and the corporate demand and DER forecasts are available for input in the LoadSEER tool to create circuit- and transformer-level load forecasts.
The analysis stage involves the analysis of the electrical distribution system to ensure that there is
adequate capacity and reliability (back-tie capabilities) to accommodate the load and DER forecasts. Planning criteria have been established that provide the basis for determining the adequacy of the electric distribution system. In situations where the criteria are not met, grid needs are identified.
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In the solution options stage, requirements to meet the grid needs are determined, and wires and non-
wires options are developed. The Non-Wires Opportunity Evaluation Methodology report in Appendix F
describes the process to identify favorable NWA opportunities.
These options are evaluated in the fourth stage of the distribution planning process, with the most cost-effective, feasible solution selected that meets the grid need requirements and need by date.
It is worth noting that during the calendar year, it is expected that new service requests, DER, or projects
will arise that will require modifications to the circuit- and or transformer-level forecasts. We continually
evaluate grid needs throughout the year and make decisions on when to address any grid deficiencies identified outside of the forecast and analysis stages.
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3 Reliability Criteria
The section describes the reliability criteria for generating resources, transmission and distribution
planning that is used to identify grid needs.
3.1 Resource Adequacy Criteria
Within the IGP process the energy reserve margin or ERM along with the hourly dependable capacity or HDC is used as an input to the RESOLVE capacity expansion modeling to ensure that the optimization ensures a reliable system. The ERM and HDC methodology is described in the September
2022 GNA Methodology Report.
The ERM is the percentage of system load by which the system capacity must exceed the system load in each hour. The energy reserve margin for each island is listed in Table B-19 below.
Table B-19. Energy Reserve Margin Percentages by Island
Island Energy Reserve Margin
O‘ahu 30%
Hawaiʻi 30%
Maui 30%
Moloka‘i 60%
Lāna‘i 60%
Energy reserve margins are derived from an assessment of historical data. Identified ‘at risk’ hours were
evaluated to determine minimum energy reserve targets for planning purposes. The loss of largest unit, multiple forced outages, and unplanned maintenance were some of the largest contributing factors for hours considered to be at-risk. Energy reserve margin targets plan for the loss of largest unit and an additional hourly reserve for emergencies. However, it does not directly assign specific reserves to cover
different events discretely. The ERM is intended to mitigate a variety of risks including the loss of the
largest unit. As an example of the dynamics, the loss of a 180 MW (largest) unit for a peak load of 1,200 MW represents 15%; the loss of the same unit during a shoulder peak load of 600 MW represents 30%. Therefore, the ERM does not explicitly allocate a percentage to the loss of the largest unit and the
other portion to other specific type of events that may occur.
The size of generating units on each island are contributing factors to energy reserve margin
targets. For instance, on Molokaʻi and Lānaʻi, the largest generating units on the island have the capability to produce roughly 60% of each island’s average daily energy usage. For comparison to the current planning criteria described above, which is to meet the peak load with the loss of the largest
available unit, the 60% energy reserve margin target for Molokaʻi and Lānaʻi is to plan for resources that
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can generate enough energy throughout the day to meet the island’s energy load without the largest
available unit.
The Hourly Dependable Capacity (“HDC”) for variable renewable resources is calculated as the typical day in the month and is the minimum expected capacity from variable generation resources based on
empirical data. Based on feedback from the TAP, the HDC (MW) is calculated as an 80 percent
probability of exceedance by hour, i.e. for each hour of the month, 80 percent of the analyzed distribution of variable renewable resource generation was at or above its stated HDC.
To assess the adequacy of a resource plan, probabilistic reliability metrics are used in the resource
adequacy step. Four metrics are reported and used to compare the various cases -- loss of load
expectation (LOLE), loss of load events (LOLEv), loss of load hours (LOLH) and expected unserved
energy (EUE). Consistent with the typical North America guideline for LOLE, we use 0.1 days per year38 LOLE in our assessment of various resource portfolios. The lower the LOLE (i.e., (≤0.1) the more reliable a resource plan will be in its ability to serve the electric demand. This provides a useful frame of
reference when evaluating resource plans that consider different additions of variable renewables and
thermal resources. Stricter reliability thresholds may be warranted to address generation resilience on
isolated island grids as high impact, low frequency events increase in frequency.
3.2 Operating Reserves (Reg Reserve)
The regulating reserve requirements were based on the methodology described in the September 2022 GNA Methodology Report. This analysis included both the 1-minute and 30-minute regulating reserve
requirements. The purpose of the regulation criteria is to establish guidelines to minimize the risk of supply and demand imbalances by ensuring sufficient regulating reserves are available to the system in long-range planning studies. This criterion applies to private rooftop solar systems, standalone grid-scale solar resources, standalone grid-scale wind resources, and gross system load.
3.3 Transmission Criteria
The transmission planning criteria for the Oʻahu, Maui and Hawaiʻi island transmission system establish
guidelines to ensure safe and reliable service to its customers for current and future system needs. These criteria also apply to facilities that interconnect to the transmission system. The primary objectives of these criteria to maintain reliable Transmission System operation (i.e., continuity of service)
include the following:
■ Ensure public safety.
■ Maintain system stability under a wide range of operating onditions.
■ Maintain equipment operating limits under a wide range of operating conditions.
38 See https://www.epri.com/research/programs/067417/results/3002023230
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■ Minimize losses where cost effective.
■ Pereserve the reliability of the existing transmission infrastructure.
■ Maintain an acceptable level of impact to customers for contingencies and events as defined within planning criteria.
■ Prevent cascading outages or system failure following credible contingencies and events.
These criteria are intended to be used as a general guide in planning the three islands’ transmission systems, for which transmission needs for reinforcement, enhancements and mitigations will be determined.
The Molokaʻi and Lanaʻi system do not have a transmission system, and therefore, do not have a
transmission planning criteria. However, in this study, maintaining system dynamic stability for a three-phase bolted fault with 2 seconds duration and for a single-phase to ground fault with 40 ohm fault impedance and 20 seconds duration is used as criteria to evaluate system dynamic stability.
3.3.1 Thermal limits
For the Oʻahu transmission system, with any generating unit offline for maintenance, all transmission system elements will operate within their normal ratings while mainaining voltage leves within planning
criteria limits for any single transmission element outage. If any transmission line out of service for
maintenance happens together with any generating unit offline for maintenance, all trasmission system elements will operate within their emergency ratings while maintainning voltage levels within their limits. Any generating station must be able to operate at maximum normal rating with no transmission system element loading exceeding its emergency rating while maintaining voltage levels within limits
for any of the transmission system element outages.
For Maui and Hawaiʻi island, with any generating unit offline for maintenance, outage of any transmission system element or another generating unit will trigger remaining transmission system elements oprate within their emergency ratings. Simliar for any generation station operating at
maximum normal rating, all transmission system element will operate at emergeny limit when there is a
transmission elment outage.
3.3.2 Voltage levels
Transmission voltage levels shall be kept within the prescribed limits for any condition for which the
transmission system is planned. These limits apply after automatic corrective action has been taken by
LTC and/or switched capacitors. For Oʻahu, 138 kV system voltage should be maintained between 126.5 kV to 145 kV, and 46 kV system voltage should be maintained between 45 kV and 48 kV. For Maui and Hawaiʻi island, 69 kV system voltage should be maintained between 62.1 kV and 72.5 kV, 34.5 kV system
voltage should be maintained between 31.05 kV and 36.2 kV, and 23 kV system voltage should be
maintained between 20.7 kV and 24.15 kV.
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3.3.3 System stability
For all three systems, system stability includes steady state voltage stability, control stability, rotor angle stability and frequency stability. Accoridng to previous studies, system critical clearing time (“CCT”) is recommended to be no longer than 24 cycles. In recent system dynamic stability studies, frequency
stability study is the focus. According to these planning criteria, for the Oʻahu transmission system,
under frequency load sheding (“UFLS”) is not allowed for planning events P1 to P5; for the Maui and Hawaiʻi island transmission system, certain amount of UFLS is allowed for single contingency with generation trip and multiple contingency.
3.4 Distribution Criteria
During the analysis stage of the distribution planning process, distribution planning criteria have been
established as technical guidelines to ensure that the distribution system has adequate capacity and reliability to accommodate forecasted load and DER growth.
3.4.1 Normal Conditions
The distribution system, or a subset of the distribution system, is operating under normal conditions when all circuits and transformers in the subject area are configured as designed. Under this normal condition, the circuits and transformers are planned to have adequate capacity to serve electrical peak
load, and with DER, the circuits and transformers are also planned to be adequate for the backflow of
generation caused by the DER.
3.4.2 Contingency Conditions
The distribution system, or a subset of the distribution system, is operating under contingency
conditions when a single circuit or transformer is out of service. This is also referred to as an N-1 scenario. A circuit or transformer may be out of service or de-energized because of equipment failure or planned maintenance. As such, a level of capacity must be available on the circuits and transformers to be available to serve customers during these N-1 scenarios. For instance, because an adjacent circuit or
transformer is often used as a backup source for another circuit or transformer, N-1 scenarios also need
to be analyzed to ensure that back-tie capacity is available.
3.4.3 Normal and Contingency Overloads
Normal overload occurs when the load exceeds the normal equipment rating of distribution circuits or distribution substation transformers under normal operating conditions. Normal overload is identified by comparing the forecasted load with the equipment rating.
Contingency (N-1) overload occurs when the load exceeds the emergency equipment ratings of a piece
of equipment under scenarios when other equipment fail or is out for maintenance. Contingency
overload is identified by studying the forecasted load for possible contingency situations.
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3.4.4 Overload and Voltage Issues
The overload of a circuit or transformer may lead to overheating issues that will damage equipment; hence, overloads are considered thermal issues. When circuit or transformer loading exceeds the equipment thermal ratings, damage may occur to the equipment. This damage may lead to extended
service interruptions and high maintenance expenses.
In addition to thermal overloads, the electrical system is also analyzed to ensure that there are no voltage issues. In general, the voltage level must be maintained within 5% of the nominal voltage at any point on the distribution system (primary and secondary)39.Low or high voltage may lead to power
quality issues that could damage customer-owned equipment or cause nuisance electrical issues, such as flickering light or tripping of equipment.
39 Hawaiian Electric is required to manage the voltage to within limits prescribed in Rule No. 2 Character of Service. See https://www.hawaiianelectric.com/documents/billing_and_payment/rates/hawaiian_electric_rules/2.pdf
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
4 Resource Portfolio
The section describes our existing resource portfolio that includes customer resources, and utility-
owned and independent power producer generation facilities.
4.1 Existing Customer energy resource programs
Our plans integrate our vast offerings of customer programs that have contributed towards the high penetration of customer resources that include private rooftop solar, battery energy storage, direct load control (i.e., demand response) and community based renewable energy offerings. The resources
acquired through these programs are an important and significant portion of our renewable portfolio.
Our programs are predominantly made up of less than 100 kW solar systems:
Net Energy Metering (“NEM”): is closed to new applicants. However, customers with renewable energy systems (predominantly private rooftop solar) are credited on their electric bill the retail rate of electricity for every kWh exported to the grid.
Net Energy Metering Plus (“NEM Plus”): allows current NEM customers with a signed agreement to
add additional non-export capacity to their system.
Standard Interconnection Agreement (“SIA”): is designed for larger customers who wish to offset their electricity bill with on-site generation. No compensation is allowed for exported energy.
Smart Export: customers with a renewable system and a battery energy storage system have the
option to export energy to the grid from 4 p.m. – 9 a.m. Systems must include grid support technology to manage grid reliability and system performance.
Customer Self-Supply (“CSS”): intended only for private rooftop solar installations that are designed to not export any electricity to the grid. Customers are not compensated for any export of energy.
Customer Grid-Supply (“CGS”): participants receive a Commission-approved credit for electricity sent
to the grid and are billed at the retail rate for electricity they use from the grid. The program remains open until the installed capacity has been reached.
Customer Grid-Supply Plus (“CGS Plus”): systems must include grid support technology to manage grid reliability and allow the utility to remotely monitor system performance, technical compliance, and
if necessary, control for grid stability. Participants receive a commission-approved credit for electricity
sent to the grid.
Community Based Renewable Energy (“CBRE”): provides an additional option for customers who are not already enrolled in a DER program to benefit from electricity generated by a renewable energy facility in their utility service territory.
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Interim Time-of-Use (“TOU-RI”): an opt-in program for residential customers that is designed for
customers to save money if they use more power during the day -- when solar energy production is the
highest -- and less at night.
The capacity of our customer programs is illustrated in Figure B-25.
Figure B-24. Hawaiian Electric DGPV Systems Installed
Grid Service Programs
In addition to customer programs where customers may export excess energy that they do not consume, we also have program offerings where customers can provide certain grid services to the grid. Customers are compensated for the provision of services which may be administered through a third-party aggregator or Hawaiian Electric. We have several grid service purchase agreements with third
party aggregators. Many of these programs are not fully subscribed as aggregators continue to recruit
customers. We also have legacy demand response programs.
Grid Services Purchase Agreements – Actively Recruiting
GSPA contracts specify the delivery of Capacity Reduction, Capacity Build, and Fast Frequency Response
Grid Services. These services are delivered by aggregators who we have contracted with. We currently
have two GSPAs on O‘ahu that have been actively enrolling participants since 2020. We have two active
GSPAs on Maui that have been actively enrolling participants since 2020, and have one GSPA on Hawai‘i Island that has been actively enrolling participants since 2022. We continue to focus on supporting and aiding the aggregators to achieve their contracted target amount.
Grid Services Purchase Agreements – Recent and on-going procurements
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APPENDIX B – FORECASTS, ASSUMPTIONS AND MODELING METHODS
We conducted a third round of GSPA procurements for the island of O‘ahu. This resulted in a
negotiated contract with an aggregator to deliver 97.4 MWs of grid services.
We recently issued a Maui GSPA RFP to acquire Grid Services to address the recently advanced end-of-life forecast for the four 12.5 MW Mitsubishi-MAN generating units on Maui.
Battery Bonus – Actively Recruiting
The Battery Bonus Program on Oahu and Maui is designed to provide scheduled export of power for 2
hours during the evening peak intended to address times where generation reserves may be tight due
to the retirement of the AES coal plant and the forthcoming retirement of generation on Maui. The program pays upfront and monthly incentives to customers in exchange for export during the peak demand period for electricity. The program is currently limited to 50 MW on Oahu and 15 MW on Maui
island.
Fast Demand Response (Fast DR)
On Oahu, the Fast DR program currently has a capacity of 4.0 MW from 16 customers in the military, hospitality, condominium, education, and office sectors. On Maui, the targeted 2023 impact for the Fast DR Program is 4.3 MW (customer level), and currently has 27 participants from the hospitality, water,
education, and retail sectors.
EnergyScout Residential (RDLC) - In Maintenance (O‘ahu)
The residential direct load control program currently has approximately 29,000 water heaters and 3,700 air conditioner direct load control devices enrolled with 26,000 participants for a capacity of 13.6 MW. We will continue existing operations to maintain customer participation and MW impacts for RDLC.
EnergyScout Commercial (CIDLC) - In Maintenance
The commercial industrial load control program currently has a capacity of 11.4 MW from 25 commercial and industrial customers in the military, hospitality, condominium, education, and office sectors. In addition, the small business direct load control program currently has a capacity of 1.0 MW from 175 small and medium business customers in the retail, restaurant, and office sectors. We will
continue the existing operations to maintain customer participation and MW impacts for CIDLC.
EnergyScout Residential Technology Replacement
We are currently pursuing a programmatic solution to transition the existing EnergyScout Program participants to a new program(s) technology that offers grid service delivery. Specifically, existing
EnergyScout Program participants would potentially be able to deliver a variety of grid services by
relying on smarter, two-way communicating devices/equipment.
We issued an RFP in early 2022 and selected multiple vendors to update technology for its EnergyScout program. The RFP requested that vendors provide a replacement technology to the current direct load control device, a software system to manage and aggregate the fleet of water heaters, and an
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administrator to enable and monitor the replacement of the existing devices and provide ongoing
program maintenance.
4.2 Existing generation portfolio
The current generation portfolio contains a mix of utility-owned generation as well as generation from independent power producers (IPPs) that includes, solar, wind, geothermal, hydro, biofuel and diesel powered generators, along with oil fired steam generation. This section describes our current
generation portfolio on each island that we serve.
4.2.1 O‘ahu
Utility-Owned Generation
Kahe Generating Station. The Kahe generation station has six steam units, all baseload generation, with a combined nameplate capacity of 650 MW, with 606 MW net generation. These are our most efficient units. The station has black start capability.
Waiau Generating Station. The Waiau generating station has eight units: six are steam units and two are diesel. Two are baseload units; four are cycling units; and two are quick-start combustion turbines. Their combined nameplate capacity is 500 MW, with 474 MW net generation. The station has black start capability.
Campbell Industrial Park (CIP). The CIP generating station has one combustion turbine, CT-1, which runs on diesel but capable of running on biodiesel. It provides 129 MW net firm generation. The unit is both quick-start capable and black start capable. This peaking unit runs approximately 10% of the time to address peak load times.
Schofield Generating Station. The Schofield generating station has six combustion engines for a total of 48.6 MW which run on biodiesel. The individual units are quick-start capable and black start capable. The Schofield generation station also has the ability to power the U.S. Army facilities in an emergency for critical missions. In normal operations this unit serves the broader grid and is a used as a peaking unit.
Honolulu Generating Station. The Honolulu generating station, located in the downtown load center, has two steam units with a combined nameplate capacity of 113 MW, with 107 MW net generation. Both are cycling units. These units were deactivated in January 2014, and are expected to be retired by the end of 2023.
Our baseload units average 54 years of age, while the cycling units average 70 years. The combined average age of all steam units is 59 years. While our existing generation fleet does well in serving stable, predictable, consistent loads, they are not as capable as modernized generation in effectively managing system stability with higher levels of variable generation.
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As the role of firm generation assets evolve, the technical and operational capabilities of these units must match their new use pattern. To meet the future requirements, many existing generators must be modified or replaced in order to cost-effectively supply supplemental energy, fast balancing services, and other requirements identified for reliable and secure power delivery in the future. Among other attributes, new assets need to have operational flexibility: the ability to start quickly, ramp up and down at high rates, and must be designed to regularly start and stop multiple times daily even after long periods of being offline. The baseload steam units in our fleet do not fully possess these characteristics and will need replacement with modern units that do.
Independent Power Producer (IPP) Generation
H-POWER. The Honolulu Program of Waste Energy Recovery (H-POWER) is a municipal solid waste refuse to energy plant that generates 68.5 MW of baseload, firm generation.
Kalaeloa. The Kalaeloa cogeneration (combined-cycle) plant burns LSFO to generate 208 MW of baseload generation.
4.2.2 Hawai‘i Island
On Hawaii Island we currently own and operate 23 firm generating units, totaling about 181.6 MW (net, maximum capacity), at five generating stations and four distributed generation sites. Three steam units (fueled with No. 6 fuel oil–MSFO) are located at the Hill, and Puna generating stations. Ten diesel engine generators (fueled with diesel) are located at the Waimea, Kanoelehua, and Keahole generating
stations. Our five combustion turbines (CTs–fueled with diesel) are located at the Kanoelehua, Keahole,
and Puna generating stations. Two of the Keahole CTs are configured to operate in combined cycle with a heat recovery steam turbine. Four distributed generation diesel engines fueled with diesel fuel are located individually at the Panaewa, Ouli, Punalu‘u, and Kapua substations (the Panaewa and Kapua
units are temporarily located at Kapoho as part of a lava mitigation plan to serve customers potentially
isolated by the flow, and will be restored for grid operation).
Two independent power producers (IPPs) provide firm capacity power to our grid. One is a combined-cycle power plant, Hamakua Energy Partners (HEP), owned and operated by Pacific Current; the other is a geothermal power plant owned and operated by Puna Geothermal Venture (PGV).
Our generation fleet has the following capabilities:
■ Quick/fast start generation including simple cycle combustion turbines (SCCT) and ICEs that provide
emergency replacement power and peaking generation, but at a higher cost than the larger resources. The simple cycle combustion turbines can be used as black start resources.
■ Combined-cycle units, comprised of two CTs, two HRSGs, and one ST with high efficiency and relatively low cost. These assets provide cycling capability with a 1–2 hour start time, and have fast ramping capability.
■ Older conventional steam units have offline cycling capability, but longer start-up times and less ramping capability when compared to the combined-cycle units.
■ Geothermal IPP provides firm energy.
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4.2.3 Maui County
In Maui County we own and operate three island electric grids on the islands of Maui, Moloka‘i, and Lāna‘i. Each island as its own unique physical grid design based on system load, demand, and customer needs. Our generation portfolio is composed of a mix of renewable and firm resources.
We generate the majority of our power from combined-cycle and internal combustion engine units, as
well as a growing portfolio of renewable energy. Maui’s total firm capacity is 251.7 MW (gross). Lāna‘i’s total firm capacity is 9.40 MW (gross). Moloka‘i’s total firm capacity is 15.18 MW (gross).
The Maui grid includes a growing portfolio of variable renewable energy that includes wind, solar photovoltaic, and hydropower. Our firm generation resources include centralized generating stations
comprised of combined cycle and internal combustion engine units, oil-fired steam units, and biomass.
Maui Island’s existing dispatchable generation fleet comprises two main power plants at Kahului and Ma‘alaea. These plants include:
■ Quick-start internal combustion engines (ICEs) that provide emergency replacement power and peaking generation.
■ Combined-cycle units, comprised of two combustion turbines (CTs), two heat recovery steam generators (HRSGs) or once-through steam generators (OTSGs), and one steam turbine (ST) that provide high efficiency and relatively low cost cycling capability with a one- to two-hour start time, and
fast ramping response. These combined-cycle units support the integration of variable renewables
resources needed to achieve the 100% RPS goal by 2045.
Molokaʻi and Lānaʻi have existing dispatchable generation fleet which comprises quick-start internal combustion engines (ICEs) at Pālā‘au and Miki Basin, respectively. Molokaʻi also has a combustion turbine, also located at Pālā‘au.
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APPENDIX C – DATA TABLES
Appendix C:
Data Tables
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APPENDIX C – DATA TABLES
Contents
1. Data Tables ........................................................................................................................................................................................................................... C-3 Fuel Price Forecast ..................................................................................................................................................................................................... C-3 Existing Resource Portfolios ................................................................................................................................................................................... C-7 Oʻahu ................................................................................................................................................................................................................... C-7 Hawaiʻi Island ................................................................................................................................................................................................... C-9 Maui .................................................................................................................................................................................................................. C-11 Molokaʻi .......................................................................................................................................................................................................... C-13 Lānaʻi ................................................................................................................................................................................................................ C-14 Resource Plans .......................................................................................................................................................................................................... C-15 Oʻahu ................................................................................................................................................................................................................ C-15 Hawaiʻi Island ................................................................................................................................................................................................ C-22 Maui .................................................................................................................................................................................................................. C-26 Molokaʻi .......................................................................................................................................................................................................... C-30 Lānaʻi ................................................................................................................................................................................................................ C-33 Resource Adequacy ................................................................................................................................................................................................ C-36 Oʻahu ................................................................................................................................................................................................................ C-36 Hawaiʻi Island ................................................................................................................................................................................................ C-38 Maui .................................................................................................................................................................................................................. C-40 Molokaʻi .......................................................................................................................................................................................................... C-42 Lānaʻi ................................................................................................................................................................................................................ C-44 Operational Statistics ............................................................................................................................................................................................. C-46 Oʻahu ................................................................................................................................................................................................................ C-46 Hawaiʻi Island ................................................................................................................................................................................................ C-52 Maui .................................................................................................................................................................................................................. C-55 Molokaʻi .......................................................................................................................................................................................................... C-59 Lānaʻi ................................................................................................................................................................................................................ C-61
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APPENDIX C – DATA TABLES
1. Data Tables
Fuel Price Forecast
The cost of producing electricity is dependent upon, in part, the cost of fuels utilized to generate power.
Hawaiian Electric uses the following fuel types:
■ Low Sulfur Fuel Oil (LSFO): A residual fuel oil similar to No. 6 fuel oil that contains less than 5,000 parts per million of sulfur; about 0.5% sulfur content
■ No. 2 Diesel Oil
■ Ultra-Low Sulfur Diesel (ULSD)
■ Naphtha
■ High Sulfur Fuel Oil (HSFO): Also called Industrial Fuel Oil (IFO), HSFO contains less than 2% sulfur
The fuel price forecast was developed using a correlation between historical, actual fuel prices and the Brent North Sea Crude Oil Benchmark (Brent) from 1983-2019. The R2 value for petroleum fuels was
greater than 0.93. Hawaiian Electric’s 2021 forecast was based on the Brent forecast provided by the
Energy Information Administration (“EIA”) Annual Energy Outlook (“AEO”). 1 Shown below in Table C-1, Table C-2, and Table C-3 is the fuel price forecast for Oʻahu, Hawaiʻi Island, and Maui County, respectively.
1 Hawaiian Electric updated its assumptions to use the fuel price forecast provided by the EIA AEO instead of FGE in response to stakeholder feedback to use publicly available, non-proprietary sources.
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APPENDIX C – DATA TABLES
Table C-1. O‘ahu Fuel Price Forecast
Year LSFO Diesel ULSD - CIP ULSD - SGS Biodiesel $/MMBTU
2021 8.73 11.49 11.93 12.72 28.55 2022 9.43 12.24 12.71 13.51 29.32
2023 10.51 13.38 13.87 14.68 30.39 2024 11.36 14.28 14.80 15.62 31.37
2025 12.14 15.14 15.68 16.52 32.41
2026 13.03 16.11 16.68 17.54 33.60
2027 13.82 16.99 17.58 18.46 34.78
2028 14.67 17.94 18.56 19.46 36.04
2029 15.49 18.85 19.50 20.42 37.30
2030 16.36 19.82 20.49 21.45 38.60
2031 17.14 20.69 21.38 22.36 39.82
2032 18.03 21.67 22.40 23.40 41.12
2033 18.74 22.47 23.22 24.25 42.29
2034 19.47 23.29 24.07 25.11 43.45
2035 20.10 24.02 24.81 25.88 44.56
2036 20.90 24.90 25.72 26.82 45.77 2037 21.76 25.86 26.70 27.82 47.03
2038 22.63 26.82 27.69 28.83 48.31 2039 23.18 27.46 28.35 29.52 49.37
2040 24.37 28.76 29.69 30.88 50.91 2041 25.34 29.83 30.79 32.00 52.32
2042 26.15 30.75 31.74 32.98 53.65
2043 27.22 31.93 32.95 34.22 55.21
2044 28.16 32.99 34.04 35.34 56.73
2045 28.65 33.59 34.66 36.00 57.99
2046 29.99 35.08 36.19 37.56 59.92
2047 31.08 36.31 37.46 38.86 61.72
2048 32.03 37.40 38.59 40.03 63.49
2049 33.05 38.57 39.79 41.28 65.38 2050 34.10 39.79 41.05 42.57 67.35
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APPENDIX C – DATA TABLES
Table C-2. Hawai‘i Island Fuel Price Forecast
Year IFO Diesel ULSD Naphtha Biodiesel $/MMBTU
2021 7.45 12.16 12.68 13.71 28.55
2022 8.06 12.98 13.52 14.50 29.32
2023 8.99 14.21 14.78 15.69 30.39
2024 9.72 15.18 15.78 16.65 31.37
2025 10.40 16.10 16.73 17.56 32.41
2026 11.17 17.15 17.81 18.61 33.60
2027 11.85 18.09 18.77 19.56 34.78
2028 12.59 19.11 19.82 20.58 36.04
2029 13.29 20.09 20.83 21.58 37.30
2030 14.05 21.13 21.91 22.63 38.60
2031 14.71 22.06 22.87 23.57 39.82
2032 15.48 23.13 23.96 24.64 41.12
2033 16.10 23.99 24.85 25.52 42.29
2034 16.72 24.86 25.75 26.41 43.45
2035 17.27 25.64 26.55 27.21 44.56
2036 17.96 26.59 27.53 28.17 45.77
2037 18.70 27.62 28.59 29.20 47.03
2038 19.45 28.65 29.65 30.24 48.31
2039 19.93 29.34 30.36 30.96 49.37
2040 20.96 30.74 31.80 32.35 50.91
2041 21.79 31.88 32.98 33.50 52.32
2042 22.50 32.87 34.00 34.51 53.65
2043 23.42 34.14 35.31 35.78 55.21
2044 24.23 35.28 36.48 36.94 56.73
2045 24.65 35.92 37.15 37.64 57.99
2046 25.81 37.52 38.79 39.24 59.92
2047 26.75 38.84 40.15 40.59 61.72
2048 27.57 40.01 41.37 41.81 63.49
2049 28.44 41.27 42.66 43.11 65.38
2050 29.35 42.57 44.01 44.46 67.35
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APPENDIX C – DATA TABLES
Table C-3. Maui County Fuel Price Forecast
Year Maui Molokaʻi Lānaʻi
$/MMBTU IFO Diesel ULSD Biodiesel ULSD ULSD
2021 7.09 11.75 12.09 28.55 12.91 16.08
2022 7.69 12.58 12.94 29.32 13.76 16.95
2023 8.62 13.85 14.23 30.39 15.04 18.26
2024 9.33 14.85 15.26 31.37 16.07 19.33
2025 10.00 15.78 16.22 32.41 17.03 20.35
2026 10.75 16.85 17.31 33.60 18.13 21.51
2027 11.42 17.80 18.28 34.78 19.12 22.58
2028 12.14 18.83 19.34 36.04 20.19 23.73
2029 12.83 19.82 20.36 37.30 21.22 24.84
2030 13.57 20.88 21.44 38.60 22.31 26.02
2031 14.22 21.82 22.40 39.82 23.29 27.08
2032 14.97 22.89 23.50 41.12 24.40 28.28
2033 15.57 23.76 24.39 42.29 25.31 29.27
2034 16.19 24.65 25.30 43.45 26.23 30.27
2035 16.72 25.43 26.10 44.56 27.05 31.17
2036 17.39 26.39 27.09 45.77 28.05 32.26
2037 18.12 27.43 28.15 47.03 29.12 33.41
2038 18.85 28.48 29.22 48.31 30.21 34.58
2039 19.31 29.16 29.93 49.37 30.93 35.39
2040 20.33 30.59 31.39 50.91 32.40 36.94
2041 21.14 31.75 32.58 52.32 33.60 38.23
2042 21.83 32.75 33.60 53.65 34.64 39.36
2043 22.73 34.03 34.92 55.21 35.97 40.79
2044 23.52 35.18 36.09 56.73 37.16 42.09
2045 23.93 35.81 36.74 57.99 37.84 42.90
2046 25.07 37.43 38.40 59.92 39.52 44.70
2047 25.98 38.76 39.76 61.72 40.90 46.22
2048 26.78 39.93 40.97 63.49 42.14 47.60
2049 27.63 41.19 42.26 65.38 43.46 49.07
2050 28.51 42.49 43.60 67.35 44.83 50.60
C-7 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Existing Resource Portfolios
Hawaiian Electric’s thermal generating unit capacity is provided by a mix of utility-owned generation
and independent power producers (IPPs). Shown below are some general info about these resources. Further information can be found in the August 2021 IGP Inputs and Assumptions.
Oʻahu
1.2.1.1 Oʻahu Firm Generation Portfolio
Shown below in Table C-4. are the various firm thermal generators on Oʻahu, along with their minimum
and maximum capacity, fuel type, and age.
Table C-4. Oʻahu Minimum and Maximum Capacity, Fuel Type, and Age of Thermal Resources
Unit Type Operating Minimum (Net MW)
Normal Top Load (Net MW) Fuel Type Age (Years)
Kahe 1 Baseload 23.2 82.6 LSFO 61 Kahe 2 Baseload 23.3 82.4 LSFO 60
Kahe 3 Baseload 23.1 86.1 LSFO 54 Kahe 4 Baseload 23.1 85.4 LSFO 52
Kahe 5 Baseload 50.4 134.9 LSFO 50 Kahe 6 Baseload 50.4 134.7 LSFO 43
Waiau 3 Cycling 23.5 47.1 LSFO 77 Waiau 4 Cycling 23.5 46.5 LSFO 74
Waiau 5 Cycling 23.4 54.4 LSFO 65
Waiau 6 Cycling 23.5 53.7 LSFO 63
Waiau 7 Baseload 23.1 82.9 LSFO 58
Waiau 8 Baseload 23.1 86.3 LSFO 56
Waiau 9 Peaking 5.9 52.9 Diesel 51
Waiau 10 Peaking 5.9 49.9 Diesel 51 Campbell Industrial Park Peaking 41.2 129.0 Diesel 15
H-Power Baseload 35.0 68.5 Refuse Kalaeloa Energy Partners Baseload 65.0 208.0 LSFO
Airport DSG Peaking 4.0 8.0 Biodiesel 6 Schofield 1 Peaking 4.0 8.1 ULSD / Biodiesel 5
Schofield 2 Peaking 4.0 8.1 ULSD / Biodiesel 5
Schofield 3 Peaking 4.0 8.1 ULSD / Biodiesel 5
Schofield 4 Peaking 4.0 8.1 ULSD / Biodiesel 5
Schofield 5 Peaking 4.0 8.1 ULSD / Biodiesel 5
Schofield 6 Peaking 4.0 8.1 ULSD / Biodiesel 5
C-8 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.2.1.2 Oʻahu Variable Renewable, Storage, and Grid Service Resource Portfolio
Shown below in Table C-5 are Oʻahu’s variable renewable, storage, and grid service resources, their first year in service, along with their maximum capacity, and their capacity factor.
Table C-5. O‘ahu Variable Renewable, Storage, and Grid Service Resources
Unit Year in Service Capacity (MW) Storage Capacity (MWh) Capacity Factor (%) Kapolei Sustainable Energy Park 2012 1.0 - 21.9%
Kalaeloa Solar Two 2013 5.0 - 25.7%
Kalaeloa Renewable Energy Park 2014 5.0 - 20.5% Kahuku Wind 2011 30.0 - 27.2%
Kawailoa Wind 2013 69.0 - 19.7% West Loch 2019 20.0 - 25.1%
Lanikuhana Solar 2019 14.7 - 27.1% Waipio PV 2019 45.9 - 27.1%
Kawailoa Solar 2019 49.0 - 27.1% Na Pua Makani 2020 24.0 - 42.5%
Waianae Solar 2017 27.6 - 27.1%
Feed-In-Tariff Tier 1 and 2 24.8 - 19.3%
Feed-In-Tariff Tier 3 20.0 -
Aloha Solar Energy Fund 1 & 2 2020 10.0 - 19.3%
Mauka FIT 1 2020 3.5 - 19.3%
Waihonu Solar 2016 6.5 - 19.3%
CBRE Phase 1 2023 5.0 - 24.5%
CBRE Phase 2 2027/2029 180.0 - -
Stage 1
Ho‘ohana Solar 1 2024 52.0 208.0 25.1%
AES West Oahu Solar 2023 12.5 50.0 25.2%
Mililani 1 Solar 2023 39.0 156.0 27.2% Waiawa Solar Power 2023 36.0 144.0 27.9%
Stage 2 Waiawa Phase 2 Solar 2024 30.0 240.0 20.5%
Mountain View Solar 2024 7.0 35.0 17.3% Kupono Solar 2024 42.0 168.0 25.3%
Kapolei Energy Storage 2023 185.0 565.0 - Grid Services RFP
Load Build 2021 14.8 - -
Load Reduce 2021 26.3 - -
Load Build 3 2023 60 - -
Load Reduce 3 2023 60 - -
FFR 3 2023 12 - -
Demand Response
Fast Demand Response (FDR) 2018 5.5 - -
Residential Direct Load Control 2018 13.2 - -
Commercial Direct Load Control 2018 7.8 - -
Small Business Direct Load Control 2018 1.6 - -
C-9 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Hawaiʻi Island
1.2.2.1 Hawaiʻi Island Firm Generation Portfolio
Shown below in Table C-6 are the various firm thermal generators on Hawaiʻi Island, along with their
minimum and maximum capacity, fuel type, and age.
Table C-6. Hawai‘i Island Minimum and Maximum Capacity, Fuel Type, and Age of Thermal Resources
Unit Type Operating Minimum (Net MW)
Normal Top Load (Net MW) Fuel Type Age (Years)
Puna Geothermal Venture (2024) Baseload 20 46 Geothermal 31
Puna Geothermal Venture (2021, off-peak) Baseload 22.0 38.0 Geothermal 31
Puna Geothermal Venture (2021, on-peak) Baseload 33.9 38.0 Geothermal 31
Hill 5 Cycling 5.0 13.8 IFO (2021-2024) /
ULSD(2025+) 58
Hill 6 Cycling 8.0 20.0 IFO (2021-2024) /
ULSD(2025+) 49
Kanoelehua CT1 Peaking 2.0 10.3 Diesel 61 Kanoelehua D11 Peaking 2.0 2.0 ULSD 61
Kanoelehua D15 Peaking 2.4 2.5 ULSD 48-51
Kanoelehua D16 Peaking 2.4 2.5 ULSD 48-51
Kanoelehua D17 Peaking 2.4 2.5 ULSD 48-51
Kapua D27 Peaking 1.3 1.3 ULSD 24-25 Keahole CT2 Peaking 6.0 13.8 Diesel 34
Keahole D21 Peaking 2.4 2.5 ULSD 35-39
Keahole D22 Peaking 2.4 2.5 ULSD 35-39
Keahole D23 Peaking 2.4 2.5 ULSD 35-39
Ouli D25 Peaking 1.3 1.3 ULSD 24-25 Panaewa D24 Peaking 1.3 1.3 ULSD 24-25
Puna Cycling 6.0 15.5 IFO 53
Puna CT3 Peaking 8.0 20.0 Diesel 31
Punaluu D26 Peaking 1.3 1.3 ULSD 24-25
Waimea D12 Peaking 2.4 2.5 ULSD 51-53 Waimea D13 Peaking 2.4 2.5 ULSD 51-53
Waimea D14 Peaking 2.4 2.5 ULSD 51-53
Keahole CT4 Cycling 8.0 20.5 Diesel 19/13
Keahole CT5 Cycling 8.0 20.5 Diesel 19/13
Keahole ST7 Cycling 1.0 9.5 - 19/13
Hamakua Energy CT1 Cycling 7.0 20.8 80% Naphtha /
20% Biodiesel 23
Hamakua Energy CT2 Cycling 7.0 20.8 80% Naphtha / 20% Biodiesel 23
Hamakua Energy ST Cycling 5.5 16.4 - 23
C-10 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.2.2.2 Hawaiʻi Island Variable Renewable, Storage, and Grid Service Resource
Portfolio
Shown below in Table C-7 are Hawaiʻi Island’s variable renewable, storage, and grid service resources,
along with their first year in service, their maximum capacity, and their capacity factor.
Table C-7. Hawai‘i Island Variable Renewable, Storage, and Grid Service Resources
Unit Year in Service Capacity (MW) Storage Capacity (MWh) Capacity Factor (%)
Small Hydros 0.2 - 85.7%
Wailuku Hydro 1993 12.1 - 18.9%
HRD Wind 2006 10.5 - 42.4%
Tawhiri 2007 20.5 63.6%
Feed-In-Tariff 9.1 18.1%
Puueo Hydro 2005 3.3 - 54.8%
Waiau Hydro 1920 2.0 - 53.2%
CBRE Phase 1 2023 0.75 - 16.9%
CBRE Phase 2 2027/ 2029 20/ 12.5 - -
Stage 1 RFP
Hale Kuawehi Solar 2024 30.0 120.0 33.2%
Waikoloa Solar 2023 30.0 120.0 30.9%
Grid Services RFP
Load Reduce 2021 4.0 - -
Load Build 2021 3.2 - -
C-11 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Maui
1.2.3.1 Maui Firm Generation Portfolio
Shown below in Table C-8. are the various firm thermal generators on Maui, along with their minimum and maximum capacity, fuel type, and age.
Table C-8. Maui Minimum and Maximum Capacity, Fuel Type, and Age of Thermal Resources
Unit2 Type Operating Minimum (Net MW)
Normal Top Load (Net MW) Fuel Type Age (Years)
Kahului 1 Peaking 2.26 4.71 IFO 75
Kahului 2 Peaking 2.28 4.76 IFO 74
Kahului 3 Baseload 3.00 11.50 IFO 69
Kahului 4 Baseload 3.00 11.50 IFO 57
Maalaea 1 Peaking 2.50 2.50 ULSD 52
Maalaea 2 Peaking 2.50 2.50 ULSD 51
Maalaea 3 Peaking 2.50 2.50 ULSD 51
Maalaea 4 Peaking 1.86 5.51 Diesel 50
Maalaea 5 Peaking 1.86 5.51 Diesel 50 Maalaea 6 Peaking 1.86 5.51 Diesel 50
Maalaea 7 Peaking 1.86 5.51 Diesel 45 Maalaea 8 Peaking 1.86 5.48 Diesel 45
Maalaea 9 Peaking 1.86 5.48 Diesel 45 Maalaea 10 Cycling 7.87 12.34 Diesel 43
Maalaea 11 Cycling 7.87 12.34 Diesel 43
Maalaea 12 Cycling 7.87 12.34 Diesel 35
Maalaea 13 Cycling 7.87 12.34 Diesel 35
Maalaea X1 Peaking 2.50 2.50 ULSD 36
Maalaea X2 Peaking 2.50 2.50 ULSD 36
Maalaea 14 Baseload 5.88 21.13 Diesel 31
Maalaea 15 Baseload 3.73 13.38 - 30
Maalaea 16 Baseload 5.88 21.13 Diesel 30 Maalaea 17 Cycling 5.93 21.47 Diesel 25
Maalaea 18 Cycling 2.96 12.99 - 17 Maalaea 19 Cycling 5.93 21.47 Diesel 23
Hana 1 Peaking 0.00 0.97 ULSD 34/39 Hana 2 Peaking 0.00 0.97 ULSD 34/39
C-12 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.2.3.2 Maui Variable Renewable, Storage, and Grid Service Resource Portfolio
Shown below in Table C-9 are Maui’s variable renewable, storage, and grid service resources, along with
their first year in service, their maximum capacity, and their capacity factor.
Table C-9. Maui Variable Renewable, Storage, and Grid Service Resources
Unit Year in Service Capacity (MW) Storage Capacity (MWh) Capacity Factor (%)
Feed-In-Tariff 6.9 - 17%
Kaheawa Wind Farm I 2006 30.0 - 43%
Kaheawa Wind Farm II 2012 21.0 - 47%
Auwahi Wind Farm 2012 21.0 - 51%
South Maui Renewable Resources 2018 2.9 - 29%
Kuia Solar 2018 2.9 - 29%
CBRE Phase 1 2021 0.02832 - 28%
CBRE Phase 2 2027/2029 33.475 - -
Stage 1 RFP
Kuihelani 2024 60.0 240.0 31%
Paeahu Solar 2025 15.0 60.0 31%
Stage 2 RFP
Kamaole Solar 2025 40.0 160.0 35%
Waena BESS 2023 40.0 160.0 -
Grid Services RFP
Load Build 2023 2.0 - -
Load Reduce 2023 7.2 - -
FFR1 2023 6.1 - -
Demand Response
Fast Demand Response 2021 4.9 - -
C-13 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Molokaʻi
1.2.4.1 Molokaʻi Firm Generation Portfolio
Shown below in Table C-10. are the various firm thermal generators on Molokaʻi, along with their
minimum and maximum capacity, fuel type, and age.
Table C-10. Molokaʻi Minimum and Maximum Capacity, Fuel Type, and Age of Thermal Resources
Unit Type Operating Minimum (Net MW)
Normal Top Load (Net MW) Fuel Type Age (Years)
Palaau 01 Peaking 0.31 1.25 ULSD 38
Palaau 02 Peaking 0.31 1.25 ULSD 38
Palaau 03 Peaking 0.25 0.97 ULSD 38/32
Palaau 04 Peaking 0.25 0.97 ULSD 38/32
Palaau 05 Peaking 0.25 0.97 ULSD 38/32
Palaau 06 Peaking 0.25 0.97 ULSD 38/32
Palaau 07 Baseload 0.66 2.20 ULSD 27
Palaau 08 Baseload 0.66 2.20 ULSD 27
Palaau 09 Baseload 0.66 2.20 ULSD 27
Palaau GT1 Peaking 1.1 2.20 ULSD 41
1.2.4.2 Molokaʻi Variable Renewable, Storage, and Grid Service Resource Portfolio
Shown below in Table C-11 are Molokaʻi’s variable renewable, storage, and grid service resources, along
with their first year in service, their maximum capacity, and their capacity factor.
Table C-11. Molokaʻi Variable Renewable, Storage, and Grid Service Resources
Unit Year in Service Capacity (MW) Storage Capacity (MWh) Capacity Factor (%)
CBRE Phase 1 2023 0.25 - 21.8%
CBRE Phase 2 2027 2.75 - 25.7%
C-14 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Lānaʻi
1.2.5.1 Lānaʻi Firm Generation Portfolio
Shown below in Table C-12. are the various firm thermal generators on Lānaʻi, along with their
minimum and maximum capacity, fuel type, and age.
Table C-12. Lānaʻi Minimum and Maximum Capacity, Fuel Type, and Age of Thermal Resources
Unit Type Operating Minimum (Net MW)
Normal Top Load (Net MW) Fuel Type Age (Years)
LL 1 Peaking 0.5 1.0 ULSD 67
LL 2 Peaking 0.5 1.0 ULSD 67
LL 3 Peaking 0.5 1.0 ULSD 67
LL 4 Peaking 0.5 1.0 ULSD 67
LL 5 Peaking 0.5 1.0 ULSD 67
LL 6 Peaking 0.5 1.0 ULSD 67
LL 7 Baseload 0.3 2.2 ULSD 27
LL 8 Baseload 0.3 2.2 ULSD 27
1.2.5.2 Lānaʻi Variable Renewable, Storage, and Grid Service Resource Portfolio
Shown below in Table C-13 are Lānaʻi’s variable renewable, storage, and grid service resources, along
with their first year in service, their maximum capacity, and their capacity factor.
Table C-13. Lānaʻi Variable Renewable, Storage, and Grid Service Resources
Unit Year in Service Capacity (MW)
Storage Capacity (MWh)
Capacity Factor (%)
CBRE Phase 2 2027 15.8 63.2 25.8%
C-15 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Resource Plans
This section provides the resource plans for each island that was analyzed in Section 8 of the Integrated
Grid Plan Report. The resource plans include the Status Quo, Base, and Land-Constrained resource plans produced by RESOLVE, and the preferred Base and Land-Constrained resource plans which includes adjustments based on the Resource Adequacy analysis and Transmission and System Security analysis.
Oʻahu
1.3.1.1 Status Quo Resource Plan
Shown below in Table C-14 are the Status Quo resource plan, which assumed the Base forecast, commercial operations of Stage 1, Stage 2, and CBRE Phase 2 Tranche 1 projects; successful renegotiation of existing independent power producers; and continued operation of most existing
thermal units. The Status Quo plan excluded CBRE Phase 2 Tranche 2, Stage 3 RFP resources, and future
resources selected by RESOLVE.
Table C-14. Oʻahu – Status Quo resource plan.
Oʻahu: Status Quo
Year Planned New Additions 2022
2023
Installed 3 MW of CBRE Ph 1 PV Installed 12.5 MW West Oahu Installed 39 MW Mililani Solar Installed 36 MW Waiawa Solar Installed 185 MW Kapolei Energy Storage Installed 60 MW Load Build 3 Installed 60 MW Load Reduce 3
2024
Installed 2 MW of CBRE Ph 1 PV Installed 52 MW Hoohana Solar Installed 7 MW Mountain View Solar Installed 30 MW Waiawa Ph 2 Solar Installed 42 MW Kupono Solar Removed 93.5 MW Waiau 3-4
2025
2026 Removed 15 MW Load Build Removed 26 MW Load Reduce
2027 Installed 75 MW of CBRE Ph 2 RFP PV Installed 30 MW of CBRE Ph 2 Small PV
2028 2029 2030 2031 2032
2033 Removed 60 MW Load Build 3 Removed 60 MW Load Reduce 3
2034 2035 2036 2037 2038 2039
C-16 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Oʻahu: Status Quo
2040 2041 2042 2043 2044 2045 Biodiesel Conversion on all firm units
2046 2047 2048 2049 2050
1.3.1.2 Base Resource Plan
Shown below in Table C-15 is the Base resource plan produced by RESOLVE.
Table C-15. Oʻahu – Base resource plan.
Oʻahu: Base
Year Planned New Additions 2022
2023
Installed 3 MW of CBRE Ph 1 PV Installed 12.5 MW West Oahu Installed 39 MW Mililani Solar Installed 36 MW Waiawa Solar Installed 185 MW Kapolei Energy Storage Installed 60 MW Load Build 3 Installed 60 MW Load Reduce 3
2024
Installed 2 MW of CBRE Ph 1 PV Installed 52 MW Hoohana Solar Installed 7 MW Mountain View Solar Installed 30 MW Waiawa Ph 2 Solar Installed 42 MW Kupono Solar Removed 93.5 MW Waiau 3-4
2025 Installed 15 MW Barbers Point Solar
2026 Removed 15 MW Load Build Removed 26 MW Load Reduce
2027
Installed 75 MW of CBRE Ph 2 RFP PV Installed 30 MW of CBRE Ph 2 Small PV Installed 450 MW RFP 3 Hybrid Solar Removed 108.1 MW Waiau 5-6
2028
2029 Installed 75 MW of CBRE Ph 2 RFP PV Installed 300 MW RFP 3 CT Removed 169.1 MW Waiau 7-8
Installed 82 MW 155 MWh Standalone BESS Installed 82 MW Group 1 Onshore Wind Installed 82 MW Group 3 Onshore Wind
2030
Installed 85 MW 158 MWh Standalone BESS Installed 84 MW 140 MWh Group 1 Hybrid Solar 15% Slope Installed 344 MW 553 MWh Group 1 Hybrid Solar 30% Slope Installed 282 MW 674 MWh Group 2 Hybrid Solar 15% Slope Installed 435 MW 923 MWh Group 3 Hybrid Solar 15% Slope 2031 Removed 30 MW Kahuku Wind
2032 Removed 1 MW Kapolei Sustainable Energy Park
C-17 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Oʻahu: Base
2033
Removed 5 MW Kalaeloa Solar Two Removed 164.9 MW Kahe 1-2 Removed 60 MW Load Build 3 Removed 60 MW Load Reduce 3 Removed 208 MW KPLP Installed 208 MW RFP 3 CC
2034 Removed 5 MW Kalaeloa Renewable Energy Park
2035 Installed 76 MWh Group 2 Hybrid Solar 15% Slope BESS Installed 151 MWh Group 3 Hybrid Solar 15% Slope BESS Installed 400 MW New Offshore Wind 2036 2037 Removed 171.5 MW Kahe 3-4 2038 Removed 69 MW Kawailoa Wind 2039 Removed 27.6 MW Waianae Solar
2040 Removed 24 MW Na Pua Makani Wind Installed 157 MW 340 MWh Group 2 Hybrid Solar 15% Slope Installed 273 MW 755 MWh Group 2 Hybrid Solar 30% Slope Installed 86 MW 88 MWh Group 3 Hybrid Solar 30% Slope 2041 Removed 109.6 MW Clearway Projects 2042 2043 2044 Removed 20 MW West Loch Solar
2045 Biodiesel Conversion on all firm units
Installed 20 MW Biomass Installed 45 MWh Group 2 Hybrid Solar 15% Slope BESS Installed 912 MW 1631 MWh Group 2 Hybrid Solar 30% Slope Installed 108 MW 106 MWh Group 3 Hybrid Solar 30% Slope Installed 22 MW Recovered Wind Potential 2046 Removed 269.5 MW Kahe 5-6 2047 2048 2049
2050
Installed 80 MW Biomass Installed 5 MWh Group 2 Hybrid Solar 15% Slope BESS Installed 50 MW 161 MWh Group 2 Hybrid Solar 30% Slope Installed 449 MW 911 MWh Group 3 Hybrid Solar 30% Slope Installed 101 MW Recovered Wind Potential
1.3.1.3 Base Preferred Resource Plan
Shown below in Table C-16 is the Preferred Base resource plan. This plan incorporates any adjustments
based on the Resource Adequacy analysis and Transmission and System Security analysis. Changes
made to the RESOLVE resource plan are highlighted in red and green.
Table C-16. Oʻahu – Preferred – Base resource plan.
Oʻahu: Preferred – Base
Year Planned New Additions
2022
2023
Installed 3 MW of CBRE Ph 1 PV Installed 12.5 MW West Oahu Installed 39 MW Mililani Solar Installed 36 MW Waiawa Solar Installed 185 MW Kapolei Energy Storage
C-18 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Oʻahu: Preferred – Base
Installed 60 MW Load Build 3 Installed 60 MW Load Reduce 3
2024
Installed 2 MW of CBRE Ph 1 PV Installed 52 MW Hoohana Solar Installed 7 MW Mountain View Solar Installed 30 MW Waiawa Ph 2 Solar Installed 42 MW Kupono Solar Removed 93.5 MW Waiau 3-4
2025 Installed 15 MW Barbers Point Solar
2026 Removed 15 MW Load Build Removed 26 MW Load Reduce
2027
Installed 75 MW of CBRE Ph 2 RFP PV Installed 30 MW of CBRE Ph 2 Small PV Installed 450 470 MW RFP 3 Hybrid Solar Removed 108.1 MW Waiau 5-6
2028
2029 Installed 75 MW of CBRE Ph 2 RFP PV Installed 300 MW RFP 3 CT Removed 169.1 MW Waiau 7-8
Installed 82 MW 155 328 MWh Standalone BESS Installed 82 MW Group 1 Onshore Wind Installed 82 MW Group 3 Onshore Wind
2030
Installed 85 MW 158 340 MWh Standalone BESS Installed 84 MW 140 336 MWh Group 1 Hybrid Solar 15% Slope Installed 344 276 MW 553 1104 MWh Group 1 Hybrid Solar 30% Slope Installed 282 272 MW 674 1088 MWh Group 2 Hybrid Solar 15% Slope Installed 435 MW 923 1740 MWh Group 3 Hybrid Solar 15% Slope 2031 Removed 30 MW Kahuku Wind
2032 Removed 1 MW Kapolei Sustainable Energy Park
2033
Removed 5 MW Kalaeloa Solar Two Removed 164.9 MW Kahe 1-2 Removed 60 MW Load Build 3 Removed 60 MW Load Reduce 3 Removed 208 MW KPLP Installed 208 MW RFP 3 CC
2034 Removed 5 MW Kalaeloa Renewable Energy Park
2035 Installed 76 MWh Group 2 Hybrid Solar 15% Slope BESS Installed 151 MWh Group 3 Hybrid Solar 15% Slope BESS Installed 400 MW New Offshore Wind 2036 2037 Removed 171.5 MW Kahe 3-4 2038 Removed 69 MW Kawailoa Wind 2039 Removed 27.6 MW Waianae Solar
2040 Removed 24 MW Na Pua Makani Wind
Installed 157 167 MW 340 668 MWh Group 2 Hybrid Solar 15% Slope Installed 273 263 MW 755 1052 MWh Group 2 Hybrid Solar 30% Slope Installed 86 MW 88 344 MWh Group 3 Hybrid Solar 30% Slope 2041 Removed 109.6 MW Clearway Projects 2042 2043 2044 Removed 20 MW West Loch Solar
C-19 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Oʻahu: Preferred – Base
2045 Biodiesel Conversion on all firm units
Installed 20 MW Biomass Installed 45 MWh Group 2 Hybrid Solar 15% Slope BESS Installed 912 MW 1631 3648 MWh Group 2 Hybrid Solar 30% Slope Installed 108 MW 106 432 MWh Group 3 Hybrid Solar 30% Slope Installed 22 MW Recovered Wind Potential 2046 Removed 269.5 MW Kahe 5-6 2047 2048 2049
2050
Installed 80 MW Biomass Installed 5 MWh Group 2 Hybrid Solar 15% Slope BESS Installed 50 MW 161 200 MWh Group 2 Hybrid Solar 30% Slope Installed 449 311 MW 911 1244 MWh Group 3 Hybrid Solar 30% Slope Installed 101 MW Recovered Wind Potential
1.3.1.4 Land-Constrained Resource Plan
Shown below in Table C-17 is the Land-Constrained resource plan produced by RESOLVE.
Table C-17. Oʻahu – Land-Constrained resource plan.
Oʻahu: Land-Constrained
Year Planned New Additions 2022
2023
Installed 3 MW of CBRE Ph 1 PV Installed 12.5 MW West Oahu Installed 39 MW Mililani Solar Installed 36 MW Waiawa Solar Installed 185 MW Kapolei Energy Storage Installed 60 MW Load Build 3 Installed 60 MW Load Reduce 3
2024
Installed 2 MW of CBRE Ph 1 PV Installed 52 MW Hoohana Solar Installed 7 MW Mountain View Solar Installed 30 MW Waiawa Ph 2 Solar Installed 42 MW Kupono Solar Removed 93.5 MW Waiau 3-4
2025 Installed 15 MW Barbers Point Solar
2026 Removed 15 MW Load Build Removed 26 MW Load Reduce
2027
Installed 75 MW of CBRE Ph 2 RFP PV Installed 30 MW of CBRE Ph 2 Small PV Installed 450 MW RFP 3 Hybrid Solar Removed 108.1 MW Waiau 5-6
2028
2029 Installed 75 MW of CBRE Ph 2 RFP PV Installed 300 MW RFP 3 CT Removed 169.1 MW Waiau 7-8 Installed 29 MW 55 MWh Standalone BESS
2030 Installed 25 MW 47 MWh Standalone BESS 2031 Removed 30 MW Kahuku Wind 2032 Removed 1 MW Kapolei Sustainable Energy Park
C-20 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Oʻahu: Land-Constrained
2033
Removed 5 MW Kalaeloa Solar Two Removed 164.9 MW Kahe 1-2 Removed 60 MW Load Build 3 Removed 60 MW Load Reduce 3 Removed 208 MW KPLP Installed 208 MW RFP 3 CC
2034 Removed 5 MW Kalaeloa Renewable Energy Park
2035
Installed 140 MW 261 MWh Standalone BESS Installed 153 MW LM6000 2x1 CC Installed 30 MW Recovered Wind Potential Installed 400 MW New Offshore Wind 2036 2037 Removed 171.5 MW Kahe 3-4 2038 Removed 69 MW Kawailoa Wind 2039 Removed 27.6 MW Waianae Solar
2040 Removed 24 MW Na Pua Makani Wind Installed 12 MW 24 MWh Standalone BESS Installed 39 MW Recovered PV Potential Installed 93 MW Recovered Wind Potential 2041 Removed 109.6 MW Clearway Projects 2042 2043 2044 Removed 20 MW West Loch Solar
2045 Biodiesel Conversion on all firm units Installed 182 MW 800 MWh Standalone BESS Installed 1310 MW 2619 MWh Aggregated DER Installed 129 MW Recovered PV Potential 2046 Removed 269.5 MW Kahe 5-6 2047 2048 2049
2050 Installed 127 MW 920 MWh Standalone BESS Installed 947 MW 1894 MWh Aggregated DER
1.3.1.5 Land-Constrained Preferred Resource Plan
Shown below in Table C-18 is the Preferred Land-Constrained resource plan. This plan incorporates any adjustments based on the Resource Adequacy analysis and Transmission and System Security analysis.
Changes made to the RESOLVE resource plan are highlighted in red and green.
Table C-18. Oʻahu – Preferred – Land-Constrained resource plan.
Oʻahu: Preferred – Land-Constrained
Year Planned New Additions
2022
2023
Installed 3 MW of CBRE Ph 1 PV Installed 12.5 MW West Oahu Installed 39 MW Mililani Solar Installed 36 MW Waiawa Solar Installed 185 MW Kapolei Energy Storage Installed 60 MW Load Build 3 Installed 60 MW Load Reduce 3
2024
Installed 2 MW of CBRE Ph 1 PV Installed 52 MW Hoohana Solar Installed 7 MW Mountain View Solar Installed 30 MW Waiawa Ph 2 Solar
C-21 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Oʻahu: Preferred – Land-Constrained
Installed 42 MW Kupono Solar Removed 93.5 MW Waiau 3-4 2025 Installed 15 MW Barbers Point Solar
2026 Removed 15 MW Load Build Removed 26 MW Load Reduce
2027
Installed 75 MW of CBRE Ph 2 RFP PV Installed 30 MW of CBRE Ph 2 Small PV Installed 450 470 MW RFP 3 Hybrid Solar Removed 108.1 MW Waiau 5-6
2028
2029 Installed 75 MW of CBRE Ph 2 RFP PV Installed 300 MW RFP 3 CT Removed 169.1 MW Waiau 7-8 Installed 29 MW 55 116 MWh Standalone BESS
2030 Installed 25 MW 47 100 MWh Standalone BESS 2031 Removed 30 MW Kahuku Wind 2032 Removed 1 MW Kapolei Sustainable Energy Park
2033
Removed 5 MW Kalaeloa Solar Two Removed 164.9 MW Kahe 1-2 Removed 60 MW Load Build 3 Removed 60 MW Load Reduce 3 Removed 208 MW KPLP Installed 208 MW RFP 3 CC
2034 Removed 5 MW Kalaeloa Renewable Energy Park
2035
Installed 140 MW 261 560 MWh Standalone BESS Installed 153 MW LM6000 2x1 CC Installed 30 MW Recovered Wind Potential Installed 400 MW New Offshore Wind 2036 2037 Removed 171.5 MW Kahe 3-4 2038 Removed 69 MW Kawailoa Wind 2039 Removed 27.6 MW Waianae Solar
2040 Removed 24 MW Na Pua Makani Wind Installed 12 MW 24 48 MWh Standalone BESS Installed 39 MW Recovered PV Potential Installed 93 MW Recovered Wind Potential 2041 Removed 109.6 MW Clearway Projects 2042 2043 2044 Removed 20 MW West Loch Solar
2045 Biodiesel Conversion on all firm units Installed 182 MW 800 728 MWh Standalone BESS Installed 1310 MW 2619 MWh Aggregated DER Installed 129 MW Recovered PV Potential 2046 Removed 269.5 MW Kahe 5-6 2047 2048 2049
2050 Installed 127 MW 920 508 MWh Standalone BESS Installed 947 MW 1894 MWh Aggregated DER
C-22 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Hawaiʻi Island
1.3.2.1 Status Quo Resource Plan
Shown below in Table C-19 is the Status Quo resource plan, which assumed the Base forecast, commercial operations of Stage 1, Stage 2, and CBRE Phase 2 Tranche 1 projects; successful renegotiation of existing independent power producers; and continued operation of most existing
thermal units. The Status Quo plan excluded CBRE Phase 2 Tranche 2, Stage 3 RFP resources, and future
resources selected by RESOLVE.
Table C-19. Hawaiʻi Island – Status Quo resource plan. Hawaiʻi Island: Status Quo Year Planned New Additions 2022
2023
Installed 0.75 MW CBRE_PV_1 Installed 30 MW 120 MWh PV_Waikoloa_Hybrid_Solar
HRD Wind contract renewed Wailuku Hydro contract renewed
2024 Installed 30 MW 120 MWh PV_Hale_Kuawehi_Hybrid_Solar
2025 Removed 15.5 MW Puna_Steam
2026
Removed 3.17 MW Load_Build Removed 4 MW Load_Reduction Waiau capacity increased to 2 MW PGV capacity increased to 46 MW
2027
Installed 12.5 MW 50 MWh CBRE_PV_Phase_2_T1_RFP_Hybrid_Solar Installed 7.5 MW CBRE_PV_Phase_2_Small Removed 33.8 MW Hill5-6
2028 2029
2030 2031
2032 2033
2034 2035
2036
2037
2038
2039
2040
2041
2042
2043 2044
2045 Biodiesel Conversion on all firm units 2046
2047 2048
2049 2050
C-23 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.3.2.2 Base Resource Plan
Shown below in Table C-20 is the Base resource plan produced by RESOLVE.
Table C-20. Hawaiʻi Island – Base resource plan. Hawaiʻi Island: Base Year Planned New Additions 2022
2023
Installed 0.75 MW CBRE_PV_1 Installed 30 MW 120 MWh PV_Waikoloa_Hybrid_Solar HRD Wind contract renewed Wailuku Hydro contract renewed
2024 Installed 30 MW 120 MWh PV_Hale_Kuawehi_Hybrid_Solar
2025 Removed 15.5 MW Puna_Steam
2026
Removed 3.17 MW Load_Build Removed 4 MW Load_Reduction Waiau capacity increased to 2 MW PGV capacity increased to 46 MW
2027
Installed 12.5 MW 50 MWh CBRE_PV_Phase_2_T1_RFP_Hybrid_Solar Installed 7.5 MW CBRE_PV_Phase_2_Small Removed 33.8 MW Hill5-6
2028 Removed 7 MW Tawhiri-A_Wind Removed 13.5 MW Tawhiri-B_Wind
2029 Installed 12.5 MW 50 MWh CBRE_PV_Phase_2_T2_RFP_Hybrid_Solar Installed 7 MW 12 MWh Standalone BESS Installed 48 MW Wind_New_AggA
2030 Installed 140 MW 560 MWh PV_Stage_3_RFP_Hybrid_Solar
2031 Removed 57.6 MW HEP Combined Cycle
2032
2033
2034
2035 Installed 2 MW 5 MWh Standalone BESS Installed 3 MW 3 MWh Hybrid_Solar_AggA 2036
2037
2038
2039
2040
Installed 1 MW 1 MWh Standalone BESS Installed 20 MW 20 MWh Hybrid_Solar_AggA Installed 1 MW Wind_New_AggA 2041
2042
2043
2044
2045 Biodiesel Conversion on all firm units Installed 2 MW 4 MWh Standalone BESS Installed 30 MW Geothermal_New 2046
2047
2048
2049
2050 Installed 15 MW 15 MWh Hybrid_Solar_AggA Installed 2 MW Wind_New_AggA
C-24 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.3.2.3 Base Preferred Resource Plan
Shown below in Table C-21 is the Preferred Base resource plan. These plans incorporate any adjustments based on the Resource Adequacy analysis and Transmission and System Security analysis. Changes made to the RESOLVE resource plan are highlighted in red and green.
Table C-21. Hawaiʻi Island – Preferred – Base resource plan.
Hawaiʻi Island: Base Year Planned New Additions 2022
2023
Installed 0.75 MW CBRE_PV_1 Installed 30 MW 120 MWh PV_Waikoloa_Hybrid_Solar HRD Wind contract renewed Wailuku Hydro contract renewed
2024 Installed 30 MW 120 MWh PV_Hale_Kuawehi_Hybrid_Solar
2025 Removed 15.5 MW Puna_Steam
2026
Removed 3.17 MW Load_Build Removed 4 MW Load_Reduction Waiau capacity increased to 2 MW PGV capacity increased to 46 MW
2027
Installed 12.5 MW 50 MWh CBRE_PV_Phase_2_T1_RFP_Hybrid_Solar Installed 7.5 MW CBRE_PV_Phase_2_Small Removed 33.8 MW Hill5-6
2028 Removed 7 MW Tawhiri-A_Wind Removed 13.5 MW Tawhiri-B_Wind
2029 Installed 12.5 MW 50 MWh CBRE_PV_Phase_2_T2_RFP_Hybrid_Solar Installed 7 MW 12 28 MWh Standalone BESS Installed 48 MW Wind_New_AggA
2030 Installed 140 MW 560 MWh PV_Stage_3_RFP_Hybrid_Solar
2031 Removed 57.6 MW HEP Combined Cycle
2032
2033
2034
2035 Installed 2 MW 5 8 MWh Standalone BESS Installed 3 MW 3 12 MWh Hybrid_Solar_AggA 2036
2037
2038
2039
2040
Installed 1 MW 1 4 MWh Standalone BESS Installed 20 MW 20 80 MWh Hybrid_Solar_AggA Installed 1 MW Wind_New_AggA 2041
2042
2043
2044
2045 Biodiesel Conversion on all firm units Installed 2 MW 4 8 MWh Standalone BESS Installed 30 MW Geothermal_New 2046
C-25 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Hawaiʻi Island: Base 2047
2048
2049
2050 Installed 15 MW 15 60 MWh Hybrid_Solar_AggA Installed 2 MW Wind_New_AggA
C-26 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Maui
1.3.3.1 Status Quo Resource Plan
Shown below in Table C-22 is the Status Quo resource plan, which assumed the Base forecast, commercial operations of Stage 1, Stage 2, and CBRE Phase 2 Tranche 1 projects; successful
renegotiation of existing independent power producers; and continued operation of most existing
thermal units. The Status Quo plan excluded CBRE Phase 2 Tranche 2, Stage 3 RFP resources, and future resources selected by RESOLVE.
Table C-22. Maui – Status Quo resource plan.
Maui: Status Quo
Year Planned New Additions
2022
2023
Installed 6.07 MW FFR Grid Service Installed 7.15 MW Load Reduce Grid Service Installed 1.98 MW Load Build Grid Service Installed 40MW/ 160 MWH Waena BESS
2024 Installed 60 MW/ 240 MWH Kuihelani Solar + Battery
2025
Installed 40 MW/ 160MWh Kamaole Solar Installed 15 MW/ 60 MWH Paeahu Solar + Battery Removed 2.42 MW Load Reduce Grid Service Removed 0.1 MW Load Build Grid Service
2026 Removed 6.07 MW FFR Grid Service Removed 4.73 MW Load Reduce Grid Service Removed 1.88 MW Load Build Grid Service
2027
Removed 9.47 MW Kahului 1-2 Removed 23 MW Kahului 3-4 Removed 49.36 MW Maalaea 10-13 Installed 12.5 MW CBRE Phase 2 RFP Paired Installed 8.475 MW CBRE Phase 2 Small Projects
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
C-27 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Maui: Status Quo
2042
2043
2044
2045 Biodiesel Conversion on all firm units
2046 2047 2048
2049
2050
1.3.3.2 Base Resource Plan
Shown below in Table C-23 is the Base resource plan produced by RESOLVE.
Table C-23. Maui – Base resource plan.
Maui: Base
Year Planned New Additions
2022
2023
Installed 6.07 MW FFR Grid Service Installed 7.15 MW Load Reduce Grid Service Installed 1.98 MW Load Build Grid Service Installed 40MW/ 160 MWH Waena BESS
2024
Installed 60 MW/ 240 MWH Kuihelani Solar + Battery Installed 20 MW/ 80 MWH Kahana Solar + Battery
2025
Installed 40 MW/ 160MWh Kamaole Solar Installed 15 MW/ 60 MWH Paeahu Solar + Battery Removed 2.42 MW Load Reduce Grid Service Removed 0.1 MW Load Build Grid Service
2026 Removed 6.07 MW FFR Grid Service Removed 4.73 MW Load Reduce Grid Service Removed 1.88 MW Load Build Grid Service
2027
Removed 30 MW Kaheawa Wind Power 1 Removed 9.47 MW Kahului 1-2 Removed 23 MW Kahului 3-4 Removed 49.36 MW Maalaea 10-13 Installed 36 MW ICE S3 RFP Installed 171 MW Hybrid Solar with 764 MWh Battery S3 RFP Installed 12.5 MW CBRE Phase 2 RFP Paired Installed 8.475 MW CBRE Phase 2 Small Projects
2028
2029 Installed 12.5 MW CBRE Phase 2 RFP Paired Installed 5 MW Onshore Wind (AggC)
2030 Removed 33 MW Maalaea 4-9 Removed 7.5 MW Maalaea 1-3 Installed 7.6 MW Onshore Wind (AggC)
2031 2032
2033 Removed 21 MW Kaheawa Wind Power 2 Removed 21 MW Auwahi Wind
C-28 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Maui: Base
2034
2035 Installed 53 MW Onshore Wind (AggC) Installed 37 MW 37 MWh Hybrid Solar(AggC) 2036 2037 2038 2039
2040 Removed 5.7 MW SMRR PV Installed 18 MW Onshore Wind (AggC) Installed 43 MW 43 MWh Hybrid Solar(AggC) 2041 2042 2043 2044
2045 Biodiesel Conversion on all firm units Installed 15 MW 15 MWh Hybrid Solar(AggB) Installed 66 MW 100 MWh Hybrid Solar(AggC) Installed 41 MW Onshore Wind (AggC) 2046 2047 2048 2049
2050 Installed 57 MW 134 MWh Hybrid Solar(AggB) Installed 57 MW 72 MWh Hybrid Solar(AggC)
1.3.3.3 Base Preferred Resource Plan
Shown below in Table C-24 is the Preferred Base resource plan. These plans incorporate any adjustments based on the Resource Adequacy analysis and Transmission and System Security analysis. Changes made to the RESOLVE resource plan are highlighted in red and green.
Table C-24. Maui – Preferred – Base resource plan.
Maui: Base
Year Planned New Additions
2022
2023
Installed 6.07 MW FFR Grid Service Installed 7.15 MW Load Reduce Grid Service Installed 1.98 MW Load Build Grid Service Installed 40MW/ 160 MWH Waena BESS
2024
Installed 60 MW/ 240 MWH Kuihelani Solar + Battery Installed 20 MW/ 80 MWH Kahana Solar + Battery
2025
Installed 40 MW/ 160MWh Kamaole Solar Installed 15 MW/ 60 MWH Paeahu Solar + Battery Removed 2.42 MW Load Reduce Grid Service Removed 0.1 MW Load Build Grid Service
2026 Removed 6.07 MW FFR Grid Service Removed 4.73 MW Load Reduce Grid Service Removed 1.88 MW Load Build Grid Service
C-29 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Maui: Base
2027
Removed 30 MW Kaheawa Wind Power 1 Removed 9.47 MW Kahului 1-2 Removed 23 MW Kahului 3-4 Removed 49.36 MW Maalaea 10-13 Installed 36 16.28 MW ICE S3 RFP Installed 171191 MW Hybrid Solar with 764 MWh Battery S3 RFP Installed 12.5 MW CBRE Phase 2 RFP Paired Installed 8.475 MW CBRE Phase 2 Small Projects
2028
2029 Installed 12.5 MW CBRE Phase 2 RFP Paired Installed 5 MW Onshore Wind (AggC)
2030 Removed 33 MW Maalaea 4-9 Removed 7.5 MW Maalaea 1-3 Installed 7.6 MW Onshore Wind (AggC)
2031 2032
2033 Removed 21 MW Kaheawa Wind Power 2 Removed 21 MW Auwahi Wind
2034
2035 Installed 53 MW Onshore Wind (AggC) Installed 37 MW 37 148 MWh Hybrid Solar(AggC) 2036 2037 2038 2039
2040 Removed 5.7 MW SMRR PV Installed 18 MW Onshore Wind (AggC) Installed 43 MW 43 172 MWh Hybrid Solar(AggC) 2041 2042 2043 2044
2045 Biodiesel Conversion on all firm units
Installed 15 8 MW 15 32 MWh Hybrid Solar(AggB) Installed 66 MW 100 264 MWh Hybrid Solar(AggC) Installed 41 MW Onshore Wind (AggC) 2046 2047 2048 2049
2050 Installed 57 MW 134 228 MWh Hybrid Solar(AggB) Installed 57 MW 72 228 MWh Hybrid Solar(AggC)
C-30 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Molokaʻi
1.3.4.1 Status Quo Resource Plan
Shown below in Table C-25 is the Status Quo resource plan, which assumed the Base forecast, commercial operations of Stage 1, Stage 2, and CBRE Phase 2 Tranche 1 projects; successful renegotiation of existing independent power producers; and continued operation of most existing
thermal units. The Status Quo plan excluded CBRE Phase 2 Tranche 2, Stage 3 RFP resources, and future
resources selected by RESOLVE.
Table C-25. Molokaʻi – Status Quo resource plan.
Moloka‘i: Status Quo
Year Planned New Additions 2022
2023 Install 0.25 MW Standalone PV (CBRE Phase 1)
2024 2025 2026
2027
Install 2.75 MW 11 MWh Hybrid Solar Storage Install 2.75 MW Hybrid Solar (CBRE Phase 2)
2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Biodiesel Conversion on all firm units 2046 2047 2048 2049 2050
C-31 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.3.4.2 Base Resource Plan
Shown below in Table C-26 is the Base resource plan produced by RESOLVE.
Table C-26. Molokaʻi – Base resource plan.
Moloka‘i: Base
Year Planned New Additions 2022 2023 Install 0.25 MW Standalone PV (CBRE Phase 1) 2024 2025 2026
2027 Install 2.75 MW 11 MWh Hybrid Solar Storage Install 2.75 MW Hybrid Solar(CBRE Phase 2)
2028
2029 Installed 0.4 MW 0.7 MWh Standalone BESS Installed 3 MW 3 MWh Hybrid Solar
2030 Installed 0.1 MW 0.3 MWh Standalone BESS Installed 8.5 MW 29.7 MWh Hybrid Solar 2031 2032 2033 2034
2035 Installed 0.1 MW 0.1 MWh Standalone BESS Installed 2.3 MW 1.9 MWh Hybrid Solar 2036 2037 2038 2039
2040 Installed 0 MW 0.1 MWh Standalone BESS Installed 1.1 MW 2.8 MWh Hybrid Solar 2041 2042 2043 2044
2045 Biodiesel Conversion on all firm units Installed 0.1 MW 0.2 MWh Standalone BESS Installed 2.6 MW 6.9 MWh Hybrid Solar 2046 2047 2048 2049
2050 Installed 0 MW 0.1 MWh Standalone BESS Installed 1.2 MW 2.9 MWh Hybrid Solar
1.3.4.3 Base Preferred Resource Plan
Shown below in Table C-27 is the Preferred Base resource plan. The original plan produced by RESOLVE was modified to match market conditions in which most batteries had a minimum duration of 4 hours. The MWh only additions of standalone battery in 2040 and 2050 were removed since more MWH’s
were added when the batteries were modified to four hour duration. Changes made to the RESOLVE
resource plan are highlighted in red and green.
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APPENDIX C – DATA TABLES
Table C-27. Molokaʻi – Preferred – Base resource plan.
Moloka‘i: Base
Year Planned New Additions 2022
2023 Install 0.25 MW Standalone PV (CBRE Phase 1)
2024 2025 2026
2027
Install 2.75 MW 11 MWh Hybrid Solar Storage Install 2.75 MW Hybrid Solar (CBRE Phase 2)
2028
2029 Installed 0.4 MW 0.7 1.6 MWh Standalone BESS Installed 3 MW 3 12 MWh Hybrid Solar
2030 Installed 0.1 MW 0.3 0.4 MWh Standalone BESS Installed 8.5 MW 29.7 34 MWh Hybrid Solar 2031 2032 2033 2034
2035 Installed 0.1 MW 0.1 0.4 MWh Standalone BESS Installed 2.3 MW 1.9 9.2 MWh Hybrid Solar 2036 2037 2038 2039
2040 Installed 0 MW 0.1 MWh Standalone BESS Installed 1.1 MW 2.8 4.4 MWh Hybrid Solar 2041 2042 2043 2044
2045 Biodiesel Conversion on all firm units Installed 0.1 MW 0.2 0.4 MWh Standalone BESS Installed 2.6 MW 6.9 10.4 MWh Hybrid Solar 2046 2047 2048 2049
2050 Installed 0 MW 0.1 MWh Standalone BESS Installed 1.2 MW 2.9 4.8 MWh Hybrid Solar
C-33 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Lānaʻi
1.3.5.1 Status Quo Resource Plan
Shown below in Table C-28 is the Status Quo resource plan, which assumed the Base forecast, commercial operations of Stage 1, Stage 2, and CBRE Phase 2 Tranche 1 projects; successful renegotiation of existing independent power producers; and continued operation of most existing
thermal units. The Status Quo plan excluded CBRE Phase 2 Tranche 2, Stage 3 RFP resources, and future
resources selected by RESOLVE.
Table C-28. Lānaʻi – Status Quo resource plan.
Lānaʻi: Status Quo
Year Planned New Additions 2022 2023 2024 2025 2026
2027 Install 15.8 MW 63.2 MWh Hybrid Solar Storage Install 15.8 MW 63.2 MWh Hybrid Solar (CBRE RFP)
2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Biodiesel Conversion on all firm units 2046 2047 2048 2049 2050
C-34 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.3.5.2 Base Resource Plan
Shown below in Table C-29 is the Base resource plan produced by RESOLVE.
Table C-29. Lānaʻi – Preferred – Base resource plan.
Lānaʻi: Base
Year Planned New Additions 2022 2023 2024 2025 2026
2027 Install 15.8 MW 63.2 MWh Hybrid Solar Storage Install 15.8 MW 63.2 MWh Hybrid Solar (CBRE RFP)
2028
2029 Installed 0.6 MW 1.1 MWh Standalone BESS Installed 0.3 MW 0.3 MWh Hybrid Solar 2030 Installed 4.9 MW 4.9 MWh Hybrid Solar 2031 2032 2033 2034
2035 Installed 0.3 MW 0.3 MWh Hybrid Solar 2036 2037 2038 2039
2040 Installed 1 MW 1 MWh Hybrid Solar 2041 2042 2043 2044
2045 Biodiesel Conversion on all firm units Installed 0.2 MW 0.3 MWh Standalone BESS Installed 1.5 MW 1.5 MWh Hybrid Solar 2046 2047 2048 2049
2050 Installed 0.1 MW 0.1 MWh Standalone BESS Installed 0.9 MW 0.9 MWh Hybrid Solar
C-35 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.3.5.3 Base Preferred Resource Plan
Shown below in Table C-30 is the Preferred Base resource plan. The original plan produced by RESOLVE
was modified to match market conditions in which batteries had a minimum duration of 4 hours.
Changes made to the RESOLVE resource plan are highlighted in red and green.
Table C-30. Lānaʻi – Preferred – Base resource plan.
Lānaʻi: Base
Year Planned New Additions 2022 2023 2024 2025 2026
2027 Install 15.8 MW 63.2 MWh Hybrid Solar Storage Install 15.8 MW 63.2 MWh Hybrid Solar (CBRE RFP)
2028
2029 Installed 0.6 MW 1.1 2.4 MWh Standalone BESS Installed 0.3 MW 0.3 1.2 MWh Hybrid Solar 2030 Installed 4.9 MW 4.9 19.6 MWh Hybrid Solar 2031 2032 2033 2034
2035 Installed 0.3 MW 0.3 1.2 MWh Hybrid Solar 2036 2037 2038 2039
2040 Installed 1 MW 1 4 MWh Hybrid Solar 2041 2042 2043 2044
2045 Biodiesel Conversion on all firm units Installed 0.2 MW 0.3 0.8 MWh Standalone BESS Installed 1.5 MW 1.5 6 MWh Hybrid Solar 2046 2047 2048 2049
2050 Installed 0.1 MW 0.1 0.4 MWh Standalone BESS Installed 0.9 MW 0.9 3.6 MWh Hybrid Solar
C-36 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Resource Adequacy
This section provides additional details to the resource adeqaucy analysis provided in Section 8 and
Section 12 of the Integrated Grid Plan Report. We provide the relationship between the 2030 LOLE and firm capacity or hybrid solar capacity for each island under the base forecast. This section also provides the relationship between the 2035 LOLE and firm capacity or hybrid solar capacity for each island under the high load forecast. For forecasts where additional firm capacity is needed to achieve the reliability
target, resources are presented in terms of the amount of firm capacity added to the system. For
forecasts where existing firm capacity is sufficient to meet the reliability target, resources are presented in terms of the cumulative firm capacity in the system.
Oʻahu
1.4.1.1 2030 Outlook
Variable Resource Curve Fit
Shown below in Figure C-1 is the relationship between the LOLE in 2030 and the amount of future hybrid solar capacity that is added after Stage 3.
Figure C-1. Oʻahu – Loss of Load vs Future Hybrid Solar Capacity. Base Load, 2030.
C-37 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-2 is the relationship between the LOLE in 2030 and the amount of future firm
capacity that is added after Stage 3.
Figure C-2. Oʻahu – Loss of Load vs Future Renewable Firm Capacity. Base Load, 2030.
1.4.1.2 2035 Outlook
Variable Resource Curve Fit
Shown below in Figure C-3 is the relationship between the LOLE in 2035 and the amount of future hybrid solar capacity that is added after Stage 3, assuming the high-load forecast.
Figure C-3. Oʻahu – Loss of Load vs Future Hybrid Solar Capacity. High Load, 2035.
C-38 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-4 is the relationship between the LOLE in 2035 and the amount of future firm
capacity that is added after Stage 3, assuming the high-load forecast.
Figure C-4. Oʻahu – Loss of Load vs Future Renewable Firm Capacity. High Load, 2035.
Hawaiʻi Island
1.4.2.1 2030 Outlook
Variable Resource Curve Fit
Shown below in Figure C-5 is the relationship between the LOLE in 2030 and the amount of future
hybrid solar capacity that is added in Stage 3.
Figure C-5. Hawaiʻi Island – Loss of Load vs Stage 3 Hybrid Solar Capacity. Base Load, 2030.
C-39 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-6 is the relationship between the LOLE in 2030 and the amount of firm
capacity remaining on the system after Stage 3.
Figure C-6. Hawaiʻi Island – Loss of Load vs Cumulative Firm Capacity. Base Load, 2030.
1.4.2.2 2035 Outlook
Variable Resource Curve Fit
Shown below in Figure C-7 is the relationship between the LOLE in 2035 and the amount of future hybrid solar capacity that is added after Stage 3, assuming the high-load forecast.
Figure C-7. Hawaiʻi Island – Loss of Load vs Future Hybrid Solar Capacity. High Load, 2035.
C-40 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-8 is the relationship between the LOLE in 2035 and the amount of future firm
capacity that is added after Stage 3, assuming the high-load forecast.
Figure C-8. Hawaiʻi Island – Loss of Load vs Future Renewable Firm Capacity. High Load, 2035.
Maui
1.4.3.1 2030 Outlook
Variable Resource Curve Fit
Shown below in Figure C-9 is the relationship between the LOLE in 2030 and the amount of future hybrid solar capacity that is added in Stage 3.
Figure C-9. Maui – Loss of Load vs Future Hybrid Solar Solar Capacity. Base Load, 2030.
C-41 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-10 is the relationship between the LOLE in 2030 and the amount of future firm
capacity that is added in Stage 3.
Figure C-10. Maui – Loss of Load vs Future Renewable Firm Capacity. Base Load, 2030.
1.4.3.2 2035 Outlook
Variable Resource Curve Fit
Shown below in Figure C-11 is the relationship between the LOLE in 2035 and the amount of future
hybrid solar capacity that is added in Stage 3, assuming the high-load forecast.
Figure C-11. Maui – Loss of Load vs Future Hybrid Solar Capacity. High Load, 2035.
C-42 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-12 is the relationship between the LOLE in 2035 and the amount of future firm
capacity that is added after Stage 3, assuming the high-load forecast.
Figure C-12. Maui – Loss of Load vs Future Renewable Firm Capacity. High Load, 2035.
Molokaʻi
1.4.4.1 2030 Outlook
Variable Resource Curve Fit
Shown below in Figure C-13 is the relationship between the LOLE in 2030 and the amount of future
hybrid solar capacity.
Figure C-13. Molokaʻi – Loss of Load vs New Hybrid Solar Capacity. Base Load, 2030.
C-43 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-14 is the relationship between the LOLE in 2030 and the amount of firm
capacity remaining on the system.
Figure C-14. Molokaʻi – Loss of Load vs Cumulative Firm Capacity. Base Load, 2030.
1.4.4.2 2035 Outlook
Variable Resource Curve Fit
Shown below in Figure C-15 is the relationship between the LOLE in 2035 and the amount of future
hybrid solar capacity that is added, assuming the high-load forecast.
Figure C-15. Molokaʻi – Loss of Load vs Future Hybrid Solar Capacity. High Load, 2035.
C-44 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-16 is the relationship between the LOLE in 2035 and the amount of firm
capacity remaining on the system, assuming the high-load forecast.
Figure C-16. Molokaʻi – Loss of Load vs Cumulative Firm Capacity. High Load, 2035.
Lānaʻi
1.4.5.1 2030 Outlook
Variable Resource Curve Fit
Shown below in Figure C-17 is the relationship between the LOLE in 2030 and the amount of future
hybrid solar capacity that is added.
Figure C-17. Lānaʻi – Loss of Load vs New Hybrid Solar Capacity. Base Load, 2030.
C-45 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-18 is the relationship between the LOLE in 2030 and the amount of firm
capacity remaining on the system.
Figure C-18. Lānaʻi – Loss of Load vs Cumulative Firm Capacity. Base Load, 2030.
1.4.5.2 2035 Outlook
Variable Resource Curve Fit
Shown below in Figure C-19 is the relationship between the LOLE in 2035 and the amount of future
hybrid solar capacity that is added, assuming the high-load forecast.
Figure C-19. Lānaʻi – Loss of Load vs Future Hybrid Solar Capacity. High Load, 2035.
C-46 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
Firm Resource Curve Fit
Shown below in Figure C-20 is the relationship between the LOLE in 2035 and the amount of firm
capacity remaining on the system, assuming the high-load forecast.
Figure C-20. Lānaʻi – Loss of Load vs Cumulative Firm Capacity. High Load, 2035.
Operational Statistics
The transition to 100% renewables will necessitate a change in how the thermal generators on our system operate. Scenarios with more renewable resources will use thermal generators less often. This is shown in the operational statistics provided in this section. The grid operations statistics shown in this section use the resource plans that were modeled before including the transmission constraints
identified in the transmission needs analysis.
Oʻahu
1.5.1.1 Grid Operations – Status Quo
Shown below in Table C-31 and Table C-32 are the estimated number of starts and capacity factor,
respectively, for thermal generators in 2030 and 2035 with the Status Quo resource plan.
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APPENDIX C – DATA TABLES
Table C-31. Oʻahu – Number of Starts for existing utility-owned thermal generators under the Status Quo resource plan.
Number of Starts 2030 2035 Kahe 1 42 35 Kahe 2 28 41 Kahe 3 38 29 Kahe 4 25 26 Kahe 5 3 4 Kahe 6 3 3 Waiau 3 Deactivated Deactivated Waiau 4 Deactivated Deactivated Waiau 5 65 71 Waiau 6 74 68 Waiau 7 29 31 Waiau 8 29 28 Waiau 9 218 223 Waiau 10 191 201 CIP CT 224 298 Airport DSG 68 112 Schofield (6 units) 1693 1810
Table C-32. Oʻahu – Capacity Factor for existing utility-owned thermal generators under the Status Quo resource plan.
Capacity Factor (%) 2030 2035 Kahe 1 62 62 Kahe 2 61 47 Kahe 3 38 57 Kahe 4 66 66 Kahe 5 7 14 Kahe 6 7 10 Waiau 3 Deactivated Deactivated Waiau 4 Deactivated Deactivated Waiau 5 42 43 Waiau 6 35 35 Waiau 7 66 65 Waiau 8 65 66 Waiau 9 24 25 Waiau 10 15 19 CIP CT 6 11 Airport DSG 7 10 Schofield (6 units) 15 21
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APPENDIX C – DATA TABLES
1.5.1.2 Grid Operations – Base
Shown below in Table C-33 and Table C-34 are the estimated number of starts and capacity factor,
respectively, for thermal generators in 2030 and 2035 with the Base resource plan.
Table C-33. Oʻahu – Number of Starts for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Number of Starts 2030 2035 Kahe 1 72 Deactivated Kahe 2 73 Deactivated Kahe 3 49 59 Kahe 4 73 57 Kahe 5 2 3 Kahe 6 2 3 Waiau 3 Deactivated Deactivated Waiau 4 Deactivated Deactivated Waiau 5 Deactivated Deactivated Waiau 6 Deactivated Deactivated Waiau 7 Deactivated Deactivated Waiau 8 Deactivated Deactivated Waiau 9 25 52 Waiau 10 12 38 CIP CT 23 21 Airport DSG 4 2 Schofield (6 units) 220 412
300MW CT – RFP3 Firm (6 units) 9 13
208MW CC – RFP3 Firm N/A 26
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APPENDIX C – DATA TABLES
Table C-34. Oʻahu – Capacity Factor for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Capacity Factor (%) 2030 2035 Kahe 1 13 Deactivated Kahe 2 14 Deactivated Kahe 3 7 17 Kahe 4 19 21 Kahe 5 0 1 Kahe 6 1 2 Waiau 3 Deactivated Deactivated Waiau 4 Deactivated Deactivated Waiau 5 Deactivated Deactivated Waiau 6 Deactivated Deactivated Waiau 7 Deactivated Deactivated Waiau 8 Deactivated Deactivated Waiau 9 2 5 Waiau 10 1 3 CIP CT 0 0 Airport DSG 0 0 Schofield (6 units) 3 7
300MW CT – RFP3 Firm (6 units) 0 0
208MW CC – RFP3 Firm N/A 2
C-50 Integrated Grid Planning Report
APPENDIX C – DATA TABLES
1.5.1.3 Grid Operations – Land-Constrained
Shown below in Table C-35 and Table C-36 are the estimated number of starts and capacity factor,
respectively, for thermal generators in 2030 and 2035 with the Land-Constrained resource plan.
Table C-35. Oʻahu – Number of Starts for existing utility-owned thermal generators and future thermal generators under the Land-Constrained resource plan.
Number of Starts 2030 2035 Kahe 1 57 Deactivated Kahe 2 33 Deactivated Kahe 3 51 57 Kahe 4 42 66 Kahe 5 4 4 Kahe 6 4 4 Waiau 3 Deactivated Deactivated Waiau 4 Deactivated Deactivated Waiau 5 Deactivated Deactivated Waiau 6 Deactivated Deactivated Waiau 7 Deactivated Deactivated Waiau 8 Deactivated Deactivated Waiau 9 167 101 Waiau 10 168 87 Schofield (6 units) 1,274 586
CIP CT 180 85 Airport DSG 29 21 300MW CT – RFP3 Firm (6 units) 471 34
208MW CC – RFP3 Firm N/A 89 151MW CC N/A 161
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APPENDIX C – DATA TABLES
Table C-36. Oʻahu – Capacity Factor for existing utility-owned thermal generators and future thermal generators under the Land-Constrained resource plan.
Capacity Factor 2030 2035 Kahe 1 62 Deactivated Kahe 2 63 Deactivated Kahe 3 38 31 Kahe 4 68 43 Kahe 5 12 7 Kahe 6 12 4 Waiau 3 Deactivated Deactivated Waiau 4 Deactivated Deactivated Waiau 5 Deactivated Deactivated Waiau 6 Deactivated Deactivated Waiau 7 Deactivated Deactivated Waiau 8 Deactivated Deactivated Waiau 9 25 12 Waiau 10 18 9 Schofield (6 units) 28 16
CIP CT 4 1 Airport DSG 0 0 300MW CT – RFP3 Firm (6 units) 4 0
208MW CC – RFP3 Firm N/A 4 151MW CC N/A 77
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APPENDIX C – DATA TABLES
Hawaiʻi Island
1.5.2.1 Grid Operations – Status Quo
Shown below in Table C-37 and Table C-38 are the estimated number of starts and capacity factor, respectively, for thermal generators in 2030 and 2035 with the Status Quo resource plan.
Table C-37. Hawaiʻi Island – Number of Starts for existing utility-owned thermal generators under the Status Quo
resource plan.
Number of Starts 2030 2035 Hill5 Deactivated Deactivated Hill6 Deactivated Deactivated Kanoelehua CT1 6 5 Kanoelehua D11 11 4 Kanoelehua D15 11 7 Kanoelehua D16 4 3 Kanoelehua D17 1 3 Kapua D27 184 157 Keahole CT2 26 27 Keahole D21 2 3 Keahole D22 0 4 Keahole D23 4 4 Ouli D25 120 124 Panaewa D24 306 272 Puna CT3 168 157 Puna Steam Deactivated Deactivated Punaluu D26 213 199 Waimea D12 31 18 Waimea D13 14 10 Waimea D14 50 43 Keahole CT4 346 376 Keahole CT5 380 367 Keahole ST7 303 327
Table C-38. Hawaiʻi Island – Capacity Factor for existing utility-owned thermal generators under the Status Quo resource plan.
Capacity Factor (%) 2030 2035
Hill5 Deactivated Deactivated
Hill6 Deactivated Deactivated
Kanoelehua CT1 0 0
Kanoelehua D11 0 0
Kanoelehua D15 0 0
Kanoelehua D16 0 0
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APPENDIX C – DATA TABLES
Capacity Factor (%) 2030 2035
Kanoelehua D17 0 0
Kapua D27 5 4
Keahole CT2 0 0
Keahole D21 0 0
Keahole D22 0 0
Keahole D23 0 0
Ouli D25 3 3
Panaewa D24 8 7
Puna CT3 2 1
Puna Steam Standby status Standby status
Punaluu D26 5 5
Waimea D12 0 0
Waimea D13 0 0
Waimea D14 1 1
Keahole CT4 51 50
Keahole CT5 42 44
Keahole ST7 43 44
1.5.2.2 Grid Operations – Base
Shown below in Table C-39 and Table C-40 are the estimated number of starts and capacity factor, respectively, for thermal generators in 2030 and 2035 with the Base resource plan.
Table C-39. Hawaiʻi Island – Number of Starts for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Number of Starts 2030 2035
Hill5 Deactivated Deactivated
Hill6 Deactivated Deactivated
Kanoelehua CT1 0 2
Kanoelehua D11 0 1
Kanoelehua D15 0 0
Kanoelehua D16 0 0
Kanoelehua D17 0 0
Kapua D27 1 4
Keahole CT2 1 1
Keahole D21 0 0
Keahole D22 0 0
Keahole D23 0 0
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APPENDIX C – DATA TABLES
Ouli D25 1 4
Panaewa D24 53 69
Puna CT3 23 34
Puna Steam Standby status Standby status
Punaluu D26 11 13
Waimea D12 0 0
Waimea D13 0 1
Waimea D14 0 0
Keahole CT4 92 98
Keahole CT5 103 101
Keahole ST7 114 107
Table C-40. Hawaiʻi Island – Capacity Factor for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Capacity Factor (%) 2030 2035
Hill5 Deactivated Deactivated
Hill6 Deactivated Deactivated
Kanoelehua CT1 0 0
Kanoelehua D11 0 0
Kanoelehua D15 0 0
Kanoelehua D16 0 0
Kanoelehua D17 0 0
Kapua D27 0 0
Keahole CT2 0 0
Keahole D21 0 0
Keahole D22 0 0
Keahole D23 0 0
Ouli D25 0 0
Panaewa D24 1 2
Puna CT3 0 0
Puna Steam Standby status Standby status
Punaluu D26 0 0
Waimea D12 0 0
Waimea D13 0 0
Waimea D14 0 0
Keahole CT4 4 5
Keahole CT5 4 4
Keahole ST7 3 4
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APPENDIX C – DATA TABLES
Maui
1.5.3.1 Grid Operations – Status Quo
Table C-41 and Table C-42 are the estimated number of starts and capacity factor, respectively, for thermal generators in 2030 and 2035 with the Status Quo resource plan.
Table C-41. Maui – Number of Starts for existing utility-owned thermal generators under the Status Quo resource plan.
Number of Starts 2030 2035
Hana 0 0
Kahului1 Deactivated Deactivated
Kahului2 Deactivated Deactivated
Kahului3 Deactivated Deactivated
Kahului4 Deactivated Deactivated
Maalaea01 30 38
Maalaea02 2 9
Maalaea03 16 22
Maalaea04 85 141
Maalaea05 50 69
Maalaea06 23 36
Maalaea07 16 38
Maalaea08 35 50
Maalaea09 66 120
Maalaea10 Deactivated Deactivated
Maalaea11 Deactivated Deactivated
Maalaea12 Deactivated Deactivated
Maalaea13 Deactivated Deactivated
Maalaea14cc 304 289
Maalaea15cc 0 0
Maalaea16cc 232 269
Maalaea17cc 154 157
Maalaea18cc 47 45
Maalaea19cc 103 126
MaalaeaX1 6 15
MaalaeaX2 4 8
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APPENDIX C – DATA TABLES
Table C-42. Maui – Capacity Factor for existing utility-owned thermal generators under the Status Quo resource plan.
Capacity Factor (%) 2030 2035
Hana 1 1
Kahului1 Deactivated Deactivated
Kahului2 Deactivated Deactivated
Kahului3 Deactivated Deactivated
Kahului4 Deactivated Deactivated
Maalaea01 1 2
Maalaea02 0 1
Maalaea03 1 1
Maalaea04 3 6
Maalaea05 2 2
Maalaea06 1 1
Maalaea07 0 1
Maalaea08 2 2
Maalaea09 4 7
Maalaea10 Deactivated Deactivated
Maalaea11 Deactivated Deactivated
Maalaea12 Deactivated Deactivated
Maalaea13 Deactivated Deactivated
Maalaea14cc 43 53
Maalaea15cc 0 0
Maalaea16cc 28 37
Maalaea17cc 46 51
Maalaea18cc 36 39
Maalaea19cc 37 45
MaalaeaX1 0 1
MaalaeaX2 0 0
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APPENDIX C – DATA TABLES
1.5.3.2 Grid Operations – Base
Shown below in Table C-43 and Table C-44 are the estimated number of starts and capacity factor, respectively, for thermal generators in 2030 and 2035 with the Base resource plan.
Table C-43. Maui – Number of Starts for existing utility-owned thermal generators and future thermal generators
under the Base resource plan.
Number of Starts 2030 2035
9 MW RICE 1 311 249
9 MW RICE 2 305 253
Hana 0 0
Kahului1 Deactivated Deactivated
Kahului2 Deactivated Deactivated
Kahului3 Deactivated Deactivated
Kahului4 Deactivated Deactivated
Maalaea01 Deactivated Deactivated
Maalaea02 Deactivated Deactivated
Maalaea03 Deactivated Deactivated
Maalaea04 Deactivated Deactivated
Maalaea05 Deactivated Deactivated
Maalaea06 Deactivated Deactivated
Maalaea07 Deactivated Deactivated
Maalaea08 Deactivated Deactivated
Maalaea09 Deactivated Deactivated
Maalaea10 Deactivated Deactivated
Maalaea11 Deactivated Deactivated
Maalaea12 Deactivated Deactivated
Maalaea13 Deactivated Deactivated
Maalaea14cc 164 122
Maalaea15cc 0 0
Maalaea16cc 126 83
Maalaea17cc 74 27
Maalaea18cc 0 1
Maalaea19cc 15 7
MaalaeaX1 26 27
MaalaeaX2 23 27
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APPENDIX C – DATA TABLES
Table C-44. Maui – Capacity Factor for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Capacity Factor (%) 2030 2035
9 MW RICE 1 26 21
9 MW RICE 2 25 21
Hana 0 1
Kahului1 Deactivated Deactivated
Kahului2 Deactivated Deactivated
Kahului3 Deactivated Deactivated
Kahului4 Deactivated Deactivated
Maalaea01 Deactivated Deactivated
Maalaea02 Deactivated Deactivated
Maalaea03 Deactivated Deactivated
Maalaea04 Deactivated Deactivated
Maalaea05 Deactivated Deactivated
Maalaea06 Deactivated Deactivated
Maalaea07 Deactivated Deactivated
Maalaea08 Deactivated Deactivated
Maalaea09 Deactivated Deactivated
Maalaea10 Deactivated Deactivated
Maalaea11 Deactivated Deactivated
Maalaea12 Deactivated Deactivated
Maalaea13 Deactivated Deactivated
Maalaea14cc 20 12
Maalaea15cc 0 0
Maalaea16cc 18 9
Maalaea17cc 6 2
Maalaea18cc 0 0
Maalaea19cc 1 1
MaalaeaX1 11 13
MaalaeaX2 10 11
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APPENDIX C – DATA TABLES
Molokaʻi
1.5.4.1 Grid Operations – Status Quo
Shown below in Table C-45 and Table C-46 are the estimated number of starts and capacity factor, respectively, for thermal generators in 2030 and 2035 with the Status Quo resource plan.
Table C-45. Molokaʻi – Number of Starts for existing utility-owned thermal generators under the Status Quo resource
plan.
Number of Starts 2030 2035
Palaau 1 12 1
Palaau 2 91 22
Palaau 3 6 0
Palaau 4 9 4
Palaau 5 13 6
Palaau 6 568 417
Palaau 7 364 262
Palaau 8 510 466
Palaau 9 1,029 920
Palaau GT 3 1
Table C-46. Molokaʻi – Capacity Factor for existing utility-owned thermal generators under the Status Quo resource plan.
Capacity Factor (%) 2030 2035
Palaau 1 0 0
Palaau 2 1 0
Palaau 3 0 0
Palaau 4 0 0
Palaau 5 0 0
Palaau 6 11 9
Palaau 7 4 3
Palaau 8 64 65
Palaau 9 46 48
Palaau GT 0 0
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APPENDIX C – DATA TABLES
1.5.4.2 Grid Operations – Base
Shown below in Table C-47 and Table C-48 are the estimated number of starts and capacity factor,
respectively, for thermal generators in 2030 and 2035 with the Base resource plan.
Table C-47. Molokaʻi – Number of Starts for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Number of Starts 2030 2035
Palaau 1 0 0
Palaau 2 1 8
Palaau 3 0 0
Palaau 4 0 0
Palaau 5 4 2
Palaau 6 68 53
Palaau 7 6 2
Palaau 8 547 445
Palaau 9 126 59
Palaau GT 0 0
Table C-48. Molokaʻi – Capacity Factor for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Capacity Factor (%) 2030 2035
Palaau 1 0 0
Palaau 2 0 0
Palaau 3 0 0
Palaau 4 0 0
Palaau 5 0 0
Palaau 6 0 0
Palaau 7 0 0
Palaau 8 18 13
Palaau 9 1 0
Palaau GT 0 0
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APPENDIX C – DATA TABLES
Lānaʻi
1.5.5.1 Grid Operations – Status Quo
Shown below in Table C-49 and Table C-50 are the estimated number of starts and capacity factor, respectively, for thermal generators in 2030 and 2035 with the Status Quo resource plan.
Table C-49. Lānaʻi – Number of Starts for existing utility-owned thermal generators under the Status Quo resource
plan.
Number of Starts 2030 2035
LL1 105 123 LL2 43 62 LL3 217 233 LL4 268 273 LL5 202 197 LL6 229 251 LL7 74 60 LL8 366 344
Table C-50. Lānaʻi – Capacity Factor for existing utility-owned thermal generators under the Status Quo resource plan.
Capacity Factor (%) 2030 2035
LL1 1 2 LL2 12 12 LL3 17 17 LL4 9 9 LL5 15 15 LL6 1 2 LL7 18 18 LL8 0 0
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APPENDIX C – DATA TABLES
1.5.5.2 Grid Operations – Base
Shown below in Table C-51 and Table C-52 are the estimated number of starts and capacity factor,
respectively, for thermal generators in 2030 and 2035 with the Base resource plan.
Table C-51. Lānaʻi – Number of Starts for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Number of Starts 2030 2035
LL1 123 115 LL2 94 95 LL3 152 139 LL4 212 216 LL5 137 126 LL6 190 164 LL7 0 1 LL8 17 18
Table C-52. Lānaʻi – Capacity Factor for existing utility-owned thermal generators and future thermal generators under the Base resource plan.
Capacity Factor (%) 2030 2035
LL1 3 2 LL2 5 4 LL3 7 7 LL4 4 4 LL5 6 6 LL6 0 0 LL7 0 0 LL8 0 0
i Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Appendix D:
System Security Study
2022 IGP System Security Study
Prepared By: Hawaiian Electric Transmission Planning
Version: 1
Date: March 2023
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APPENDIX D – SYSTEM SECURITY STUDY
EXECUTIVE SUMMARY
To accomodate future transmission grid-scale generation interconnection and system load growth
according to the Company Integrated Grid Planning (“IGP”) resource plans, a study which consists of
both steady state and dynamic stability analyses is performed for the Company’s five island systems for
selected near term and long term years considering forcasted system resource and load. The study
identifies system transmission level grid needs to accommodate various future plans in accordance
with transmission system planning criteria, which include wire solutions (transmission network
expansion and renewable energy zone enablement to identified desired potential), portfolio
alternatives (limiting locational capacity to reduce the necessary transmission upgrades), and dynamic
stability needs (e.g., grid-forming BESS, grid-forming STATCOM). High level cost estimates for wire
solution based grid needs are also provided in the study.
With these new resource plans and impending reductions of synchronous machines on the system, the
Company is truly embarking on a future of uncertainty ripe with technical challenges. As these analyses
are sensitive to attributes outside of the Company’s full control, (e.g., resource type, location, size,
capabilities, etc.), transmission needs will need to be modified as resources are planned and added to
the system. In addition, the future will heavily rely on the capabilities of grid-forming resources, which
are the current latest and greatest inverter-based technologies available. Such resources are not yet
operational on the Hawaiian Electric system, vary in capabilities, and will continue to evolve as much
R&D related to grid-forming resources are currently on-going.
For each island system, both IGP base load scenario resource plan and high load scenario resource plan
are studied. In the high load scenario resource plan, only near-term years (i.e., before 2040) are
studied. Study years were selected according to major grid-scale resource commissioned year and the
IGP resource plans. In each selected year, system dispatches representing annual system peak load
without DER generation are identified and analyzed in the steady state analyses to determine steady
state grid needs, and a system dispatch representing daytime high load and high DER generation with a
short list of high-risk contingencies are analyzed to identify system dynamic stability grid needs.
A summary of findings for each island system are listed below. These study findings are sensitive to
the future grid-scale resource interconnection locations and size, as well as system load growth and
system DER growth. Therefore, it is necessary to update study when grid scale resource procurement
plans are identified and finalized. Detailed study results with recommended system upgrade for each
studied year are also summarized the Appendix A of this report.
Oʻahu Transmission System Grid Needs Summary
In the near term, it is possible that the Oʻahu transmission system will not require transmission
network expansion.1 Beyond 2040, both the interconnection of grid-scale generation projects from REZ
development and system load increase will require transmission network expansion.
1 Transmission network expansion refers to upgrades (e.g., reconductoring, new transmission lines, new switching stations,
etc.) to the transmission network required to address the increase in capacity required to support addition(s) of grid-scale
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APPENDIX D – SYSTEM SECURITY STUDY
It is important to continue exploring the use of grid-scale BESS, energy efficiency, demand response
programs, and DER to reduce loading in the urban core to avoid overloading 138 kV overhead and
underground lines. Additionally, the west side of system already has major generation stations, and
further grid-scale renewable resources from REZ development located on the west side of the island
will cause generation congestion on the 138 kV system for a contingency that results in losing one or
multiple transmission lines. Full development of the REZ on the north shore of the island will require
significant transmission network expansion around the Wahiawa 138 kV substation, which is consistent
with the 2021 REZ study report.
For system stability condition in future years the system stability performance is within the planning
criteria for the base scenario resource plan, and is attributed to interconnecting large amounts of PV
paired with BESS with grid-forming (“GFM”) control. For the land constrainted scenario resouce plan,
due to the limited amount of grid-scale resources, it is likely addtional grid-scale GFM resources will be
needed (i.e., retrofit of existing renewable plants or new standalone energy storage) to maintain
system stability within the Oʻahu transmission planning criteria. To maintain system stability within the
planning criteria, the study recommends the minimum requirement of contingency reserve provided
by available MW headroom from grid-scale GFM resource at anytime should be 70% of DER generation
being produced. System stability performance is highly dependent on the performance of future GFM
resources, and is strongly recommended to continue to procure resources with GFM capability,
provide specific control recommendations during project interconnection requirement studies, and
continue through work with industry and operational experience, to improve our planning and
operational expertise in best utilizing the emerging GFM technology .
Maui Transmission System Grid Needs Summary
From the study results, it is likely the new renewable resource procurements, including Stage 3
procurements, requires additional transmission system capacity. The capacity needs will likely be met
by a combination of reconductoring 69 kV lines and adding new 69 kV lines and substations, the
specifics of which are highly dependent on the locations of future grid-scale projects interconnection.
In addition to these 69 kV requirements, overloading of Maui 69/23 kV tie transformers is identified in
multiple study scenarios. This can be mitigated by solutions such as reducing the transfer, by adding
grid-scale generation or energy at Maui 23 kV systems, replacing 69/23 kV tie transformers or reducing
the 23 kV system load, or by increasing the tie transfer capability.
The grid-scale resources identified in the base scenario resource plan provide the system stability in
accordance with the planning criteria, providing s a minimum MW headroom from GFM resources is
held as contingency reserve. This minimum is a reserve equal to at least 60% of DER generation being
produced . The study does not identify any addtional needs to maintain system stability within the
planning criteria for this portfolio.
Hawaiʻi Island Transmission System Grid Needs Summary
The cross-island tie L6200 line and west side L8100/8900 line has risk of overloading condition in both
near-term year and long-term. The cross-island tie L6200 overloading particularly for base scenarios
resources to the network. Transmission network expansions are different from renewable energy zone enablement, which
are transmission resources (e.g., new transmission lines, new switching stations, etc.) required to connect new utility-scale
resources to the existing transmission network.
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APPENDIX D – SYSTEM SECURITY STUDY
with a significant imbalance of energy production between the East and West sides of the island.
Overloads occurred for single contingencies conditions, particularly for base case generation scenarios
with a large west to east flow. This overloading ccould be mitigated by either reconductoring of the
L6200 line to 556 AAC or resource procurements to meet requirements of a balanced generation
dispatch between west side and east side of the system. The overloading of the L8100/8900 line also
occurred, particularly for base scenarios involving large flow of power from east side to west side of
system when L6800 line is tripped, especially when there is significant generation interconnected at
Keamuku substation.
The steady state analysis for the Hawaiʻi Island system also showed that imbalance of generation
production between west and east side of island would cause a significant undervoltage issue on either
southern or northern part of the system. This undervoltage issue will become much worse if there is no
generation resource interconnected in south Hawaiʻi Island. All these identified issues are more severe
in the high load scenario resouce plan. It is recommended to have grid-scale resource (capable of
providing voltage support regardless of active power generation) in south Hawaiʻi Island if voltage
regulation from the Tawhiri wind plant is unavailable.
The dynamic stability study results indicate that the future grid-scale generation procurement the GFM
resources assumed in the resouce plan, can maintain system stability within the planning criteria.
Molokaʻi and Lanaʻi System Grid Needs Summary
For the Molokaʻi and Lanaʻi system, a system dynamic stability review with very low and zero
synchronous machine generation online was performed. Theminimum performance criteria used in the
analyses for these two island systems is maintaining system stability when the system has a three-
phase to ground fault with zero fault impedance for 2 seconds duration, or when the system has a
single phase to ground fault with 40 ohm fault impedance for 20 seconds duration.
The Molokaʻi system study concluded that system has acceptable stability performance in the years
from 2030 to 2050 when the system is powered by 100% GFM inverter based resources, but have out
of synchronism issues for the existing diesel units before 2030 when the system still need rely on the
existing diesel units.
For the Lanaʻi system in the scenario without the resort load, a simliar conclusion as Molokaʻi is
identified – system has acceptable stability performance once the system is solely supplied by the GFM
inverter-based resources, during the years from 2030 to 2050, and system will have risk of existing unit
out of synchronism issues for the existing diesel units before 2029 when system still need rely on the
exisitng disel units. For the scenario with the resort load and large GFM inverter based resource (with
15.8 MW capacity), the system can survive both the 2 seconds duration three-phase to ground fault
and the 20 seconds high impedance single phase to ground fault.
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APPENDIX D – SYSTEM SECURITY STUDY
Contents
Appendix D: System Security Study ............................................ Error! Bookmark not defined.
EXECUTIVE SUMMARY .................................................................................................................................ii
1. Introduction ...................................................................................................................................... 16
2. Studied System Resource Plans ........................................................................................................ 18
2.1. Oʻahu Resource Plans ..................................................................................................... 18
2.2. Maui Resource Plans ...................................................................................................... 20
2.3. Hawaiʻi Island Resource Plans ........................................................................................ 21
2.4. Molokaʻi and Lanaʻi Resource Plans ............................................................................... 22
3. Study Methodology........................................................................................................................... 24
3.1. Past Studies .................................................................................................................... 24
3.1.1 Hawaiian Electric Transmission Renewable Energy Zone (“REZ”) Study ............................ 24
3.1.2 Hawaiian Electric Island-Wide PSCAD Studies (Stage 2 System Impact Study) .................. 24
3.1.3 2021 System Stability Study ................................................................................................ 24
3.1.4 Waena BESS Stability Study ................................................................................................ 26
3.1.5 Hawaiʻi Island RFP Stage 3 Grid Needs Assessment ........................................................... 26
3.1.6 RFP Stage 3 injection capacity studies ................................................................................ 26
3.2. Important Assumptions and Scope Limitations ............................................................. 27
3.3. Modeling ........................................................................................................................ 27
3.4. Study Generation Dispatches ......................................................................................... 29
3.5. Study Criteria .................................................................................................................. 30
4. Study Results ..................................................................................................................................... 31
4.1. Oʻahu System Study Results ........................................................................................... 31
4.1.1 Steady state analyses .......................................................................................................... 31
4.1.2 Dynamic Stability Study ...................................................................................................... 64
4.2. Maui System Study Results ............................................................................................ 77
4.2.1 Steady state analyses .......................................................................................................... 77
4.2.2 Dynamic stability study ..................................................................................................... 107
4.3. Hawaiʻi Island System Study Results ............................................................................ 112
4.3.1 Steady state analyses ........................................................................................................ 112
4.3.2 Dynamic stability study ..................................................................................................... 124
4.4. Molokaʻi and Lana’i Study Results................................................................................ 130
4.4.1 Molokaʻi Study Results ...................................................................................................... 131
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APPENDIX D – SYSTEM SECURITY STUDY
4.4.2 Lana’i Study Results .......................................................................................................... 136
5. Technical Advisory Panel Feedbacks .............................................................................................. 145
A. Summary of Study Results .............................................................................................................. 148
A.1 Oʻahu Study Results Summary ..................................................................................................... 148
A.2 Maui Study Results Summary ...................................................................................................... 166
A.3 Hawaiʻi Island Results Summary .................................................................................................. 183
List of Figures
Figure 1 High-level description of the studied resource plans ................................................................. 18
Figure 2 Oʻahu base scenario resource plan ............................................................................................. 19
Figure 3 Oʻahu land constrained scenario resource plan ......................................................................... 19
Figure 4 Oʻahu high load scenario resource plan ..................................................................................... 19
Figure 5 Maui base scenario resource plan .............................................................................................. 20
Figure 6 Maui high load scenario resource plan ....................................................................................... 20
Figure 7 Hawaiʻi island base scenario resource plan ................................................................................ 21
Figure 8 Hawaiʻi island high load scenario resource plan ......................................................................... 21
Figure 9 Relative range of system stability contribution by resource type .............................................. 26
Figure 10 Simplified Maui system single line diagram with future resources and REZ ............................ 29
Figure 11 High-Level Oʻahu map for assumed RFP Stage 3 project locations and REZ zone development
by 2030 ...................................................................................................................................................... 32
Figure 12 High-Level Oʻahu map for assumed generation projects’ locations by 2035 ........................... 35
Figure 13 High-Level Oʻahu map for assumed generation projects’ locations by 2045 ........................... 37
Figure 14 High-Level single line diagram for proposed transmission networks expansion, Oʻahu base
scenario resource plan, year 2045 ............................................................................................................ 41
Figure 15 High-Level Oʻahu map with REZ development status by 2050 ................................................. 42
Figure 16 High-Level Oʻahu map, land constrained scenario resource plan, by 2030 ............................. 46
Figure 17 High-Level Oʻahu map, land constrained scenario resource plan, by 2035 ............................. 48
Figure 18 High-Level Oʻahu map, land constrained scenario resource plan, by 2045 ............................. 50
Figure 19 Simplified single line diagram for proposed transmission networks expansion, Oʻahu land
constrained scenario resource plan, by 2045 ........................................................................................... 54
Figure 20 High-Level Oʻahu map, land constrained scenario resource plan, by 2050 ............................. 55
Figure 21 High-Level Oʻahu map, high load scenario resource plan, by 2030 ......................................... 58
Figure 22 High-Level Oʻahu map, high load scenario resource plan, by 2030 ......................................... 61
Figure 23 Dynamic stability simulation results, O’ahu base scenario resource plan, year 2027, P3
planning event .......................................................................................................................................... 66
Figure 24 Dynamic stability simulation results, O’ahu base scenario resource plan, year 2027, P3
planning event .......................................................................................................................................... 67
Figure 25 Dynamic stability mitigation study results, O’ahu base scenario resource plan, year 2027, P3
planning event, with system re-dispatch .................................................................................................. 69
Figure 26 Dynamic stability study results, O’ahu base scenario resource plan, year 2035, P3 planning
event ......................................................................................................................................................... 71
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 27 Dynamic stability study results, O’ahu land constrained scenario resource plan, year 2035, P3
planning event .......................................................................................................................................... 73
Figure 28 Dynamic stability study results, O’ahu land constrained scenario resource plan, year 2035, P3
planning event, with one more GFM resource out-of-service ................................................................. 74
Figure 29 Dynamic stability study results, O’ahu land constrained scenario resource plan (GNA Stage 3),
year 2030, P3 planning event ................................................................................................................... 76
Figure 30 Comparison of system voltage recovery performance post fault clearing .............................. 77
Figure 31 High-Level Maui map for assumed RFP Stage 3 project locations by 2027 ............................. 78
Figure 32 High-Level single line diagram for the two line interconnection RFP Stage 3 projects, Maui
system base scenario resource planning, year 2027 ................................................................................ 79
Figure 33 High-Level single line diagram for proposed transmission networks expansion, Maui base
scenario resource plan, year 2027 ............................................................................................................ 81
Figure 34 High-Level Maui map for assumed future grid-scale project interconnection locations by 2035
................................................................................................................................................................... 82
Figure 35 High-level single line diagram for the 43 MW line interconnection project, Maui base scenario
resource planning, year 2035 ................................................................................................................... 83
Figure 36 Overloading on tie transformers and undervoltage in 23 kV networks when losing one 69 kV
feed for the 23 kV networks ..................................................................................................................... 85
Figure 37 Proposed Maui transmission networks expansion, Maui base scenario resource plan, year
2035 .......................................................................................................................................................... 86
Figure 38 High-Level Maui map for assumed future grid-scale project interconnection locations by 2040
................................................................................................................................................................... 87
Figure 39 Proposed Maui transmission networks expansion, Mau i base scenario resource plan, year
2040 .......................................................................................................................................................... 89
Figure 40 High-Level Maui map for assumed future grid-scale project interconnection locations by 2045
................................................................................................................................................................... 90
Figure 41 High-Level single line diagram for a new substation REZ C.2, Maui base scenario resource
plan, year 2045 ......................................................................................................................................... 90
Figure 42 Proposed Maui transmission networks expansion, Mau i base scenario resource plan, year
2045 .......................................................................................................................................................... 93
Figure 43 High-Level Maui map for assumed future grid-scale project interconnection locations by 2050
................................................................................................................................................................... 94
Figure 44 High-Level single line diagram for a new substation REZ C.3, Maui base scenario resource
plan, year 2050 ......................................................................................................................................... 95
Figure 45 High-Level Maui map for assumed RFP Stage 3 project locations by 2027 ............................. 97
Figure 46 High-Level single line diagram for proposed transmission networks expansion, Maui high load
scenario resource plan, year 2027 ............................................................................................................ 99
Figure 47 High-Level Maui map for assumed future grid-scale project interconnection locations by
2030, high load scenario resource plan .................................................................................................. 100
Figure 48 High-level single line diagram for the 17 MW line interconnection project, Maui high load
scenario resource planning, year 2030 ................................................................................................... 101
Figure 49 High-Level single line diagram for proposed 69 kV transmission networks expansion, Maui
high load scenario resource plan, year 2030 .......................................................................................... 103
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 50 High-Level Maui map for assumed future grid-scale project interconnection locations by
2035, high load scenario resource plan .................................................................................................. 104
Figure 51 Dynamic stability simulation results, Maui base scenario resource plan, year 2028, P3
planning event ........................................................................................................................................ 108
Figure 52 Dynamic stability simulation results, Maui base scenario resource plan, year 2028, P3
planning event ........................................................................................................................................ 109
Figure 53 Dynamic stability simulation results, Maui base scenario resource plan, year 2036, P3
planning event ........................................................................................................................................ 110
Figure 54 Dynamic stability simulation results, Maui base scenario resource plan, year 2036, P3
planning event ........................................................................................................................................ 111
Figure 55 High-Level Hawaiʻi island map with assumed future grid-scale project interconnection
locations by 2032, base scenario resource plan ..................................................................................... 112
Figure 56 High-Level Hawaiʻi island map with assumed future grid-scale project interconnection
locations by 2050, base scenario resource plan ..................................................................................... 116
Figure 57 High-Level Hawaiʻi island map with assumed future grid-scale project interconnection
locations by 2032, high load scenario resource plan ............................................................................. 119
Figure 58 High-Level Hawaiʻi island map with assumed future grid-scale project interconnection
locations by 2036, high load scenario resource plan ............................................................................. 122
Figure 59 Dynamic stability simulation results, Hawai’i Island base scenario resource plan, year 2026,
base dispatch, P5 planning event ........................................................................................................... 126
Figure 60 Dynamic stability simulation results, Hawai’i Island base scenario resource plan, year 2026,
sensitivity dispatch, P3 planning event................................................................................................... 127
Figure 61 Dynamic stability simulation results, Hawai’i Island base scenario resource plan, year 2032,
base dispatch, P5 planning event ........................................................................................................... 128
Figure 62 Dynamic stability simulation results, Hawai’i Island base scenario resource plan, year 2032,
base dispatch, P3 planning event ........................................................................................................... 129
Figure 63 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2029, three-
phase close in fault ................................................................................................................................. 131
Figure 64 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2029, three-
phase close in fault ................................................................................................................................. 132
Figure 65 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2029, single
phase far end fault with high fault impedance ....................................................................................... 132
Figure 66 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2030, three-
phase close in fault ................................................................................................................................. 133
Figure 67 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2030, three-
phase far end fault .................................................................................................................................. 134
Figure 68 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2030, high
impedance far end fault .......................................................................................................................... 134
Figure 69 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2050, three-
phase close in fault ................................................................................................................................. 135
Figure 70 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2050, three-
phase far end fault .................................................................................................................................. 135
Figure 71 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2050, high
impedance far end fault .......................................................................................................................... 136
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 72 Dynamic stability simulation results, Lana’i base scenario resource plan, year 2029, three-
phase close in fault ................................................................................................................................. 137
Figure 73 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2029, three-
phase close in fault ................................................................................................................................. 137
Figure 74 Dynamic stability simulation results, Lana’i base scenario resource plan, year 2029, single
phase far end fault with high fault impedance ....................................................................................... 138
Figure 75 Dynamic stability simulation results, Lana’i base scenario resource plan, year 2050, three-
phase close in fault ................................................................................................................................. 138
Figure 76 Dynamic stability simulation results, Lana’i base scenario resource plan, year 2050, three-
phase close in fault ................................................................................................................................. 139
Figure 77 Dynamic stability simulation results, Lana’i base scenario resource plan, year 2050, single
phase far end fault with high fault impedance ....................................................................................... 139
Figure 78 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2029,
three-phase close in fault ....................................................................................................................... 140
Figure 79 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2029,
three-phase close in fault ....................................................................................................................... 141
Figure 80 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2029, single
phase far end fault with high fault impedance ....................................................................................... 141
Figure 81 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2030,
three-phase close in fault ....................................................................................................................... 142
Figure 82 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2030,
three-phase close in fault ....................................................................................................................... 142
Figure 83 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2030, single
phase far end fault with high fault impedance ....................................................................................... 143
Figure 84 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2050,
three-phase close in fault ....................................................................................................................... 143
Figure 85 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2050,
three-phase close in fault ....................................................................................................................... 144
Figure 86 Dynamic stability simulation results, Lana’i no resort scenario resource plan, year 2050, single
phase far end fault with high fault impedance ....................................................................................... 144
List of Tables
Table 1 Molokaʻi System Base and High Load Scenario Resource Plans .................................................. 22
Table 2 Lanaʻi System Base and High Load Scenario Resource Plans, and without Resort Load Resource
Plan............................................................................................................................................................ 22
Table 3 P4 DER Voltage Ride-Through and Trip Settings Included in the PSCAD Models ........................ 28
Table 4 P4 DER Frequency Ride-Through and Trip Settings Included in the PSCAD Models ................... 28
Table 5 P4 DER Momentary Cessation Assumptions ................................................................................ 28
Table 6 System Generation Dispatches Studied for Maui Base Scenario Resource Plan, Year 2035 ....... 30
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APPENDIX D – SYSTEM SECURITY STUDY
Table 7 Oʻahu Grid-Scale Generation Project Development by 2030, after RFP Stage 2, Base Scenario
Resource Plan ............................................................................................................................................ 32
Table 8 Oʻahu Grid-Scale Generation Removal by 2030 .......................................................................... 32
Table 9 Oʻahu System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan,
Year 2030 .................................................................................................................................................. 32
Table 10 Studied System Generation (MW) Dispatches, Oʻahu Base Scenario Resource Plan, Year 2030
................................................................................................................................................................... 33
Table 11 Oʻahu REZ Enablement Cost Estimate for REZ Development by 2030 ...................................... 34
Table 12 Oʻahu Grid-Scale Generation Project Development between 2031 and 2035, Base Scenario
Resource Plan ............................................................................................................................................ 35
Table 13 Oʻahu Grid-Scale Generation Removal between 2031 and 2035 .............................................. 35
Table 14 Oʻahu System Resource Summary and Forecasted Demand (MW), Base Scenario Resource
Plan, Year 2035 ......................................................................................................................................... 35
Table 15 Studied System Generation (MW) Dispatches, Oʻahu Base Scenario Resource Plan, Year 2035
................................................................................................................................................................... 36
Table 16 Oʻahu Grid-Scale Generation Project Development between 2036 and 2045, Base Scenario
Resource Plan ............................................................................................................................................ 37
Table 17 Oʻahu Grid-Scale Generation Removal between 2036 and 2045 .............................................. 38
Table 18 Oʻahu System Resource Summary and Forecasted Demand (MW), Base Scenario Resource
Plan, Year 2045 ......................................................................................................................................... 38
Table 19 Studied System Generation (MW) Dispatches, Oʻahu Base Scenario Resource Plan, Year 2045
................................................................................................................................................................... 38
Table 20 138 kV Line Overloading Summary, Oʻahu Base Scenario Resource Plan, Year 2045 ............... 39
Table 21 Transmission Networks Expansion and High-Level Cost Estimate, Oʻahu Base Scenario
Resource Plan, Year 2045 ......................................................................................................................... 40
Table 22 Oʻahu REZ Enablement Cost Estimate for REZ Development between 2036 and 2045 ............ 42
Table 23 Oʻahu Grid-Scale Generation Project Development between 2046 and 2050, Base Scenario
Resource Plan ............................................................................................................................................ 42
Table 24 Oʻahu Grid-Scale Generation Removal between 2046 and 2050 .............................................. 43
Table 25 Oʻahu System Resource Summary and Forecasted Demand (MW), Base Scenario Resource
Plan, Year 2050 ......................................................................................................................................... 43
Table 26 Studied System Generation (MW) Dispatches, Oʻahu Base Scenario Resource Plan, Year 2050
................................................................................................................................................................... 43
Table 27 138 kV Line Overloading Summary, Oʻahu Base Scenario Resource Plan, Year 2050 ............... 44
Table 28 Transmission Networks Expansion and High-Level Cost Estimate, Oʻahu Base Scenario
Resource Plan, Year 2050 ......................................................................................................................... 44
Table 29 Oʻahu REZ Enablement Cost Estimate for REZ Development between 2046 and 2050 ............ 45
Table 30 Oʻahu Grid-Scale Generation Project Development by 2030, after RFP Stage 2, Land
Constrained Scenario Resource Plan ........................................................................................................ 46
Table 31 Oʻahu Grid-Scale Generation Removal by 2030 ........................................................................ 46
Table 32 Oʻahu System Resource Summary and Forecasted Demand (MW), Land Constrained Scenario
Resource Plan, Year 2030 ......................................................................................................................... 46
Table 33 Studied System Generation (MW) Dispatches, Oʻahu Land Constrained Scenario Resource
Plan, Year 2030 ......................................................................................................................................... 47
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Table 34 Oʻahu Grid-Scale Generation Project Development by 2035, Land Constrained Scenario
Resource Plan ............................................................................................................................................ 48
Table 35 Oʻahu Grid-Scale Generation Removal by 2035 ........................................................................ 48
Table 36 Oʻahu System Resource Summary and Forecasted Demand (MW), Land Constrained Scenario
Resource Plan, Year 2035 ......................................................................................................................... 49
Table 37 Studied System Generation (MW) Dispatches, Oʻahu Land Constrained Scenario Resource
Plan, Year 2035 ......................................................................................................................................... 49
Table 38 Oʻahu Grid-Scale Generation Project Development by 2045, Land Constrained Scenario
Resource Plan ............................................................................................................................................ 50
Table 39 Oʻahu Grid-Scale Generation Removal by 2045 ........................................................................ 50
Table 40 Oʻahu System Resource Summary and Forecasted Demand (MW), Land Constrained Scenario
Resource Plan, Year 2045 ......................................................................................................................... 51
Table 41 Studied System Generation (MW) Dispatches, Oʻahu Land Constrained Scenario Resource
Plan, Year 2045 ......................................................................................................................................... 51
Table 42 138 kV Line Overloading Summary, Oʻahu Land Constrained Scenario Resource Plan, Year
2045 .......................................................................................................................................................... 52
Table 43 Transmission Networks Expansion and High-Level Cost Estimate, Oʻahu Land Constrained
Scenario Resource Plan, Year 2045 ........................................................................................................... 53
Table 44 Grid-Scale Generation Project Development by 2050, Land Constrained Scenario Resource
Plan............................................................................................................................................................ 55
Table 45 Oʻahu Grid-Scale Generation Removal by 2050 ........................................................................ 55
Table 46 Oʻahu System Resource Summary and Forecasted Demand (MW), Land Constrained Scenario
Resource Plan, Year 2050 ......................................................................................................................... 55
Table 47 Studied System Generation (MW) Dispatches, Oʻahu Land Constrained Scenario Resource
Plan, Year 2050 ......................................................................................................................................... 55
Table 48 138 kV Line Overloading Summary, Oʻahu Land Constrained Scenario Resource Plan, Year
2050 .......................................................................................................................................................... 56
Table 49 Transmission Networks Expansion and High-Level Cost Estimate, Oʻahu Land Constrained
Scenario Resource Plan, Year 2050 ........................................................................................................... 57
Table 50 Oʻahu Grid-Scale Generation Project Development by 2030, High Load Scenario Resource Plan
................................................................................................................................................................... 58
Table 51 Oʻahu Grid-Scale Generation Removal by 2030 ........................................................................ 58
Table 52 Oʻahu System Resource Summary and Forecasted Demand (MW), High Load Scenario
Resource Plan, Year 2030 ......................................................................................................................... 58
Table 53 Studied System Generation (MW) Dispatches, Oʻahu High Load Scenario Resource Plan, Year
2030 .......................................................................................................................................................... 59
Table 54 138 kV Line Overloading Summary, Oʻahu High Load Scenario Resource Plan, Year 2030....... 59
Table 55 138 kV Line Overloading Summary, Oʻahu High Load Scenario Resource Plan, Year 2030....... 60
Table 56 Oʻahu REZ Enablement Cost Estimate for REZ Development by 2030 ...................................... 61
Table 57 Oʻahu Grid-Scale Generation Project Development by 2035, High Load Scenario Resource Plan
................................................................................................................................................................... 61
Table 58 Oʻahu Grid-Scale Generation Removal by 2035 ........................................................................ 62
Table 59 Oʻahu System Resource Summary and Forecasted Demand (MW), High Load Scenario
Resource Plan, Year 2030 ......................................................................................................................... 62
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Table 60 Studied System Generation (MW) Dispatches, Oʻahu High Load Scenario Resource Plan, Year
2035 .......................................................................................................................................................... 62
Table 61 138 kV Line Overloading Summary, Oʻahu High Load Scenario Resource Plan, Year 2035....... 63
Table 62 138 kV Line Overloading Summary, Oʻahu High Load Scenario Resource Plan, Year 2035....... 64
Table 63 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu
Base Scenario Resource Plan, Year 2027 .................................................................................................. 65
Table 64 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu
Base Scenario Resource Plan, Year 2027 .................................................................................................. 68
Table 65 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu
Base Scenario Resource Plan, Year 2035 .................................................................................................. 70
Table 66 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu
Land Constrained Scenario Resource Plan, Year 2035 ............................................................................. 72
Table 67 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu land
constrained scenario resource plan (GNA Stage 3), year 2030 ................................................................ 75
Table 68 Maui Grid-Scale Generation Project Development by 2027, after RFP Stage 2, Base Scenario
Resource Plan ............................................................................................................................................ 79
Table 69 Maui Grid-Scale Generation Removal by 2027 .......................................................................... 79
Table 70 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource
Plan, Year 2027 ......................................................................................................................................... 79
Table 71 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2027 80
Table 72 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2027 .... 80
Table 73 Transmission Networks Expansion and High-Level Cost Estimate, Maui Base Scenario Resource
Plan, Year 2027 ......................................................................................................................................... 80
Table 74 Maui Grid-Scale Generation Project Development between 2028 and 2035, Base Scenario
Resource Plan ............................................................................................................................................ 83
Table 75 Maui Grid-Scale Generation Removal between 2028 and 2035 ............................................... 83
Table 76 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource
Plan, Year 2035 ......................................................................................................................................... 83
Table 77 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2035 84
Table 78 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2035 .... 84
Table 79 Transmission Networks Expansion and High-Level Cost Estimate, Maui Base Scenario Resource
Plan, Year 2035 ......................................................................................................................................... 86
Table 80 Maui Grid-Scale Generation Project Development between 2036 and 2040, Base Scenario
Resource Plan ............................................................................................................................................ 87
Table 81 Maui Grid-Scale Generation Removal between 2028 and 2035 ............................................... 87
Table 82 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource
Plan, Year 2040 ......................................................................................................................................... 88
Table 83 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2040 88
Table 84 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2040 .... 88
Table 85 Maui Grid-Scale Generation Project Development between 2041 and 2044, Base Scenario
Resource Plan ............................................................................................................................................ 90
Table 86 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource
Plan, Year 2045 ......................................................................................................................................... 91
Table 87 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2045 91
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APPENDIX D – SYSTEM SECURITY STUDY
Table 88 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2045 .... 91
Table 89 Transmission Networks Expansion and High-Level Cost Estimate, Maui Base Scenario Resource
Plan, Year 2045 ......................................................................................................................................... 92
Table 90 REZ Enablement and High-Level Cost Estimate, Maui Base Scenario Resource Plan, Year 2045
................................................................................................................................................................... 93
Table 91 Maui Grid-Scale Generation Project Development between 2046 and 2050, Base Scenario
Resource Plan ............................................................................................................................................ 95
Table 92 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource
Plan, Year 2050 ......................................................................................................................................... 95
Table 93 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2050 95
Table 94 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2050 .... 96
Table 95 Transmission Networks Expansion and High-Level Cost Estimate, Maui Base Scenario Resource
Plan, Year 2050 ......................................................................................................................................... 96
Table 96 REZ Enablement and High-Level Cost Estimate, Maui Base Scenario Resource Plan, Year 2050
................................................................................................................................................................... 97
Table 97 Studied System Generation (MW) Dispatches, Maui High Load Scenario Resource Plan, Year
2027 .......................................................................................................................................................... 98
Table 98 List of Overloaded Transmission Elements, Maui High Load Scenario Resource Plan, Year 2027
................................................................................................................................................................... 98
Table 99 Transmission Networks Expansion and High-Level Cost Estimate, Maui High Load Scenario
Resource Plan, Year 2027 ......................................................................................................................... 99
Table 100 Maui Grid-Scale Generation Project Development between 2028 and 2030, High Load
Scenario Resource Plan ........................................................................................................................... 101
Table 101 Maui System Resource Summary and Forecasted Demand (MW), High Load Scenario
Resource Plan, Year 2030 ....................................................................................................................... 101
Table 102 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2030
................................................................................................................................................................. 101
Table 103 List of Undervoltage Violation and Voltage Collapse, Maui High Load Scenario Resource Plan,
Year 2030 ................................................................................................................................................ 102
Table 104 List of Overloaded Transmission Elements, Maui High Load Scenario Resource Plan, Year
2030 ........................................................................................................................................................ 102
Table 105 Transmission Networks Expansion and High-Level Cost Estimate, Maui High Load Scenario
Resource Plan, Year 2030 ....................................................................................................................... 103
Table 106 REZ Enablement and High-Level Cost Estimate, Maui High Load Scenario Resource Plan, Year
2030 ........................................................................................................................................................ 104
Table 107 Maui Grid-Scale Generation Project Development between 2030 and 2035, High Load
Scenario Resource Plan ........................................................................................................................... 105
Table 108 Maui System Resource Summary and Forecasted Demand (MW), High Load Scenario
Resource Plan, Year 2035 ....................................................................................................................... 105
Table 109 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2035
................................................................................................................................................................. 105
Table 110 List of Overloaded Transmission Elements, Maui High Load Scenario Resource Plan, Year
2035 ........................................................................................................................................................ 105
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Table 111 Transmission Networks Expansion and High-Level Cost Estimate, Maui High Load Scenario
Resource Plan, Year 2035 ....................................................................................................................... 106
Table 112 REZ Enablement and High-Level Cost Estimate, Maui High Load Scenario Resource Plan, Year
2035 ........................................................................................................................................................ 107
Table 113 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, Maui
Base Scenario Resource Plan, Year 2028 ................................................................................................ 107
Table 114 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, Maui
Base Scenario Resource Plan, Year 2036 ................................................................................................ 109
Table 115 Hawaiʻi Island Grid-Scale Generation Project Development by 2032, after RFP Stage 2, Base
Scenario Resource Plan ........................................................................................................................... 113
Table 116 Hawaiʻi Island Grid-Scale Generation Removal by 2032 ........................................................ 113
Table 117 Hawaiʻi Island System Resource Summary and Forecasted Demand (MW), Base Scenario
Resource Plan, Year 2032 ....................................................................................................................... 113
Table 118 Studied System Generation (MW) Dispatches, Hawaiʻi Island Base Scenario Resource Plan,
Year 2032 ................................................................................................................................................ 113
Table 119 List of High Loading and Overloaded Transmission Lines, Hawaiʻi Island Base Load Scenario
Resource Plan, Year 2032 ....................................................................................................................... 114
Table 120 List of Undervoltage Violations, Hawaiʻi Island Base Load Scenario Resource Plan, Year 2032
................................................................................................................................................................. 114
Table 121 Hawaiʻi Island Grid-Scale Generation Project Development by 2050, Base Scenario Resource
Plan.......................................................................................................................................................... 117
Table 122 Hawaiʻi Island System Resource Summary and Forecasted Demand (MW), Base Scenario
Resource Plan, Year 2032 ....................................................................................................................... 117
Table 123 Studied System Generation (MW) Dispatches, Hawaiʻi Island Base Scenario Resource Plan,
Year 2032 ................................................................................................................................................ 117
Table 124 List of High Loading and Overloaded Transmission Lines, Hawaiʻi Island Base Load Scenario
Resource Plan, Year 2050 ....................................................................................................................... 118
Table 125 List of Undervoltage Violations, Hawaiʻi Island Base Load Scenario Resource Plan, Year 2050
................................................................................................................................................................. 118
Table 126 Hawaiʻi Island Grid-Scale Generation Project Development by 2032, High Load Scenario
Resource Plan .......................................................................................................................................... 119
Table 127 Hawaiʻi Island System Resource Summary and Forecasted Demand (MW), High Scenario
Resource Plan, Year 2032 ....................................................................................................................... 120
Table 128 Studied System Generation (MW) Dispatches, Hawaiʻi Island Base Scenario Resource Plan,
Year 2032 ................................................................................................................................................ 120
Table 129 List of High Loading and Overloaded Transmission Lines, Hawaiʻi Island High Load Scenario
Resource Plan, Year 2032 ....................................................................................................................... 120
Table 130 List of Undervoltage Violations, Hawaiʻi Island High Load Scenario Resource Plan, Year 2032
................................................................................................................................................................. 120
Table 131 Hawaiʻi Island Grid-Scale Generation Project Development by 2036, High Load Scenario
Resource Plan .......................................................................................................................................... 122
Table 132 Hawaiʻi Island System Resource Summary and Forecasted Demand (MW), High Load Scenario
Resource Plan, Year 2036 ....................................................................................................................... 123
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Table 133 Studied System Generation (MW) Dispatches, Hawaiʻi Island High Load Scenario Resource
Plan, Year 2036 ....................................................................................................................................... 123
Table 134 List of High Loading and Overloaded Transmission Lines, Hawaiʻi Island High Load Scenario
Resource Plan, Year 2036 ....................................................................................................................... 123
Table 135 List of Undervoltage Violations, Hawaiʻi Island High Load Scenario Resource Plan, Year 2036
................................................................................................................................................................. 124
Table 136 System Generation Dispatches (Base Dispatch and Sensitivity Dispatch) for Daytime Peak
Load High DER Generation Scenario, Hawai’i Island Base Scenario Resource Plan, Year 2026 ............. 125
Table 137 Hawai’i Island System Dynamic Stability Study Results Summary, Hawai’i Island Base Scenario
Resource Plan, Year 2026 ....................................................................................................................... 125
Table 138 System Generation Dispatches (Base Dispatch and Sensitivity Dispatch) for Daytime Peak
Load High DER Generation Scenario, Hawai’i Island Base Scenario Resource Plan, Year 2032 ............. 127
Table 139 Hawai’i Island System Dynamic Stability Study Results Summary, Hawai’i Island Base Scenario
Resource Plan, Year 2032 ....................................................................................................................... 128
Table 140 Hawai’i Island System Minimum GFM Requirement Study Results Summary, Hawai’i Island
Base Scenario Resource Plan, Year 2032, Base Dispatch ....................................................................... 130
Table 141 Hawai’i Island System Minimum GFM Requirement Study Results Summary, Hawai’i Island
Base Scenario Resource Plan, Year 2032, Sensitivity Dispatch ............................................................... 130
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APPENDIX D – SYSTEM SECURITY STUDY
1. INTRODUCTION
As part of Company’s Integrated Grid Planning process, Transmission Planning Department
commenced with the 2022 IGP system security study in November 2022, in which both steady state
and dynamic stability analyses are conducted to identify the transmission system of Oʻahu, Maui and
Hawaiʻi island and Molokaʻi and Lanaʻi system grid needs in order to accomodate the Company’s
various resource plans, including both future grid-scale generation interconnection and load increase,
to achieve 100% decarbonize Company’s all systems by 2045.
The studied resource plans include base scenario resource plans for all five island systems, high load
scenario resource plans for all five island systems, and Oʻahu land constrained resource plan. For each
island system, several study years are selected according to the resource plan. Steady state analyses,
performed in PSS/E, is conducted for each selected year. Considering future advance grid technology
developments’ impact on grid dynamic stability, the dynamic stability analyses are only performed for
the selected near-term years (i.e., before 2040) in PSCAD/EMTDC for high-risk system dispatches and
high-risk contingencies.
Past studies conducted in recent years are used as important inputs for this study. The past studies are
Hawaiian Electric Transmission Renewable Energy Zone (“REZ”) Study2, Hawaiian Electric Island-Wide
PSCAD Studies (Stage 2 System Impact Study)3, 2021 system stability studies4, Hawai’i Island RFP Stage
3 grid needs assessment5, and RFP Stage 3 injection study for O’ahu system, Maui system and Hawai’i
Island6. From these past studies, general information regarding system available capacity for future
generation interconnection is obtained. These past studies inform selection of the high-risk system
dispatches and high-risk contingencies for the 2022 IGP system security study dynamic stability
analyses.
This study assesses system capacity and stability needs. Based on these needs, traditional wire
solutions and non-wire solutions for certain wire solutions are identified and provided to resource
expansion and production simulation to determine grid needs cost.
2 Available at
https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/
working_groups/solution_evaluation_and_optimization/20211105_transmission_renewable_energy_zone_study.pdf 3 Available at
https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/
working_groups/stakeholder_technical/20210630_electranix_report.pdf
4 See Dkt. No. 2018-0165, filed Feb. 13, 2023
5 See Dkt. No. 2017-0352, filed July 15, 2021
6 See Dkt. No. 2017-0352 - Hawaii Island injection study filed Nov. 2, 2022, Oahu and Maui injection studies filed Dec. 22,
2022, and Maui injection update filed March 16, 2023.
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APPENDIX D – SYSTEM SECURITY STUDY
In this report, section 2 describes the studied resource plan, section 3 summarizes study methodology,
and section 4 lists study results. In section 5, feedback from the Technical Advisory Panel, with
Company’s review, is provided.
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APPENDIX D – SYSTEM SECURITY STUDY
2. STUDIED SYSTEM RESOURCE PLANS
From Company’s resource planning study, different resource plans are provided for this study. A high-
level description of the provided resource plans is shown in the Figure 1. For all five islands
transmission systems, both base scenario resource plans and high load resource plans are studied;
additionally, the land constrained resource plan is also studied for O’ahu transmission system. In every
resource plan, grid-scale resource retirement, new resources (both grid-scale and DER) adding into
system, as well as system load forecast are provided from the resource planning results and hourly
production simulation profiles, from 2024 to 2050. The study is performed from the year of the RFP
Stage 3 projects guaranteed commercial operation date (“GCOD”) to 2050.
Figure 1 High-level description of the studied resource plans
2.1. Oʻahu Resource Plans
Three Oʻahu resource plans are analyzed in this study – Oʻahu base scenario resource plan, Oʻahu land
constrained resource plan, and Oʻahu high load resource plan. In the base resource plan, Renewable
Energy Zone (“REZ”) development is included. Hence, large amounts of grid-scale resource
interconnection is described in the base resource plan. The land constrained resource plan has the
same system load forecast as the base resource plan; however, grid-scale generation from the REZ
development is reduced and replaced by the combination of more firm generation and DER generation
from distribution side. Therefore, after RFP Stage 3 procurement, grid-scale generation
interconnection described in the land constrained resource plan is less than that in the base resource
plan. In the high load resource plan, higher system load forecast is constructed in the resource plan.
And only near term years in this resource plan is analyzed in this study. All three resource plans are
summarized in following figures. For the high load resource plan, only near-term years are selected for
the study.
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 2 Oʻahu base scenario resource plan
Figure 3 Oʻahu land constrained scenario resource plan
Figure 4 Oʻahu high load scenario resource plan
Based on the grid-scale generation projects online time, the following years are selected for the study.
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APPENDIX D – SYSTEM SECURITY STUDY
• Oʻahu system base scenario resource plan and land contrained scenario resource plan – 2030,
2035, 2046 and 2050.
• Oʻahu system high load scenario resource plan – 2030 and 2035.
2.2. Maui Resource Plans
Two Maui resource plans are analyzed in this study – Maui base scenario resource plan and high load
scenario resource plan. Both resource plans have grid-scale generation interconnections for future
years. The high load resource plan has faster system load increase than the base scenario resource
plan. High level descriptions for the two studied resource plans are shown in follwing figures.
Figure 5 Maui base scenario resource plan
Figure 6 Maui high load scenario resource plan
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APPENDIX D – SYSTEM SECURITY STUDY
Based on the grid-scale generation projects online time, following years are selected for the study.
• Maui system base scenario resource plan – 2027, 2035, 2041, 2045 and 2050.
• Maui system high load scenario resource plan – 2027, 2030 and 2035.
2.3. Hawaiʻi Island Resource Plans
Similiar as Maui system, two resource plans are analyzed for Hawaiʻi island system in this study –
Hawaiʻi island base scenario resource plan and high load scenario resource plan. Both resource plans
have grid-scale generation interconnections for future years. The high load resource plan has faster
system load increase than the base scenario resource plan. High level descriptions for the two studied
resource plans are shown in follwing figures.
Figure 7 Hawaiʻi island base scenario resource plan
Figure 8 Hawaiʻi island high load scenario resource plan
Based on the grid-scale generaiton projects online time, following years are selecte for the study.
• Hawaiʻi island system base scenario resource plan – 2032 and 2050.
• Hawaiʻi island system high load scenario resource plan – 2032 and 2036.
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APPENDIX D – SYSTEM SECURITY STUDY
2.4. Molokaʻi and Lanaʻi Resource Plans
Molokaʻi and Lanaʻi are much smaller systems for which Company which, due to the smaller size,
follow different reliability criteria than the other islands. Grid-scale generation projects must be
interconnected through the system 12 kV substation bus. Both base scenario resource plans and high
load scenario resource plans are studied for these two systems. Addtionally, without resort load
resource plan is also studied for the Lanaʻi system. The studied Molokaʻi and Lanaʻi resource plans are
described in the Table 1 .
Table 1 Molokaʻi System Base and High Load Scenario Resource Plans
Year Resource Added to System in
Base/High Load Scenario
Resource Plan
Pre-2029 CBRE Phase 1 – 0.25 MW PV
CBRE Phase 2 – 2.75 MW 11
MWh PV-BESS
2029 0.4 MW/0.7 MWh SA BESS
3 MW/3MWh PV-BESS
2030 0.1 MW/0.3 MWh SA BESS
8.5 MW/29.7MWh PV-BESS
2035 0.1 MW/0.1 MWh SA BESS
2.3 MW/1.9 MWh PV-BESS
2040 0.1 MW/0.1 MWh SA BESS
1.1 MW/2.8 MWh PV-BESS
2045 0.1 MW/0.2 MWh SA BESS
2.6 MW/6.9 MWh PV-BESS
2050 0.1 MW/0.2 MWh SA BESS
1.2 MW/2.9 MWh PV-BESS
Table 2 Lanaʻi System Base and High Load Scenario Resource Plans, and without Resort Load Resource Plan
Year With Resort Load
Base/High Load Scenario
Resource Plan
Without Resort Load Resource
Plan
Pre-2029 RFP Phase 2 – 15.8
MW/63.2 MWh PV-BESS
No new resource
2029 0.6 MW/1.1 MWh SA BESS
0.3 MW/0.3MWh PV-BESS
0.7 MW/1.3 MWh SA BESS
3.9 MW/3.9 MWh PV-BESS
2030 4.9MW/4.9 MWh PV-BESS 6.4 MW/24.5 MWh PV-BESS
2035 0.3 MW/0.3 MWh PV-BESS 0.4 MW/1.4 MWh PV-BESS
2040 0.3 MW/0.3 MWh PV-BES
0.3 MW/0.9 MWh PV-BESS
2045 0.2 MW/0.3 MWh SA BESS
1.5 MW/1.5 MWh PV-BESS
0.1 MW/0.1 MWh SA BESS
1.1 MW/2 MWh PV-BESS
2050 0.1 MW/0.1 MWh SA BESS
0.9 MW/0.9 MWh PV-BESS
0 MW/0.2 MWh SA BESS
0.5 MW/1.1 MWh PV-BESS
Years that are selected in each scenario for the study are:
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APPENDIX D – SYSTEM SECURITY STUDY
• Molokaʻi system base scenario resource plan – 2029, 2030 and 2050.
• Molokaʻi system high load scenario resource plan – 2029, 2030 and 2050
• Lanaʻi system base scenario resource plan – 2029 and 2050.
• Lanaʻi system high load scenario resource plan – 2029 and 2050
• Lanaʻi system No Resort scenario resource plan – 2029, 2030 and 2050
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APPENDIX D – SYSTEM SECURITY STUDY
3. STUDY METHODOLOGY
3.1. Past Studies
In recent years, Transmission Planning Department has performed several studies that addressed both
near term and long term plans. These studies provide important inputs to the the 2022 IGP System
Security Study, such as system available injection capacity, system stability related high-risk generation
dispatch and high-risk contingencies, and importance of grid-forming (“GFM”) resource. A brief
summary of the referenced past studies is provided in this subsection.
3.1.1 Hawaiian Electric Transmission Renewable Energy Zone (“REZ”) Study
In November 2021, Company released the first version of transmission REZ study report. In this report,
high level cost estimate for both REZ enablment (e.g., interconnection facilities) and transmission
network expansions are identified, based on assumptions of resource procurement targets by 2040
and a fix rate of system load increase, for Oʻahu, Maui and Hawaiʻi island systems. The cost per MW
REZ enablement for each studied interconnection substation is used in the 2022 IGP System Security
Study for the REZ enablment cost esitmate with new resource plan and system load forecast. Also,
several transmission networks expansion solutions identified in the 2021 REZ study are used in the
2022 IGP System Security Study.
3.1.2 Hawaiian Electric Island-Wide PSCAD Studies (Stage 2 System Impact Study)
In June 2021, Company released a report regarding system-wide dynamic stability condition
assessment for post RFP Stage 2 system conditions. This is the first island-wide system stabilty study
performed in electromagnetic transient (“EMT”) simulation enviroment via a tool called PSCAD/EMTDC
for Oʻahu, Maui and Hawaiʻi island system. The dynamic stability study was performed for a few
selected generation dispatch with a list of high-risk contingency. The report summarizes system
stability performance issue caused by the high penetration of inverter-based resource (“IBR”) and
distributed energy resources (“DER”) and the displacement of synchronou machine-based resource
after the RFP Stage 2 projects online. From the study, it is also recommended that Company should
continue to require and implement GFM technology in all battery energy storage system (“BESS”)
devices for future projects and continue to perform EMT study to evaluate future system stability risks.
3.1.3 2021 System Stability Study
A more comprehensive system stability study for near-term years before the RFP Stage 3 projects
online was conducted for all five islands from summer of 2021 to end of 2022. The study looked into
more stability related topics than what was studied in the Stage 2 System Impact Study. Both PSS/E
and PSCAD were used as simulation tool; however, as part of study results, it is confirmed that at
current stage, PSS/E has great limitation to be used for performing dynamic stability study for systems
with high IBR and DER penetration and for GFM resource modeling and simulation. Important study
recommendations that are used in the 2022 IGP System Security Study are:
• Company should continue to require GFM control for generation paried with BESS component
and procure enough GFM resource to make sure system stability performance within planning
criteria.
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APPENDIX D – SYSTEM SECURITY STUDY
• DER momentary cessation poses high risk to system stability. Daytime peak load high DER
generation with low wind generation dispatch currently poses the highest risk on system
stability. During the daytime, generation from customer-scale inverter-based DER may makeup
the highest proportion of generation, and in the future, this could be also true during the
evening. When there is a three-phase to ground fault that happens at the transmission system,
before the fault get cleared, the voltage across the entire system can be very low (e.g.,
everywhere less than 0.2 pu) during the fault. This magnitude of voltage sag can cause DER to
enter into momentary cessation mode (or trip offline). After the fault being cleared, which
normally takes no more than 5 cycles after fault inception, system voltage would recover within
continous operation range, which means most of system demand would also recover. However,
depending on the inverter model, DER generation may not recover to pre-event level as fast as
the system demand once it enters into momentary cessation mode. This slow DER generation
recovery would take dozens of cycles, which would cause huge system wide generation load
imbalance. Since system physical inertia is already low, the huge generation load imbalance can
potentially cause very fast frequency decline, generation and load tripping, and even system
blackout if frequency is not regulated back to acceptable range within a time limit. From a
recent system event, DER momentary cessation is observed from distribution substation power
quality meter fast recording data. The voltage sag caused by a fault is one of common causes
for DER entering into momentary cessation mode. The momentary cessation exists in both
legacy DER inverters and the latest inverters. More importantly, according to the IEEE 1547-
2018 and Hawaii Rule14h Source Requirement Document, DER momentary cessation is allowed
when system voltage below a certain threshold. Currently, according to the Rule 14h, this low
voltage threshold for all the new inverters is no higher than 0.5 pu. For grid-scale inverters, we
have been not allowing DER momentary cessation from RFP Stage 1 procurement. Currently,
we are working with NREL, doing more inverter testings to better understanding inverter
momentary cessation, and preliminary results indicate certain inverters do indeed enter
momentary cessation or trip at low voltage levels (e.g., under 0.5 p.u.).
• Existing Oʻahu standalone solar grid-scale generation projects have fault ride-through issue,
which cannot recovery pre-event active power generation within 1 second after clearing fault.
According to the historical performance recording, these plants may take more than 20 seconds
to recover 90% of the pre-event generation. It is recommend to manual trip these plants during
the dynamic stability study simulation.
• O’ahu, Maui and Hawai’i Island high-risk contingency list is generated, which will be used for
future dynamic stability studies.
• Substation interconnected GFM resource is critical for Moloka‘i and Lāna‘i system stability once
the existing diesel units are retired.
• System critical clearing times (“CCT”) should be no longer than 24 cycles.
The study also concludes qualitive way to describe impacts from various resources on system stability
performance, which is shown as Figure 9.
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 9 Relative range of system stability contribution by resource type
3.1.4 Waena BESS Stability Study
In 2022, per Commission’s request, a dynamic stability study was conducted in PSCAD/EMTDC to
evaluate impacts from various MW sizes of Waena BESS project on Maui system dynamic stability. The
study results indicates that Maui system could have excessive under-frequency load shedding (“UFLS”)
or even system collapse if the RFP Stage 2 projects power purchase agreement (“PPA”) or applications
are not approved, or project withdrawal happens.
3.1.5 Hawaiʻi Island RFP Stage 3 Grid Needs Assessment
In July 2021, per Commission’s request, a high-level grid needs assessment was performed for Hawaiʻi
island system in order to allow existing system resource retirement and RFP Stage 3 resource
interconnected into the Hawaiʻi island transmission system. From the high-level analysis based on the
proposed RFP Stage 3 resource plans, the near-term steady-state concerns are identified as follows:
• Immediate voltage support needs in East Hawaiʻi island caused by removal of existing
generating units.
• Potential voltage support needs in South Hawaii caused by the absence of nearby local
generation and dynamic voltage regulation (i.e., Tawhiri/Apollo wind plant).
• Potential future thermal overloads in the Waikoloa area if additional future generation is
connected near the area.
In addition to the needs identified in the system security assessment and the high-level steady-state
analysis, system security study needs will need to be assessed after RFP Stage 3 projects are selected.
Also, the RFP Stage 3 resources should be procured in strategic locations to maintain past levels of
resource locational diversity and provide a balanced generation portfolio supplied from different areas
of the island to avoid planning criteria violations such as voltage violations or potential cross-island line
overloads.
3.1.6 RFP Stage 3 injection capacity studies
In 2022, an injection capacity study was performed for Oʻahu, Maui and Hawaiʻi island separately,
which is part of Company’s RFP Stage 3 activities. In the injection capacity studies, locations (i.e.,
transmission lines and substations) with available injection capacity are identified to help project
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APPENDIX D – SYSTEM SECURITY STUDY
bidders prepare their proposals. In the 2022 IGP System Security Study, it is assumed that future grid-
scale generation procured in the near-term years take the location with available injection capacity
first, and later years’ generation interconnections rely on Company’s transmission system expansion.
3.2. Important Assumptions and Scope Limitations
For future grid-scale generation interconnection, the study assumes current interconnection sites with
avaiable grid capacity will be used first. Also, awarded projects that were withdrew from the RFP Stage
2 procurement are assumed to come back to system during the RFP Stage 3 procurement. Once all
existing capacity is occupied, future interconnection sites will be selected based on the renewable
potential, community feedback and cost of system upgrades. It is possible that actual project
interconnections in future procurements are at different locations. Different interconnection locations
can drive very different transmisson system ` capacity upgrade needs.
In each studied case, load is allocated in proportion to existing substation loads, aggregated at
transmission substations, instead of using spatial load forecast. In reality, load may increase at
different rates across the system.
To identify Company’s transmission system needs for accommodating future grid-scale generation
projects as well as system load per the load forecast, DER generation is not considered in the steady
state analyses.
Dynamic stability study is senstive to advanced grid technology development. Therefore, only near
term year scenarios (i.e., before 2040) are analyzed for system dynamic stability. New grid technology,
on both generation side and customer load side, can possibly drive different grid needs regarding
stability. Also, detailed control tunning for future grid-scale generation projects are not included in the
scope of this study, which will be addressed by future generation projects’ interconnection
requirements study.
In this study systems with very high penetration of inverter-based resource (“IBR”) and distributed
energy resource (“DER”) are studied. For example, in the Maui dynamic study, all studied scenarios
represent 100% IBR and DER system scenarios. Currently, industry has very limited operational
experience for a system with 100% IBR and DER. Both study scope and models used for the dynamic
stability study have limitations. As such, there may be other stability risks that are unknown currently,
and hence, not included in the current study, or represented in current models used for this study.
3.3. Modeling
In this study, PSS/E is used for steady state analyses which determines studied system networks
expansion needs and steady state voltage regulation needs; PSCAD/EMTDC is used for dynamic
stability analyses which determine system dynamic stability needs, such as minimum requirement of
GFM resource in a system.
For the steady state analyses, all the PSS/E models which represent studied future year scenarios are
developed based on 2021 benchmarked system power flow cases. Future system demand is modeled
by scaling up load in a fixed rate across the system to match the forecast system total demand. Future
system DER is modeled in a similar way. Future grid-scale generation projects are modeled in an
aggregated way without a detailed modeling for in-plant feeders but one aggregated generation unit
with a properly sized generator step-up transformer (“GSU”).
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APPENDIX D – SYSTEM SECURITY STUDY
The PSCAD/EMTDC models are built based on a model conversion process of converting a PSS/E model
into a PSCAD/EMTDC model. This process is performed in a commercially available software called E-
Tran. All the future PV paired with BESS generation projects are represented by the same inverter
model which were provided by an inverter OEM and assumed to have GFM control. Because of the
limited time frame of performing this study, sensitivity study of using different inverter models from
different inverter OEM for future projects is not performed.
Model preparation and related assumptions are the same as what was used in the 2021 system
stability study, with one addition – P4 type DER. Per Company’s Customer Energy Resource team, for
all DER inverters that are online later than October 1st, 2022, inverter ride-through capability should
comply with Company’s Utility Required Profile (“URP”). According to this rule, a new type of DER, P4
DER, is created to represent the DER that are online later than October 1st, 2022, for transmission
planning study purpose. The P4 type DER ride-through and trip settings are listed in Table 3, Table 4,
and Table 5.
Table 3 P4 DER Voltage Ride-Through and Trip Settings Included in the PSCAD Models
Remain
Connected
(p.u.)
Over-Voltage Under-Voltage
Voltage (p.u.) Delay (s) Voltage (p.u.) Delay (s)
0.1 < V > 1.1 V>1.1 V>1.2 13 0.16 V<0.88 V<0.1 21 2
Table 4 P4 DER Frequency Ride-Through and Trip Settings Included in the PSCAD Models
Remain
Connected
(Hz)
Over-Frequency Under-Frequency
Frequency (Hz) Delay (s) Frequency (Hz) Delay (s)
0.1 < V > 1.1 f>63
f>65
180
0.16
f<57
f<50
180
0.16
Table 5 P4 DER Momentary Cessation Assumptions
UV Block Limit
(Vmc, p.u.)
UV Unblock Limit
(Vmc, p.u.)
Recovery Delay
(∆tsr, s)
Recovery Ramp Rate
(during ∆trr, p.u./s)
0.5 0.5 0.033 2.2
In the dynamic stability study, system load is modeled as ZIP (i.e., constant impedance, constant
current, constant power load or the combinations of them) load, but not complex type load with
explicit modeling of motor load. This load modeling may have limitations of representing system
votlage recovery dynamics during post-fault clearing stage.
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APPENDIX D – SYSTEM SECURITY STUDY
3.4. Study Generation Dispatches
From the resource plans and production simulation results of the selected study years, various
generation dispatches are generated for the study. Every selected generation dispatch represents a
snapshot of system operated under certain degree of stress, which is used to identify if system has
enough capacity or stability resources in the studied situation.
For steady state analysis, the way of creating study dispatch is demonstrated by using Maui system
with addition and retirement of resource in 2035 according to the base scenario resource plan. A
simplified system one-line diagram with REZ is shown in Figure 10. In the study for the 2035, system
load, forecasted for 2036 as 237 MW, is used for the study.
Figure 10 Simplified Maui system single line diagram with future resources and REZ
It can be found that system load can be supplied by generation from one REZ (i.e., Zone B),
combination of two different zones (i.e., Zone A+B, Zone B+C and Zone A+C), or all three zones.
Therefore, system generation dispatches are created to cover those combinations of zones for
performing steady state analyses. The studied system generation dispatches for the 2035 of Maui base
resource plan are summarized in Table 6. All studied system generation dispatches are listed in Section
4 study results.
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APPENDIX D – SYSTEM SECURITY STUDY
Table 6 System Generation Dispatches Studied for Maui Base Scenario Resource Plan, Year 2035
Max Rating Zone A Zone B* Zone C Zone A+C Zone B+C All Zones
Zone A 140 140 0 0 118 0 77.5
Zone B 257 97.3 237.3 33.3 0 116.3 85.5
Zone C 204 0 0 204 119.3 121 74.3
Total Load 237.3 237.3 237.3 237.3 237.3 237.3 237.3
For dynamic stability study, since previous studies indicate daytime peak load high DER low wind
generation dispatch poses the highest risk toward system stability and island wide PSCAD simulation is
extremely time consuming, the study will only focus on a few selected scenarios of daytime peak load,
high DER, with low wind generation dispatch. The process of identifying system load, DER generation
and other grid-scale generation in this studied dispatch is the same as the process described in the
2021 system stability study report. All studied system generation dispatches for the dynamic stability
study are described in Section 4 as well.
3.5. Study Criteria
Company’s transmission planning criteria of O’ahu, Maui and Hawai’i island are used as primary study
criteria. For Molokaʻi and Lanaʻi systems, smaintaining system dynamic stability for a three-phase
bolted fault with 2 seconds duration and for a single-phase to ground fault with 40 ohm fault
impedance and 20 seconds duration is used as the criteria to evlaluate system dynamic stability
condition.
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APPENDIX D – SYSTEM SECURITY STUDY
4. STUDY RESULTS
In this section, both steady state analyses and dynamic stability analyses for each selected study year
in each resource plan are presented. For the scenarios with planning criteria violation, mitigation
solutions are also discussed.
4.1. Oʻahu System Study Results
4.1.1 Steady state analyses
Base scenario resource plan, year 2030
Study descriptions
According to the base scenario resource plan, by 2030, the Oʻahu system will have new generation
from Stage 3 Oʻahu RFP procurement and initial REZ development. Specifically, there will be 450 MW
renewable dispatch generation (“RDG”) and 300 MW firm generation procured through the Stage 3
Oʻahu RFP activity, 510 MW RDG development from the REZ zone 1, 2 and 7, and 543 MW RDG
development from the REZ zone 3, 4, 5 and 6. The grid-scale generation projects from the REZ
development are assumed interconnected at various Oʻahu 138 kV substations and 46 kV substations,
same as assumed in the 2021 REZ study. Specifically, REZ zone 1 interconnection location is Hoʻohana
substation, REZ zone 2 interconnection location is Ewa Nui substation, REZ zone 3 interconnection
location is Kahe substation, REZ zone 4 interconnection location is Waiau substation, REZ zone 5
interconnection location is Halawa substation, REZ zone 6 and 7 interconnection location is Koʻolau
substation, and REZ zone 8 interconnection location is Wahiawa substation. The REZ development is
expected to have both solar and wind generation. In this timeframe, it is also planned to remove 371
MW generation from Waiau power plant. High-level locations of the RFP Stage 3 projects assumed in
the study and developed REZ zones are shown in Figure 11. The detailed system grid-scale resources
changes are summarized in Table 7 and Table 8. By 2031, system annual peak load forecast is 1,364
MW, which is used for the study for this year. System resource summary and the forecasted system
load is summarized in Table 9.
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APPENDIX D – SYSTEM SECURITY STUDY
RFP Stage 3
Projects
1
2
3 4
5
6
7
8
Fully Developed
REZ
Partial Developed REZ
Not Developed REZ
Figure 11 High-Level Oʻahu map for assumed RFP Stage 3 project locations and REZ zone development by 2030
Table 7 Oʻahu Grid-Scale Generation Project Development by 2030, after RFP Stage 2, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
Stage 3 Oʻahu RFP Renewable Dispatchable
Generation
450 2027 Central Oʻahu, West Oʻahu
Firm Generation 300 2029 Central Oʻahu
REZ Development Renewable Dispatchable
Generation
510 2030 Zone 1, 2, and 7
543 2030 Zone 3, 4, 5 and 6
Other Standalone BESS 84 2030 138/46 kV substations
Table 8 Oʻahu Grid-Scale Generation Removal by 2030
Removal Generation Type MW Capacity Year Location
Waiau 3, 4 Fossil Generation 94 2024 Waiau Power Plant
Waiau 5, 6 108 2027
Waiau 7, 8 169 2029
Table 9 Oʻahu System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2030
Firm
Generation
Onshore
Standalone Wind
Standalone
Grid-Scale Solar
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak
Load
1,462 257 168 1,573 219 1,171 1,364
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APPENDIX D – SYSTEM SECURITY STUDY
To evaluate Oʻahu transmission system needs, various system dispatches are generated to stress the
system during normal configuration and contingency configurations, which are listed in Table 10. For
the 543 MW RDG development from the REZ zone 3, 4, 5 and 6, the study investigated two
sensitivities: study case A and E in which all the 543 MW projects interconnected at west side of
system, and study case D in which all the 543 MW projects interconnect at east side of system.
Table 10 Studied System Generation (MW) Dispatches, Oʻahu Base Scenario Resource Plan, Year 2030
Region Substation
Study Cases
A B C Cm1a D E
West
HP, CIP 35 35 198 198 35 35
CEIP 0 177 202 202 0 0
Ewa Nui 324 336 336 256 0 0
Kalaeloa 0 0 208 208 0 0
Kahe 543 271 270 270 0 821
North Hema/Akau 39 39 0 0 0 0
Wahiawa 0 22 0 0 0 142
Central
Hoʻohana 232 232 0 80 276 0
Mahi 120 120 0 0 120 0
Waiau 5 66 150 150 300 366
East Halawa 0 0 0 0 396 0
Koolau 66 66 0 0 237 0
System Total Demand 1,364 1,364 1,364 1,364 1,364 1,364
Study results
Power flow simulations are performed for all the system generation dispatches, for system under
normal configuration and contingency configurations (i.e., N-1 and N-2). The simulation results show
that there is no voltage criteria violation, no 138 kV transmission line overloading in either system
normal configuration or N-2 contingency configuration. However, overloading is identified on Ewa Nui-
Waiau #1 & #2 138 kV lines during one N-1 contingency in study case C. The overloading is caused by
too large an amount of generation dispatched from West region of system, which causes high level
power flowing from the west region to Waiau substation via the Ewa Nui-Waiau #1 & #2 138 kV lines.
When one of these two lines is out of service, the other line will have overloading condition.
Mitigation study – transmission networks expansion
The identified trasmission line overloading can be mitigated by reconductoring the Ewa Nui-Waiau #1
and #2 line as double bundle 795 AAC conductor. High level cost estimate to reconductor these two
138 kV lines is $161.4 million.
D-34 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Mitigation study – portfolio alternatives
An alternative for the Ewa Nui – Waiau #1 and #2 line reconductor could be reducing REZ zone 2
interconnection MW size by 150 MW.
REZ Enablement
In the 2021 REZ study, REZ enablement cost estimate in term of $MM/MW is obtained for each REZ
zones of Oʻahu. Based on these estimate, REZ enablement cost estimate by year 2030 is listed in Table
11. Since there is no detailed information regarding a breakdown of the 543 MW development from
zone 3 to 6 for each zone, only a range of cost estimate is provided by assuming the 543 MW
development come from the lower cost zones or higher cost zones.
Table 11 Oʻahu REZ Enablement Cost Estimate for REZ Development by 2030
REZ Zone 1 2 3 4 5 6 7
Cost ($MM) per
MW
0.21 0.27 1.32 0.82 1.51 0.62 N/A
REZ Enablement
($MM)
24.6 87.6 448.4-819.9 N/A
Base scenario resource plan, year 2035
Study descriptions
In addition to previous system resource changes by 2030, by 2035, the Oʻahu system will have addition
of 64 MW grid-scale standalone BESS and 509 MW offshore wind. There is no further development of
REZ during this time frame. There will be 208 MW firm generation procured and interconnected at the
Kalaeloa substation once the Kalaeloa power plant contract expires. High-level locations of the new
grid-scale generation projects added into system between 2031 and 2035 assumed in the study are
shown in Figure 12. The detailed system grid-scale resources changes are summarized in Table 12 and
Table 13. By 2036, system annual peak load forecast is 1,432 MW, which is used for the study for this
year. System resource summary and the forecasted system load is summarized in Table 14.
D-35 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed REZ
Not Developed
REZ
Offshore Wind
Figure 12 High-Level Oʻahu map for assumed generation projects’ locations by 2035
Table 12 Oʻahu Grid-Scale Generation Project Development between 2031 and 2035, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
Others Firm Generation 208 2033 Kalaeloa Substation
Standalone BESS 64 2035 138/46 kV substations
Offshore wind 509 2035 Koʻolau 138 kV substation
Table 13 Oʻahu Grid-Scale Generation Removal between 2031 and 2035
Removal Generation Type MW Capacity Year Location
Kahuku Wind Onshore Wind 30 2031 Kahuku 46 kV substation
Kapolei
Sustainable
Energy Park
Solar 1 2032 Kahe 46 kV substation
Kalaeloa Solar Solar 5 2032 KS substation
Kahe 1, 2 Fossil 165 2033 Kahe substation
Kalaeloa
Power Plant
Fossil 208 2033 KPLP substation
KREP Solar 5 2034 KREP substation
Table 14 Oʻahu System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2035
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,297 257 509 157 1,573 282 1,295 1,432
D-36 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table 15 summarizes studied system generation dispatches for the 2035. It is worth noting that the
conductor upgrade mitigation solution identified in the 2030 study is not included in the model for the
study for 2035.
Table 15 Studied System Generation (MW) Dispatches, Oʻahu Base Scenario Resource Plan, Year 2035
Region Substation
Study Cases
A B C Cm1 Cm1a D Dm1a E
West
HP, CIP 35 35 198 198 198 35 35 35
CEIP 0 177 202 202 202 0 0 0
Ewa Nui 336 336 336 336 186 0 0 0
Kalaeloa 0 0 208 0 208 0 0 0
Kahe 543 339 396 396 396 0 0 845
North Hema/Akau 39 39 0 0 0 0 0 0
Wahiawa 0 22 0 0 0 0 0 142
Central
Hoʻohana 257 232 0 0 120 0 10 0
Mahi 120 120 0 0 0 0 0 44
Waiau 36 66 92 300 92 255 255 366
East Halawa 0 0 0 0 0 396 396 0
Koolau 66 66 0 0 30 746 736 0
System Total Demand 1,432 1,432 1,432 1,432 1,432 1,432 1,432 1,432
Study results
According to the power flow simulation results, overloading is identified for the Ewa Nui-Waiau #1 and
#2 138 kV lines from the study case C when system is under N-1 contingency configuration, and high
loading condition (96% of emergency rating) is identified for Koolau-Waiau #1 and #2 line, and Halawa-
Koolau line from the study case D when system is under N-2 contingency configuration. It is worth
noting that study case D represents a scenario that majority part of system load (79%) is supplied from
REZ generation and offshore wind farm interconnected at east side of system. The identified high
loading condition indicates the dispatched generation in east side is close to system transfer limit.
Mitigation study – transmission network expansion
Besides the reconductor of Ewa Nui-Waiau #1 and #2 circuits as identified in the 2030 study, there is
no addtional transmission network expansion identified.
Mitigation study – portfolio alternatives
In addition to reducing REZ zone 2 interconnection MW size by 150 MW to avoid overloading the Ewa
Nui-Waiau transmission lines, the REZ zone 6 or 7 interconnection size can be reduced by 10 MW to
avoid high load conditions on the Koolau-Waiau #1 and #2 line, and Halawa-Koolau line.
D-37 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
REZ Enablement
There is no onshore REZ development between 2031 to 2035. However, the offshore wind
development that requires interconnection facility is the 509 MW offshore wind, which requires
expansion of the Koʻolau substation by adding 4 BAAH bay for the offshore wind interconnection. The
cost estimate is $50.6 million.
Base scenario resource plan, year 2045
Study descriptions
In addition to previous system resource changes, by 2045, the Oʻahu system will finish developing the
majority of REZ zone 1, 2, 3, 4, 5, 6 and 7, only 106 MW potential remaining undeveloped. Meanwhile,
452 MW solar potential of the REZ zone 8 will also be developed by 2045. System load is forecasted
with significant growth, reaching 1,692 MW peak demand at 2046, which is used for the study. High
level system map with REZ development is shown in Figure 13. The detailed system grid-scale
resources changes are summarized in Table 16 and Table 17. System resource summary and the
forecasted system load is summarized in Table 18.
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed
REZ
Partial Developed
REZ
Not Developed REZ
Offshore Wind
Figure 13 High-Level Oʻahu map for assumed generation projects’ locations by 2045
Table 16 Oʻahu Grid-Scale Generation Project Development between 2036 and 2045, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ
Development
Renewable
Dispatchable
Generation
521 2040 REZ zone 3, 4, 5, and 6
504 2045
452 2045 REZ zone 8
Other Standalone BESS 1 2040 Hoʻohana substation
32 2045 Hoʻohana substation
D-38 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Recovered
Solar
Standalone Solar 168 2045 Waiver project locations
Recovered Wind Wind 123 2045 Removed wind locations
Table 17 Oʻahu Grid-Scale Generation Removal between 2036 and 2045
Removal Generation Type MW Capacity Year Location
Kahe 3, 4 Fossil 172 2037 Kahe substation
Kawailoa Wind Wind 69 2038 Wahiawa 46 kV
Waianae Solar Solar 27.6 2039 Kahe 46 kV
Na Pua
Makani Wind
Wind 24 2040 Koʻolau 46 kV
Waiver
Clearway
Projects
Solar/Wind 110 2041 Various 138 kV and 46 kV
substations
West Loch
Solar
Solar 20 2044 CEIP 46 kV
Table 18 Oʻahu System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2045
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,126 287 509 441 2,777 315 1,454 1,692
Table 19 summarizes studied system generation dispatch for the 2045. By comparing with previous
study cases, a case (i.e., study case E) with much higher generation from Wahiawa substation (i.e., REZ
zone 8) is considered in the study for 2045.
Table 19 Studied System Generation (MW) Dispatches, Oʻahu Base Scenario Resource Plan, Year 2045
Region Substation
Study Cases
A B C Cm1 Cm1a D E
West
HP, CIP 35 35 198 198 198 35 35
CEIP 0 177 202 202 202 0 0
Ewa Nui 324 336 336 336 226 0 0
Kalaeloa 0 0 208 0 208 0 0
Kahe 588 599 656 656 656 0 588
North Hema/Akau 0 39 0 0 0 0 99
Wahiawa 0 22 0 0 0 0 623
Central
Hoʻohana 120 232 0 0 110 3 0
Mahi 0 120 0 0 0 0 0
Waiau 331 66 92 300 92 300 347
D-39 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
East Halawa 228 0 0 0 0 608 0
Koolau 66 66 0 0 0 746 0
System Total Demand 1692 1692 1692 1692 1692 1692 1692
Study results
Significant 138 kV line overloading and high loading conditions is identified in both N-1 system
contingency configurations and N-2 system contingency configurations from multiple study cases. A
detailed summary of the conductor overloading and high loading is provided in Table 20. 138 kV line
overloading is not identified in the normal system configuration study. Also, there is no steady state
voltage planning criteria violation from the study results.
Table 20 138 kV Line Overloading Summary, Oʻahu Base Scenario Resource Plan, Year 2045
Study Case N-1 Contingency N-2 Contingency
Overloading/High loading
Line
Max. Loading
(%)
Overloading/High loading
Line
Max.
Loading (%)
A None Makalapa-Airport 99
Halawa-Iwilei 98
Halawa-School 97
B Halawa-Hoʻohana #1 101 Halawa-Hoʻohana #1 110
Halawa-Hoʻohana #2 99 Halawa-Hoʻohana #2 107
Ewa Nui-Waiau #1 and #2 98 Makalapa-Airport 98
Halawa-Iwilei 97
Halawa-School 96
C Ewa Nui-Waiau #1 and #2 124 Halawa-Koʻolau 108
Kahe-Hoʻohana #1 and #2 101 Koolau-Waiau #1 and #2 108
Ewa Nui-Waiau #1 and #2 108
Kahe-Hoʻohana #1 and #2 103
Halawa-Hoʻohana #1 and #2 99
Makalapa-Airport 98
Halawa-Iwilei 97
Halawa-School 96
Cm1 Ewa Nui-Waiau #1 and #2 99 Halawa-Koʻolau 108
Makalapa-Waiau 97 Koolau-Waiau #1 and #2 108
Makalapa-Airport 102
Makalapa-Waiau 101
Iwilei-Airport 99
Halawa-Iwilei 97
Halawa-School 97
D None Makalapa-Airport 99
Halawa-Iwilei 98
Halawa-School 97
E Wahiawa-Waiau 150 Wahiawa-Waiau 131
Kahe-Hema 149 Kahe-Hema 130
Akau-Hema 136 Akau-Hema 118
Wahiawa-Akau 122 Makalapa-Airport 109
Makalapa-Waiau 104 Halawa-Koʻolau 108
Koʻolau-Waiau #1 and #2 108
D-40 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Wahiawa-Akau 107
Iwilei-Airport 106
Makalapa-Waiau 105
Halawa-Hoʻohana #1 and #2 103
Kahe-Hoʻohana #1 and #2 97
Halawa-Iwilei 96
Halawa-School 96
Mitigation study – transmission networks expansion
Significant transmission networks expansion will be required in order to interconnect all the grid-scale
generation projects and host the forecasted system load. The transmission networks expansion option
2 identified in the 2021 REZ study is adopted here as the mitigation solution for the overloading and
high loading conditions listed in the study results, which is shown in Table 21. A high-level single line
diagram which represents the proposed transmission networks expansion is shown in Figure 14.
Table 21 Transmission Networks Expansion and High-Level Cost Estimate, Oʻahu Base Scenario Resource Plan, Year 2045
No. Transmission Line Upgrade Type Conductore Requirements Cost Estimate
($MM)
1 Kahe-Akau-Hema-Wahiawa Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 314.1
2 Wahiawa-Kahe New Line, 138 kV Two circuits, with double-
bundled 795 AAC 875.3
3 Wahiawa-Waiau Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 214.1
4 Wahiawa-Waiau New Line, 138 kV Two circuits, with double-
bundled 795 AAC 962.8
5 Waiau-Makalapa #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 72.3
6 Halawa-Ko‘olau Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 172.1
7 Halawa-Ko‘olau New Line, 138 kV One circuit, with 1590 AAC
conductor 195.3
8 Ko‘olau-Waiau #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 233
9 Ko‘olau-Waiau #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 247.4
10 Makalapa-Airport #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
32.1
11 Halawa-School #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
92.8
12 Halawa-Iwilei #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
248.7
D-41 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
13 Airport-Iwilei #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
161.2
WahiawaAkauHema
Kahe
Waiau
Existing 138 kV Line
Existing 138 kV Line ReconductorExisting 138 kV Substation
New 138 kV Line
Halawa
Koʻolau
School
Iwilei
Makalapa
Airport
Waiau
Figure 14 High-Level single line diagram for proposed transmission networks expansion, Oʻahu base scenario resource
plan, year 2045
Mitigation study – portfolio alternatives
Considering the degree of identified overloading conditions and scale of proposed transmission
networks expansion, it is determined that there is no alternative to fully replace the proposed wire
solution considering current electric grid technology developments and renewable procurement
needs.
REZ Enablment
According to the REZ development MW target and the per MW cost estimate for REZ enablement
identified in the 2021 REZ study, a high-level REZ enablment cost for REZ development between 2036
and 2045 is provided in Table 22.
D-42 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table 22 Oʻahu REZ Enablement Cost Estimate for REZ Development between 2036 and 2045
REZ Zone 3 4 5 6 8
Cost ($MM) per MW 1.32 0.82 1.51 0.62 1.25
REZ Enablement
($MM)
1084.6-1468.5 565.0
Base scenario resource plan, year 2050
Study descriptions
By 2050, 3,344 MW of all eight REZ zones will be fully developed. System load is forecasted with
significant growth: 1,829 MW peak demand at 2050, which could possibly cause underground cable
overloading for 138 kV underground cable among School Street, Iwilei and Archer 138 kV substations.
All Kahe fossil generation units will be retired by 2050. Besides switching fossil fuel to biodiesel fuel for
remaining firm units, 153 MW new firm units will be added to the Oʻahu system by 2050. A high-level
system map with REZ development status is shown in Figure 15. The detailed system grid-scale
resources changes are summarized in Table 23 and Table 24. System resource summary and the
forecasted system load is summarized in Table 25.
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed
REZ
Partial Developed REZ
Not Developed
REZ
Offshore Wind
Figure 15 High-Level Oʻahu map with REZ development status by 2050
Table 23 Oʻahu Grid-Scale Generation Project Development between 2046 and 2050, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ
Development
Renewable
Dispatchable
Generation
106 2050 REZ zone 3, 4, 5, and 6
714 2050 REZ zone 8
Other Standalone BESS 18 2050 138 kV Substation
Other Firm Generation 153 2050 Kahe Substation
D-43 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table 24 Oʻahu Grid-Scale Generation Removal between 2046 and 2050
Removal Generation Type MW Capacity Year Location
Kahe 5, 6 Fossil 270 2046 Kahe substation
Table 25 Oʻahu System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2050
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,010 287 509 480 3,558 333 1,497 1,829
Table 26 summarizes studied system generation dispatch for the 2050. It is worth noting that all the
transmission networks expansion identified in the 2045 study is included in the system model for the
2050 study.
Table 26 Studied System Generation (MW) Dispatches, Oʻahu Base Scenario Resource Plan, Year 2050
Region Substation
Study Cases
A B C Cm1 Cm1a D E Em1a
West
HP, CIP 35 35 198 198 198 35 35 35
CEIP 0 177 202 202 202 0 0 0
Ewa Nui 324 336 336 336 186 0 0 0
Kalaeloa 0 0 208 0 208 0 0 0
Kahe 588 736 793 793 793 0 358 358
North Hema/Akau 0 39 0 0 0 0 99 99
Wahiawa 0 22 0 0 0 0 1337 1117
Central
Hoʻohana 120 232 0 0 120 140 0 0
Mahi 0 120 0 0 0 0 0 0
Waiau 331 66 92 300 92 300 0 0
East Halawa 218 0 0 0 0 608 0 220
Koolau 213 66 0 0 30 746 0 0
System Total Demand 1,829 1829 1829 1829 1829 1829 1829 1829
Study results
After the transmission networks expansion proposed for 2045, transmission line high loading and
overloading conditions are still identified from all study cases. A summary of identified high loading
and overloading conditions are listed in Table 27. There is no steady state voltage violation identified
from the study.
D-44 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table 27 138 kV Line Overloading Summary, Oʻahu Base Scenario Resource Plan, Year 2050
Study Case N-1 Contingency N-2 Contingency
Overloading/High loading
Line
Max. Loading
(%)
Overloading/High loading
Line
Max.
Loading (%)
A Archer-School 100 None
Archer-Iwilei 100
B Archer-School 99 Halawa-Hoʻohana #1 97
Archer-Iwilei 99
Halawa-Hoʻohana 96
C Ewa Nui-Waiau #1 and #2 112 Kahe-Hoʻohana #1 101
Archer-School 99 Kahe-Hoʻohana #2 100
Archer-Iwilei 99
Kahe-Hoʻohana #1 97
Kahe-Hoʻohana #2 96
Cm1 Archer-School 99 Makalapa-Waiau #1 97
Archer-Iwilei 99 Makalapa-Airport 96
D Archer-School 100 Halawa-Makalapa 99
Archer-Iwilei 100
E
Makalapa-Waiau #1 101 Wahiawa-Waiau #3 125
Makalapa-waiau #2 99 Wahiawa-Waiau #2 114
Archer-School 98 Wahiawa-Waiau #1 103
Archer-Iwilei 98 Makalapa-Airport 102
Makalapa-waiau #2 101
Iwilei-Airport 99
Em1a None None
Mitigation study – transmission networks expansion
Study results indicate the high loading and potential overloading on the 138 kV underground cables:
Archer-Iwilei and Archer-School. As a wire solution, cable repalcement for these two underground line
is recommended. Meanwhile, overloading and high loading conditions are also identified on Kahe-
Hoʻohana #1 and #2 lines and Hoʻohana-Halawa #1 and #2 lines. The proposed transmission networks
expansion is summarized in Table 28.
Table 28 Transmission Networks Expansion and High-Level Cost Estimate, Oʻahu Base Scenario Resource Plan, Year 2050
No. Transmission Line Upgrade Type Conductore Requirements Cost Estimate
($MM)
1 Kahe-Hoʻohana #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 174.4
2 Kahe-Hoʻohana #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 158.5
3 Hoʻohana-Halawa #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 258.3
4 Hoʻohana-Halawa #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 272.6
D-45 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
5 Archer-School #1 Cable
Replacement
2 cables per phase of 3000KCM
CU XLPE 166.6
6 Archer Iwilei #1 Cable Replacement 2 cables per phase of 3000KCM CU XLPE 178.5
The results of the study case E, in which all REZ zone 8 capacity is dispatched, shows overloading on the
new lines and reconductored lines that connect with Wahiawa substation. Wire-based solution is not
identified for mitigating this overloading, instead, non-wire solution is identified, which will be
discussed in next subsection.
Mitigation study – portfolio and non-wire solutions
To avoid overloading the transmission lines that connect with the Wahiawa substation, it is
recommened to reduce interconnection size of REZ zone 8 by 220 MW. Also, to avoid the 138 kV
underground cable Archer-Iwilei and Archer-School overloading, would require reduction of peak
demand in areas supplied by Archer substation, Kewalo substation and Kamoku substation by 37 MW
(assuming 0.95 inductive power factor).
REZ Enablement
The high-level cost estimate for the REZ enablement of the REZ development between 2046 and 2050
is summarized in Table 29.
Table 29 Oʻahu REZ Enablement Cost Estimate for REZ Development between 2046 and 2050
REZ Zone 3 4 5 6 8
Cost ($MM)
per MW
1.32 0.82 1.51 0.62 1.25
REZ
Enablement
($MM)
86.9-160.1 892.5
Land Constrained scenario resource plan, year 2030
Study descriptions
By 2030, the Oʻahu system will have all new generation from Stage 3 Oʻahu RFP procurement on
transmission and sub-transmisison side. Specifically, there will be 450 MW renewable dispatch
generation (“RDG”) and 300 MW firm generation procured through the Stage 3 Oʻahu RFP activity,
which is the same as this in the base scenario resource plan. Most of these new generation are
expected to be interconnected at Oʻahu 138 kV system. In this time frame, it is also planned to remove
371 MW generation from Waiau power plant. There is no REZ development in the land constrained
scenario resource plan. High-level system map with the new grid-scale generation projects coming
online by 2030 is shown in Figure 16. The assumptions regarding RFP Stage 3 project interconnection
locations are the same as what are used in the base scenario resource plan studies.
D-46 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
RFP Stage 3 Projects
Figure 16 High-Level Oʻahu map, land constrained scenario resource plan, by 2030
The detailed system grid-scale resources changes are summarized in Table 30 and Table 31. By 2031,
system annual peak load forecast is 1,364 MW, which is used for the study for this year. System
resource summary and the forecasted system load is summarized in Table 32.
Table 30 Oʻahu Grid-Scale Generation Project Development by 2030, after RFP Stage 2, Land Constrained Scenario
Resource Plan
Development Generation Type MW Capacity GCOD Location
Stage 3 Oʻahu RFP Renewable Dispatchable
Generation
450 2027 Central Oʻahu, West Oʻahu
Firm Generation 300 2029 Central Oʻahu
Table 31 Oʻahu Grid-Scale Generation Removal by 2030
Removal Generation Type MW Capacity Year Location
Waiau 3, 4 Fossil Generation 94 2024 Waiau Power Plant
Waiau 5, 6 108 2027
Waiau 7, 8 169 2029
Table 32 Oʻahu System Resource Summary and Forecasted Demand (MW), Land Constrained Scenario Resource Plan, Year 2030
Firm Generation Onshore Standalone Wind Standalone Grid-Scale Solar Grid-Scale Hybrid Solar/BESS Standalone BESS DER System Peak Load
1,462 123 168 684 135 1,171 1,364
Table 33 summarizes studied system generation dispatches for the land constrained scenario resource
plan in 2030.
D-47 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table 33 Studied System Generation (MW) Dispatches, Oʻahu Land Constrained Scenario Resource Plan, Year 2030
Region Substation
Study Cases
A B F
West
HP, CIP 35 198 35
CEIP 202 202 67
Ewa Nui 12 12 12
Kalaeloa 0 208 208
Kahe 302.6 270 302
North Hema/Akau 99.4 0 0
Wahiawa 141 0 157
Central
Hoʻohana 112 54 112
Mahi 120 120 120
Waiau 316 300 351
East Halawa 0 0 0
Koolau 24 0 0
System Total Demand 1,364 1,364 1,364
Study results
Power flow simulation results for the three system generation dispatches show that there are no
steady state voltage or transmission line loading planning criteria violations. Hence, there is no
discussion regarding mitigation solutions.
Land Constrained scenario resource plan, year 2035
Study descriptions
In addtion to previous system resource changes by 2030, by 2035, the Oʻahu system will have 105 MW
grid-scale standalone BESS and 400 MW offshore wind. 153 MW Firm resource will also be added to
system by 2035. There will be 208 MW firm generation procured and interconnected at the Kalaeloa
substation once the Kalaeloa power plant is removed. 30 MW wind recovered wind resource from the
retired wind power plant will be added to system to meet the system demand as well. According to the
forecast, system annual peak demand will reach 1,432 MW by 2036, which is used for the study. High-
level system map with the addtion of the grid-scale resources is shown in Figure 17. The detailed
system grid-scale resource changes are summarized in Table 34 and Table 35. System resource
summary and the forecasted system load is summarized in Table 36.
D-48 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
RFP Stage 3 Projects
New Onshore Resource Between 2031 and 2035
Offshore Wind
Figure 17 High-Level Oʻahu map, land constrained scenario resource plan, by 2035
Table 34 Oʻahu Grid-Scale Generation Project Development by 2035, Land Constrained Scenario Resource Plan
Generation Type MW Capacity GCOD Location
Firm Generation 208 2033 Kalaeloa Substation
Firm Generation 153 2035 Waiau Power Plant
Standalone BESS 105 2035 138/46 kV substations
Offshore wind 400 2035 Koʻolau 138 kV substation
Table 35 Oʻahu Grid-Scale Generation Removal by 2035
Removal Generation Type MW Capacity Year Location
Kahuku Wind Onshore Wind 30 2031 Kahuku 46 kV
substation
Kapolei Sustatinable
Energy Park
Solar 1 2032 Kahe substation
Kalaeloa Solar Solar 5 2033 Kahe 46 kV
substation
Kahe 1, 2 Fossil 165 2033 Kahe substation
Kalaeloa Power Plant Fossil 208 2033 KPLP substation
KREP Solar 5 2034 KREP substation
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APPENDIX D – SYSTEM SECURITY STUDY
Table 36 Oʻahu System Resource Summary and Forecasted Demand (MW), Land Constrained Scenario Resource Plan,
Year 2035
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,450 123 400 157 684 240 1,295 1,432
Table 37 summarizes the studied system generation dispatches for the land constrained scenario
resource plan in 2035. New system generation dispatches are added to evaluate system resource
changes.
Table 37 Studied System Generation (MW) Dispatches, Oʻahu Land Constrained Scenario Resource Plan, Year 2035
Region Substation
Study Cases
A B1 B2 C F
West
HP, CIP 35 198 198 35 35
CEIP 197 202 202 177 67
Ewa Nui 12 12 117 12 12
Kalaeloa 0 208 208 0 208
Kahe 297 270 270 20 370
North Hema/Akau 99 0 0 39 0
Wahiawa 141 0 0 22 157
Central
Hoʻohana 217 122 17 217 112
Mahi 120 120 120 120 120
Waiau 290 300 300 366 351
East Halawa 0 0 0 0 0
Koolau 24 0 0 424 0
DER 0 0 0 0 0
System Total Demand 1,432 1,432 1,432 1,432 1,432
Study results
Power flow simulation results for aforementioned system generation dispatches show that there are
no steady state voltage or transmission line loading planning criteria violations. Hence, there is no
discussion regarding mitigation solutions.
Land Constrained scenario resource plan, year 2046
Study descriptions
In addtion to previous system resource changes, by 2045, the Oʻahu system will add another 153 MW
firm geneartion into the system. Also, 169 MW standalone solar and 93 MW wind development from
retired solar and wind locations will be completed by 2045. 169 MW new Grid-scale standalone BESS
will be interconnected to system from transmission substations. System load is forecasted with
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APPENDIX D – SYSTEM SECURITY STUDY
significant growth: 1,692 MW peak demand at 2046. 783 MW DER coupled with 1,567 MWh DER BESS
will be added to the system to supply system load demand. A high-level map for Oʻahu system with
addtion of grid-scale resource since 2036 is shown in Figure 18. The detailed system grid-scale
resources changes are summarized in Table 38 and Table 39. System resource summary and the
forecasted system load is summarized in Table 40.
RFP Stage 3 Projects
New Onshore Resource Between 2031 and 2035
Offshore Wind
New Onshore Resource Between 2036 and 2045
Figure 18 High-Level Oʻahu map, land constrained scenario resource plan, by 2045
Table 38 Oʻahu Grid-Scale Generation Project Development by 2045, Land Constrained Scenario Resource Plan
Generation Type MW Capacity GCOD Location
Standalone BESS 14 2040 Hoʻohana substation
Firm Generation 153 2040 Waiau substation
Standalone Solar 39 2040 Waiver project locations
Wind 93 2040 Retired wind locations
Standalone BESS 145 2045 Hoʻohana substation
Standalone Solar 130 2045 Waiver project locations
Table 39 Oʻahu Grid-Scale Generation Removal by 2045
Removal Generation Type MW Capacity Year Location
Kahe 3, 4 Fossil 172 2037 Kahe substation
Kawailoa Wind Wind 69 2038 Wahiawa 46 kV
Waianae Solar Solar 27.6 2039 Kahe 46 kV
Na Pua Makani
Wind
Wind 24 2040 Koʻolau 46 kV
Waiver
Clearway
Projects
Solar/Wind 104 2041 Various 138 kV and 46 kV
substations
West Loch
Solar
Solar 20 2044 CEIP 46 kV
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APPENDIX D – SYSTEM SECURITY STUDY
Table 40 Oʻahu System Resource Summary and Forecasted Demand (MW), Land Constrained Scenario Resource Plan,
Year 2045
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,432 123 400 169 684 399 3,020 1,692
Table 41 summarizes studied system generation dispatches for the land constrained scenario resource
plan in 2045. By assuming DER technology maturity, system level monitoring and control being ready,
and Company has sufficient DER program, two study cases (i.e., D and E) are created to represent
scenarios where the majority system load is supplied by DER on distribution side. For this case creation
spacial forecast of DER adoption across system is not used, instead, a flat rate of DER adoption across
the system is assumed. Also, neither 46 kV subtransmission circuits nor distribution circuits (25 kV, 12
kV and 4 kV) are modeled in the PSS/E models used for this study. So, it is likely that potential sub-
transmission and distribution system capacity needs in the study case D and E are not captured.
Table 41 Studied System Generation (MW) Dispatches, Oʻahu Land Constrained Scenario Resource Plan, Year 2045
Region Substation
Study Cases
A B1 B2 B2m1a C D E
West
HP, CIP 35 198 198 198 35 35 35
CEIP 202 202 202 202 177 0 0
Ewa Nui 12 12 276 246 12 0 0
Kalaeloa 0 208 208 208 0 0 0
Kahe 302.6 328 328 358 121 0 0
North
Hema/Akau 99.4 0 0 0 39 0 0
Wahiawa 171 0 0 0 22 0 0
Central
Hoʻohana 376 324 60 60 376 0 0
Mahi 120 120 120 120 120 0 0
Waiau 350 300 300 300 366 0 0
East
Halawa 0 0 0 0 0 0 0
Koolau 24 0 0 0 424 0 400
DER 0 0 0 0 0 1,657 1,257
System Total Demand 1,692 1,692 1,692 1,692 1,692 1,692 1,692
D-52 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Study results
High loading and overloading conditions on many 138 kV lines are observed in several study cases. A
summary of the findings regarding transmission line high loading and overloading conditions are listed
in Table 42. There is no voltage planning criteria violation identifed from the study.
Table 42 138 kV Line Overloading Summary, Oʻahu Land Constrained Scenario Resource Plan, Year 2045
Study Case N-1 Contingency N-2 Contingency
Overloading/High loading
Line
Max. Loading
(%)
Overloading/High loading
Line
Max.
Loading (%)
A Halawa-Hoʻohana #1 99 Halawa-Hoʻohana #1 111
Halawa-Hoʻohana #2 96 Halawa-Hoʻohana #2 108
Halawa-Koʻolau 105
Koʻolau-Waiau #1 and #2 103
Halawa-Iwilei 98
Halawa-School 97
Makalapa-Airport 98
B1 Halawa-Hoʻohana #1 104 Halawa-Koʻolau 112
Halawa-Hoʻohana #2 101 Koʻolau-Waiau #1 and #2 109
Halawa-Hoʻohana 96 Halawa-Hoʻohana #1 108
Halawa-Hoʻohana #2 106
Halawa-Iwilei 99
Halawa-School 98
Makalapa-Airport 99
B2 Ewa Nui-Waiau #1 98 Halawa-Koʻolau 112
Ewa Nui-Waiau #2 97 Koʻolau-Waiau #1 and #2 109
Makalapa-Waiau #1 99 Makalapa-Airport 105
Makalapa-Waiau 104
Iwilei-Airport 102
Halawa-Iwilei 99
Halawa-School 98
C None Halawa-Iwilei 99
Makalapa-Airport 99
Halawa-School 98
D None None
E None None
The reason of the high loading and overloading condition is generation congestion and system load
increase. The results of study case A, B1 and B2 indicate that interconnecting future generation
projects, including standalone BESS, in west side or west central part of system could cause generation
congestion on transmission lines. Instead, interconnecting those project on east side of system would
avoid certain transmission line overloading or high loading conditions.
Study results for case D and E also demonstrate that DER resources supplying system load would not
cause transmission line overloading. However, for this case creation instead of using spatial DER
adoption forecast a flat rate of DER adopton increase on top of existing DER adopton across system is
used for modeling future years’ DER generation. To fully demonstrate that adopting DER can avoid
transmission networks expasion, more detailed study will be performed, and system level monitoring
and control of DER will be required.
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APPENDIX D – SYSTEM SECURITY STUDY
Mitigation study – transmission networks expansion
According to the study results, following transmission line upgrades summarized in Table 43 are
proposed to mitigate the identified transmission line high load conditions or overloading conditions. A
simplified single line diagram as Figure 19 shows the proposed line upgrade.
Table 43 Transmission Networks Expansion and High-Level Cost Estimate, Oʻahu Land Constrained Scenario Resource
Plan, Year 2045
No. Transmission Line Upgrade Type Conductore Requirements Cost Estimate
($MM)
1 Waiau-Makalapa #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 72.3
2 Halawa-Ko`olau Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 172.1
3 Halawa-Ko`olau New Line, 138 kV One circuit, with 1590 AAC
conductor 178.3
4 Ko`olau-Waiau #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 233
5 Ko`olau-Waiau #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 247.4
6 Makalapa-Airport #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 32.1
7 Halawa-School #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 92.8
8 Halawa-Iwilei #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 248.7
9 Airport-Iwilei #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 161.2
10 Kahe-Hoʻohana #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 150.5
11 Kahe-Hoʻohana #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 136.7
12 Hoʻohana-Halawa #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 222.8
13 Hoʻohana-Halawa #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 235.1
D-54 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Existing 138 kV Line
Existing 138 kV Line ReconductorExisting 138 kV Substation
New 138 kV Line
Halawa
Koʻolau
School
Iwilei
Makalapa
Airport
Waiau
Kahe HalawaHoʻohana
Figure 19 Simplified single line diagram for proposed transmission networks expansion, Oʻahu land constrained scenario
resource plan, by 2045
Mitigation study – non-wire alternatives
Considering the degree of identified overloading condition and scale of proposed transmission
networks expansion, it is determined that there is no non-wire alternative to fully replace the proposed
wire solution in current electric grid technology development condition.
Land Constrained scenario resource plan, year 2050
Study descriptions
From 2046 to 2050, the only grid-scale resource added to the Oʻahu system as planned is a 119
MW/1,110 MWh grid-scale BESS. Kahe 5, 6, which will be the only remaining fossil generation at Kahe
power plant by 2050, will be retired in 2050. It is also planned to add 1,017 MW DER, coupled with
2,033 MWh DER BESS into system distribution side. System peak load is forecasted to be 1,829 MW by
2050. A high-level map for Oʻahu system with addtion of grid-scale resource is shown in Figure 20. The
detailed system grid-scale resources changes are summarized in Table 44 and Table 45. System
resource summary and the forecasted system load is summarized in Table 46.
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APPENDIX D – SYSTEM SECURITY STUDY
RFP Stage 3 Projects
New Grid-Scale Onshore Resource Between 2031 and 2035
Offshore Wind
New Onshore Grid-Scale Resource Between 2036 and 2045
New Onshore Resource Between 2046 and 2050
Figure 20 High-Level Oʻahu map, land constrained scenario resource plan, by 2050
Table 44 Grid-Scale Generation Project Development by 2050, Land Constrained Scenario Resource Plan
Generation Type MW Capacity GCOD Location
Standalone BESS 119 2050 138 kV Substation
Table 45 Oʻahu Grid-Scale Generation Removal by 2050
Removal Generation Type MW Capacity Year Location
Kahe 5, 6 Fossil 270 2050 Kahe substation
Table 46 Oʻahu System Resource Summary and Forecasted Demand (MW), Land Constrained Scenario Resource Plan,
Year 2050
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,163 123 400 169 684 519 5,097 1,829
Table 47 summarizes studied system generation dispatches for the land constrained scenario resource
plan in 2050. All the transmission networks expansion identified in the 2045 study is included in the
models for study cases listed in the Table 47.
Table 47 Studied System Generation (MW) Dispatches, Oʻahu Land Constrained Scenario Resource Plan, Year 2050
Region Substation
Study Cases
A B1 B2 B2m1a C D E
West HP, CIP 36 198 198 198 35 35 35
D-56 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
CEIP 202 202 202 202 177 0 0
Ewa Nui 12 12 396 206 12 0 0
Kalaeloa 0 208 208 208 0 0 0
Kahe 302.6 345 345 345 138 0 0
North
Hema/Akau 99.4 0 0 0 39 0 0
Wahiawa 171 0 0 0 22 0 0
Central
Hoʻohana 496 444 60 250 496 0 0
Mahi 120 120 120 120 120 0 0
Waiau 366 300 300 300 366 0 0
East
Halawa 0 0 0 0 0 0 0
Koolau 24 0 0 0 424 0 400
DER 0 0 0 0 0 1,794 1,394
System Total Demand 1,829 1,829 1,829 1,829 1,829 1,829 1,829
Study results
High loading and overloading conditions are still observed on a few 138 kV lines in several study cases.
A summary of the findings regarding transmission line high loading and overloading conditions are
listed in Table 48. There is no voltage planning criteria violation identifed from the study.
Table 48 138 kV Line Overloading Summary, Oʻahu Land Constrained Scenario Resource Plan, Year 2050
Study Case N-1 Contingency N-2 Contingency
Overloading/High loading Line Max. Loading (%) Overloading/High
loading Line
Max.
Loading
(%)
A Archer-School 100 Halawa-Hoʻohana #1 99
Archer-Iwilei 100 Halawa-Hoʻohana #2 98
B1 Archer-School 100 Halawa-Hoʻohana #1 98
Archer-Iwilei 100 Halawa-Hoʻohana #2 97
CEIP-Ewa Nui 96
B2 Ewa Nui -Waiau #1 114 Ewa Nui-Waiau #1 100
Ewa Nui -Waiau #2 113 Ewa Nui-Waiau #2 99
Archer-School 100 Makalapa-Waiau #1 97
Archer-Iwilei 100 Makalapa-Waiau #2 96
B2m1a Archer-School 100 None
Archer-Iwilei 100
C Archer-School 101 None
Archer-Iwilei 100
D None None
E None None
High loading and overloading is identified on the 138 kV underground cable Archer-School and Archer-
Iwilei in several study cases. This is due to the system load increase. Simliar to what is observed and
D-57 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
recommended in the base scenario resource plan 2050 study, either cable replacement (2 cables per
phase of 3000KCM CU XLPE) for these two lines or peak load reduction by 37 MW (assuming load
power factor is inductive 0.95) will mitigate the overloading and high loading issues.
Regarding the overloading and high loading on the remaining 138 kV overhead lines, by comparing
study case A, B1, B2 and B2m1a, it is observed that relocating part of new 138 kV standalone BESS
from Ewa Nui substation or Hoʻohana substation to east side of system, such as Halawa substation or
Koʻolau substation will mitigate those high loading or overloading issue.
Mitigation study – transmission networks expansion
To mitigate the high loading and overloading on the 138 kV underground cables, cable replacement is
recommended as Table 49, which is the transmission networks expansion solution for the 2050 in land
constrained resource plan.
Table 49 Transmission Networks Expansion and High-Level Cost Estimate, Oʻahu Land Constrained Scenario Resource
Plan, Year 2050
No. Transmission Line Upgrade Type Conductore Requirements Cost Estimate
($MM)
1 Archer-School #1 Cable
Replacement
2 cables per phase of 3000KCM
CU XLPE 166.6
2 Archer Iwilei #1 Cable
Replacement
2 cables per phase of 3000KCM
CU XLPE 178.5
Mitigation study – non-wire alternatives
Simliar as what is recommended in the base scenario resource plan 2050 study, an alternative for the
cable replacement mitigation listed in the Table 49, could be a reduction in peak demand in areas
supplied by Archer substation, Kewalo substation and Kamoku substation by 37 MW (assuming 0.95
inductive power factor). Also, generation congestion is identified on the west side and west central
part of the system, interconnecting the grid-scale standalone BESS project on the east side of system
will mitigate the generation congestion issue if dispatched to reduce west side generation.
High load scenario resource plan, year 2030
Study descriptions
By 2030, the Oʻahu system will have new generation from Stage 3 Oʻahu RFP procurement and initial
REZ development. Specifically, there will be 450 MW RDG and 300 MW firm generation procured
through the Stage 3 Oʻahu RFP activity, 510 MW RDG development from the REZ zone 1, 2 and 7, and
1,225 MW RDG development from the REZ zone 3, 4, 5 and 6. Most of these new generation will be
interconnected at Oʻahu 138 kV system. The REZ development is expected to have both solar and wind
generation. In this time frame, it is also planned to add 60 MW standalone BESS into system and
remove 371 MW generation from Waiau power plant. System peak load will reach 1,595 MW in 2031,
according to the forecast. The high load scenario resource plan has much more aggresive grid-scale
generation projects interconnection schedule than that in the base scenario resource plan and land
constrained scenario resource plan.
A high-level map for Oʻahu system with addtion of grid-scale resource is shown in Figure 21. The
detailed system grid-scale resources changes are summarized in Table 50 and Table 51. System
resource summary and the forecasted system load is summarized in Table 52.
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 21 High-Level Oʻahu map, high load scenario resource plan, by 2030
Table 50 Oʻahu Grid-Scale Generation Project Development by 2030, High Load Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
Stage 3 Oʻahu
RFP
Renewable
Dispatchable
Generation
450 2027 Central Oʻahu, West Oʻahu
Firm Generation 300 2029 Central Oʻahu
REZ
Development
Renewable
Dispatchable
Generation
510 2030 Zone 1, 2, and 7
1,225 2030 Zone 3, 4, 5 and 6
Other Standalone BESS 60 2030 138/46 kV Substations
Table 51 Oʻahu Grid-Scale Generation Removal by 2030
Removal Generation Type MW Capacity Year Location
Waiau 3, 4 Fossil Generation 94 2024 Waiau Power Plant
Waiau 5, 6 108 2027
Waiau 7, 8 169 2029
Table 52 Oʻahu System Resource Summary and Forecasted Demand (MW), High Load Scenario Resource Plan, Year 2030
Firm
Generation
Onshore
Standalone Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak Load
1,462 123 168 2,419 195 1,147 1,595
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APPENDIX D – SYSTEM SECURITY STUDY
Table 53 summarizes studied system generation dispatch for the 2030.
Table 53 Studied System Generation (MW) Dispatches, Oʻahu High Load Scenario Resource Plan, Year 2030
Region Substation
Study Cases
A B C Cm1a D E
West
HP, CIP 35 35 198 198 35 35
CEIP 0 177 202 202 0 0
Ewa Nui 324 336 336 276 0 0
Kalaeloa 0 0 208 208 0 0
Kahe 588 502 351 351 0 845
North
Hema/Akau 0 39 0 0 0 0
Wahiawa 0 22 0 0 0 142
Central
Hoʻohana 120 232 0 0 232 87
Mahi 0 120 0 0 120 120
Waiau 331 66 300 300 363 366
East
Halawa 131 0 0 0 608 0
Koolau 66 66 0 60 237 0
System Total Demand 1,595 1,595 1,595 1,595 1,595 1,595
Study results
Transmission line high loading and overloading conditions are identified in serval study cases, which
are simliar to the findings in the base scenario resource plan, however, in later years. A summary of the
high loading and overloading results are listed in Table 54. There is no steady state voltage violation
identified from the study.
Table 54 138 kV Line Overloading Summary, Oʻahu High Load Scenario Resource Plan, Year 2030
Study Case N-1 Contingency N-2 Contingency
Overloading/High loading
Line
Max. Loading
(%)
Overloading/High loading
Line
Max.
Loading (%)
A None None
B Halawa-Hoʻohana #1 96 Halawa-Hoʻohana #1 103
Halawa-Hoʻohana #2 101
C Ewa Nui-Waiau #1 102 Halawa-Koʻolau 105
Ewa Nui-Waiau #2 101 Makalapa-Airport 104
Makalapa-Waiau #1 98 Koʻolau-Waiau #1 102
Koʻolau-Waiau #2 102
Makalapa-Waiau #1 101
Iwilei-Airport 100
D None None
E None Halawa-Koʻolau 104
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APPENDIX D – SYSTEM SECURITY STUDY
Koʻolau-Waiau #1 102
Koʻolau-Waiau #2 102
Halawa-Hoʻohana #1 98
Halawa-Hoʻohana #2 96
Mitigation study – transmission networks expansion
To mitigate high loading and overloading issue identified fromt the study, transmission networks
expansion, including both reconductor and adding new circuit, are proposed as listed in Table 55.
Table 55 138 kV Line Overloading Summary, Oʻahu High Load Scenario Resource Plan, Year 2030
Networks Expansion Descriptions Cost Estimate
(Million Dollars) Transmission Line Upgrade Type Conductor Requirements
Waiau-Makalapa #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
46.4
Halawa-Ko`olau Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
110.5
Halawa-Ko`olau New Line, 138 kV One circuit, with 1590 AAC
conductor
114.4
Ko`olau-Waiau #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
149.6
Ko`olau-Waiau #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
158.8
Kahe-Hoʻohana #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
96.6
Kahe-Hoʻohana #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
87.7
Hoʻohana-Halawa #1 Re-conductor One circuit, re-conductor to double-bundled 795 AAC 143
Hoʻohana-Halawa #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
150.9
Ewa Nui – Waiau #1 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
80.5
Ewa Nui – Waiau #2 Re-conductor One circuit, re-conductor to
double-bundled 795 AAC
80.9
Mitigation study – portfolio alternatives
Same as previous study results, a non-wire alternative for deferring the reconductor of Ewa Nui-Waiau
#1 and #2 reconductoring is to reduce interconnection MW size at Ewa Nui substation of future
generation projects from REZ zone 2 development by 150 MW.
REZ Enablement
Based on the REZ enablement cost estimate for each MW generation in all REZ zones, a REZ
enablement cost estimate for REZ project interconnection by year 2030 is listed in Table 56. Since
there is no detailed inforamtion regarding a breakdown of the 1,225 MW development from zone 3 to
6 for each zone, only a range of cost estimate is provided by assuming the 1,225 MW development
come from the lower cost zones or higher cost zones.
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APPENDIX D – SYSTEM SECURITY STUDY
Table 56 Oʻahu REZ Enablement Cost Estimate for REZ Development by 2030
REZ Zone 1 2 3 4 5 6 7
Cost ($MM) per MW 0.21 0.27 1.32 0.82 1.51 0.62 N/A
REZ Enablement ($MM) 24.6 87.6 1,378.8-1,718.0 N/A
High load scenario resource plan, year 2035
Study descriptions
In addtion to previous system resource changes by 2030, by 2035, the Oʻahu system will have 95 MW
grid-scale standalone BESS and 600 MW offshore wind. There is no further development of REZ
between 2031 and 2035. There will be 208 MW firm generation interconnected at the Kalaeloa
substation. By 2035, the BESS MWh of the PV/BESS projects developed in REZ zones in 2030 will be
increased as well. According to the forecast, system annual peak load will reach 1,776 MW by 2036. A
high-level map for Oʻahu system with addtion of grid-scale resource is shown in Figure 22. The detailed
system grid-scale resources changes are summarized in Table 50 and Table 51. System resource
summary and the forecasted system load is summarized in Table 52.
RFP Stage 3
Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed
REZ
Not Developed REZ
Offshore Wind
Figure 22 High-Level Oʻahu map, high load scenario resource plan, by 2030
Table 57 Oʻahu Grid-Scale Generation Project Development by 2035, High Load Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
Others Firm Generation 208 2033 Kalaeloa Substation
Standalone BESS 95 2035 138/46 kV substations
Offshore wind 600 2035 Koʻolau 138 kV substation
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APPENDIX D – SYSTEM SECURITY STUDY
Table 58 Oʻahu Grid-Scale Generation Removal by 2035
Removal Generation Type MW Capacity Year Location
Kahuku Wind Onshore Wind 30 2031 Kahuku 46 kV substation
Kapolei
Sustatinable
Energy Park
Solar 1 2032 Kahe substation
Kalaeloa Solar Solar 5 2032 KS substation
Kahe 1, 2 Fossil 165 2033 Kahe substation
Kalaeloa Power
Plant
Fossil 208 2033 KPLP substation
KREP Solar 5 2034 KREP substation
Table 59 Oʻahu System Resource Summary and Forecasted Demand (MW), High Load Scenario Resource Plan, Year 2030
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak Load
1,297 93 600 157 2,419 290 1,271 1,776
Table 60 summarizes studied system generation dispatch for the 2035. Study case D represents a
scenario in which the 600 MW offshore wind is dispatched, and majority of system load is supplied by
the east side generation. Also, it is worth noting that the transmission network expansion in the 2030
study is included in the model for this 2035 study.
Table 60 Studied System Generation (MW) Dispatches, Oʻahu High Load Scenario Resource Plan, Year 2035
Region Substation
Study Cases
A B C Cm1 Cm1a D E
West
HP, CIP 35 35 198 198 198 35 35
CEIP 0 177 202 202 202 0 36
Ewa Nui 324 336 336 336 306 0 0
Kalaeloa 0 0 208 0 208 0 0
Kahe 588 683 551 551 551 0 845
North
Hema/Akau 0 39 0 0 0 0 0
Wahiawa 0 22 0 0 0 0 142
Central
Hoʻohana 120 232 0 0 0 0 232
Mahi 0 120 0 0 0 0 120
Waiau 331 66 281 489 281 296 366
East
Halawa 305 0 0 0 0 608 0
Koolau 73 66 0 0 30 837 0
System Total Demand 1,776 1,776 1,776 1,776 1,776 1,776 1,776
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Study results
Significant transmission line high loading and overloading conditions are identified from the study
results, which are summarized in Table 61. The high loaded and overloaded transmission lines indicate
both generation congestion and high system loading issue. More importantly, the study results also
indicates that when system load reach closing to 1.8 GW magnitude, system generation dispatch
should maintain certain balance between east, central and west of system, or large amount of power
transfer from one side to another side of system would cause trasmission line overloading. Study does
not identify any steady state voltage planning criteria violation.
Table 61 138 kV Line Overloading Summary, Oʻahu High Load Scenario Resource Plan, Year 2035
Study Case N-1 Contingency N-2 Contingency
Overloading/High loading
Line
Max. Loading
(%)
Overloading/High loading
Line
Max.
Loading (%)
A Archer-School 97 Makalapa-Airport 105
Archer-Iwilei 97 Halawa-Iwilei 103
Halawa-School 103
Iwilei-Airport 101
B Ewa Nui-Waiau #1 and #2 101 Makalapa-Airport 104
Archer-School 96 Halawa-Iwilei 102
Archer-Iwilei 96 Halawa-School 102
Iwilei-Airport 100
Waiau-Mahi 97
C Ewa Nui-Waiau #1 112 Makalapa-Airport 108
Ewa Nui-Waiau #2 111 Halawa-Iwilei 103
Archer-School 96 Halawa-School 102
Archer-Iwilei 96 Iwilei-Airport 103
Ewa Nui-Waiau #1 96
Ewa Nui-Waiau #2 96
Cm1 Archer-School 96 Makalapa-Airport 114
Archer-Iwilei 96 Halawa-Iwilei 103
Halawa-School 102
Iwilei-Airport 111
Makalapa-Waiau 97
D Archer-School 97 Makalapa-Airport 104
Archer-Iwilei 97 Halawa-Iwilei 103
Halawa-School 102
Iwilei-Airport 101
E Archer-School 96 Makalapa-Airport 103
Halawa-Iwilei 102
Halawa-School 101
Iwilei-Airport 99
Waiau-Mahi 96
Mitigation study – transmission networks expansion
To mitigate high loading and overloading issue identified fromt the study, transmission networks
expansion, including both reconductor and adding new circuit, are proposed as listed in Table 62.
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Table 62 138 kV Line Overloading Summary, Oʻahu High Load Scenario Resource Plan, Year 2035
Networks Expansion Descriptions Cost Estimate
(Million Dollars) Transmission Line Upgrade Type Conductor Requirements
Makalapa-Airport Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 23.9
Halawa-School Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 69.1
Halawa-Iwilei Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 185
Airport-Iwilei Re-conductor One circuit, re-conductor to
double-bundled 795 AAC 119.9
For the high loading condition on Archer-Iwilei and Archer-School lines, it is recommend to keep
monitoring on the two lines, and prepare solutions to reduce peak load on the related substations (i.e.,
Archer, Kewalo and Kamoku) to avoid these two underground cable having overloading issue.
Mitigation study – portfolio and/or non-wire alternatives
Due to the magnitude of overloading conditions, identification of portfolio change or non-wire
alternative of the proposed mitigation solution in Table 62 is not pursued in this study. The non-wire
alternative can be re-evaluated when more detailed information regaridng system is obtained, such as
detailed load forecast and future generation interconnection locations.
REZ Enablement
There is no REZ development between 2021 and 2035. The cost for interconnecting 600 MW offshore
wind at Koʻolau substation is $50.6 million, without the cost of transmisison networks expansion,
which was estimated in the 2021 REZ study.
4.1.2 Dynamic Stability Study
The O’ahu system in near-term years 2027 and 2035 for both the base scenario resource plan and land
constrained resource plan are selected for performing dynamic stability study to evaluate system
dynamic stability performance. Considering the O’ahu system has similar grid-scale generation
resources by the RFP Stage 3 GCOD in both plans, only the base scenario resource plan is studied for
2027. Both resource plans are studied for the 2035.
System generation dispatch for daytime peak load with high DER generation, which poses the highest
risk to the system stability according to the past studies, is modeled for the dynamic stability study,
with simulations of a high-risk contingency. The high-risk contingencies for O’ahu system are 1) P3
planning event - the largest GFM resource is out-of-service, and a three-phase fault happens at gen-tie
of another grid-scale GFM resource resulting in the loss of the GFM resource, and 2) P5 planning event
- delayed fault clearing of a three-phase fault on a transmission line close to load center.
Base scenario resource plan, year 2027
Study descriptions and study results
According to the resource plan, a system generation dispatch that represents daytime peak load with
high DER generation scenario is created (as Table 63) and modeled in PSCAD/EMTDC.
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Table 63 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu Base Scenario
Resource Plan, Year 2027
Generation Station Dispatched (MW) Gen/System Load (%) Capacity (MW)
H-Power 35 2.8 68.5
Waiver Standalone PV 117 17.2 168
Stage 1 PV/BESS (GFL) 101 140
KES (GFM) 0 27 135
Stage 2 PV/BESS (GFM) 69 94
Stage 3 PV/BESS (GFM) 273 450
Wind 0 0 123
DER 670 53 1,004
System Load (MW) 1,265
GFM MW Headroom
(Excluding KES)/DER
Generation
0.3
PSCAD simulations with a total simulation time of 25 seconds are performed with three-phase to
ground faults applied at 10 seconds. For the simulated P3 planning event, it is assumed that the KES is
out of service before the fault happens. Simulation results for the P3 planning event are shown in
Figure 23 and for the P5 planning event are shown in Figure 24.
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Figure 23 Dynamic stability simulation results, O’ahu base scenario resource plan, year 2027, P3 planning event
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Figure 24 Dynamic stability simulation results, O’ahu base scenario resource plan, year 2027, P3 planning event
The PSCAD simulation results indicate two stages of UFLS in the P3 planning event, which is a severe
planning criteria violation. Acceptable dynamic stability performance is observed in the P5 planning
event. In the P3 planning event, frequency nadir reaches below 58.5 Hz; however, in the P5 planning
event, frequency nadir still maintains above 59.5 Hz, which indicate sufficient stability margin during
the event. The results comparison between the studied P3 planning event and the studied P5 planning
event indicates the P3 planning event poses higher stability risk to the O’ahu system.
According to the past studies, maintaining available contingency reserve in the form of MW headroom
(i.e., contract MW capacity minus dispatched MW generation) on GFM resources is critical for
maintaining system stability and avoiding excessive UFLS. To mitigate the planning criteria violation
identified from the P3 planning event, system generation is re-dispatched by turning on more
synchronous machine-based generation and reducing the dispatch of the Stage 2 and 3 project GFM
generation to ensure contingency reserve from GFM resources. The re-dispatched system generation
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dispatch is shown in Table 64. After the re-dispatch, system available MW headroom from GFM
resource (excluding KES) over DER generation increase to 0.5 from the previous 0.3. The P3 planning
event results with this updated system generation dispatch. Simulation results are shown in Figure 25.
For GFM provided from paired energy resources, operational interfaces to support management of
contingency reserve may be require additional consideration over that considered in the present
requirements. The simulation results indicate that after the system generation re-dispatch (i.e.,
dispatching more synchronous machine generation to provide contingency reserve from GFM
resources), system stability can be maintained within planning criteria. However, system frequency
nadir is still below 59 Hz (the triggering point of the first stage of the instantanous UFLS is 58.9 Hz),
which indicates very limited stability margin of the system during the simulated system event.
It is worth noting that even though the minimum contingency reserve has been defined as a ratio of
available MW headroom from GFM resources over DER generation, to achieve the desired ratio
required more synchronous machine-based resources be online in order create the reserve headroom
on GFM, assuming the available GFM IBR in the resource plans. Therefore, the results represent the
response of the increased GFM contingency reserve and required online synchronous machine-based
resources which also provide effective contribution toward maintaining system stability. It is possible
that adding more GFM resource into the resource plans may provide the needed system stability
without requiring operation of synchronous machines; this could be confirmed through additional
study.
Table 64 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu Base Scenario
Resource Plan, Year 2027
Generation Station Dispatched (MW) Gen/System Load (%) Capacity (MW)
H-Power, KPLP 168 13 277
Waiver Standalone PV 117 17 168
Stage 1 PV/BESS (GFL) 101 140
KES (GFM) 0 17 135
Stage 2 PV/BESS (GFM) 0 94
Stage 3 PV/BESS (GFM) 209 450
Wind 0 0 123
DER 670 53 1,004
System Load (MW) 1,265
GFM MW Headroom
(Excluding KES)/DER
Generation
0.5
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Figure 25 Dynamic stability mitigation study results, O’ahu base scenario resource plan, year 2027, P3 planning event,
with system re-dispatch
Base scenario resource plan, year 2035
Study descriptions and study results
According to the resource plan, a system generation dispatch that represents daytime peak load with
high DER generation scenario for 2035 is created (as Table 65) and modeled in PSCAD/EMTDC. In this
dispatch, due to the REZ development and new grid-scale standalone BESS interconnected to the
system, the O’ahu system has much more grid-forming resources than in 2027. The ratio of available
MW headroom from GFM resources (exclude KES) over DER generation reaches 1.65. The P3 planning
event is simulated in this system model, and results are shown in Figure 26.
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Table 65 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu Base Scenario
Resource Plan, Year 2035
Generation Station Dispatched (MW) Gen/System Load (%) Capacity (MW)
H-Power 47 3 68.5
Waiver Standalone PV 117 10 168
Stage 1 PV/BESS (GFL) 19 140
KES (GFM) 0 13 135
Stage 2 PV/BESS (GFM) 13 94
Stage 3 PV/BESS (GFM) 167 450
REZ 148 11 1,053
New Standalone BESS
(GFM)
0 0 147
Wind 0 0 123 + 400
DER 858 63 1,295
System Load (MW) 1,369
GFM MW Headroom
(Excluding KES)/DER
Generation
1.65
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Figure 26 Dynamic stability study results, O’ahu base scenario resource plan, year 2035, P3 planning event
Simulation results indicate that the O’ahu system stability performance is within planning criteria limit
and has sufficient stability margin.
Land constrained scenario resource plan, year 2035
Study descriptions and study results
In the land constrained scenario resource plan, it is assumed that the REZ development will not
happen. Instead, after the RFP Stage 3 GCOD, grid-scale resources will be only offshore wind and
standalone BESS. Since at the time of performing this study, offshore wind GFM technology is not
commercially available, it is assumed that the offshore wind will not provide GFM type stability
response in the study scope. According to the resource plan, a system generation dispatch that
represents daytime peak load with high DER generation scenario for 2035 is created (as Table 66) and
modeled in PSCAD/EMTDC. The P3 planning event is simulated in this system model, and results are
shown in Figure 27.
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Table 66 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu Land Constrained
Scenario Resource Plan, Year 2035
Generation Station Dispatched (MW) Gen/System Load (%) Capacity (MW)
H-Power 68 5 68.5
Waiver Standalone PV 117 14 168
Stage 1 PV/BESS (GFL) 79 140
KES (GFM) 0 22 135
Stage 2 PV/BESS (GFM) 52 94
Stage 3 PV/BESS (GFM) 243 450
New Standalone BESS
(GFM)
0 0 147
Wind 0 0 123 + 509
DER 810 59 1,295
System Load (MW) 1,369
GFM MW Headroom
(Excluding KES)/DER
Generation
0.44
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Figure 27 Dynamic stability study results, O’ahu land constrained scenario resource plan, year 2035, P3 planning event
UFLS is not identified from the 25 seconds simulation results, which means system stability
performance stays within the planning criteria. However, a trend of decling frequency is observed. This
trend is caused by the faded virtual inertia response from the online GFM resources which reaches
their steady state generation limit. Considering the trend of the frequency, without adding more active
power generation to the grid, the frequency my trigger the kicker block or the first block of UFLS if the
simulation time is longer than 25 seconds.
To better understand the stability margin of the study case for the year 2035 in the land constrained
scenario resource plan, the same P3 planning event is simulated with one more GFM resource offline
due to maintenance prior to the system event. In this case, the ratio of available MW headroom from
GFM resources over DER generation reduces to 0.36 from 0.44. Simulation results are shown in Figure
28.
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Figure 28 Dynamic stability study results, O’ahu land constrained scenario resource plan, year 2035, P3 planning event,
with one more GFM resource out-of-service
For the examined case, system collapse was observed. These results indicate that even though for a
regular P3 planning event the system does not have any UFLS load shedding (as Figure 27), the system
would not survive the same fault with one more GFM resource pre-event outage. Therefore, system
stability margin is limited and a higher ratio of available MW headroom from GFM resource over DER
generation is required.
During the Stage 3 Quick Stability Study, a PSCAD simulation was performed for system generation
dispatch with daytime peak load high DER generation in 2030 with a P3 planning event. The system
generation dispatch is created according to an outdated land constrained scenario resource plan which
has more grid-scale standalone BESS resources and achieve 0.7 of avaiable MW headroom from GFM
resource over DER generation. This can be observed by comparing the system generation dispatch (in
Table 67) studied in the Stage 3 Quick Stability Study and the dispatched studied in the current 2022
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IGP system security study (shwon in Table 66). The simulation results obtained in the Stage 3 Quick
Stability Study are shown in Figure 29, which indicates system stability performance within planning
criteria and sufficient stability margin.
Table 67 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, O’ahu land constrained
scenario resource plan (GNA Stage 3), year 2030
Generation Station Dispatched (MW) Gen/System Load (%) Capacity (MW)
H-Power, New Firm
(assumed as LM6000 unit)
102 8 211
Waiver Standalone PV 117 10 168
Stage 1 PV/BESS (GFL) 11 140
KES (GFM) 0 20 135
Stage 2 PV/BESS (GFM) 0 94
Stage 3 PV/BESS (GFM) 262 450
New Standalone BESS
(GFM)
0 0 321
Wind 15 1 123 + 509
DER 770 60 1,030
System Load (MW) 1,279
GFM MW Headroom
(Excluding KES)/DER
Generation
0.7
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Figure 29 Dynamic stability study results, O’ahu land constrained scenario resource plan (GNA Stage 3), year 2030, P3 planning event
In addition to short term frequency stability, the systems voltage recovery performance post fault
clearing is also analyzed by comparing the rms voltage at the Halawa bus from all forementioned
simulation cases for the P3 planning event. Generally, with faster voltage recovery, generation
resources can recover to pre-disturbance generation levels faster and the system has better stability
performance as well as a lower chance of having fault induced delayed voltage recovery (“FIDVR”). The
comparison is shown in Figure 30, which illustrates different system voltage recovery performance
under different amount of available grid forming resources. With more available GFM resources (i.e.,
higher the ratio of available MW headroom from GFM resource over DER generation), system voltage
recovery is faster. The fewer GFM resource, voltage recovery is slower. Once the recovery time is
beyond a certain limit, system will have high risk of not being able to recover voltage post fault
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clearing, which means system collapse. Based on this observation, and past studies, it is recommended
that at any time for O’ahu system the ratio of available MW headroom from GFM resources over DER
generation should be no lower than 0.7.
It is important to point out that in addtion of fast active power injection, using GFM resouces to
provide fast reactive current support during systme fault and post-fault clearing stage will be more and
more important when more synchronous generation resouces are displaced by grid-scale IBR and DER
resouces. This is not only for Oʻahu system, but applicable for all five island systems. With further
studies, the detailed reactive current injection requirement will be added into the GFM functions and
capability requirement in future generation resouce procurement.
This study assumes that the GFM resources have adequate energy (MWh) to support and ride through
the examined contingencies. Additionally, because of existing limitations in the “state of the art” of
EMT modeling of IBR the DC energy source representation is idealized for the GFM resources. To
provide adequate dynamic support the GFM resources should be operated to maintain adequate
energy (MWh) to respond to system events.
Figure 30 Comparison of system voltage recovery performance post fault clearing
4.2. Maui System Study Results
4.2.1 Steady state analyses
Base scenario resource plan, year 2027
Study descriptions
By 2027, the Maui system will have new generation from Stage 3 RFP procurement which will be 171
MW RDG and 36 MW firm generation, interconnected to Maui 69 kV system. Meanwhile, by 2027, the
Maui system will finish Waena switchyard construction, Kahului Power Plant (“KPP”) retirement and
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conversion of KPP K3 and K4 units to synchronous condensers, and Maalaea Power Plant (“MPP”) unit
10-13 retirement. The system peak load is forecasted to reach 207 MW by 2028. High-level locations of
the RFP Stage 3 projects assumed in the study and planned REZ zones are shown in Figure 31. It is
assumed in the study that the RFP Stage 3 projects will be interconnect at Lahainaluna substation (60
MW), MPP-Waiinu line (30 MW via a new substation STG 3.1), MPP-Lahainaluna line (30 MW via a new
substation STG 3.2), KWP 1 substation (30 MW) and Kealahou substation (21 MW). The 60 MW line
interconnection generation is shown in a high-level one line diagram as Figure 32. The 36 MW firm
generation is assumed to be interconnected at Waena switchyard. The detailed system grid-scale
resources changes are summarized in Table 68 and Table 69. By 2028, system annual peak load
forecast is 207 MW, which is used for the study for this year. System resource summary and the
forecasted system load is summarized in Table 70.
A
A
A
C
C
B
RFP Stage 3
Projects
A B C REZ
Figure 31 High-Level Maui map for assumed RFP Stage 3 project locations by 2027
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MPPLahainaluna
STG3.2
STG3.1
Waiinu
30 MW
30
MW
Existing 69 kV Line
Existing 69 kV Substation
Stage 3 RFP Project
New 69 kV Substation
30 MW
Figure 32 High-Level single line diagram for the two line interconnection RFP Stage 3 projects, Maui system base scenario
resource planning, year 2027
Table 68 Maui Grid-Scale Generation Project Development by 2027, after RFP Stage 2, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
Stage 3 Maui RFP Renewable Dispatchable
Generation
171 2027 West Maui, Central Maui
and South Maui
Firm Generation 36 2027 Central Maui
Table 69 Maui Grid-Scale Generation Removal by 2027
Removal Generation Type MW Capacity Year Location
Kaheawa Wind Power 1 Wind Generation 30 2027 KWP 1 substation
Kahului 1-4 Fossil Generation 32.5 2027 Kahului Power Plant
Maalaea 10-13 Fossil Generation 49.4 2027 Maalaea Power Plant
Table 70 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2027
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
197.5 42 296 40 170.7 207
Table 71 summarizes studied system generation dispatches for the 2027. The studied dispatches
represent all possible combinations of differnt REZ zones supplying Maui system load.
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Table 71 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2027
Aggregated Generation Capacity Rating
(MW)
Zone A Zone B* Zone C* Zone A+C All Zones
Zone A 161 161 0 0 160 70
Zone B 313.5 46 207 106 0 70
Zone C 101 0 0 101 101 67
Total Load 207 207 207 207 207 207
*Studied variation of dispatches in the zone
Study results
Power flow simulations are performed for all stuided system generation dispatches with normal
system configuration and N-1 contingency configurations. From the study results for system with
normal configuration, there are no steady state voltage planning criteria violations or transmission
element loading violations. For the system with N-1 contingency configurations, transmission line
overloadng is identified, which is shown as percentage of conductor emergency rating. Steady state
voltages are within planning criteria acceptable limits. A brief summary of identified overloading
results are listed in Table 72.
Table 72 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2027
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
Overloading Element Max. Loading (%) Overloading
Element
Max. Loading(%)
Zone A None Lahaina-
Lahainaluna 69kV
Line
126
Zone B_1 None None
Zone B_2 None None
Zone C_1 None None
Zone C_2 None Wailea-Auwahi
69kV Line
102
Zone A+C None None
All Zones None None
Mitigation study – transmission networks expansion
To mitigate the transmission line overloading conditions listed above, reconductoring of the
overloading transmisison lines is proposed. The interconnecting 60 MW at the Lahainaluna substation
in west Maui would also result in a Single Point of Failure MW value of 60 MW occurring when the
MPP-Lahaina line is out of service. To solve this issue, it is propsed to add a normally closed circuit
breaker at Mahinahina Substation to connect the west Maui Lahainaluna-Mauka and Lahainaluna-
Makai two radial lines as a normal closed loop. A list of transmission networks expansion proposed for
Maui system is listed in Table 73. A high-level one line diagram in Figure 33 demonstrates the proposed
transmission networks expansion.
Table 73 Transmission Networks Expansion and High-Level Cost Estimate, Maui Base Scenario Resource Plan, Year 2027
Networks Expansion Descriptions Cost Estimate
(Million Dollars) Transmission Line Upgrade Type Conductor Requirements
Lahaina-Lahainaluna Re-conductor One circuit, re-conductor to
556 AAC
2.5
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Waena-Kanaha Re-conductor One circuit, re-conductor to
556 AAC
6.1
Wailea-Auwahi Re-conductor One circuit, re-conductor to 556 AAC 1.8
Mahinahina Substation Expand West network Install one 69kV circuit breaker 2.7
M
To Napili (Mauka)
M
M
To Lahainaluna Sub (Mauka)
To Napili (Makai)To Lahaina Sub (Makai)
CB
Lahaina
Lahainaluna
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Equipment
MPP
Waena
PukalaniKanaha
Kealahou
AuwahiWailea
Figure 33 High-Level single line diagram for proposed transmission networks expansion, Maui base scenario resource plan, year 2027
Mitigation study – portfolio alternatives and non-wire solutions.
The transmission line Lahiana-Lahainaluna reconductoring work could be avoided by reducing MW
interconnection total at the west Maui side (at Lahainaluna substation, KWP 1 substation, Lahainaluna-
MPP line interconnection) by 24 MW. Waena-Kanaha and Wailea-Auwahi reconductor can be avoided
by reducing the interconnection total at Waena switchyard and Kealahou substation by 18 MW.
Reducing MW interconnections in these locations would require additional procurements somewhere
else in the system, which, depending on size and location, might also require new or upgraded
transmission. There is no non-wire alternative solution for deferring adding a circuit breaker in the
Mahinahina substation to close west Maui loop.
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REZ enablment
There is no REZ development by 2027, hence, there is no REZ enablement cost estimate.
Base scenario resource plan, year 2035
Study descriptions
In addtion to previous system resource changes by 2027, the Maui system resource plan provides 66
MW grid-scale onshore wind generation and 37 MW PV/BESS generation as addtional generation
interconnected at Maui transmission system by 2035. This new generation will be developed in the
Maui REZ zone C. Also, it is planned that the MPP unit 1 to 9 will be removed by 2030 and wind power
generation KWP 2 and Auwahi will be retired by 2033. The system annual peak load is forecasted to
reach 235 MW by 2036. A high-level Maui system map with locations of the RFP Stage 3 projects
assumed in the study and developed REZ zones by 2035 is shown in Figure 34. In the total 103 MW
new grid-scale generation project from the REZ zone C development, it is assumed that 60 MW
generation will be interconnected at Waena switchyard, and the remaining 43 MW will be
interconnected at a new substation REZ C.1 on the Waena-MPP line, which is shown as Figure 35.
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
Figure 34 High-Level Maui map for assumed future grid-scale project interconnection locations by 2035
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MPP
REZC.1
Waena Switch Yard
21.5
MW
Existing 69 kV Line
Existing 69 kV Substation
REZ C New Generation
New 69 kV Substation
21.5
MW
21.5 MW
Figure 35 High-level single line diagram for the 43 MW line interconnection project, Maui base scenario resource planning, year 2035
The detailed system grid-scale resources changes are summarized in Table 74 and Table 75. System
resource summary and the forecasted system load is summarized in Table 76.
Table 74 Maui Grid-Scale Generation Project Development between 2028 and 2035, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development Onshore Wind
Generation
5 2029 REZ Zone C
Onshore Wind
Generation
8 2030 REZ Zone C
Onshore Wind
Generation
53 2035 REZ Zone C
Solar/BESS 37 2035 REZ Zone C
Table 75 Maui Grid-Scale Generation Removal between 2028 and 2035
Removal Generation Type MW Capacity Year Location
Maalaea Power Plant Units
1-9
Fossil 40.5 2030 MPP
Kaheawa Wind Power 2 Onshore Wind
Generation
21 2033 KWP 2 Substation
Auwahi Wind Onshore Wind
Generation
21 2033 Auwahi Substation
Table 76 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2035
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
152 66 333 40 202 237
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Table 77 summarizes studied system generation dispatches for the 2035. It is worth noting that the
transmission networks expansion requirement identified in the 2027 study is assumed to be
implemented before 2027 to mitigate the transmission line overloading issues.
Table 77 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2035
Aggregated Generation Capacity
Rating (MW)
Zone A Zone B Zone C Zone A+C Zone B+C All Zones
Zone A 140 140 0 0 118 0 77.5
Zone B 257 97 237 33 0 116 85.5
Zone C 204 0 0 204 119 121 74
Total Load 237 237 237 237 237 237 237
Study results
Power flow simulations are performed for all the system generation dispatches, for normal
configuration and N-1 contingency configurations. Simulation results show that there is no
transmission equipment overloading issue or steady state voltage planning criteria violation for the
system with normal configuration. However, both transmission equipment overloading and
undervoltage violations are identified for N-1 contingency configurations. In Table 78, a summary of
overloading results is listed. There are three 69/23 kV tie transformers currently supplying the Maui
system 23 kV networks. For the contingencies of losing one 69 kV feed for the tie transformers, the
remaining two tie transformers have an overloading issue when they need supply all the 23 kV
networks load. Additionally, this condition results in voltages outside planning criteria limits. An
example shown in Figure 36 illustrates the tie transformer overloading issue and the undervoltage
issue.
Table 78 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2035
Generation Dispatch
N-1 Contingency Configuration
Overloading Element Max. Loading(%)
Zone A Kanaha 69/23kV Tie Tsf 1
and Tie Tsf 2 112
Zone B Kanaha 69/23kV Tie Tsf 1
and Tie Tsf 2 112
Zone C Kanaha 69/23kV Tie Tsf 1
and Tie Tsf 2 111
Zone A+C Kanaha 69/23kV Tie Tsf 1
and Tie Tsf 2 108
Zone B+C Kanaha 69/23kV Tie Tsf 1
and Tie Tsf 2 109
All Zones Kanaha 69/23kV Tie Tsf 1
and Tie Tsf 2 109
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 36 Overloading on tie transformers and undervoltage in 23 kV networks when losing one 69 kV feed for the 23 kV
networks
Mitigation study – transmission networks expansion
To mitigate the tie transformers’ overloading issue and the 23 kV networks undervoltage issue, it is
proposed to add another 69 kV line between MPP and STG 3.1 substation, and from STG 3.1 to Waiinu
substation. It is worth noting that there are other options to mitigate the tie transformers’ overloading
issue and the 23 kV networks undervoltage issue, such as replacing the tie transformers or adding
generation in the 23 kV networks. Adding this new line can remove losing the 69 kV feed for the 23 kV
networks from the N-1 contingency list and allow for increased future grid-scale generation
interconnecting to the Maui transmission system via the STG 3.1 substation.
It is also proposed that a new line is added between Waena switchyard and MPP as well as adding a
new substation, REZ C.1, interconnecting both lines between the Waena switchyard and MPP. This new
substation also can be used for future grid-scale generation interconnection in the REZ development.
All aforementioned mitigation solutions are illustrated in Figure 37. Cost estimate for the proposed
solution is listed in Table 79.
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 37 Proposed Maui transmission networks expansion, Maui base scenario resource plan, year 2035
Table 79 Transmission Networks Expansion and High-Level Cost Estimate, Maui Base Scenario Resource Plan, Year 2035
Networks Expansion Descriptions Cost Estimate
(Million Dollars) Transmission Line/Substation Upgrade Type Upgrade Requirements
MPP – REZC.1 Sub – Waena New Transmission Line One circuit, 556 AAC 25.0
MPP Substation New Transmission Line Install One 69kV circuit
breaker
2.9
REZ C.1 Substation New Substation Adding 3 BAAH Bays less 2
breakers
27.7
1 BAAH Bay in Waena Adding 1 BAAH Bay Adding 1 BAAH bay less 1
breaker
6.7
MPP – STG3.1 – Waiinu New Transmission Line One circuit, 336 AAC 18.4
MPP Substation New Transmission Line Install One 69kV circuit
breaker
2.9
STG3.1 Substation Adding 1 BAAH Bay Adding 1 BAAH Bay 9.6
Waiinu Substation New Transmission Line Install One 69kV circuit
breaker
2.9
Mitigation study – portfolio or non-wires solutions
Considering that the proposed portfolio additions are critical to meet the transformation goals, and the
new lines and substations are critical to reliably interconnect these future grid-scale generation
projects, there were no portfolio or non-wire alternatives identified in this study.
REZ Enablement
According to the resource plan, total 103 MW grid-scale generation from REZ zone C development will
be interconnected to the Maui transmission system by 2035. It is assumed that 43 MW will be
interconnected at the new substation REZ C.1, and remaining 60 MW will be interconnected at the
MPP
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Line
New 69 kV Substation
Waena Switch Yard
STG3.1
Waiinu Substation
REZ C.1
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APPENDIX D – SYSTEM SECURITY STUDY
Waena switchyard. The 60 MW Waena switchyard interconnection enablement cost is $13.5 million.
The estimate to allow 43MW interconnection at the new substation REZ C.1 cost estimate is $5.8
million. So, the total REZ enablement cost estimate is $19.3 million.
Base scenario resource plan, year 2040
Study descriptions
In 2040, another 61 MW REZ zone C development will be completed. It is assumed that 61 MW will be
interconnected at Waena switchyard. Meanwhile, there will be retirement of existing 5.7 MW
distribution interconnected PV. System annual peak demand is forecasted to reach 266 MW in 2041. A
high-level Maui system map with locations of the future grid-scale project interconnection locations by
2040 are shown in Figure 38.
A
A
A
C
C
B
RFP Stage 3
Projects
REZ Projects
2029-2035
REZ Projects
2040
A B C REZ
Figure 38 High-Level Maui map for assumed future grid-scale project interconnection locations by 2040
The detailed system grid-scale resources changes are summarized in Table 80 and Table 81. System
resource summary and the forecasted system load is summarized in Table 82.
Table 80 Maui Grid-Scale Generation Project Development between 2036 and 2040, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development Onshore Wind
Generation
18 2040 REZ Zone C
PV/BESS Generation 43 2040 REZ Zone C
Table 81 Maui Grid-Scale Generation Removal between 2028 and 2035
Removal Generation Type MW Capacity Year Location
Distribution
Interconnected PV
Solar 5.7 2040 12 kV Distribution System
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APPENDIX D – SYSTEM SECURITY STUDY
Table 82 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2040
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
152 84 376 40 218 266
Table 83 summarizes studied system generation dispatches for 2040. The transmission networks
expansion requirement identified in the 2035 study is assumed to be implemented before 2035 to
mitigate the transmission line overloading issues. Therefore, all the networks expansion listed in the
Table 79 are included in the 2040 study models.
Table 83 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2040
Aggregated Generation
Capacity Rating (MW)
Zone A Zone B Zone C Zone A+C Zone B+C Zone
A+B
All
Zones
Zone A 140 140 0 0 134 0 140 85
Zone B 257 126 257 1 0 130 126 88
Zone C 265 0 9 265 132 136 0 93
Total
Load
266 266 266 266 266 266 266 266
Study results
Results of power flow simulations for all the studied dispatches for system with both normal
configuration and N-1 contingency configurations show undervoltage violation on Pukalani-Hana 23 kV
circuit for both normal and N-1 contingency configurations and 69 kV transmission line overloading
and high loading condition when system is with N-1 contingency configurations. The worst
undervoltage violation is 0.75 p.u. during normal conditions and 0.67 p.u. during N-1 contingency. The
undervoltage issue is caused by load growth on the Pukalani-Haiku 23 kV line. A summary of the 69 kV
line overloading is provided in Table 84.
Table 84 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2040
Generation Dispatch
N-1 Contingency Configuration
Overloading Element Max. Loading(%)
Zone A Kealahou-Kamaole 69kV
Line
97
Zone B None
Zone C MPP-REZC.1 Ckt 1 or Ckt
2 69kV Line
114
Zone A+C Kealahou-Kamaole 69kV
Line
96
Zone B+C None
Zone A+B None
All Zones None
D-89 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Mitigation study – transmission networks expansion
To mitigate the identified undervoltage issue, it is proposed to add one 3.6 Mvar (at 69 kV) capacitor
bank at Keanae substation and another 3.6 Mvar (at 69 kV) capacitor bank at Kailua substaton. To
mitigate the transmission line overloading issue, it is recommend to add one 69 kV line from MPP to
the Waena switchyard via the REZ C.1 substation, which is shown in Figure 39. The high leve cost
estimate for adding this new line is $51.9 million.
MPP
REZ C.1
Waena
Switch Yard
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Line
Figure 39 Proposed Maui transmission networks expansion, Mau i base scenario resource plan, year 2040
Mitigation study – portfolio mitigation
To defer the addtion of the new line from MPP to the Waena switchyard, would require 48 MW
interconnection size reduction at the Waena switchyard. The needs for additional infrastructure for
alternate resources would depend on the location(s).
REZ Enablement
According to the resource plan, total 61 MW grid-scale generation from REZ zone C development will
be interconnected to the Waena switchyard. The 61 MW Waena switchyard interconnection
enablement cost is $15.6 million.
Base scenario resource plan, year 2045
Study descriptions
Between 2041 and 2045, 66 MW PV/BESS generation and 41 MW onshore wind generation will be
developed in REZ zone C; 15 MW PV/BESS generation will be developed in REZ zone B. Also, all the
remaining fossil units will switch to biodiesel. The system annual peak demand is forecasted to reach
289 MW in 2046. A high-level Maui system map with locations of the future grid-scale project
interconnection locations by 2045 are shown in Figure 40. Assumptions of future grid-scale generation
interconnection locations are:
• Auwahi substation – 15 MW (REZ zone B)
• STG3.1 – 30 MW (REZ zone C)
• Kanaha substation (23 kV) – 30 MW (REZ zone C)
• New switching station, REZ C.2 (see Figure 41), on Waena-Kealahou line – 47 MW (REZ zone C)
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APPENDIX D – SYSTEM SECURITY STUDY
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
REZ Projects2040
REZ Projects2045
A B C REZ
Figure 40 High-Level Maui map for assumed future grid-scale project interconnection locations by 2045
Waena Switch Yard Kealahou
23.5
MW
23.5
MW
REZ C.2
Existing 69 kV Line
Existing 69 kV Substation
REZ C New Generation
New 69 kV Substation
23.5 MW
Figure 41 High-Level single line diagram for a new substation REZ C.2, Maui base scenario resource plan, year 2045
The detailed system grid-scale resources changes are summarized in Table 85 and Table 68. System
resource summary and the forecasted system load is summarized in Table 86.
Table 85 Maui Grid-Scale Generation Project Development between 2041 and 2044, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development PV/BESS Generation 15 2045 REZ Zone B
PV/BESS Generation 66 2045 REZ Zone C
Onshore Wind
Generation
41 2045 REZ Zone C
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APPENDIX D – SYSTEM SECURITY STUDY
Table 86 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2045
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
152 125 457 40 229 289
Table 87 summarizes studied system generation dispatches for the 2045. It is worth noting that all the
networks expansion identified in the 2040 study are included in the 2045 study models.
Table 87 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2045
Aggregated Generation
Capacity Rating (MW)
Zone A Zone B Zone C Zone A+C Zone B+C Zone
A+B
All
Zones
Zone A 140 140 0 0 140 0 140 93
Zone B 272 149 272 0 0 135 149 105
Zone C 372 0 17 289 149 139 0 91
Total Load 289 289 289 289 289 289 289 289
Study results
Power flow simulation results indicate 69 kV line overloading issue in all the studied system generation
dispatch cases when system is with N-1 contingency configurations, which is shown in Table 88. These
violations are caused by both system load increase and generation congestion. Voltage planning
criteria violation is not identified in the study.
Table 88 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2045
Generation Dispatch
N-1 Contingency Configuration
Overloading Element Max. Loading(%)
Zone A Kealahou-Kamaole 69kV
Line 102
Zone B MPP-Kaonoulu and
Kaonoulu-Kihei 69kV
Lines
101
Zone C MPP-Kaonoulu and Kaonoulu-Kihei 69kV
Lines
101
Zone A+C MPP-Kaonoulu and
Kaonoulu-Kihei 69kV
Lines
103
Zone B+C MPP-Kaonoulu and
Kaonoulu-Kihei 69kV
Lines
101
Zone A+B MPP-Kaonoulu and
Kaonoulu-Kihei 69kV
Lines
103
All Zones MPP-Kaonoulu and
Kaonoulu-Kihei 69kV
Lines
103
D-92 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Mitigation study – transmission networks expansion
To address the identified overloading issue, a set of mitigation solutions, including reconductor, adding
new 69 kV line and substations are proposed. The proposed solutions are listed in Table 89 with high-
level cost estimate and shown in Figure 42. The adding of new substatino REZ C.2 on the Waena-
Kealahou line and REZ B.1 on south Maui provide benefit for the grid-scale generation projects
interconnection between 2046 and 2050.
Table 89 Transmission Networks Expansion and High-Level Cost Estimate, Maui Base Scenario Resource Plan, Year 2045
Networks Expansion Descriptions Cost Estimate
(Million Dollars) Transmission Line/Substation Upgrade Type Upgrade Requirements
Kamaole – Kealahou Re-conductor One circuit, re-conductor
to 556 AAC
17.4
Waena – REZ C.2 – Kealahou Add New Circuit One circuit, 556 AAC 21.4
REZC.2 (Waena-Kealahou) Sub New Substation Adding 3 BAAH bays less 2
breakers
37.6
Waena Substation Add new circuit Install one 69kV circuit
breaker
3.9
Kealahou Substation Add new circuit Add 1 BAAH bay less 1
breaker
9.9
New Substation REZ B.1
Adding a new 69 kV substation between Kihei
substation and Wailea substation.
• Add new substation (REZB.1) between Kihei
Sub 35 and Wailea Sub 25 with (3) BAAH less 3 breaker.
32.5
MPP - REZ B.1 Adding New
Circuit
One circuit, 556 AAC 42.0
D-93 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Waena
Switch Yard Kealahou
REZ C.2
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Line
Kuihelani Solar Kuihelani
MPP
Kaonoulu Kihei
New 69 kV Substation
Kamaole Solar Kealahou
REZ B.1
Wailea
Figure 42 Proposed Maui transmission networks expansion, Mau i base scenario resource plan, year 2045
Mitigation study – alternative resource portfolio
The Kamaole-Kealahou line reconductoring. can be deferred by reducing south Maui generation
interconnection size by 7 MW.
REZ Enablement
According to the resource plan, 15 MW generation from REZ zone B and 107 MW generation from REZ
zone C will be interconnected to the Maui system between 2041 and 2045. It is assumed in the study
that the total 122 MW generation will be interconnected at Auwahi substation (15 MW), STG 3.1
substation (30 MW), Kahana substation (23 kV, 30 MW), and the new substation REZ C.2 (47 MW). The
high-level cost estimate for these REZ enablement is listed in Table 90.
Table 90 REZ Enablement and High-Level Cost Estimate, Maui Base Scenario Resource Plan, Year 2045
Enablement Descriptions Cost Estimate
(Million Dollars) Transmission Line/Substation Upgrade Type Upgrade Requirements
Kanaha Substation REZC development Install one 23kV breaker 3.8
STG 3.1 POI (MPP-Waiinu) Sub REZC development Install one 69kV breaker 3.9
REZC.2 (Waena-Kealahou) Sub REZC development Install two 69kV breakers 7.8
D-94 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Base scenario resource plan, year 2050
Study descriptions
In 2050, 57 MW PV/BESS generation will be developed in REZ zone C and another 57 MW PV/BESS
generation will be developed in REZ zone B. System annual peak demand is forecasted to reach 310
MW in 2050. A high-level Maui system map with locations of the future grid-scale project
interconnection locations by 2050 are shown in Figure 43.
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
REZ Projects2040
REZ Projects2045
REZ Projects2050
A B C REZ
Figure 43 High-Level Maui map for assumed future grid-scale project interconnection locations by 2050
Interconnection locations for the total 114 MW grid-scale interconnection are assumed as following:
• REZ B.1 Substation – 51 MW (REZ zone B)
• Auwahi Substation – 7 MW (REZ zone B)
• REZ C.2 (Waena-Kealahou) Substation - 13MW (REZ zone C)
• New switching station, REZ C.3 (shown in Figure 44), on Waena-Pukalani line – 44 MW (REZ
zone C)
D-95 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Waena Switch Yard Pukalani
22 MW22
MW
REZ C.3
Existing 69 kV Line
Existing 69 kV Substation
REZ C New Generation
New 69 kV Substation
22
MW
Figure 44 High-Level single line diagram for a new substation REZ C.3, Maui base scenario resource plan, year 2050
The detailed system grid-scale resources changes are summarized in Table 91 and Table 68. System
resource summary and the forecasted system load is summarized in Table 92.
Table 91 Maui Grid-Scale Generation Project Development between 2046 and 2050, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development PV/BESS Generation 57 2050 REZ Zone B
PV/BESS Generation 57 2050 REZ Zone C
Table 92 Maui System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year 2050
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
152 125 571 40 240 310
Table 93 summarizes studied system generation dispatches for the 2050. It is worth noting that all the
networks expansion identified in the 2045 study are included in the 2050 study models.
Table 93 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2050
Aggregated Generation
Capacity Rating (MW)
Zone A Zone B Zone C Zone A+C Zone B+C Zone
A+B
All Zones
Zone A 140 140 0 0 140 0 140 96
Zone B 329 170 310 0 0 152 170 113
Zone C 429 0 0 310 170 158 0 101
Total Load 310 310 310 310 310 310 310 310
Study results
Undervoltage violation is not observed from the power flow simulations for all the system generation
dispatches, with either system normal configuration or N-1 contingency configurations. Transmission
line overloading is not observed, either. The only planning criteria violation observed is overloading on
D-96 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
62/23 kV tie transformers during N-1 system contingency configurations. A summary of observed
overloading is listed in Table 94.
Table 94 List of Overloaded Transmission Elements, Maui Base Scenario Resource Plan, Year 2050
Generation Dispatch
N-1 Contingency Configuration
Overloading Element Max. Loading(%)
Zone A None
Zone B 69/23 kV Tie transformer 96
Zone C None
Zone A+C 69/23 kV Tie transformer 97
Zone B+C 69/23 kV Tie transformer 100
Zone A+B 69/23 kV Tie transformer 97
All Zones 69/23 kV Tie transformer 96
Mitigation study – transmission networks expansion
To mitigate the potential overloading on the tie-transformers, it is recommend to replace the two units
of tie transformer in Kanaha substations with higher emergency rating, at least 24 MVA forced air
rating. To mitigate transmission line overloading, adding the second 69 kV line between the Waena
switchyard and the Pukalani substation via the REZ C.3 is proposed. The proposed mitigation solution is
summarized in Table 95, with high-level cost estimate.
Table 95 Transmission Networks Expansion and High-Level Cost Estimate, Maui Base Scenario Resource Plan, Year 2050
Enablement Descriptions Cost Estimate
(Million Dollars) Transmission Line/Substation Upgrade Type Upgrade Requirements
Waena – REZC.3 – Pukalani Add New Circuit One circuit, 336 AAC 31.2
Waena Substation Add New Circuit Install one 69kV circuit breaker 4.5
Pukalani Substation Add New Circuit Rebuild Sub—add 2 BAAH bays
less one breaker
25.5
REZC.3 (Waena-Pukalani) Sub New Substation Add 3 BAAH bays less 2
breakers
46.9
Transformer Transformer Upgrade Description
New 69/23 kV Tie Transformer Upgrade both Kahana Tie Transformers with FA rating of
at least 24 MVA
15.0
Mitigation solution – non-wire alternatives
Non-wire alternatives are identified for deferring the tie-transformers upgrade. To bring down the tie
transformer loading limit no higher than 95% of emergency loading during N-1 contingency
configurations, 4 MW peak load reduction is required.
REZ Enablement
According to the resource plan, 57 MW generation from REZ zone B and another 57 MW generation
from REZ zone C will be interconnected to the Maui system between by 2050. It is assumed in the
study that the total 114 MW generation will be interconnected at Auwahi substation (7 MW), REZ B.1
substation (51 MW), REZ C.2 (13 MW), and the new substation REZ C.3 (44 MW). The high-level cost
estimate for these REZ enablement is listed in Table 96.
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APPENDIX D – SYSTEM SECURITY STUDY
Table 96 REZ Enablement and High-Level Cost Estimate, Maui Base Scenario Resource Plan, Year 2050
Enablement Descriptions Cost Estimate
(Million Dollars) Transmission Line/Substation Upgrade Type Upgrade Requirements
REZB.1 (Kihei-Wailea) Sub REZB development Install two 69kV circuit
breakers
9.0
REZC.3 (Waena-Pukalani) Sub REZC development Install two 69kV circuit
breakers
9.0
High load scenario resource plan, year 2027
Study descriptions
By 2027, the Maui system will have new generation from Stage 3 RFP procurement which will be 171
MW RDG PV/BESS and 36 MW firm generation, interconnection at at Maui 69 kV system. Meanwhile,
the Maui system will finish Waena switchyard construction, KPP retirement and conversion of KPP K3
and K4 units to synchronous condensers, and MPP unit 10-13 retirement. The system peak load is
forecasted to reach 239 MW by 2028. A high-level locations of the RFP Stage 3 projects assumed in the
study and developed REZ zones are shown in Figure 45. The assumptions regarding locations of the RFP
Stage 3 projects are the same as what are used in the base scenario resource plan study. System grid-
scale resource change in this high loare scenario resource plan by 2027 is the same as what is shown in
the base scenario resource plan (i.e., Table 68 and Table 69). There are two differences, by comparing
the 2027 base scenario resource plan and 2027 high load scenario resoiuce plan: 1) System peak load
becomes 239 MW, instead of 207 MW in the base scenario resource plan, and 2) DER adoption
forecast is 194 MW, instead of 170.7 MW in the base scenario resource plan.
A
A
A
C
C
B
RFP Stage 3 Projects
A B C REZ
Figure 45 High-Level Maui map for assumed RFP Stage 3 project locations by 2027
Table 97 summarizes studied system generation dispatches for the 2027.
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APPENDIX D – SYSTEM SECURITY STUDY
Table 97 Studied System Generation (MW) Dispatches, Maui High Load Scenario Resource Plan, Year 2027
Aggregated Generation Capacity
Rating (MW)
Zone A* Zone
B_1
Zone B_2 Zone A+C Zone
B+C
All Zones
Zone A 161 161 0 55 138 0 70
Zone B 313.5 78 239 184 0 138 70
Zone C 101 0 0 0 101 101 67
Total Load 239 239 239 239 239 239 239
*Studied variation of dipatch zone
Study results
Power flow simulation results indicate that 1) 69 kV lines experience high loading condition during
normal configuration for one generation dispatch, 2) overloading conditions are identified on 69 kV
lines and 69/23 kV tie transformers when system is under N-1 contingency configurations, and 3)
voltage planning criteria violations are observed, with worst undervoltage issues at 0.75-0.76 p.u..
Summary of transmission element overloading is listed in Table 98.
Table 98 List of Overloaded Transmission Elements, Maui High Load Scenario Resource Plan, Year 2027
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
Overloading
Element
Max Loading
(%)
Overloading Element Max. Loading(%)
Zone A_1 KuihelaniSolar-
Kuihelani 69kV
Line
97 KuihelaniSolar-
Kuihelani 69kV Line
117
Zone A_2 None None Kanaha 69/23kV Tie
Tsf 1 and Tie Tsf 2
110
Zone B_1 None None Kanaha 69/23kV Tie
Tsf 1 and Tie Tsf 2
110
Zone B_2 None None Kanaha 69/23kV Tie
Tsf 1 and Tie Tsf 2
110
Zone A+C None None Kanaha 69/23kV Tie
Tsf 1 and Tie Tsf 2
110
Zone B+C None None Kanaha 69/23kV Tie
Tsf 1 and Tie Tsf 2
110
All Zones None None Kanaha 69/23kV Tie
Tsf 1 and Tie Tsf 2
110
Mitigation study – transmission networks expansion
To mitigate the transmission line overloading conditions, reconductoring of the overloading
transmisison lines are proposed. Besides fixing the transmission line overloading issue, simimilar to
what is proposed in the base scenario resource plan, closing west Maui loops is proposed for the high
load scenario resource plan. A list of transmission networks expansion proposed for Maui system is
listed in Table 99. A high-level one line diagram in Figure 46 demonstrates the proposed transmission
networks expansion.
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APPENDIX D – SYSTEM SECURITY STUDY
Table 99 Transmission Networks Expansion and High-Level Cost Estimate, Maui High Load Scenario Resource Plan, Year
2027
Networks Expansion Descriptions Cost Estimate
(Million Dollars) Transmission Line Upgrade Type Conductor Requirements
Mahinahina Substation Expand West network Install one 69kV circuit breaker 2.7
Lahaina-Lahainaluna Re-conductor One circuit, re-conductor to
556 AAC
2.5
MPP – Waiinu #2 New Transmission Line One circuit, 336 AAC 13.6
1 BAAH Bay in STG3.1 Adding 1 BAAH Bay Adding 1 BAAH Bay 7.8
Waiinu Substation New Transmission Line Install One 69kV circuit
breaker
2.4
MPP Substation New Transmission Line Install One 69kV circuit
breaker
2.4
M
To Napili (Mauka)
M
M
To Lahainaluna Sub (Mauka)
To Napili (Makai)To Lahaina Sub (Makai)
CB
Lahaina
Lahainaluna
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Equipment
MPP
Kuihelani
Solar
Kuihelani
MPP
STG3.1
Waiinu Substation
Figure 46 High-Level single line diagram for proposed transmission networks expansion, Maui high load scenario resource plan, year 2027
D-100 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
REZ enablment
There is no REZ development by 2027, hence, there is no REZ enablement cost estimate.
High load scenario resource plan, year 2030
Study descriptions
By 2030, the Maui system will have 69 MW grid-scale renewable generation from REZ zone C
development. Also, it is planned that MPP unit 1 to 9 will be removed by 2030. The system annual peak
load is forecasted to reach 266 MW by 2031. A high-level Maui system map with locations of all the
future grid-scale generation projects by 2030 are shown in Figure 47. In total 69 MW of new grid-scale
generation project from the REZ zone C development, it is assumed that 52 MW generation will be
interconnected at the Waena switchyard, and the remaining 17 MW will be interconnected at a new
substation REZ C.1 on the Waena-MPP line, which is shown as Figure 48.
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
Figure 47 High-Level Maui map for assumed future grid-scale project interconnection locations by 2030, high load
scenario resource plan
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APPENDIX D – SYSTEM SECURITY STUDY
MPP
REZC.1
Waena
Switch Yard
17MW
Existing 69 kV Line
Existing 69 kV Substation
REZ C New Generation
New 69 kV Substation
17
MW
Figure 48 High-level single line diagram for the 17 MW line interconnection project, Maui high load scenario resource
planning, year 2030
The detailed system grid-scale resources changes are summarized in Table 100. System resource
summary and the forecasted system load is summarized in Table 101. Regarding system grid-scale
resource retirement, both base scenario resource plan and high load scenario resource plan have the
same resource retirment schedule.
Table 100 Maui Grid-Scale Generation Project Development between 2028 and 2030, High Load Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development Onshore Wind
Generation
6 2029 REZ Zone C
Onshore Wind
Generation
46 2030 REZ Zone C
Solar/BESS 17 2030 REZ Zone C
Table 101 Maui System Resource Summary and Forecasted Demand (MW), High Load Scenario Resource Plan, Year 2030
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
152 94 313 40 217 266
Table 102 summarizes studied system generation dispatches for the 2030.
Table 102 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2030
Aggregated Generation Capacity
Rating (MW)
Zone
A+B*
Zone
B_1
Zone
B_2
Zone B+C* Zone A+C All Zones
Zone A 140 140 0 124 0 134 88
Zone B 257 126 257 142 97 0 88
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Zone C 170 0 9 0 170 132 90
Total Load 266 266 266 266 266 266 266
*Studied variation of dipatch zone
Study results
Power flow analyses are performed for the above system generation dispatches. Analyses results
indicate transmission element overloading happen in both normal and N-1 contingency configurations.
Undervoltage violation and voltage collapse (i.e., power flow simulation does not converge) are
identified during N-1 contingency configurations. A summary of undervoltage violations,voltage
collapse issues, and transmission element overloading issues identified from the analyses are shown in
Table 103 and Table 104.
Table 103 List of Undervoltage Violation and Voltage Collapse, Maui High Load Scenario Resource Plan, Year 2030
Generation Dispatch
N-1 Contingency Configuration
Low Voltage Element Lowest Voltage
(p.u.)
Zone A+B_1 Haiku Substation 0.83
Zone A+B_2 Haiku Substation 0.83
Zone B_1 Haiku Substation 0.84
Zone B_2 Haiku Substation 0.83
Zone B+C_1 Haiku Substation 0.86
Zone B+C_2 Haiku Substation 0.85
Zone A+C Haiku Substation 0.83
All Zones HHaiku Substation 0.85
Table 104 List of Overloaded Transmission Elements, Maui High Load Scenario Resource Plan, Year 2030
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
Overloading Element Max. Loading(%) Overloading Element Max. Loading(%)
Zone A+B_1 KuihelaniSolar-
Kuihelani 69kV Line
105 KuihelaniSolar-Kuihelani
69kV Line
126
Zone A+B_2 None None None None
Zone B_1 None None None None
Zone B_2 None None MPP-KuihelaniSolar
69kV Line
121
Zone B+C_1 None None Waena-Kanaha 69kV
Line
127
Zone B+C_2 Wailea-Auwahi 69kV
Line
97 Waena-Kanaha 69kV
Line
160
Zone A+C None None None None
All Zones None None None None
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APPENDIX D – SYSTEM SECURITY STUDY
Mitigation study – transmission networks expansion
By adding one more 69 kV circuit between MPP and Waena switchyard, via the new substation REZ C.1,
multiple 69 kV line overloading issues (i.e., MPP-REZC, MPP-Kuihelani Solar, KuihelaniSolar-Kuihelani,
Waena-Kanaha, Wailea-Auwahi) are mitigated. Also, by converting Pukalani-Haiku 23 kV line to a 69 kV
line and adding a capacitor bank at Kailu substation and Keanae substation, undervoltage and potential
voltage collapse issue on the Pukalani-Haiku-Hana 23 kV line, as well as the Pukalani 69/23 kV
transformer overloading will be mitigated. A summary of the proposed transmission networks
expansion, with high-level cost estimate are listed in Table 105, with a simplified single line diagram
shown in Figure 49.
Table 105 Transmission Networks Expansion and High-Level Cost Estimate, Maui High Load Scenario Resource Plan, Year
2030
Networks Expansion Descriptions Cost Estimate
(Million Dollars) Transmission Line Upgrade Type Conductor Requirements
MPP – Waena #2 New Transmission Line One circuit, 556 AAC 21.6
REZ C.1 (MPP-Waena)
Substation
Adding 3 BAAH Bay Adding 3 BAAH Bays less 2
breakers
23.7
MPP Substation New Transmission Line Install one 69kV circuit breaker 2.5
Waena Substation New Transmission Line Install one 69kV circuit breaker 5.8
Converting Pukalani-Haiku line to 69 kV line; converting Makawao, Kauhikoa, Haiku
substations to 69/12 kV substations; converting Kamole Weir, Hʻpoko substaions 85, 86 and
87 to 69/23 kV substation; adding a tie transformer 12/16/20 MVA at Haiku substation;
remove Pukalani 69/23 kV tie transformer; reconductor Pukalani-Haiku as 556 AAC
86.2
Add cap bank (1.2MVAR or greater) at Kailua substation and Keanae substation. 0.3
MPP
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Line
New 69 kV Substation
Waena
Switch Yard
REZ C.1
Figure 49 High-Level single line diagram for proposed 69 kV transmission networks expansion, Maui high load scenario
resource plan, year 2030
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APPENDIX D – SYSTEM SECURITY STUDY
REZ enablment
For the 2030 REZ development, 69 MW generation will be developed from REZ zone C and
interconnected with Mauiʻs 69 kV system. It is assumed that 52 MW will be interconnected at Waena
switch yard, and 17 MW will be interconnected at a new substation REZ C.1 as shown in Figure 48.
According to the REZ enablement cost identified in the 2021 REZ study, the estimate of REZ
enablement for the 52 MW interconnection at the Waena switch yard is $45.8 million. A high-level cost
estimate for the REZ enablement is listed in Table 106.
Table 106 REZ Enablement and High-Level Cost Estimate, Maui High Load Scenario Resource Plan, Year 2030
Enablement Descriptions Cost Estimate
(Million Dollars) Transmission Line/Substation Upgrade Type Upgrade Requirements
REZ C.1 (MPP-Waena) REZC development Install one 69kV circuit
breaker
2.5
Waena Substation REZC development Add 2 BAAH bays less 2
breakers
11.6
High load scenario resource plan, year 2035
Study descriptions
In 2035, another 159 MW REZ zone C development will be completed. It is assumed that 38 MW
generation will be interconnected at Waena switchyard, 60MW generation interconnected at REZC.1,
30MW generation interconnected at STG3.1 and 30MW generation interconnected at Kanaha
Substation on the 23kV bus. In addition, system will have existing 42 MW wind contract expires. The
system annual peak demand is forecasted to reach 313 MW in 2036. A high-level Maui system map
with locations of all the future grid-scale generation projects by 2035 are shown in Figure 50.
Figure 50 High-Level Maui map for assumed future grid-scale project interconnection locations by 2035, high load
scenario resource plan
The detailed system grid-scale resources changes are summarized in Table 107. System resource
summary and the forecasted system load is summarized in Table 101.
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2030
REZ Projects2035
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APPENDIX D – SYSTEM SECURITY STUDY
Table 107 Maui Grid-Scale Generation Project Development between 2030 and 2035, High Load Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development Onshore Wind
Generation
76 2035 REZ Zone C
PV/BESS Generation 84 2035 REZ Zone C
Table 108 Maui System Resource Summary and Forecasted Demand (MW), High Load Scenario Resource Plan, Year 2035
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
152 127 396 40 242 313
Table 109 summarizes studied system generation dispatches for the 2035. It is worth pointing out that
the transmission networks expansion requirements identified in previous years are all assumed to be
implmented per the schedule, and are all considered as availble in the models for the 2035 analyses.
Table 109 Studied System Generation (MW) Dispatches, Maui Base Scenario Resource Plan, Year 2035
Aggregated Generation Capacity
Rating (MW)
Zone
A+B*
Zone B Zone C Zone B+C* Zone A+C All Zones
Zone A 140 140 0 0 0 140 104
Zone B 257 173 257 0 155 0 104
Zone C 330 0 56 313 158 173 105
Total Load 313 313 313 313 313 313 313
*Studied variation of dipatch zone
Study results
According to the power flow analyses performed for all the studied system generation dispatches, high
loading on 69/23 kV tie transformers and 69 kV line are observed in normal configuration, and 69 kV
line and 69/23 kV tie transformer overloading are observed during system N-1 contingency
configurations. A summary of transmission elements with high loading and overloading conditions is
provided in Table 110.
Table 110 List of Overloaded Transmission Elements, Maui High Load Scenario Resource Plan, Year 2035
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
Overloading Element Max. Loading(%) Overloading Element Max.
Loading(%)
Zone A+B_1 KuihelaniSolar-
Kuihelani 69kV Line
98% Kanaha 69/23kV Tie Tsf 1
or Tie Tsf 2
100%
Zone A+B_2 Waiinu 69/23kV Tie
Tsf
98% Kanaha 69/23kV Tie Tsf 1
or Tie Tsf 2
97%
Zone A+B_3 KuihelaniSolar-
Kuihelani 69kV Line
104% KuihelaniSolar-Kuihelani
69kV Line
102%
Zone B None None Kanaha 69/23kV Tie Tsf 1
or Tie Tsf 2
103%
Zone C None None MPP-REZC Ckt 1 or Ckt 2 114%
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APPENDIX D – SYSTEM SECURITY STUDY
Zone B+C_1 None None Kanaha 69/23kV Tie Tsf 1
or Tie Tsf 2
105%
Zone B+C_2 None None Kanaha 69/23kV Tie Tsf 1 or Tie Tsf 2 103%
Zone B+C_3 None None Kanaha 69/23kV Tie Tsf 1
or Tie Tsf 2
110%
Zone A+C None None Kanaha 69/23kV Tie Tsf 1
or Tie Tsf 2
104%
All Zones None None Kanaha 69/23kV Tie Tsf 1
and Tie Tsf 2
96%
Mitigation study – transmission networks expansion
To mitigate the overloading and undervoltage issues identified from the study, following networks
expansion is proposed. It is worth noting that adding a new line between Waena switchyard and MPP
through REZ C.1 provides potential of interconnecting future grid-scale generation project at the REZ
C.1 substaiton. High-level cost estimate is also provided along with the description of the proposed
networks expansion.
Table 111 Transmission Networks Expansion and High-Level Cost Estimate, Maui High Load Scenario Resource Plan, Year
2035
Networks Expansion Descriptions Cost Estimate
(Million Dollars) Transmission Line/Substation Upgrade Type Conductor Requirements
Kamaole Solar – Kealahou Reconductor One circuits, 556 AAC 12.9
Kuihelani Solar- Kuihelani Reconductor One circuits, 556 AAC 2.7
MPP – Waena #3 Adding New Circuit One circuits, 556 AAC 29.3
REZ C.1 (MPP-Waena) Adding 1 BAAH Bay Adding 1 BAAH Bay 9.6
MPP Substation Adding New Circuit Install One 69kV circuit
breaker
2.9
Waena Substation Adding New Circuit Install One 69kV circuit
breaker
2.9
Increase 1.2 Mvar cap bank to 3.6 Mvar cap bank at Keanae substation to mitigate
undervoltage issue.
0.2
Increase 1.2 Mvar cap bank to 3.6 Mvar cap bank at Kailua substation to mitigate
undervoltage issue.
0.2
REZ enablement
For the total 159 MW grid-scale generation interconnection from the development of REZ zone C, it is
assumed that 38 MW generation will be interconnected at Waena switchyard, 60MW generation
interconnected at REZC.1, 30MW generation interconnected at STG3.1 and 30MW generation
interconnected at Kanaha Substation on the 23kV bus. The REZ enablment and high-level cost estiamte
is listed in Table 112.
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APPENDIX D – SYSTEM SECURITY STUDY
Table 112 REZ Enablement and High-Level Cost Estimate, Maui High Load Scenario Resource Plan, Year 2035
Enablement Descriptions Cost Estimate
(Million Dollars) Transmission Line/Substation Upgrade Type Upgrade Requirements
Waena Substation REZC development Add 2 BAAH bays less 2
breakers
13.5
REZC.1 (MPP-Waena) REZC development Install one 69kV circuit
breaker
2.9
STG3.1 (MPP-Waiinu) REZC development Install one 69kV circuit
breaker
2.9
Kanaha Substation REZC development Install one 23kV circuit
breaker
2.8
4.2.2 Dynamic stability study
The Maui system in near-term years 2028 and 2036 for the base scenario resource plan are selected
for performing dynamic stability study to evaluate system dynamic stability performance. Similar to the
steady state analyses, the following assumptions are used in the Maui dynamic stability study:
• KPP K3 an K4 units are converted to synchronous condensers in the study.
• Puunene substation is removed, and the tie transformer #2 in Kanaha substation is in service.
• Stage 1 projects (Kuihelani Solar and Paeahu Solar, both in GFL model) are in service.
• Stage 2 projects (Kanaha Solar, Kamaole Solar, and Waena BESS, all in GFM model) are in
service.
The system generation dispatch for daytime peak load with high DER generation, which poses the
highest risk to the system stability according to the past studies, is modeled for the dynamic stability
study, with simulations of high-risk contingencies. The high-risk contingencies for Maui system is 1) P3
planning event - the largest GFM resource is out-of-service due to maintenance, and a three-phase
fault happens at gen-tie of another grid-scale GFM resource and results in the loss of this gen-tie, and
2) P5 planning event - delayed fault clearing (24 cycles) of a three-phase fault on a 69 kV transmission
line that cause the whole system experience low voltage condition during the fault.
Base scenario resource plan, year 2028
Study descriptions and study results
According to the resource plan, a system generation dispatch that represents daytime peak load with
high DER generation scenario in 2028 is created (as Table 113) and modeled in PSCAD/EMTDC. In this
dispatch there is no synchronous machine-based generation dispatched.
Table 113 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, Maui Base Scenario
Resource Plan, Year 2028
Generation Station Dispatched (MW) Gen/System Load (%) Capacity (MW)
Existing Standalone PV 5.3 2.9 5.7
Existing Wind 2.2 1.2 42
Stage 1 PV/BESS (GFL) 30 16.4 75
Stage 2 PV/BESS (GFM) 10 10.4 50
Waena BESS (GFM) 0 40
Stage 3 PV/BESS (GFM) 9 171
DER 126.2 69.0 198.6
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APPENDIX D – SYSTEM SECURITY STUDY
System Load (MW) 183
GFM MW Headroom /DER
Generation
2
PSCAD simulations with a total simulation time of 25 seconds are performed with three-phase to
ground faults applied at 10 seconds. For the simulated P3 planning event, it is assumed that the Waena
BESS one POI is out of service before the fault occurs. Simulation results for the P3 planning event are
shown in Figure 51 and for the P5 planning event are shown in Figure 52.
Figure 51 Dynamic stability simulation results, Maui base scenario resource plan, year 2028, P3 planning event
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 52 Dynamic stability simulation results, Maui base scenario resource plan, year 2028, P3 planning event
From above simulation results, UFLS is not identified, and system frequency nadir is well above the first
block of UFLS trigger limit, 59 Hz. According to the Maui transmission planning criteria for the P3
planning event 20% of system net load UFLS is the acceptable limit and for the P5 planning event 15%
of system net load UFLS is the acceptable limit.
Base scenario resource plan, year 2036
Study descriptions and study results
According to the resource plan, a system generation dispatch that represents daytime peak load with
high DER generation scenario in 2036 is created (as Table 114) and modeled in PSCAD/EMTDC. It is
worth noting that in this dispatch there is no synchronous machine-based generation dispatched.
Table 114 System Generation Dispatch for Daytime Peak Load High DER Generation Scenario, Maui Base Scenario
Resource Plan, Year 2036
Generation Station Dispatched (MW) Gen/System Load (%) Capacity (MW)
Existing Standalone PV 5.3 2.5 5.7
Existing Wind 2.2 1.1 42
Stage 1 PV/BESS (GFL) 0 0 75
Stage 2 PV/BESS (GFM) 10 9.2 60
Waena BESS (GFM) 0 40
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APPENDIX D – SYSTEM SECURITY STUDY
Stage 3 PV/BESS (GFM) 9 171
REZ Wind 0 0 60
REZ PV/BESS (GFM) 30 14.5 43
DER 151.8 73.3 246
System Load (MW) 207
GFM MW Headroom /DER
Generation
1.7
PSCAD simulations with a total simulation time of 25 seconds are performed with three-phase to
ground faults applied at 10 seconds. For the simulated P3 planning event, it is assumed that the Waena
BESS one POI is out of service before the fault occurs. In this P3 event, another GFM resource with 30
MW generation is tripped. Simulation results for the P3 planning event are shown in Figure 53 and for
the P5 planning event are shown in Figure 54.
Figure 53 Dynamic stability simulation results, Maui base scenario resource plan, year 2036, P3 planning event
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APPENDIX D – SYSTEM SECURITY STUDY
Figure 54 Dynamic stability simulation results, Maui base scenario resource plan, year 2036, P3 planning event
From above simulation results, UFLS is not identified, and system frequency nadir is well above the first
block of UFLS trigger limit, 59 Hz. It can be concluded that system has sufficient GFM resource to
maintain system stability within planning criteria.
Currently, industry has very limited operational experience for a system with 100% inverter-based
resource. Though planning criteria violation is not observed from the PSCAD study, both study scope
and models used for the study have limitations. And there may be other stability risks that are
unknown currently, and hence not included in the current study, or represented in current models.
To identify the minimum capacity requirement of GFM resource procurement in RFP Stage 3 and REZ
development to maintain Maui system stability within the planning criteria, the P3 and P5 planning
events are simulated considering reduction of GFM resource in the studied 2028 and 2026 scenarios,
until excessive UFLS is observed from the simulations. From the study, it is observed that for the year
2028, Maui system would require at least 90 MW contract capacity GFM resource. This include both
Stage 2 and Stage 3 projects. For the year 2036, the Maui system would need at least 140 MW contract
capacity of GFM resource. For the minimum requirement of the ratio of available MW headroom of
GFM resource over DER generation, Maui system will need maintain this ratio as 0.6. It is worth noting
that MWh energy and a realistic DC side model is not included in the dynamic stability study, and
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APPENDIX D – SYSTEM SECURITY STUDY
sufficient MWh energy in the battery side of GFM resource should always be available for the GFM
resource contingency reserve.
4.3. Hawaiʻi Island System Study Results
4.3.1 Steady state analyses
Base scenario resource plan, year 2032
Study descriptions
By 2030, the Hawaiʻi system will have new generation from Stage 3 RFP procurement and REZ
development, which will be 48 MW wind generation of REZ development by 2029 and 140 MW Stage 3
RFP PV/BESS generation by 2030. All of them will be interconnected at the Hawaiʻi island 69 kV system.
Also, three existing generation plants will be removed by 2031: the 34 MW Hill 5 and 6 will be removed
by 2028; the 21 MW Tawhiri wind generation PPA is expected to expire by 2028; and the 58 MW
Hamakua Energy Partners (“HEP”) contract is expected to expire by 2031. The system peak load is
forecasted to reach 214 MW by 2032. A high-level map with locations of the grid-scale generation
projects assumed in the study by 2032 is shown in Figure 55. For the 48 MW onshore wind generation
from REZ zone A development, it is assumed that interconnection of the project is at the Keamuku
substation. For the 140 MW RFP Stage 3 generation projects, it is assumed the generation
interconnection locations are Puueo (30 MW), Kanoelehua (30 MW), Ouli (20 MW), Poopoomino (30
MW), and Keamuku (30 MW).
RFP Stage 3 Projects
REZ Project2029
Figure 55 High-Level Hawaiʻi island map with assumed future grid-scale project interconnection locations by 2032, base
scenario resource plan
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APPENDIX D – SYSTEM SECURITY STUDY
The detailed system grid-scale resources changes are summarized in Table 115 and Table 116. After
the retirement of HEP and Tawhiri wind generation, by assuming no new generation added in north
and south of system, or no contract renew, there will not be any grid-scale generation on south or
northeast side of the Hawaiʻi island system. The system resource summary and the forecasted system
load is summarized in Table 117.
Table 115 Hawaiʻi Island Grid-Scale Generation Project Development by 2032, after RFP Stage 2, Base Scenario Resource
Plan
Development Generation Type MW Capacity GCOD Location
REZ Development Wind Generation 48 2029 West Hawaiʻi island
Stage 3 Hawaiʻi
Island RFP
Solar/BESS Generation 140 2030 West and east side of
Hawaiʻi island
Table 116 Hawaiʻi Island Grid-Scale Generation Removal by 2032
Removal Generation Type MW Capacity Year Location
Hill 5, 6 Fossil Generation 34 2027 Kanoelehua substation
Tawhiri Generation Wind Generation 21 2028 Kamaoa substation
HEP Fossil Generation 49.4 2031 Haina substation
Table 117 Hawaiʻi Island System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year
2032
Fossil
Generation
Onshore
Standalone Wind
Geothermal
Generation
Grid-Scale Hybrid
Solar/BESS
Hydro DER System Peak Load
85.8 58.5 46 200 16.6 174 214
To evaluate 69 kV transmission system adequacy to host both grid-scale generation interconnection
and the forecasted load according to the resource plan, various system generation dispatches are
created for the study, which is shown in Table 118.
Table 118 Studied System Generation (MW) Dispatches, Hawaiʻi Island Base Scenario Resource Plan, Year 2032
Area Max
Capability
System Generation Dispatches
Max West 1 Max West 2 Max West 3 West Gen Only Max East 1 Max East 2 East Gen Only Max PV/BESS
North n.a. 0 0 0 0 0 0 0 0
West 264 214 214 146 146 71 119 0 140
East 143 0 0 69 0 143 95 143 74
South n.a. 0 0 0 0 0 0 0 0
Total 407 214 214 214 146 214 214 143 214
Study results
Power flow simlations are performed for all studed system generation dispatches with system normal
configuration and N-1 contingency configurations. From the simulation results, transmission line
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APPENDIX D – SYSTEM SECURITY STUDY
overloading is identified from several system generation dispatches with system N-1 contingency
configurations; undervoltage planning criteria violations are identified when system is under both
normal configuration and N-1 contingency configurations. A summary of transmission line overloading
is provided in Table 119, and a summary of undervoltage planning criteria violation is listed in Table
120. Max West 1 and 2 have 8 contingencies each that have non-divergent issues that do not solve and
most likely result in voltage collapse cases.
Table 119 List of High Loading and Overloaded Transmission Lines, Hawaiʻi Island Base Load Scenario Resource Plan, Year
2032
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
High
Loading/Overloading
Element
Max. Loading(%) High
Loading/Overloading
Element
Max. Loading(%)
Max West 1 None None L6200 147
Max West 2 None None L6200 148
Max West 3 None None None None
West Gen Only None None None None
Max East 1 None None L8900 97
Max East 2 None None L8900 99
East Gen Only None None L6200 98
Max PV/BESS None None None None
Table 120 List of Undervoltage Violations, Hawaiʻi Island Base Load Scenario Resource Plan, Year 2032
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
Minimum Voltage (pu) Substation Minimum Voltage (pu) Substation
Max West 1 None None 0.266 Keauhou
Max West 2 None None 0.240 Keauhou
Max West 3 None None 0.810 Keauhou
West Gen Only None None 0.923 Keauhou
Max East 1 None None 0.829 Keauhou
Max East 2 None None 0.816 Keauhou
East Gen Only None None 0.900 Keauhou
Max PV/BESS None None 0.803 Keauhou
Mitigation study – transmission networks expansion
To mitigate the overloading issue on the L6200, a minimum requirement of reconductor is replacing
the L6200 line from Keamuku substation to Kaumana substation by 556 AAC conductor. To mitigate
the high loading condition on the L890 line, from Keamuku substation to Waikoloa distribution
substation, the reconductor requirement is also to replace the line by 556 AAC conductor. A high-level
cost estimate for the L6200 reconductor is $89.2 million, and for L8900 is $10.9 million.
Though the high loading and overloading conditon on the L6200 and L8900 is fixed by the reconductor,
the undervoltage issues still exist, which cannot be mitigated by the reconductor. The undervoltage
issue is mainly caused by the resource retirement in the south and north/east side of the Hawaiʻi island
system.
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APPENDIX D – SYSTEM SECURITY STUDY
Dependent on the system total load and the east side generation resources chosen to meet this
minimum requirement, the east may require 20 MVAR of additional reactive power capability to
resolve potential north/east voltage violations. At the peak load with 20 MW generation on east side of
island, the following options are viable for mitigating north/east undervoltage violations:
• All 3 units of PGV online
• Puna CT3 online with 2.8 MVAR additional reactive capability required at Kanoelehua or Puueo
substations
• Stage 3 Kanoelehua with 20 MVAR additional reactive capability required at Kanoelehua
• Stage 3 Kanoelehua & Puueo (split output) with 20 MVAR additional reactive capability required
between the two locations. The Additional reactive capability at Kanoelehua and Puueo are in
addition to the assumed capability of the Stage 3 resources at that location
To mitigate undervoltage violation identifed on south side of system, it is recommend to have a
resource interconnected at Keauhou substation with at least 10.4 Mvar capability or at Kamaoa
substation with 13.7 Mvar or 13.3 MW capability. The reactive power capability can be replaced by
active power capability, or the combination of reactive power and active power capability.
Mitigation study – portfolio options
From the power flow analyses for various system generation dispatches, it can be concluded that:
• Overloading on the L6200 line will occur with higher levels of generation dispached on west
side of system pre-contingency, and large volumn of cross island power flow through it during
post contingency. This cross island power flow from west to east side of the system if
generation resources are located to balance production in East and West Hawaii. It is also
observed that system load is below 174 MW, the overloading on the L6200 is unlikely to
happen.
• Reconductoring the L6200 line does not mitigate the undervotlage issue on north/east side and
south side of the system. Generation resources and reactive power resources will be required
on the east and south side of the system. Procuring resources on both the East and South side
is required for the voltage constraint, which also improves the L6200 overload.
Therefore, reconductoring the L6200 is required for unconstrained use of resources identified in the
portfolio. The resource acquisition would need to procure MW generation on the east side of Hawaii
Island, at the levels needed to avoid overloading the L6200 line for single contingencies. The minimum
requirement of MW generation on the east side of the system was calculated by following equation:
East side minimum generation (MW) = 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝑆𝑆𝑡𝑡𝑆𝑆𝑡𝑡𝑡𝑡 𝑡𝑡𝑡𝑡𝑡𝑡𝑙𝑙−174214−174 ∙20
The L8900 line high loading condition is caused by high production from the east side and Keamuku
substation. By shifting of generation on further west side of system (e.g., Keahole, Poopoomino, Ouli),
the overloading on the L8900 can be avoided.
The planning study did not consider beyond N-1 conditions, however, the reconductoring and
procuring resources distributed around the island’s transmission system, will improve resilience, in
addition to removing dispatch constraints on the present base resource portfolio that otherwise would
be necessary.
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REZ Enablement
The interconnection of 48 MW wind generation from REZ development is assumed at the Keamuku
substation. The estimated REZ enablement cost for the 48 MW offshore wind interconnection at the
Keamuku substation is $37.8 million.
Base scenario resource plan, year 2050
Study descriptions
In addition to previous system resource changes by 2031, the Hawaiʻi island system will have 2 MW
standalone BESS and 3 MW Solar/BESS from the REZ development by 2035. It is assumed that both
interconnection will be in distribution circuits by considering their MW size. In 2040, there will be
another 20 MW Solar/BESS generation developed from REZ. In 2045, all fossil generation will have fuel
switch to biodisel. In the same year, there will be 30 MW geothermal generation and 2 MW standalone
BESS interconnected to the system. By 2050, an additional 14 MW Solar/BESS and 2 MW onshore wind
generation will be developed from REZ. The system annual peak load is forecasted to reach 295 MW by
2050. A high-level map with locations of the grid-scale generation projects assumed in the study by
2050 is shown in Figure 56. For the 20 MW PV/BESS generation from REZ zone A development by 2040,
it is assumed that interconnection of the project is at the Pepeekeo substation. For the 30 MW
geothermal generation project, it is assumed the generation interconnection is at Haina substation. For
the 17 MW PV/BESS project, it is assumed the generation interconnection is at Kaumana substation.
RFP Stage 3
Projects
REZ Project2029
REZ Projects2040
Geothermal2045
REZ Projects
2050
Figure 56 High-Level Hawaiʻi island map with assumed future grid-scale project interconnection locations by 2050, base
scenario resource plan
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The detailed system grid-scale resource changes are summarized in Table 121. The system resource
summary and the forecasted system load is summarized in Table 122.
Table 121 Hawaiʻi Island Grid-Scale Generation Project Development by 2050, Base Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development Solar/BESS 3 2035 REZ, distribution
interconnected
Other Standalone BESS 2 2035 Distribution
interconnected
REZ Development Solar/BESS 20 2040 REZ, east side of Hawaiʻi
island
Other Geothermal 30 2045 North side of Hawaiʻi
island
REZ Development Solar/BESS 14 2050 REZ, east side of Hawaiʻi
island Onshore wind 2 2050
Table 122 Hawaiʻi Island System Resource Summary and Forecasted Demand (MW), Base Scenario Resource Plan, Year
2032
Fossil
Generation
Onshore
Standalone Wind
Geothermal
Generation
Grid-Scale Hybrid
Solar/BESS
Hydro DER System Peak Load
85.8 60.5 76 237 16.6 243 295
To evaluate 69 kV transmission system adequacy to host both grid-scale generation interconnection
and the forecasted load according to the resource plan, various system generation dispatches are
created for the study, which is shown in Table 123.
Table 123 Studied System Generation (MW) Dispatches, Hawaiʻi Island Base Scenario Resource Plan, Year 2032
Area Max
Capability
System Generation Dispatches
Max West Max East East Gen
Only
Max PV
Paird
North 30 30 30 0 6
West 264 264 86 0 192
East 180 0 180 180 97
South n.a. 0 0 0 0
Total 474 294 294 294 294
Study Results
Similiar to what is observed in the base scenario resource plan year 2032 study, transmission line
overloading, undervoltage violation and voltage collapse are also observed from the power flow
analyses performed for the system generation dispatches. A summary of transmission line overloading
condition is provided in Table 124. A summary of undervoltage planning criteria violation and voltage
collapse is listed in Table 125. Max East case has 1 non-divergent issue, Max PV/BESS has 2 non-
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divergent issues, and Max West has 2 non-divergent issues. These cases with non-divergent issues
have contingencies that do not solve and most likely result in voltage collapse.
Table 124 List of High Loading and Overloaded Transmission Lines, Hawaiʻi Island Base Load Scenario Resource Plan, Year
2050
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
High
Loading/Overloading
Element
Max. Loading(%) High
Loading/Overloading
Element
Max. Loading(%)
Max West None None L6200 137
Max East None None L8900 127
East Gen Only None None L8600 128
Max PV/BESS None None L8600 122
Table 125 List of Undervoltage Violations, Hawaiʻi Island Base Load Scenario Resource Plan, Year 2050
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
Minimum Voltage (pu) Substation Minimum Voltage (pu) Substation
Max West 0.848 PGV 0.161 Keauhou
Max East None None 0.414 Keauhou
East Gen Only None None 0.891 Keauhou
Max PV/BESS None None 0.235 Keauhou
Mitigation study – transmission networks expansion
Reconductoring L6200 and L8900 to 556 AAC is recommended to mitigate overloading issues. The
estimated cost for reconductoring L6200 is $89.2 million, and the estimated cost for reconductoring
L8900 is $10.9 million. To mitigate undervoltage violations on the north side of the system, it is
recommended to dispatch an East unit (e.g., PGV, etc.) at 5 MW or higher.
To mitigate undervoltage violation on south and southwest side of the system, it is recommend to have
a resource interconnected at Kamaoa with 22.5 MW generation capacity.
REZ Enablement
It is assumed that the geothermal generation in service in 2045 will be interconnected at Haina
substation, and the REZ generation will be interconnected at Pepeekeo substation (20 MW) in 2040
and Kaumana substation (17 MW) in 2050.
High level cost estimate for the 20 MW interconnection REZ enablement at the Pepeekeo substation is
$24.5 million, and for the 17 MW interconnection REZ enablement at the Kaumana substation is $27.9
million.
High load scenario resource plan, year 2032
Study descriptions
According to the resource plan, by 2030, the Hawaiʻi system will have new generation from Stage 3 RFP
procurement, REZ development and a new geothermal generation plant, which will be 48 MW wind
generation of REZ development and 30 MW geothermal generation by 2029 and 140 MW Stage 3 RFP
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PV/BESS IBR generation by 2030. All of these new generation will be interconnected at Hawaiʻi island
69 kV system. Meanwhile, three generation plants will be removed by 2031: the 34 MW Hill 5 and 6
will be removed by 2028; the 21 MW Tawhiri wind generation will be removed by 2028; the 58 MW
Hamakua Energy Partners (“HEP”) will be removed from system by 2031. Accoridng to the forecast,
system peak load will reach 280 MW by 2032. A high-level map with locations of the grid-scale
generation projects assumed in the study by 2032 is shown in Figure 57. For the 48 MW onshore wind
generation from REZ zone A development and the 140 MW generation projects from the RFP Stage 3
procurement, the assumptions regarding the generation interconnection locations are the same as
what is used in the base scenario resource plan. For the 30 MW geothermal generation project, it is
assumed that it will be interconnected at Haina substation.
RFP Stage 3 Projects
REZ Project
2029REZ Project
2029
Figure 57 High-Level Hawaiʻi island map with assumed future grid-scale project interconnection locations by 2032, high
load scenario resource plan
The detailed system grid-scale resources changes are summarized in Table 126. The system resource
summary and the forecasted system load is summarized in Table 127. System resource retirement
schedule in the high load scenario resource plan is the same as that in the base scenario resource plan.
Table 126 Hawaiʻi Island Grid-Scale Generation Project Development by 2032, High Load Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development Wind Generation 48 2029 West Hawaiʻi island
Other Geothermal Generation 30 2029 North of Hawaiʻi island
Stage 3 Hawaiʻi
Island RFP
Solar/BESS Generation 140 2030 West and east side of
Hawaiʻi island
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Table 127 Hawaiʻi Island System Resource Summary and Forecasted Demand (MW), High Scenario Resource Plan, Year
2032
Fossil
Generation
Onshore
Standalone Wind
Geothermal
Generation
Grid-Scale Hybrid
Solar/BESS
Hydro DER System Peak Load
85.8 58.5 76 200 16.6 174 280
To evaluate 69 kV transmission system adequacy to host both grid-scale generation interconnection
and the forecasted load according to the resource plan, various system generation dispatches are
created for the study, which is shown in Table 128.
Table 128 Studied System Generation (MW) Dispatches, Hawaiʻi Island Base Scenario Resource Plan, Year 2032
Area Max
Capability
System Generation Dispatches
Max West Max East Max
North/East
Max PV
Paird
North 30 16 30 30 21
West 264 264 107 107 199
East 142 0 143 143 60
South n.a. 0 0 0 0
Total 437 280 280 280 280
Study results
Significant transmission line overloading, undervoltage planning criteria violations and voltage collapse
issues are identified from power flow analyses performed for all the studied system generation
dispatches. A summary of transmission line overloading conditions are provided in Table 129.
Asummary of undervoltage planning criteria violation and voltage collapse are listed in Table 130. Max
East case has 1 non-divergent issue, Max PV/BESS has 1 non-divergent issue, and Max West has 18
non-divergent issues. These cases with non-divergent issues have contingencies that do not solve and
most likely result in voltage collapse and show 0 PU minimum voltage.
Table 129 List of High Loading and Overloaded Transmission Lines, Hawaiʻi Island High Load Scenario Resource Plan, Year
2032
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
High
Loading/Overloading
Element
Max. Loading(%) High
Loading/Overloading
Element
Max. Loading(%)
Max West L8600 95 L6200 126
Max East None None L8900 121
Max North/East None None L8600 100
Max PV/BESS None None L8600 99
Table 130 List of Undervoltage Violations, Hawaiʻi Island High Load Scenario Resource Plan, Year 2032
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
Minimum Voltage (pu) Substation Minimum Voltage (pu) Substation
Max West 0.787 PGV 0.645 PGV
Max East None None 0.771 Panaewa
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Max North/East None None 0.835 Panaewa
Max PV/BESS None None 0.815 PGV
Mitigation study – transmission networks expansion
Reconductoring to 556 AAC for the L8100 line is recommended to mitigate the overloading on the
L8100 line. The estimated cost for reconductoring L8100 is $10.9 million. Regarding the L6200 line
overloading, it is recommended to defer the reconductor to further year by requiring minimum
generation dispatch on the east side of the system.
Simliar as discussed in the base scenario resource plan study, generation resource and reactive power
resource is required to mitigate the overvoltage and voltage collapse issues. Depending on the system
total load and the East side generation resources chosen to meet this minimum requirement, the East
may require 28 MVAR of additional reactive power capability to resolve potential North/East voltage
violations. 14 MVAR at Kanoelehua and 14 MVAR at Puueo are recommended to be installed (in
addition to the assumed capability of Stage 3 resources at that location).
To mitigate undervoltage violation identifed on south side of system, it is recommend to have a
resource interconnected at Kamaoa substation with at least 24 MW generation capability, with var
capability independent of active power generation. If a minimum MW is required this may require
some resource to ensure it is available if the resource is variable, or define the requirement in terms of
MVAR.
Mitigation study – Portfolio alternative
Reconductoring L6200 line to 556 AAC is required to accommodate the base portfolio without
dispatch constraints. A minimum generation requirement on the east side of the system can be
described as:
East side minimum generation (MW) = 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝑆𝑆𝑡𝑡𝑆𝑆𝑡𝑡𝑡𝑡 𝑡𝑡𝑡𝑡𝑡𝑡𝑙𝑙−174214−174 ∙20
If the system total load is lower than 178 MW, there is no mimimum MW requirement of generation
dispatched on east side of the system.
REZ Enablement
The interconnection of 48 MW wind generation from REZ development is assumed at the Keamuku
substation. The estimated REZ enablement cost for the 48 MW offshore wind interconnection at the
Keamuku substation is $37.8 million.
High load scenario resource plan, year 2036
Study descriptions
In addtion to previous system resource changes, by 2035 the Hawaiʻi island system will have another
30 MW geothermal generation, 30 MW firm generation and 22 MW solar/BESS generation from REZ
development. Accoriding to the forecast, system annual peak load will be reached at 323 MW by 2036.
A high-level map with locations of the grid-scale generation projects assumed in the study by 2032 is
shown in Figure 58. For the 22 MW PV/BESS generation from REZ zone A development, it is assumed to
be interconnected at Pepeekeo substation; for the 30 MW firm generation, it is assumed to be
interconnected at the Kanoelehua substation; and for the second 30 MW geothermal generation
project, it is assumed to be interconnected at the Haina substation. The detailed system grid-scale
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resources changes are summarized in Table 131. The system resource summary and the forecasted
system load is summarized in Table 132. System resource retirement schedule in the high load scenario
resource plan is the same as that in the base scenario resource plan.
Figure 58 High-Level Hawaiʻi island map with assumed future grid-scale project interconnection locations by 2036, high
load scenario resource plan
Table 131 Hawaiʻi Island Grid-Scale Generation Project Development by 2036, High Load Scenario Resource Plan
Development Generation Type MW Capacity GCOD Location
REZ Development Solar/BESS 22 2035 East side of Hawaiʻi island
system
Other Geothermal 30 2035 North side of Hawaiʻi
island system
Other Firm 30 2045 East side of Hawaiʻi island
system
RFP Stage 3 Projects
REZ Project2029REZ Project
2029
REZ Project
2035Geothermal2035
Firm 2035
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Table 132 Hawaiʻi Island System Resource Summary and Forecasted Demand (MW), High Load Scenario Resource Plan,
Year 2036
Fossil
Generation
Onshore
Standalone Wind
Geothermal
Generation
Grid-Scale Hybrid
Solar/BESS
Hydro DER System Peak Load
115.8 58.5 106 220 16.6 230 323
To evaluate 69 kV transmission system adequacy to host both grid-scale generation interconnection
and the forecasted load according to the resource plan, various system generation dispatches are
created for the study, which is shown in Table 133.
Table 133 Studied System Generation (MW) Dispatches, Hawaiʻi Island High Load Scenario Resource Plan, Year 2036
Area Max
Capability
System Generation Dispatches
Max West Max East 1 Max East
2
Max
Renewable
North 30 58 60 60 21
West 264 264 69 119 199
East 195 3 195 145 0
South n.a. 0 0 0 0
Total 519 325 325 325 220
Study results
Power flow analyses are performed for all the system generation dispaches, when the Hawaiʻi island
system is with normal configuration and when the system is with N-1 contingency configuration.
Analysis results indicate significant trasmission line overloading on the cross-island line L6200 and
undervoltage violation with voltage collapse potential, which is simliar as what is observed in the high
load scenario resource plan year 2032 study. Additonally, overloading on the L8600 is also identified.
This is due to the generation retirement, as well as load growth on the south side of the system. A
summary of transmission line overloading condition is provided in Table 134. A summary of
undervoltage planning criteria violation and voltage collapse is listed in Table 135. Max East 1 case has
4 non-divergent issue, Max East 2 has 3 non-divergent issues, Max Renewable has 4 non-divergent
issues, and Max West has 20 non-divergent issues. These cases with non-divergent issues have
contingencies that do not solve and most likely result in voltage collapse and show 0 PU minimum
voltage.
Table 134 List of High Loading and Overloaded Transmission Lines, Hawaiʻi Island High Load Scenario Resource Plan, Year
2036
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
High
Loading/Overloading
Element
Max. Loading(%) High
Loading/Overloading
Element
Max. Loading(%)
Max West L8600 100 L8600 118
Max East 1 None None L8900 167
Max East 2 None None L8900 131
Max Renewable None None L8900 123
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Table 135 List of Undervoltage Violations, Hawaiʻi Island High Load Scenario Resource Plan, Year 2036
Generation Dispatch
Normal Configuration N-1 Contingency Configuration
Minimum Voltage (pu) Substation Minimum Voltage (pu) Substation
Max West None None 0.658 Kilauea
Max East None None 0.256 Keauhou
Max East 2 None None 0.316 Keauhou
Max Renewable None None 0.815 Capt Cook
Mitigation study – transmission networks expansion
To mitigate the transmission line overloading issues, reconductor of L6200 line to 556 AAC and L8600
line to 336 AAC is proposed. The estimated cost for reconductoring the L6200 is $89.2 million, and the
estimated cost for reconductoring the L8600 is $32.3 million.
To mitigate undervoltage violations on the north side of the system, it is recommended to dispatch an
East unit (e.g., PGV, etc.) at 14 MW or higher.
To mitigate undervoltage violation on south and southwest side of the system, , it is recommended to
have a resource interconnected at Kamaoa with at least 24 MW active power generation capacity and
7.5 Mvar reactive power capability.
To mitigate undervoltage violations on the west side of the system during dispatches with high east
generation, it is recommended to dispatch Keahole at 10 MW or higher.
REZ Enablement
Between 2033 and 2036, there is 20 MW PV/BESS generation project from the REZ zone A
development, which is assumed to be interconnected at the Pepeekeo substation. The estimated cost
for the REZ enablement in Pepeekeo substation is $24.5 million.
4.3.2 Dynamic stability study
The Hawai’i Island system in near-term years 2026 and 2032 of base scenario resource plan are
selected for performing dynamic stability study to evaluate system dynamic stability performance.
Similar to the O’ahu and Maui studies, the Hawai’i Island system dynamic stability study is performed
in PSCAD/EMTDC for the high-risk system generation dispatch, which is also the daytime peak load
with high DER generation, with a short list of high-risk system contingency.
The Hawai’i Island system high-risk contingency consists of a contingency for each category of planning
events from P1 to P5. Also, due to the system topology and interconnection of existing grid-scale
generations, for each selected year, dynamic stability study is performed for a base dispatch, in which
most synchronous machine-based generation is dispatched from east side of the system, and a
sensitivity dispatch, in which most of synchronous machine-based generation is dispatched from west
side of the system.
Base scenario resource plan, year 2026
Study descriptions and study results
According to the resource plan, in 2026, there is no additional grid-scale generation resource
interconnected to the system beyond RFP Stage 1 projects. So, the study of 2026 benchmarks system
dynamic stability performance. A base system generation dispatch and a sensitivity system generation
dispatch, both representing daytime peak load with high DER generation scenario in 2026 with
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different system topology, are created (as Table 136) and modeled in PSCAD/EMTDC. In these two
dispatches, there is no GFM IBR resources in the system. Study results are summarized in Table 137.
From the simulation results, it can be concluded that the Hawai’i Island system does not have sufficient
resource to maintain system stability within planning criteria for the selected dispatch scenarios before
the RFP Stage 3 projects interconnected online.
Table 136 System Generation Dispatches (Base Dispatch and Sensitivity Dispatch) for Daytime Peak Load High DER
Generation Scenario, Hawai’i Island Base Scenario Resource Plan, Year 2026
Generation Station Capacity (MW) Base Dispatch (MW) Sensitivity Dispatch (MW)
PGV 38 38 0
Keahole DTCC 52 0 38
Hill 5&6 34 13 13
Hydro Generation 17 5 5
Wind Generation 31 5 5
Stage 1 PV/BESS (GFL) 60 36 36
DER 143 103 103
System Load (MW) 200 200
Table 137 Hawai’i Island System Dynamic Stability Study Results Summary, Hawai’i Island Base Scenario Resource Plan,
Year 2026
Planning
Event
2026 Base Dispatch 2026 Sensitivity Dispatch
UFLS (MW) DER Trip (MW)
Freq. Nadir (Hz)
UFLS Blocks Shed
Planning Criteria Violation?
Notes UFLS (MW) DER Trip (MW)
Freq. Nadir (Hz)
UFLS Blocks Shed
Planning Criteria Violation?
Notes
P1/P3 6 5 58.8 B1 Yes 1 32 41 58.5 B1-3 Yes 1,2
P2 57 47 58.1 B1-4 Yes 1,2 57 47 58.0 B1-4 Yes 1,2
P4 0 8 59.3 None No 3 0 1 59.5 None No 3
P5 32 31 58.2 B1-3 Yes 1 57 46 58 B1-4 Yes 1
Note:
1. UFLS caused by DER momentary cessation during transmission fault voltages.
2. Legacy DER trip due to overfrequency overshoot caused by excessive UFLS.
3. Small synchronous machine power oscillations caused by unbalanced tripping of DER
Detailed simulation results for selected planning events (a P5 event for base dispatch and a P3 event
for sensitivity dispatch) are shown in Figure 59 and Figure 60.
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Figure 59 Dynamic stability simulation results, Hawai’i Island base scenario resource plan, year 2026, base dispatch, P5
planning event
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Figure 60 Dynamic stability simulation results, Hawai’i Island base scenario resource plan, year 2026, sensitivity dispatch,
P3 planning event
Base scenario resource plan, year 2032
Study descriptions and study results
According to the resource plan, a base system generation dispatch and sensitivity system generation
dispatch, both representing daytime peak load with high DER generation scenario in 2032 with RFP
Stage 3 projects, are created (as Table 138) and modeled in PSCAD/EMTDC.
Table 138 System Generation Dispatches (Base Dispatch and Sensitivity Dispatch) for Daytime Peak Load High DER
Generation Scenario, Hawai’i Island Base Scenario Resource Plan, Year 2032
Generation Station Capacity (MW) Base Dispatch (MW) Sensitivity Dispatch (MW)
PGV 46 20 0
Keahole STCC 26 0 20
Hydro Generation 17 4 4
Wind Generation 59 0 0
Stage 1 PV/BESS (GFL) 60 20 20
Stage 3 PV/BESS (GFM) 140 28 28
DER 214 134 134
System Load (MW) 206 206
GFM Available MW Headroom/DER Generation 0.84 0.84
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PSCAD simulation results are summarized in Table 139. After adding the 140 MW GFM resource from
the RFP Stage 3 procurement, planning criteria violation is not identified, and according to the
frequency nadirs of all simulated system events, the Hawai’i Island system has sufficient stability
margin. From the simulations, sustained oscillations in real power are also observed in the Stage 3 IBR
responses and synchronous machine responses. This may come from the untuned models which are
used for representing the RFP stage 3 projects. Detailed simulation results for selected planning events
(a P5 event for base dispatch and a P3 event for sensitivity dispatch) are shown in Figure 59 and Figure
60.
Table 139 Hawai’i Island System Dynamic Stability Study Results Summary, Hawai’i Island Base Scenario Resource Plan,
Year 2032
Planning
Event
2032 Base Dispatch 2032 Sensitivity Dispatch
UFLS
(MW)
DER
Trip
(MW)
Freq.
Nadir
(Hz)
UFLS
Blocks
Shed
Planning
Criteria
Violation?
Notes UFLS
(MW)
DER
Trip
(MW)
Freq.
Nadir
(Hz)
UFLS
Blocks
Shed
Planning
Criteria
Violation?
Notes
P1/P3 0 0 59.6 None No 0 0 59.2 None No
P2 0 0 59.6 None No 1 0 0 59.2 None No 1
P4 0 0 59.8 None No 1 0 0 59.8 None No 1
P5 0 0 59.6 None No 0 0 59.6 None No 1
Note:
1. Steady state real power oscillations in RFP Stage 3 projects and synchronous machines.
Figure 61 Dynamic stability simulation results, Hawai’i Island base scenario resource plan, year 2032, base dispatch, P5 planning event
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Figure 62 Dynamic stability simulation results, Hawai’i Island base scenario resource plan, year 2032, base dispatch, P3
planning event
Further study is also performed to identify minimum requirement regarding GFM resource
procurement in order to maintain the Hawai’i Island dynamic stability within planning criteria, by step
reducing the size of future GFM resource and creating different combinations of east side
interconnection size and west side interconnection size. This study is performed for both base dispatch
(i.e., major synchronous generation dispatched on east side) and sensitivity dispatch (i.e., major
synchronous generation dispatched on west side), with the same high-risk contingency list. Study
results for the base dispatch and sensitivity dispatch are summarized as following tables. From the
study, it can be concluded that the minimum GFM requirements are dependent on system available
GFM resource and synchronous generation and it is important to have a balanced interconnection of
grid-scale GFM resources between east and west side of Hawai’i Island system. By 2032, the minimum
requirement for Hawai’i Island system may be between 60MW – 110MW of GFM capacity on the
system, and the ratio of available MW headroom from GFM resource to DER generation should be
roughly 0.24 to 0.61 depending on system dispatch. All these requirements are based on the model
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performance used in the study to represent future GFM generation, and hence these requirements will
be updated according to the future procured resource performance.
Table 140 Hawai’i Island System Minimum GFM Requirement Study Results Summary, Hawai’i Island Base Scenario
Resource Plan, Year 2032, Base Dispatch
MW Size of
GFM Resource
Total GFM
MW Size
GFM
Headroom/
DER
Generation
Contingency
West
side
East
side 1 2 3 4
80 60 140 0.84 No Identified Issues Steady-state oscillations Steady-state oscillations Steady-state oscillations
80 0 80 0.39 No Identified
Issues
Steady-state
oscillations
No Identified
Issues
No Identified
Issues
30 30 60 0.24 No Identified
Issues
Steady-state
oscillations
Steady-state
oscillations
No Identified
Issues
50 0 50 0.16 UFLS observed UFLS observed No Identified
Issues
No Identified
Issues
30 0 30 0.01 UFLS observed UFLS observed No Identified
Issues UFLS observed
Table 141 Hawai’i Island System Minimum GFM Requirement Study Results Summary, Hawai’i Island Base Scenario
Resource Plan, Year 2032, Sensitivity Dispatch
MW Size of
GFM Resource
Total GFM
MW Size
GFM
Headroom/
DER
Generation
Contingency
West
side
East
side 1 2 3 4
80 60 140 0.84 No Identified Issues Steady-state oscillations Steady-state oscillations Steady-state oscillations
60 50 110 0.61 No Identified
Issues
Steady-state
oscillations
No Identified
Issues
Steady-state
oscillations
20 60 80 0.39 UFLS observed UFLS observed Steady-state oscillations
No Identified
Issues
No Identified
Issues
20 30 50 0.16 UFLS observed UFLS observed No Identified
Issues
No Identified
Issues
0 30 30 0.01 UFLS observed UFLS observed No Identified Issues UFLS observed
4.4. Molokaʻi and Lāna‘i Study Results
Both Moloka’i and Lāna‘i are much smaller systems by comparing with the remaining three island
systems. Neither the Moloka’i nor the Lāna‘i system has a transmission planning criterion since there is
no transmission system there. In the scope of this study, only dynamic stability of the Moloka’i and
Lāna‘i system based on the resource plan is reviewed. The criteria used for this study is that the two
systems can survive a primary circuit (12 kV or 33 kV) three-phase bolted fault with 2 seconds duration
and single phase to ground high impedance fault with 40 Ohm fault impedance with 20 seconds
duration. For each selected year for the study, for both the three-phase fault and the single line to
ground fault, both close in fault, which is the fault applied at the beginning of the circuit, and far end
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fault, which is the fault applied at the end of a circuit, are simulated. All simulations are performed in
PSCAD/EMTDC. The years that are selected for the study are:
• Molokaʻi system base scenario resource plan – 2029, 2030 and 2050.
• Molokaʻi system high load scenario resource plan – 2029, 2030 and 2050
• Lanaʻi system base scenario resource plan – 2029 and 2050.
• Lanaʻi system high load scenario resource plan – 2029 and 2050
• Lanaʻi system No Resort scenario resource plan – 2029, 2030 and 2050
4.4.1 Molokaʻi Study Results
Base scenario resource plan, year 2029
Daytime peak load low DER and low diesel generation dispatch is selected for the study. In this
dispatch, system load is 5.4 MW, supplied by DER (1 MW), existing diesel unit (D8, generating 2 MW),
and centralized IBR (5.75 MW GFM BESS capacity and 6 MW PV generation capacity). Simulation
results for a three-phase close in fault are shown in Figure 63, and for a three-phase far end fault is
shown in Figure 64. From the close in fault results, it can be observed that system can survive the 2
seconds duration fault by successfully recovering system voltage and frequency; however, system may
have diesel unit out of synchronism during the far end three-phase fault. In both cases, the GFM IBR
resources demonstrate stability of ride-through the fault.
Figure 63 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2029, three-phase close in fault
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Figure 64 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2029, three-phase close in fault
For the single phase to ground high impedance fault, a case with a far end high impedance single phase
to ground is shown in Figure 65. From the simulation, it can be found that Moloka’i Palaau substation
could experience voltage dip down to 0.5 p.u., and system frequency could swing between 56 Hz to 64
Hz. Once again, the diesel unit become out of synchronism 3 seconds after the fault inception, which
causes system frequency reach 64 Hz. After fault clearing, the system voltage and frequency can
recover within acceptable limits. It is worth noting that in the current system, there is no out of
synchronism protection for the diesel unit. Once system has enough GFM resource to pick up load
supplied by the synchronous machine pre-event, system protection should be configured to let the
synchronous machine trip, in order to reduce disturbance in the system.
Figure 65 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2029, single phase far end fault
with high fault impedance
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Base scenario resource plan, year 2030
Daytime peak load low DER and low diesel generation dispatch is selected for the study. In this
dispatch, system load is 5.4 MW, supplied by DER (1 MW), existing diesel unit (D8, generating 1.1 MW),
and centralized IBR (14.25 MW GFM BESS capacity, and 14.5 MW PV generation capacity). Simulation
results of system voltage and frequency for a close in three-phase bolted fault with 2 seconds duration
are shown in Figure 66, and for a far end three-phase fault are shown in Figure 67. The simulation
results indicate system can maintain stable during the fault and after fault clearing. The large capacity
of GFM resource can quickly recovery system voltage and frequency after the fault clearing. Simulation
results for a far end high impedance single line to ground fault are shown in Figure 68 which indicates
the same conclusion that system has sufficient stability to survive the 20 seconds duration high
impedance fault.
Figure 66 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2030, three-phase close in fault
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Figure 67 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2030, three-phase far end fault
Figure 68 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2030, high impedance far end
fault
Base scenario resource plan, year 2050
For the 2050 case, system evening peak load no DER no diesel unit generation dispatch is created for
the study. In this scenario, all of the system load, which is 6.29 MW, is supplied by the centralized GFM
BESS resources (with 21.5 MW capacity). Same three-phase faults and the far end high impedance
single line to ground fault are studied. The simulation results indicate that the system can survive both
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the three-phase fault and the high impedance single line to ground fault. Simulation results are shown
in Figure 69, Figure 70, and Figure 71.
Figure 69 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2050, three-phase close in fault
Figure 70 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2050, three-phase far end fault
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Figure 71 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2050, high impedance far end
fault
In summary, it is found from the studies that sufficient centralized GFM resource interconnected at the
Palaau substation can maintain system stability (i.e., surviving the 2 second three-phase bolted fault
and the 20 seconds high impedance single line to ground fault) without need of the existing diesel unit.
The existing diesel unit is likely to be out of synchronism during the fault, which could cause the system
to experience large voltage or frequency swing. It is recommended that once system has sufficient
GFM resource (from 2030), out-of-step protection should be installed for the existing diesel unit to
make sure the machine can be tripped during the fault to avoid system voltage and frequency swing
and equipment damage. This conclusion and recommendations are very similar as what is concluded in
the 2021 System Stability Study.
High load scenario resource plan study
The Moloka’i system high load scenario resource plan is the same as the base scenario resource plan,
but with different load forecast. According to the high load scenario resource plan, the Moloka’i
system load is normally 1-2 MW higher than the same year load forecast in the base scenario resource
plan. Exact same generation dispatches are studied for the same selected years (2029, 2030 and 2050),
with the same fault events. Simulation results indicate the same conclusion as what is found for the
base resource scenario that GFM resource in 2030 and further years is sufficient to maintain system
stability, and out-of-step protection should be installed for the existing diesel units to avoid system
voltage and frequency swing caused by the diesel units out of synchronism.
4.4.2 Lāna‘i Study Results
Base scenario resource plan, year 2029
Daytime peak load low DER and low diesel generation dispatch is selected for the study. In this
dispatch, system load is 5.9 MW, supplied by DER (0.33 MW), existing diesel unit (D8, generating 0.5
MW), centralized IBR (16.1 MW GFM BESS capacity, and 16.1 MW PV generation capacity). Simulation
results for a three-phase close in fault are shown in Figure 72, and for a three-phase far end fault is
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shown in Figure 73. From the close in fault results, it can be observed that system can survive the 2
seconds duration fault by successfully recovering system voltage and frequency. In both cases, the
GFM IBR resources demonstrate stability and the ability to ride-through the fault.
Figure 72 Dynamic stability simulation results, Lāna‘i base scenario resource plan, year 2029, three-phase close in fault
Figure 73 Dynamic stability simulation results, Moloka’i base scenario resource plan, year 2029, three-phase close in fault
Figure 74 shows the simulation results of system voltage and frequency for a far end high impedance
single phase to ground fault scenario. From the simulation, it can be found that the Miki Basin
substation voltage could experience voltage dip down to 0.75 p.u., and system frequency could be
maintained between 59.5 Hz and 60 Hz. System can immediately recover voltage and frequency after
clearing the fault. The system stability performance is well within acceptable range.
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Figure 74 Dynamic stability simulation results, Lāna‘i base scenario resource plan, year 2029, single phase far end fault
with high fault impedance
Base scenario resource plan, year 2050
Daytime peak load low DER and low diesel generation dispatch is selected for the study. In this
dispatch, system load is 5.83 MW, supplied by DER (0.34 MW), existing diesel unit (D8, generating 2
MW), centralized IBR (24.8 MW GFM BESS capacity, and 24.8 MW PV generation capacity). The same
fault scenarios as studied in the 2029 case are also simulated in the study for the 2050 case. Simulation
results indicate that the 24.8 MW GFM resource is sufficient to maintain system stability during both
the three-phase fault and the high impedance single phase fault. The simulation results are shown in
Figure 75, Figure 76, and Figure 77.
Figure 75 Dynamic stability simulation results, Lāna‘i base scenario resource plan, year 2050, three-phase close in fault
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Figure 76 Dynamic stability simulation results, Lāna‘i base scenario resource plan, year 2050, three-phase close in fault
Figure 77 Dynamic stability simulation results, Lāna‘i base scenario resource plan, year 2050, single phase far end fault
with high fault impedance
High load scenario resource plan study
Lāna‘i system high load scenario resource plan is the same as the base scenario resource plan, but with
higher load forecast. Exact same generation dispatches are studied for the same selected years (2029
and 2050), with the same fault events. Simulation results indicate the same conclusion as what is found
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for the base resource scenario that GFM resource in 2029 and further years is sufficient to maintain
system stability.
No resort load scenario resource plan, year 2029
In this resource plan, it is assumed that a big part of system load will be off grid. Hence, system load
forecast is much smaller than what is shown in the base scenario and high load scenario resource
plans. The load reduction also causes much smaller centralized resource planned for the system. For
2029, daytime peak load low DER and low diesel generation dispatch is selected for the study. In this
dispatch, system load is 2.9 MW, supplied by DER (0.28 MW), existing diesel unit (D8, generating 1.02
MW), centralized IBR (3.9 MW GFM BESS capacity, and 3.9 MW PV generation capacity). The same
three-phase faults and single line to ground faults are simulated in the PSCAD. Simulation results are
shown as Figure 78, Figure 79, and Figure 80. From the three-phase fault simulation results, it can be
observed that the dispatched diesel unit would not be able to ride-through the 2 seconds duration
fault. Instead, the diesel unit shows out of synchronism from the simulation, which could cause system
frequency swing after clearing the fault. Also, the 3.9 MW GFM resource is not big enough apparently
to absorb disturbance caused by the diesel unit out of synchronism. However, the 3.9 MW GFM unit
can survive from both the three-phase fault and the high impedance single line to ground fault.
Figure 78 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2029, three-phase close in
fault
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Figure 79 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2029, three-phase close in fault
Figure 80 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2029, single phase far end fault with high fault impedance
No resort load scenario resource plan, year 2030
According to the resource plan, in 2030, 6.3 MW GFM resource will be added into the system. System
peak load forecast is 3.0 MW. Daytime peak load low DER and low diesel generation dispatch is
selected for the study. In this dispatch, system load (3 MW) is supplied by DER (0.28 MW), existing
diesel unit (D8, generating 0.5 MW), centralized IBR (10.2 MW GFM BESS capacity, and 10.2 MW PV
generation capacity). The same three-phase faults and high impedance single line to ground fault as
what are studied previously are simulated in the PSCAD/EMTDC. From the simulation results, it is
concluded that system stability can be maintained by the GFM resource, and system voltage and
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frequency can be recovered after clearing the fault. Simulation results are shown in Figure 81, Figure
82, and Figure 83.
Figure 81 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2030, three-phase close in
fault
Figure 82 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2030, three-phase close in
fault
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Figure 83 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2030, single phase far end
fault with high fault impedance
No resort load scenario resource plan, year 2050
Another 2.3 MW GFM resource is added to system by 2050, with system peak load forecast as 3.3 MW.
A daytime peak load with low DER and low diesel generation dispatch is selected for year 2050 study.
In this dispatch, system load (3.3 MW) is supplied by DER (0.34 MW), existing diesel unit (D8,
generating 1.0 MW), and centralized IBR (12.5 MW GFM BESS capacity, and 12.5 MW PV generation
capacity). The same three-phase faults and high impedance single line to ground fault as what are
studied previously are simulated in the PSCAD/EMTDC. Simulation results indicate that the 12.5 MW
GFM resource is sufficient to maintain system stability during both the three-phase fault and the high
impedance single phase fault. The simulation results are shown in Figure 84, Figure 85 and Figure 86.
Figure 84 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2050, three-phase close in
fault
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Figure 85 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2050, three-phase close in
fault
Figure 86 Dynamic stability simulation results, Lāna‘i no resort scenario resource plan, year 2050, single phase far end
fault with high fault impedance
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5. TECHNICAL ADVISORY PANEL FEEDBACKS
During the study, the IGP Technical Advisory Panel transmisison sub-committee met three times with
Company to review the study methodology and results from December 2022 to February 2023.
Summary of TAP’s feedback are listed as following, and the detailed TAP feedback of each meeting are
available from Company’s IGP website7.
In general, the TAP agrees with study methodology and findings. The following is a list of comments or
questions on the details of the study, which were raised by the TAP as suggestion for future discussion
or consideration.
1) The TAP agreed that the uncertainties in the inputs to the study are very high due to project
timelines and withdrawals, future generation location uncertainty, load growth uncertainty,
and DER growth uncertainty. The TAP noted that proactive construction of transmission to
enable renewable resources has been very successful in California, Colorado, Texas, and other
regions. HECO is already considering this and is encouraged to continue.
Company is currently reviewing options of proactive construction of transmission system to
enable renew energy zone development.
2) In the land-constrained scenario resource plan, the TAP agrees that it is a good idea to consider
using grid-forming STATCOM to mitigate system stability issue when there is not sufficient grid-
scale grid-forming resource. The TAP recommends to use Grid Needs Assessment process to do
the cost/benefit analysis by comparing grid-forming STATCOM sulotion with a grid-forming
BESS solution.
Company identified system stability risk from the Oʻahu land-constrained scenario resource
plan, and currently is running model iteration according to the stability needs to determine if
more synchronous machine based resource can be dispatched to maintain system stability or
more grid-forming resources need to be procured in near term years. Company expects that in
long term years under the land-constrained scenario resource plan, Oʻahu system will need
more grid-forming resources (e.g., grid-forming BESS and grid-forming STATCOM), and agrees
with the TAP team’s advice that a Grid Needs Assess process will be needed for the prcurement
of grid stability related resource.
3) For Hawaiʻi Island, HECO presented the issue of unbalanced generation on the two sides of the
island, which can lead to voltage collapse. The TAP supports continuing the discussion of
potential solutions to the reliability issue of cross-island energy imbalance on Hawaiʻi Island.
The TAP agreed with HECO that an active power resource is likely to be very helpful in the
southern portion of Hawaiʻi Island given the severe undervoltage conditions identified,
especially if/when the Pakini Nui wind plant retires. The dynamic portion of the study can
further inform what type of resource is needed in that location.
In the study, Company addressed generation balance issue between east and west side of the
Hawaiʻi Island system, and identified requirements from both steady state analyses and
dynamic stability analyses. Company also identifies minimum resources needs (both active and
7 https://www.hawaiianelectric.com/clean-energy-hawaii/integrated-grid-planning
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reactive resource) to maintain south part of the Hawaiʻi Island system voltage within planning
criteria.
4) The TAP strongly supports working towards obtaining grid-forming capacity as soon as possible,
including by converting Stage 1 plants and executing Stage 2 and Stage 3 plants, as well as by
other means as appropriate.
In this study, Company identifies minimum requirements of grid-forming capacity for each island
system in order to maintain system stability within planning criteria. Meanwhile, Company has
been working with developers to negotiate PPA amendments regarding converting grid-
following projects to grid-forming projects.
5) The TAP agree that using ratio of available MW headroom in GFM plants to DER generation
(“GFM HR/DER”) is a reasonable metric, and can easily be applied in production cost models.
The TAP also suggested that some other metrics may also be needed for other times of day
when DER generation is low. Such metrics could include a minimum online capacity of GFM
and/or a minimum available energy (SOC) from GFM plants. The TAP looks forward to
continuing to discuss metric development to improve resource planning and production cost
modeling with HECO as industry learns more. Meanwhile, the TAP understands the metric
(GFM HR/DER) is primarily proposed to improve the stability of schedules developed from
production cost simulations, but could potentially also be used for operations in the future.
Company is actively looking into ways to integrate this GFM MW headroom/DER generation
minimum contingency reserve requirement into the production cost models. Meanwhile,
Company will include a MW/MWH requirement in the model for the GFM BESS component for
responding system event. Regarding how to apply this requirement in future system operations,
Company will look into ways to implment this contingency reserve requirement from the eligible
GFM resources into the future EMS system.
6) As HECO begins to rely on GFM inverter-based plants for system security, the TAP advises HECO
to be alert for potential signs that GFM plants could fail to perform as designed, especially if
failure modes could affect multiple plants. GFM inverters for transmission-connected
applications are still a relatively new technology, and initial results from plants in the field have
generally been positive but have also required troubleshooting. Achieving reliable GFM
performance to meet Hawaii’s needs will likely require close monitoring of field performance
and an ongoing collaborative relationship with the GFM plant owners and their inverter
manufacturers. Arrangements with GFM plant owners should be designed and managed to
promote collaboration rather than adversarial relationships as much as possible.
Company expects a great deal of additional study, monitoring, and evaluation of actual field
performance will need to be done in order to assure GFM IBR is an effective solution to provide
stability to the Company’s systems. Besides refining GFM performance requirements for the RFP
Stage 3 procurement, Company will also rely on generation technical model review process to
make sure high quality generation facility models are obtained, and will require all the plants to
install ditigal fault recorder (“DFR”) to monitor plant performance during system events.
Company will also use those measured data from the DFRs to validate the plant models and
determine if the plant performan reached PPA performance standards. Company will work with
plant owners if issues are identified.
7) The TAP agree that improved grid-supportive performance from DERs would be beneficial and
may be feasible in the 2035 timeframe.
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Company agrees to look for ways to obtain better grid support from DERs.
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A. SUMMARY OF STUDY RESULTS
A.1 Oʻahu Study Results Summary
Summary of study results for the select years of Oʻahu base scenario resource plan, land constrainted
scenario resouce plan and high load scenario resouce plan are shown as following tables.
Table A 1 Oʻahu Transmission System Grid Needs - Base Load Scenario, Year 2030
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2030
By 2030, the Oʻahu system will
have new generation from Stage 3
Oʻahu RFP procurement and initial
Renewable Energy Zone (“REZ”)
development. Specifically, there
will be 450 MW renewable dispatch
generation (“RDG”) and 300 MW
firm generation procured through
the Stage 3 Oʻahu RFP activity, 510
MW RDG development from the
REZ zone 1, 2 and 7, and 543 MW
RDG development from the REZ
zone 3, 4, 5 and 6. Most of these
new generation will be
interconnected at Oʻahu 138 kV
system. The REZ development is
expected to have both solar and
wind generation.
In this timeframe, it is also planned
to remove 371 MW fossil
generation from Waiau power
plant.
System Grid Scale Resource Changes
Development Generation
Type
MW
Capacity
GCOD Location
Stage 3 Oʻahu RFP
Solar/BESS and
Wind
450 2027 Central Oʻahu, West Oʻahu
Firm
Generation
300 2029 Central Oʻahu
REZ
Development
Solar/BESS and
Wind
510 2030 Zone 1, 2, and 7
543 2030 Zone 3, 4, 5 and 6
Other Standalone
BESS
84 2030 138/46 kV Substations
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed REZ
Not Developed
REZ
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Studied Resource Plan Studied Year
Base Scenario Resource Plan 2030
Removal Generation
Type
MW
Capacity
Year Location
Waiau 3, 4 Fossil
Generation
94 2024
Waiau Power Plant Waiau 5, 6 108 2027
Waiau 7, 8 169 2029
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Standalone Grid-Scale
Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,462 257 168 1,573 219 1,171 1,364
REZ Enablement
Examples of REZ Enablment are shown as following for zones with lower MW potential (upper) and higher MW
potential (lower). Red color means new enablment facility, and black color means existing facility.
REZ Enablement Cost Estimate
REZ Zone 1 2 3 4 5 6 7
Cost ($MM) per MW 0.21 0.27 1.32 0.82 1.51 0.62 N/A
REZ Enablement ($MM) 24.6 87.6 448.4-819.9 N/A
Grid Needs - Transmission System Networks Expansion
G
G
324 MW
336 AAC
Group 2
CB CB CB
CB CB CB
Ewa Nui 138 kV
G
G
336 AAC
336 AAC
336 AAC CB CB CB
CB CB CB
Waiau-Ewa Nui 2 Line
Waiau-Ewa Nui 1 Line
CEIP-Ewa Nui Line
Kalaeloa-Ewa Nui Line
G
G
G
G
437 MW
CB CB CB
CB CB CB
CB CB CB
CB CB CB
556 AAC
556 AAC
556 AAC
556 AAC
G
CB CB CB
G
171 MW
Halawa
138 kVGroup 5
CB CB CB
CB CB CB
New 138 kV Switching Station 1590 AAC
1590 AAC
1590 AAC
1590 AAC
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Studied Resource Plan Studied Year
Base Scenario Resource Plan 2030
Networks Expansion Descriptions Cost
Estimate
($MM)
Transmission Line Upgrade Type Conductor Requirements
Waiau-Ewa Nui
1&2
Re-conductor Two circuits, re-conductor to double-
bundled 795 AAC
161.4
Alternative for this conductor upgrade will be reduce Ewa Nui REZ generation interconnection from 324 MW to
175 MW.
Grid Needs – System Stability Needs
Grid has sufficient GFM resources to maintain system stability, but the system must be operated so that GFM
Headroom/DER Generation ratio is at least 0.7.
Table A 2 Oʻahu Transmission System Grid Needs - Base Load Scenario, Year 2035
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2035
In addtion to previous system
resource changes by 2030, the Oʻahu
system will have 64 MW grid-scale
standalone BESS and 509 MW
offshore wind, by 2035. There is no
futhur development of REZ. There will
be 208 MW firm generation procured
and interconnected at the Kalaeloa
substation once the Kalaeloa power
plant is removed.
System Grid Scale Resource Changes since 2031
Developme
nt
Generation Type MW Capacity GCOD Location
Others Firm Generation 208 2033 Kalaeloa Substation
Ewa Nui Waiau
Existing 138 kV Line ReconductorExisting 138 kV Substation
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed REZ
Not Developed REZ
Offshore Wind
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Studied Resource Plan Studied Year
Base Scenario Resource Plan 2035
Standalone BESS 64 2035 138/46 kV substations
Offshore wind 509 2035 Koʻolau 138 kV substation
Removal Generation Type MW Capacity Year Location
Kahuku Wind Onshore Wind 30 2031 Kahuku 46 kV substation
Kapolei
Sustatinable
Energy Park
Solar 1 2032 Kahe 46 kV substation
Kalaeloa
Solar
Solar 5 2032 KS substation
Kahe 1, 2 Fossil 165 2033 Kahe substation
Kalaeloa
Power Plant
Fossil 208 2033 KPLP substation
KREP Solar 5 2034 KREP substation
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone
Grid-Scale Solar
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,297 257 509 157 1,573 282 1,295 1,432
REZ Enablement
There is no REZ development between 2031 to 2035. In this time frame, the development that requires
interconneciton facility is the 509 MW offshore wind, which requires expansion of the Koʻolau substation by
adding 4 BAAH bay for the offshore wind interconnection. The cost estimate is $50.6 million.
Grid Needs - Transmission System Networks Expansion
None. But high conductor loading is observed on multiple 138 kV overhead conductors. It is recommend to
reduce grid-scale generation interconnection at Koʻolau substation by 10 MW.
Grid Needs – System Stability Needs
Grid has sufficient GFM resources to maintain system stability, but the system must be operated so that GFM
Headroom/DER Generation ratio is at least 0.70.
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Table A 3 Oʻahu Transmission System Grid Needs - Base Load Scenario, Year 2045
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2045
In addtion to previous system resource
changes, by 2045, the Oʻahu system
will finish developing the majority of
REZ zone 1, 2, 3, 4, 5, 6 and 7, only 106
MW potential remaining undevelopped. Meanwhile, 452 MW
solar potential of the REZ zone 8 will
be developped by 2045. System load is
forecasted with significant growth:
1,692 MW peak demand at 2046. Both
REZ development and system load
growth drive large amount of Oʻahu
transmission system network
expansion.
System Grid Scale Resource Changes since 2036
Developme
nt
Generation Type MW Capacity GCOD Location
REZ
Developmen
t
Renewable
Dispatchable
Generation
521 2040 REZ zone 3, 4, 5, and 6
504 2045
452 2045 REZ zone 8
Other Standalone BESS 1 2040 Hoʻohana substation
32 2045 Hoʻohana substation
Recovered
Solar
Standalone Solar 168 2045 Waiver project locations
Recovered
Wind
Wind 123 2045 Removed wind locations
Removal Generation Type MW Capacity Year Location
Kahe 3, 4 Fossil 172 2037 Kahe substation
Kawailoa
Wind
Wind 69 2038 Wahiawa 46 kV
Waianae
Solar
Solar 27.6 2039 Kahe 46 kV
Na Pua
Makani Wind
Wind 24 2040 Koʻolau 46 kV
Waiver
Clearway
Projects
Solar/Wind 110 2041 Various 138 kV and 46 kV
substations
West Loch Solar Solar 20 2044 CEIP 46 kV
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed
REZ
Partial Developed REZ
Not Developed REZ
Offshore Wind
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Studied Resource Plan Studied Year
Base Scenario Resource Plan 2045
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone
Grid-Scale
Solar
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,126 287 509 441 2,777 315 1,454 1,692
REZ Enablement
REZ Zone 3 4 5 6 8
Cost ($MM)
per MW
1.32 0.82 1.51 0.62 1.25
REZ
Enablement
($MM)
1084.6-1468.5 565.0
Grid Needs - Transmission System Networks Expansion
The total estimated cost for these transmission networks expansion is $3,980.5 million.
Grid Needs – System Stability Needs
Not studied.
WahiawaAkauHema
Kahe
Waiau
Existing 138 kV Line
Existing 138 kV Line ReconductorExisting 138 kV Substation
New 138 kV Line
Halawa
Koʻolau
School
Iwilei
Makalapa
Airport
Waiau
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APPENDIX D – SYSTEM SECURITY STUDY
Table A 4 Oʻahu Transmission System Grid Needs - Base Load Scenario, Year 2050
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2050
By 2050, 3,344 MW of all eight REZ
zones will be fully developed. System
load is forecasted with significant
growth: 1,829 MW peak demand at
2050, which could possibly cause underground cable replacement for
138 kV underground cable among
School Stree, Iwilei and Archer 138 kV
substations. All Kahe fossil generation
units will be retired by 2050. Besides
switching fossil fuel to biodiesel fuel
for remaining firm units, 135 MW
new firm units will be added to the
Oʻahu system by 2050.
System Grid Scale Resource Changes since 2046
Developm
ent
Generation Type MW Capacity GCOD Location
REZ
Developme
nt
Renewable
Dispatchable
Generation
106 2050 REZ zone 3, 4, 5, and 6
714 2050 REZ zone 8
Other Standalone BESS 18 2050 138 kV Substation
Other Firm Generation 153 2050 Kahe Substation
Removal Generation Type MW Capacity Year Location
Kahe 5, 6 Fossil 270 2046 Kahe substation
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone
Grid-Scale
Solar
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,010 287 509 480 3,558 333 1,497 1,829
REZ Enablement
REZ Zone 3 4 5 6 8
Cost
($MM) per
MW
1.32 0.82 1.51 0.62 1.25
REZ
Enablemen
t ($MM)
86.9-160.1 892.5
Grid Needs - Transmission System Networks Expansion
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed
REZ
Partial Developed REZ
Not Developed REZ
Offshore Wind
D-155 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2050
The total estimated cost for these transmission networks expansion is $1,208.9 million.
Reducing load from 138 kV substations Kamoku, Kewalo, School St. and Iwilei by 20 MW can avoid cable
replacement for the 138 kV underground cable Archer-School, Archer-Iweilei. This can be realized by adding
generation such as grid-scale BESS in those substations, or procure demand response on circuits supplied by
those substations, or implmenenting energy efficiency program.
Fully development of the north shore REZ zone (i.e., zone 8) would also cause overloadings on the 138 kV lines
connected with Wahiawa substation. By reducing generation interconnection size at Wahiawa substation by 220
MW, the line overloading will be mitigated.
Grid Needs – System Stability Needs
Not studied.
Kahe Halawa
Existing 138 kV Line
Existing 138 kV Line ReconductorExisting 138 kV Substation
Existing 138 kV UB Cable
Replacement
Hoʻohana
School IwileiArcher
D-156 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 5 Oʻahu Transmission System Grid Needs – Land Constrained Scenario, Year 2030
Studied Resource Plan Studied Year
Land Constrained Scenario Resource Plan 2030
By 2030, the Oʻahu system will
have all new generation from
Stage 3 Oʻahu RFP procurement
on transmission and sub-
transmisison side. Specifically, there will be 450 MW renewable
dispatch generation (“RDG”) and
300 MW firm generation
procured through the Stage 3
Oʻahu RFP activity. Most of these
new generation are expected to
be interconnected at Oʻahu 138
kV system. In this time frame, it is
also planned to remove 371 MW
generation from Waiau power
plant.
System Grid- Scale Resource Changes
Development Generation Type MW Capacity GCOD Location
Stage 3 Oʻahu
RFP
Renewable Dispatchable
Generation
450 2027 Central Oʻahu, West Oʻahu
Firm Generation 300 2029 Central Oʻahu
Removal Generation Type MW Capacity Year Location
Waiau 3, 4
Fossil Generation
94 2024
Waiau Power Plant Waiau 5, 6 108 2027
Waiau 7, 8 169 2029
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone Wind
Standalone Grid-Scale
Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS DER System
Peak Load
1,462 123 168 684 135 1,171 1,364
Grid Needs - Transmission System Networks Expansion
None
Grid Needs – System Stability Needs
System may need more GFM resource, and it is recommended to maintain MW headroom of GFM
resource/DER generation ratio at least 0.7. If the ratio canʻt be maintained, it is recommend to dispatch more
synchronous machine resources to create more head room from the GFM resource, or curtail DER generation.
RFP Stage 3 Projects
D-157 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 6 Oʻahu Transmission System Grid Needs – Land Constrained Scenario, Year 2035
Studied Resource Plan Studied Year
Land Constrained Scenario Resource Plan 2035
In addtion to previous system
resource changes by 2030, the Oʻahu
system will have 105 MW grid-scale
standalone BESS and 400 MW
offshore wind, by 2035. 153 MW Firm
resource will also be added to system
by 2035. There will be 208 MW firm
generation procured and
interconnected at the Kalaeloa
substation once the Kalaeloa power
plant is removed. 30 MW wind
recovered wind resource from the
retired wind power plant will be
added to system to meet the system
demand as well.
System Grid- Scale Resource Changes since 2031
Developme
nt Generation Type MW Capacity GCOD Location
Others
Firm Generation 208 2033 Kalaeloa Substation
Firm Generation 153 2035 Waiau Power Plant
Standalone BESS 105 2035 138/46 kV substations
Offshore wind 400 2035 Koʻolau 138 kV substation
Removal Generation Type MW Capacity Year Location
Kahuku
Wind Onshore Wind 30 2031 Kahuku 46 kV substation
Kapolei
Sustatinabl
e Energy
Park
Solar 1 2032 Kahe substation
Kalaeloa
Solar Solar 5 2033 Kahe 46 kV substation
Kahe 1, 2 Fossil 165 2033 Kahe substation
Kalaeloa
Power
Plant
Fossil 208 2033 KPLP substation
KREP Solar 5 2034 KREP substation
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone
Grid-Scale Solar
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,450 123 400 157 684 240 1,295 1,432
RFP Stage 3 Projects
New Onshore Resource Between 2031 and 2035
Offshore Wind
D-158 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Land Constrained Scenario Resource Plan 2035
Grid Needs - Transmission System Networks Expansion
None
Grid Needs – System Stability Needs
System may need more GFM resources, and it is recommended to maintain MW headroom of GFM resource/DER
generation ratio at least 0.7. If the ratio canʻt be maintained, it is recommended to dispatch more synchronous
machine based resources to create more head room from the GFM resource.
Table A 7 Oʻahu Transmission System Grid Needs – Land Constrained Scenario, Year 2045
Studied Resource Plan Studied Year
Land Constrained Scenario Resource Plan 2045
In addtion to previous system resource
changes, by 2045, the Oʻahu system
will add another 153 MW firm
generation into the system. Also, 169
MW standalone solar and 93 MW wind
development from retired solar and
wind locations will be completed by
2045. 169 MW new Grid-scale
standalone BESS will be
interconnected to system from
transmission substations. System load
is forecasted with significant growth:
1,692 MW peak demand at 2046. On
the distribution side, 783 MW DER
coupled with 1,567 MWh DER BESS will
be added to the system to supply
system load demand.
System Grid- Scale Resource Changes since 2036
Developm
ent Generation Type MW Capacity GCOD Location
Other Standalone BESS 14 2040 Hoʻohana substation
Firm Generation 153 2040 Waiau substation
Recovered
Solar Standalone Solar 39 2040 Waiver project locations
Recovered
Wind Wind 93 2040 Retired wind locations
Other Standalone BESS 145 2045 Hoʻohana substation
Recovered
Solar Standalone Solar 130 2045 Waiver project locations
Removal Generation Type MW Capacity Year Location
RFP Stage 3 Projects
New Onshore Resource Between 2031 and 2035
Offshore Wind
New Onshore Resource Between 2036 and 2045
D-159 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Land Constrained Scenario Resource Plan 2045
Kahe 3, 4 Fossil 172 2037 Kahe substation
Kawailoa
Wind Wind 69 2038 Wahiawa 46 kV
Waianae
Solar Solar 27.6 2039 Kahe 46 kV
Na Pua
Makani
Wind
Wind 24 2040 Koʻolau 46 kV
Waiver
Clearway
Projects
Solar/Wind 104 2041 Various 138 kV and 46 kV
substations
West Loch
Solar Solar 20 2044 CEIP 46 kV
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone
Grid-Scale
Solar
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,432 123 400 169 684 399 3,020 1,692
Grid Needs - Transmission System Networks Expansion
Kahe Halawa
Existing 138 kV Line
Existing 138 kV Line ReconductorExisting 138 kV Substation
New 138 kV Line
Halawa
Koʻolau
School
Iwilei
Makalapa
Airport
Waiau
Hoʻohana
D-160 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Land Constrained Scenario Resource Plan 2045
The total estimated cost for these transmission networks expansion is $2,291.6 million.
Grid Needs – System Stability Needs
The dynamic stability study is not performed. However, according to the avaiable GFM resource and signification
growth of DER, the system may require more grid-scale GFM resource. This could be more GFM BESS
interconnected on subtransmission or transmission grid, or GFM STATCOM interconnected on the transmission
grid.
Table A 8 Oʻahu Transmission System Grid Needs – Land Constrained Scenario, Year 2050
Studied Resource Plan Studied Year
Land Constrained Scenario Resource Plan 2050
From 2046 to 2050, the only grid-
scale resource added to the Oʻahu
system as planned is a 119 MW/1,110
MWh grid-scale BESS. Kahe 5, 6,
which will be the only remaining fossil
generation at Kahe power plant by
2050, will be retired in 2050. It is also
planned to add 1,017 MW DER,
coupled with 2,033 MWh DER BESS
into system distribution side. System
peak load is forecasted to be 1,829
MW by 2050. The load increase will
require cable replacement for the 138
kV underground conductors Archer-
School and Archer-Iwilei.
System Grid- Scale Resource Changes since 2036
Developm
ent
Generation Type MW Capacity GCOD Location
Other Standalone BESS 119 2050 138 kV Substation
Removal Generation Type MW Capacity Year Location
Kahe 5, 6 Fossil 270 2046 Kahe substation
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone
Grid-Scale
Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone BESS DER System
Peak
Load
1,163 123 400 169 684 519 5,097 1,829
RFP Stage 3 Projects
New Grid-Scale Onshore Resource Between 2031 and 2035
Offshore Wind
New Onshore Grid-Scale Resource Between 2036 and 2045
New Onshore Resource Between 2046 and 2050
D-161 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Land Constrained Scenario Resource Plan 2050
Grid Needs - Transmission System Networks Expansion
The total estimated cost for these transmission networks expansion is $345.1 million.
Reducing load from 138 kV substations Kamoku, Kewalo, School St. and Iwilei by 20 MW can avoid cable
replacement for the 138 kV underground cable Archer-School, Archer-Iweilei. This can be realized by adding
generation such as grid-scale BESS at those substations, acquiring demand response on circuits supplied by those
substations, or implementing a targeted energy efficiency program.
Grid Needs – System Stability Needs
The dynamic stability study for this scenario is not performed. However, the recommendation for the Oʻahu
system regarding system stability needs are simliar as what is recommended for the 2045 scenario.
Table A 9 Oʻahu Transmission System Grid Needs – High Load Scenario, Year 2030
Existing 138 kV Line
Existing 138 kV Line
ReconductorExisting 138 kV Substation
Existing 138 kV UB Cable
Replacement
School IwileiArcher
D-162 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Resource Plan 2030
By 2030, the Oʻahu system will have new
generation from Stage 3 Oʻahu RFP
procurement and initial Renewable Energy
Zone (“REZ”) development. Specifically,
there will be 450 MW renewable dispatch
generation (“RDG”) and 300 MW firm generation procured through the Stage 3
Oʻahu RFP activity, 510 MW RDG
development from the REZ zone 1, 2 and
7, and 1,225 MW RDG development from
the REZ zone 3, 4, 5 and 6. Most of these
new generation will be interconnected at
Oʻahu 138 kV system. The REZ
development is expected to have both
solar and wind generation.
In this time frame, it is also planned to add
60 MW standalone BESS into system and
remove 371 MW generation from Waiau
power plant.
System Resource Changes
Development Generation Type MW Capacity GCOD Location
Stage 3 Oʻahu
RFP
Renewable
Dispatchable
Generation
450 2027 Central Oʻahu, West Oʻahu
Firm Generation 300 2029 Central Oʻahu
REZ
Development
Renewable
Dispatchable
Generation
510 2030 Zone 1, 2, and 7
1,225 2030 Zone 3, 4, 5 and 6
Other Standalone BESS 60 2030 138/46 kV Substations
Removal Generation Type MW Capacity Year Location
Waiau 3, 4
Fossil Generation
94 2024
Waiau Power Plant Waiau 5, 6 108 2027
Waiau 7, 8 169 2029
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Standalone Grid-
Scale Solar
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak
Load
1,462 123 168 2,419 195 1,147 1,595
REZ Enablement
Examples of REZ Enablment are shown as following for zones with lower MW potential (upper) and higher MW
potential (lower). Red denotes new enablment facility, and black denotes existing facility.
D-163 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Resource Plan 2030
REZ Enablement Cost Estimate
REZ Zone 1 2 3 4 5 6 7
Cost ($MM) per MW 0.21 0.27 1.32 0.82 1.51 0.62 N/A
REZ Enablement ($MM) 24.6 87.6 1,378.8-1,718.0 N/A
Grid Needs - Transmission System Networks Expansion
G
G
324 MW
336 AAC
Group 2
CB CB CB
CB CB CB
Ewa Nui 138 kV
G
G
336 AAC
336 AAC
336 AAC CB CB CB
CB CB CB
Waiau-Ewa Nui 2 Line
Waiau-Ewa Nui 1 Line
CEIP-Ewa Nui Line
Kalaeloa-Ewa Nui Line
G
G
G
G
437 MW
CB CB CB
CB CB CB
CB CB CB
CB CB CB
556 AAC
556 AAC
556 AAC
556 AAC
G
CB CB CB
G
171 MW
Halawa138 kVGroup 5
CB CB CB
CB CB CB
New 138 kV Switching Station 1590 AAC
1590 AAC
1590 AAC
1590 AAC
D-164 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Resource Plan 2030
The total estimated cost for these transmission networks expansion is $1,289 million.
Alternative option for deferral reconductor of Ewa Nui – Waiau #1 & #2 is reducing REZ zone 2 interconnection
MW size at Ewa Nui substation by 150 MW, and dispatch more generation on the east side of island.
Grid Needs – System Stability Needs
Not studied.
Ewa Nui Waiau
Existing 138 kV Line ReconductorExisting 138 kV Substation
Halawa
Koʻolau
Makalapa
Waiau
Kahe HalawaHoʻohana
D-165 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 10 Oʻahu Transmission System Grid Needs – High Load Scenario, Year 2035
Studied Resource Plan Studied Year
High Load Resource Plan 2035
In addtion to previous system resource
changes by 2030, the Oʻahu system
will have 95 MW grid-scale standalone
BESS and 600 MW offshore wind, by
2035. There is no further development of REZ. There will be 208 MW firm
generation interconnected at the
Kalaeloa substation. By 2035, the BESS
MWh of the PV/BESS projects
developed in REZ zones in 2030 will be
increased as well.
System Resource Changes since 2031
Development Generation Type MW Capacity GCOD Location
Others Firm Generation 208 2033 Kalaeloa Substation
Standalone BESS 95 2035 138/46 kV substations
Offshore wind 600 2035 Koʻolau 138 kV substation
Removal Generation Type MW Capacity Year Location
Kahuku Wind Onshore Wind 30 2031 Kahuku 46 kV substation
Kapolei Sustatinable
Energy Park
Solar 1 2032 KREP substation
Kalaeloa Solar Solar 5 2032 KS substation
Kahe 1, 2 Fossil 165 2033 Kahe substation
Kalaeloa
Power Plant
Fossil 208 2033 KPLP substation
KREP Solar 5 2034 KREP substation
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone
Wind
Offshore
Wind
Standalone Grid-
Scale Solar
Grid-Scale
Hybrid
Solar/BESS
Standalone
BESS
DER System
Peak Load
1,297 93 600 157 2,419 290 1,271 1,776
REZ Enablement
There is no REZ MW potential development between 2031 to 2035. In this timeframe, the development that
requires interconneciton facility is the 600 MW offshore wind, which requires expansion of the Koʻolau substation
by adding 4 BAAH bay for the offshore wind interconnection. The cost estimate is $50.6 million.
Grid Needs - Transmission System Networks Expansion
RFP Stage 3 Projects
1
2
3 4
5
6
7
8
Fully Developed REZ
Partial Developed REZ
Not Developed
REZ
Offshore Wind
D-166 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Resource Plan 2035
The total estimated cost for these transmission networks expansion is $397.9 million.
In addition, 138 kV underground cable Archer-Iwilei, Archer-School also have high loading condition during
contingencies. It is recommended to install a standalone BESS project in east side of island close to the urban core
load center to reduce load, in order to avoid reconductoring or potential cable repalcement. Alternative options
can be using DER programs, demand response programs, or energy efficiency programs to reduce load on east
side of system.
Grid Needs – System Stability Needs
Not studied.
A.2 Maui Study Results Summary
Summary of study results for the Maui base scenario resource plan and high load scenario resouce plan
are listed as following.
Existing 138 kV Line
ReconductorExisting 138 kV Substation
Halawa
School
Iwilei
Makalapa
Airport
D-167 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 11 Maui Transmission System Grid Needs – Base Scenario, Year 2027
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2027
By 2027, the Maui system will
have new generation from Stage 3
RFP procurement which will be
171 MW renewable dispatchable
generation (“RDG”) PV/BESS and 36 MW firm generation,
interconnected at Maui 69 kV
system. Meanwhile, the Maui
system will finish Waena
switchyard construction, Kahului
Power Plant (“KPP”) retirement
and conversion of KPP K3 and K4
units to synchronous condensers,
and Maalaea Power Plant (“MPP”)
unit 10-13 retirement. The system
peak load is forecasted to reach
207 MW by 2028. System Grid Scale Resource Changes
Development Generation Type MW Capacity GCOD Location
Stage 3 Maui
RFP
Renewable
Dispatchable
Generation
171 2027 West Maui, Central Maui and
South Maui
Firm Generation 36 2027 Central Maui
Removal Generation Type MW Capacity Year Location
Kaheawa Wind
Power 1
Wind Generation 30 2027 KWP 1 substation
Kahului 1-4 Fossil Generation 32.5 2027 Kahului Power Plant
Maalaea 10-13 Fossil Generation 49.4 2027 Maalaea Power Plant
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
197.5 42 296 40 170.7 207
REZ Enablement
No REZ enablment cost estimate since by 2027 there will be only Stage 3 development but no REZ development.
Interconnection sites for the 171 MW Stage 3 RFP projects and 36 MW firm generation are as following.
Substation/Switching station interconnections:
• Lahainaluna substation station – 60 MW
• KWP 2 substation – 30 MW
• Waena switch yard – 40 MW firm generation
• Kealahou substation – 21 MW
69 kV Transmisison line interconnection:
• MPP – Waiinu line interconnection – 30 MW, through a new substation STG3.1
• MPP – Lahainaluna line interconnection – 30 MW, through a new substation STG3.2
A
A
A
C
C
B
RFP Stage 3 Projects
D-168 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2027
Grid Needs - Transmission System Networks Expansion
MPPLahainaluna
STG3.2
STG3.1
Waiinu
30 MW
30
MW
Existing 69 kV Line
Existing 69 kV Substation
Stage 3 RFP Project
New 69 kV Substation
30 MW
M
To Napili (Mauka)
M
M
To Lahainaluna Sub (Mauka)
To Napili (Makai)To Lahaina Sub (Makai)
CB
Lahaina
Lahainaluna
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Equipment
MPP
Waena
PukalaniKanaha
Kealahou
AuwahiWailea
D-169 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2027
The total estimated cost for these transmission networks expansion is $10.5 million.
Alternative options for above re-conductor upgrade include reducing grid-scale resource interconnection MW
size by 24 MW on west Maui and reducing grid-scale resource interconnection MW size in Waena switch yard,
up-country or south Maui by 16 MW.
Grid Needs – System Stability Needs
After adding 171 MW Stage 3 RDG projects with grid forming (“GFM”) BESS component, it is expected that Maui
system stability performance stay within planning criteria, and no addtional grid needs regarding system stability
is identified. Maui system single point of failure (“SPOF”) limit can be increased to 30 MW as well.
Table A 12 Maui Transmission System Grid Needs – Base Scenario, Year 2035
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2035
In addtion to previous system resource
changes by 2027, by 2035, the Maui system
will have 66 MW of grid-scale onshore wind
generation and 37 MW of PV/BESS
generation as addtional generation
interconnected to the Maui transmission
system. This new generation will be
developed in the REZ zone C. Also, it is
planned that MPP unit 1 to 9 will be
removed by 2030, and wind power
generation KWP 2 and Auwahi will be retired
by 2033. The system annual peak load is
forecasted to reach 235 MW by 2036.
System Resource Changes since 2031
Development Generation Type MW Capacity GCOD Location
REZ
Development
Onshore Wind
Generation 5 2029 REZ Zone C
Onshore Wind
Generation 8 2030 REZ Zone C
Onshore Wind
Generation 53 2035 REZ Zone C
Solar/BESS 37 2035 REZ Zone C
Removal Generation Type MW Capacity Year Location
Maalaea Power
Plant Units 1-9 Fossil 40.5 2030 MPP
Kaheawa Wind
Power 2
Onshore Wind
Generation 21 2033 KWP 2 Substation
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
D-170 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2035
Auwahi Wind Onshore Wind
Generation 21 2033 Auwahi Substation
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak
Load
152 66 333 40 202 237
REZ Enablement
From 2028 to 2035, 5 MW onshore wind genration in 2029, 8 MW onshore wind generation in 2030, 53 MW
onshore wind in 2035, and 37 MW PV/BESS, connected to zone C, totaling 103 MW. It is assumed that there will
be a new switching station on the MPP-Waena line which will host 43 MW out of 103 MW generation, and the
remaining 60 MW will be hosted in the Waena switchyard. The cost of REZ enablement through the Waena
switchyard is estimated as $13.5 million. For the new switching station REZ C.1, the REZ enablement cost is
estimated as $5.8 million.
Grid Needs - Transmission System Networks Expansion
MPP
REZC.1
Waena Switch Yard
21.5 MW
Existing 69 kV Line
Existing 69 kV Substation
REZ C New Generation
New 69 kV Substation
21.5 MW
21.5
MW
D-171 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2035
The total estimated cost for these transmission networks expansion is $96.2 million.
Grid Needs – System Stability Needs
None
Table A 13 Maui Transmission System Grid Needs – Base Scenario, Year 2040
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2040
In 2040, another 61 MW REZ zone C
development will be completed. It is
assumed that 61 MW will be
interconnected at Waena switchyard.
Meanwhile, there will be retirement of
existing 5.7 MW distribution
interconnected PV. System annual
peak demand is forecasted to reach
266 MW in 2041.
System Resource Changes since 2036
Development Generation Type MW Capacity GCOD Location
REZ
Development
Onshore Wind
Generation 18 2040 REZ Zone C
MPP
Existing 69 kV Line
Existing 69 kV Line
ReconductorExisting 69 kV Substation
New 69 kV Transmission Line
New 69 kV Substation
Waena
Switch Yard
STG3.1
Waiinu
Substation
REZ C.1
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
REZ Projects2040
D-172 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2040
PV/BESS Generation 43 2040 REZ Zone C
Removal Generation Type MW Capacity Year Location
Distribution
Interconnected
PV
Solar 5.7 2040 12 kV Distribution System
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak
Load
152 84 376 40 218 266
REZ Enablement
The new 61 MW of generation in the REZ zone C development is assumed to interconnec at the Waena
switchyard, which will require two BAAH bays for the generation interconnection.
The estimated cost of REZ enablement for 61 MW generation from REZ zone C development interconnected at
the Waena switchyard is $15.6 million.
Grid Needs - Transmission System Networks Expansion
The total estimated cost for these transmission networks expansion is $51.9 million.
An alternative option for adding a new circuit between MPP and Waena switchyard is to reduce grid-scale
generation interconnection from the REZ zone C development by 48.4 MW.
Grid Needs – System Stability Needs
None
MPP
REZ C.1
Waena
Switch Yard
Existing 69 kV Line
Existing 69 kV Line
ReconductorExisting 69 kV Substation
New 69 kV Transmission Line
D-173 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 14 Maui Transmission System Grid Needs – Base Scenario, Year 2045
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2045
In 2045, 66 MW PV/BESS generation
and 41 MW onshore wind generation
will be developed in REZ zone C; 15
MW PV/BESS generation will be
developed in REZ zone B. Also, all the remaining fossil units will switch to
biodiesel. The system annual peak
demand is forecasted to reach 289
MW in 2046.
System Resource Changes since 2041
Development Generation Type MW Capacity GCOD Location
REZ
Development
PV/BESS Generation 15 2045 REZ Zone B
PV/BESS Generation 66 2045 REZ Zone C
Onshore Wind
Generation 41 2045 REZ Zone C
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak
Load
152 125 457 40 229 289
REZ Enablement
According to the resource plan, 15 MW generation from REZ zone B and 107 MW generation from REZ zone C will
be interconnected to the Maui system. In the study, following interconnection sites are assumed.
• Auwahi substation – 15 MW
• STG3.1 – 30 MW
• Kanaha substation (23 kV) – 30 MW
• New switching station, REZ C.2, on Waena-Kealahou line – 47 MW
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
REZ Projects2040
REZ Projects2045
D-174 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2045
The cost estimate of the REZ enablement for the 30 MW interconnection at the STG 3.1 substation is $3.9 million,
for the 30 MW interconnection at the Kanaha substation 23 kV side is $3.8 million, and for the 47 MW
interconnection at the new substation REZ C.2 is $7.8 million. The total estimate for the REZ enablement is $15.4
million.
Grid Needs - Transmission System Networks Expansion
Waena Switch Yard Kealahou
23.5
MW23.5 MW
REZ C.2
Existing 69 kV Line
Existing 69 kV Substation
REZ C New Generation
New 69 kV Substation
23.5
MW
Waena Switch Yard Kealahou
REZ C.2
Existing 69 kV Line
Existing 69 kV Line
ReconductorExisting 69 kV Substation
New 69 kV Transmission Line
Kuihelani Solar Kuihelani
MPP
Kaonoulu Kihei
New 69 kV Substation
Kamaole
Solar Kealahou
REZ B.1
Wailea
D-175 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2045
The total estimated cost for these transmission networks expansion is $171.2 million.
An alternative option for reconductor of Kamaole-Kealahou line is to reduce south Maui generation
interconnection size by 7 MW.
Grid Needs – System Stability Needs
Not studied.
Table A 15 Maui Transmission System Grid Needs – Base Scenario, Year 2050
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2050
In 2050, 57 MW PV/BESS
generation will be developed in REZ
zone C; 57 MW PV/BESS generation
will be developed in REZ zone B.
System annual peak demand is
forecasted to reach 310 MW in
2050.
System Resource Changes since 2036
Development Generation Type MW Capacity GCOD Location
REZ
Development
Solar/BESS
Generation 57 2050 REZ Zone B
Solar/BESS
Generation 57 2050 REZ Zone C
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak
Load
152 125 571 40 240 310
REZ Enablement
In the study, it is assumed following interconnection sites for the 114 MW generation development in the REZ
zone B and C:
• REZ B.1 Substation – 51 MW
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2035
REZ Projects2040
REZ Projects2045
REZ Projects2050
D-176 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2050
• Auwahi Substation – 7 MW
• REZ C.2 (Waena-Kealahou) Substation = 13MW
• New switching station, REZ C.3, on Waena-Pukalani line – 44 MW
The estimated cost for REZ enablement in REZ B.1 substation is $9.0 million and for REZ enablement of building
the REZ C32 is $9.0 million. The total REZ enablement estimated cost is $18.0 million. It is assumed in the study
that the 7 MW generation interconnection at the Auwahi substation and 13 MW generation interconnection at
the REZ C.2 substation are interconnected without adding new BAAH bay but just expansion of previous
developed projects.
Grid Needs - Transmission System Networks Expansion
Besides above adding a new 69 kV line between Waena switchyard and Pukalani substation, it is also proposed to
replace the two 69/23 kV tie transformers at Kanaha substation by two units of larger transformers with at least
FA rating as 24 MVA. The total estimated cost for these transmission networks expansion is $123.1 million.
An alternative of upgrading two units of the Kanaha tie transformer is to use DER program, or demand response
program, or energy efficiency program to reduce peak load of the Maui 23 kV network by at least 4 MW.
Grid Needs – System Stability Needs
Not studied
Waena Switch Yard Pukalani
22 MW22
MW
REZ C.3
Existing 69 kV Line
Existing 69 kV Substation
REZ C New Generation
New 69 kV Substation
22 MW
Existing 69 kV Line
Existing 69 kV Substation
New 69 kV Transmission Line
Waena Pukalani
New 69 kV Substation
REZ C.3
D-177 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 16 Maui Transmission System Grid Needs – High Load Scenario, Year 2027
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2027
By 2027, the Maui system will
have new generation from Stage 3 RFP procurement which will be
171 MW renewable dispatchable
generation (“RDG”) PV/BESS and
36 MW firm generation,
interconnection at at Maui 69 kV
system. Meanwhile, the Maui
system will finish Waena
switchyard construction, Kahului
Power Plant (“KPP”) retirement
and conversion of KPP K3 and K4
units to synchronous condensers,
and Maalaea Power Plant (“MPP”)
unit 10-13 retirement. The system
peak load is forecasted to reach
239 MW by 2028.
System Grid Scale Resource Changes
Development Generation Type MW Capacity GCOD Location
Stage 3 Maui
RFP
Renewable
Dispatchable
Generation
171 2027 West Maui, Central Maui and
South Maui
Firm Generation 36 2027 Central Maui
Removal Generation Type MW Capacity Year Location
Kaheawa Wind
Power 1 Wind Generation 30 2027 KWP 1 substation
Kahului 1-4 Fossil Generation 32.5 2027 Kahului Power Plant
Maalaea 10-13 Fossil Generation 49.4 2027 Maalaea Power Plant
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore Standalone
Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak Load
197.5 42 296 40 194 239
REZ Enablement
No REZ enablment cost estimate since by 2027 there will be only Stage 3 development but no REZ development.
Interconnection sites for the 171 MW Stage 3 RFP projects and 36 MW firm generation are as following.
Substation/Switching station interconnections:
• Lahainaluna substation station – 60 MW
• KWP 2 substation – 30 MW
• Waena switch yard – 40 MW firm generation
• Kealahou substation – 21 MW
A
A
A
C
C
B
RFP Stage 3 Projects
D-178 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2027
69 kV Transmisison line interconnection:
• MPP – Waiinu line interconnection – 30 MW, through a new substation STG3.1
• MPP – Lahainaluna line interconnection – 30 MW, through a new substation STG3.2
Grid Needs - Transmission System Networks Expansion
MPPLahainaluna
STG3.2
STG3.1
Waiinu
30 MW
30 MW
Existing 69 kV Line
Existing 69 kV Substation
Stage 3 RFP Project
New 69 kV Substation
30 MW
D-179 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2027
M
To Napili (Mauka)
M
M
To Lahainaluna Sub (Mauka)
To Napili (Makai)To Lahaina Sub (Makai)
CB
Lahaina
Lahainaluna
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Equipment
MPP
STG3.1
Waiinu Substation
The total estimated cost for these transmission networks expansion is $28.7 million.
Grid Needs – System Stability Needs
Not studied
D-180 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 17 Maui Transmission System Grid Needs – High Load Scenario, Year 2030
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2030
By 2030, the Maui system will have 69
MW grid-scale renewable generation from
REZ zone C development. Also, it is
planned that MPP unit 1 to 9 will be
removed by 2030. The system annual peak load is forecasted to reach 266 MW by
2031.
System Resource Changes since 2031
Development Generation Type MW Capacity GCOD Location
REZ Development Onshore Wind Generation 6 2029 REZ Zone C
Onshore Wind
Generation
46 2035 REZ Zone C
Solar/BESS 17 2035 REZ Zone C
Removal Generation Type MW Capacity Year Location
Maalaea Power
Plant Units 1-9
Fossil 40.5 2030 MPP
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak
Load
152 94 313 40 217 266
REZ Enablement
For the 2030 REZ development, 69 MW generation will be developed from REZ zone C and interconnected with
Mauiʻs 69 kV system. It is assumed that 52 MW will be interconnected at Waena switchyard, and 17 MW will be
interconnected at a new substation REZ C.1 as shown in the following diagram. The estimated cost of REZ
enablement for the 52 MW interconnection at the Waena switchyard is $11.6 million; the estimated cost of REZ
enablement for the 17 MW interconnection at the REZ C.1 substation is $2.5 million.
REZ Enablement Cost Estimat for 17 MW Generation Interconnected at a new switching station REZC.1
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2030
D-181 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2030
Grid Needs - Transmission System Networks Expansion
Besides adding the new 69 kV line from MPP to Waena via the REZ C.1 substation, converting Pukalani-Haiku 23
kV line into a 69 kV line and adding 1.8 Mvar cap bank at Kailu substation and Keanae substation are also proposed as part of the required trasmission networks expansion. The total estimated cost for these transmission
networks expansion is $134.0 million.
Grid Needs – System Stability Needs
Not studied.
MPP
REZC.1
Waena
Switch Yard
17M
W
Existing 69 kV Line
Existing 69 kV Substation
REZ C New Generation
New 69 kV Substation
17 MW
MPP
Existing 69 kV Line
Existing 69 kV Line
ReconductorExisting 69 kV Substation
New 69 kV Transmission
Line
New 69 kV Substation
Waena
Switch Yard
REZ C.1
D-182 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 18 Maui Transmission System Grid Needs – High Load Scenario, Year 2035
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2035
In 2035, another 159 MW REZ zone C
development will be completed. 38
MW will be interconnected at Waena
switchyard, 60MW interconnected at
REZC.1 30MW interconnected at STG3.1 and 30MW interconnected at
Kanaha Substation on the 23kV bus. In
addition, it is assumed the existing 42
MW wind contract expires. The system
annual peak demand is forecasted to
reach 313 MW in 2036.
System Resource Changes since 2036
Development Generation Type MW Capacity GCOD Location
REZ
Development
Onshore Wind
Generation 75 2035 REZ Zone C
PV/BESS Generation 84 2035 REZ Zone C
Removal Generation Type MW Capacity Year Location
Kaheawa Wind
Power 2
Onshore Wind
Generation 21 2033 KWP 2 Substation
Auwahi Wind Onshore Wind
Generation 21 2033 Auwahi Substation
System Resource Summary and Forecasted Demand (MW)
Firm
Generation
Onshore
Standalone Wind
Grid-Scale Hybrid
Solar/BESS
Standalone
BESS
DER System Peak
Load
152 127 396 40 242 313
REZ Enablement
It is assumed that 38 MW generation will be interconnected at Waena switchyard (with estimated REZ
enablement cost as $13.5 million), 60MW generation interconnected at REZC.1 (with estimated REZ enablement
cost as $2.9 million), 30MW generation interconnected at STG3.1 (with estimated REZ enablement cost as $2.9
million), and 30MW generation interconnected at Kanaha Substation on the 23kV bus (with estimated REZ
enablement cost as $2.8 million). The total estimated cost for the REZ enablement regarding the 158 MW
generation from the REZ development is $22.1 million.
Grid Needs - Transmission System Networks Expansion
A
A
A
C
C
B
RFP Stage 3 Projects
REZ Projects2029-2030
REZ Projects2035
D-183 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2035
Kuihelani Solar Kuihelani
Kamaole
Solar Kealahou
MPP
REZ C.1
Waena
Switch Yard
Existing 69 kV Line
Existing 69 kV Line ReconductorExisting 69 kV Substation
New 69 kV Transmission Line Besides above mitigation solutions, it is also proposed to replace the two 69/23 kV tie transformers at Kanaha
substation by two units of larger transformers with at least FA rating as 24 MVA. The total estimated cost for
these transmission networks expansion is $70.0 million.
Grid Needs – System Stability Needs
Not studied.
A.3 Hawaiʻi Island Results Summary
Summary of the study results for the Hawaiʻi Island base scenario and high load resource plan is as
following.
D-184 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 19 Hawaiʻi Island Transmission System Grid Needs – Base Scenario, Year 2032
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2032
By 2030, the Hawai’i Island system will
have new generation from Stage 3 RFP
procurement and REZ development, which will be 48 MW wind generation of REZ
development by 2029 and 140 MW Stage
3 RFP PV/BESS generation by 2030. All of
them will be interconnected to the
Hawai’i Island 69 kV system. Also, three
existing generation plants will be removed
by 2031: the 34 MW Hill 5 and 6 will be
removed by 2027; the 21 MW Tawhiri
wind generation PPA is expected to expire
by 2028; and the 58 MW Hamakua Energy
Partners (“HEP”) contract is expected to
expire by 2031. The system peak load is
forecasted to reach 214 MW by 2032.
System Grid Scale Resource Changes
Development Generation Type MW
Capacity
GCOD Location
REZ
Development
Wind Generation 48 2029 West Hawaiʻi island
Stage 3 Hawaiʻi Island RFP Solar/BESS Generation 140 2030 West and east side of Hawaiʻi island
Removal Generation Type MW
Capacity
Year Location
Hill 5, 6 Fossil Generation 34 2027 Kanoelehua substation
Tawhiri
Generation
Wind Generation 21 2028 Kamaoa substation
HEP Fossil Generation 49.4 2031 Haina substation
System Resource Summary and Forecasted Demand (MW)
Fossil
Generation
Onshore
Standalone Wind
Geothermal
Generation
Grid-Scale Hybrid
Solar/BESS
Hydro DER System Peak Load
85.8 58.5 46 200 16.6 214 214
REZ Enablement
Interconnection sites for the 140 MW Stage 3 RFP projects and 48 MW onshore wind generation are as
following.
• Keamuku substation – 30 MW Stage 3 project
• Puueo substation – 30 MW
• Kanoelehua substation – 30 MW
RFP Stage 3 Projects
D-185 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2032
• Ouli substation – 20 MW
• Poopoomino substation – 30 MW
The interconnection of 48 MW wind generation from REZ development is assumed at the Keamuku substation.
The estimated REZ enablement cost for the 48 MW offshore wind interconnection at the Keamuku substation is
$37.8 million.
Grid Needs - Transmission System Networks Expansion
None
L6200 overloading observed in the study due for maximum west generation dispatches in which the 214 MW
system load is solely supplied by generation from west side of island. This would be required for unconstrained
use of the modeled base portfolio resources. The L6200 reconductor is not required if there is a minimum MW
generation provided from east side of the system. as calculated by following equation:
East side minimum generation (MW) = 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝑆𝑆𝑡𝑡𝑆𝑆𝑡𝑡𝑡𝑡 𝑡𝑡𝑡𝑡𝑡𝑡𝑙𝑙−174214−174 ∙20
If system total load is lower than 178 MW, there is no mimimum MW requirement of generation on east side of
the system.
Dependent on the system total load and the east side generation resources chosen to meet this minimum
requirement, the east may require 20 MVAR of additional reactive power capability to resolve potential
north/east voltage violations. At the peak load with 20 MW generation on east side of island, the following
options are viable for mitigating north/east undervoltage violations:
• All 3 units of PGV online
• Puna CT3 online with 2.8 MVAR additional reactive capability required at Kanoelehua or Puueo
substations
• Stage 3 Kanoelehua with 20 MVAR additional reactive capability required at Kanoelehua
• Stage 3 Kanoelehua & Puueo (split output) with 20 MVAR additional reactive capability required
between the two locations. The Additional reactive capability at Kanoelehua and Puueo are in addition
to the assumed capability of the Stage 3 resources at that location
To mitigate high loading condition of L8900/8100, it is necessary to move the generation resource
interconnection location from Keamuku and the East towards the further west side system (e.g., Keahole
substation) when the system total load reaches above 200 MW.
To mitigate undervoltage violation identifed on south side of system, it is recommend to have a resource
interconnected at Keauhou substation with at least 10.4 Mvar capability or at Kamaoa substation with 13.7
Mvar or 13.3 MW capability. The reactive power capability can be replaced by active power capability, or the
combination of reactive power and active power capability.
Grid Needs – System Stability Needs
After adding 140 MW Stage 3 PV/BESS projects with grid forming (“GFM”) BESS component, it is expected that
Hawaiʻi island system stability performance will stay within planning criteria, providing sufficient contingency
reserve can be held on these resources - and no addtional grid needs regarding system stability were identified.
When PGV units are online, at minimum, a total of 60 MW GFM PV/BESS project is required. A 30 MW GFM
PV/BESS project is required on both East and West side of the Hawaiʻi island system, while maintaining GFM
D-186 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2032
resource headroom as 24% of DER generation. When PGV units are offline, at minimum, a total of 110 MW GFM
resource is required. The east side of the system will need 50 MW GFM resource online and west side of the
system will need 60 MW GFM resource online, while together maintaining GFM resource headroom as 61% of
DER generation.
Table A 20 Hawaiʻi Island Transmission System Grid Needs – Base Scenario, Year 2050
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2050
In addition to previous system resource changes
by 2031, the Hawaiʻi island system will have 2
MW standalone BESS and 3 MW Solar/BESS from
the REZ development by 2035. It is assumed that
both interconnections will be in distribution
circuits considering their MW size. In 2040, there
will be another 20 MW Solar/BESS generation
developed from REZ. In 2045, all fossil
generation will have fuel switch to biodisel. In the same year, there will be 30 MW geothermal
generation and 2 MW standalone BESS
interconnected to the system. By 2050, an
additional 14 MW Solar/BESS and 2 MW onshore
wind generation will be developed from REZ. The
system annual peak load is forecasted to reach
295 MW by 2050.
System Resource Changes since 2031
Development Generation Type MW Capacity GCOD Location
REZ Development Solar/BESS 3 2035 REZ, distribution
interconnected
Other Standalone BESS 2 2035 Distribution interconnected
REZ Development Solar/BESS 20 2040 REZ, east side of Hawaiʻi
island
Other Geothermal 30 2045 North side of Hawaiʻi island
REZ Development Solar/BESS 14 2050 REZ, east side of Hawaiʻi
island Onshore wind 2 2050
System Resource Summary and Forecasted Demand (MW)
Fossil
Generation
Onshore
Standalone Wind
Geothermal
Generation
Grid-Scale
Hybrid
Solar/BESS
Hydro DER System Peak Load
RFP Stage 3 Projects
REZ Project
2029
REZ Projects2040
Geothermal
2045
REZ Projects2050
D-187 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
Base Scenario Resource Plan 2050
85.8 60.5 76 237 16.6 271 295
REZ Enablement
It is assumed that the geothermal generation in service in 2045 will be interconnected at Haina substation, and the REZ generation will be interconnected at Pepeekeo substation (20 MW) in 2040 and Kaumana substation (17
MW) in 2050.
High level cost estimate for the 20 MW interconnection REZ enablement at the Pepeekeo substation is $24.5
million, and for the 17 MW interconnection REZ enablement at the Kaumana substation is $27.9 million.
Grid Needs - Transmission System Networks Expansion
The estimated cost for the two line reconductor is $100.1 million.
To mitigate undervoltage violations on the north side of the system, it is recommended to dispatch an East unit
(e.g., PGV, etc.) at 5 MW or higher.
To mitigate undervoltage violation on south and southwest side of the system, it is recommend to have a
resource interconnected at Kamaoa with 22.5 MW generation capacity and/or a minimum reactive power
requirement (defined on further study when resouces are known).
Grid Needs – System Stability Needs
Not studied.
Keamuku PohakuloaWaikii Kaumana
Existing 69 kV Line ReconductorExisting 69 kV Substation
L6200
Hinai Waikoloa
L8100
D-188 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Table A 21 Hawaiʻi Island Transmission System Grid Needs – High Load, Year 2032
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2032
According to the resource plan, by 2030,
the Hawaiʻi system will have new
generation from Stage 3 RFP procurement, REZ development and a
new geothermal generation plant, which
will be 48 MW wind generation of REZ
development and 30 MW geothermal
generation by 2029 and 140 MW Stage 3
RFP PV/BESS IBR generation by 2030. All
of this new generation will be
interconnected to the Hawaiʻi island 69 kV
system. Meanwhile, three generation
plants will be removed by 2031: the 34
MW Hill 5 and 6 will be removed by 2027;
the 21 MW Tahiri wind generation will be
removed by 2028; the 58 MW Hamakua
Energy Partners (“HEP”) will be removed
from system by 2031. According to the
forecast, system peak load will reach 280
MW by 2032. System Grid Scale Resource Changes
Development Generation Type MW
Capacity
GCOD Location
REZ
Development
Wind Generation 48 2029 West Hawaiʻi island
Other Geothermal
Generation
30 2029 North of Hawaiʻi island
Stage 3 Hawaiʻi
Island RFP
Solar/BESS Generation 140 2030 West and east side of Hawaiʻi
island
Removal Generation Type MW
Capacity
Year Location
Hill 5, 6 Fossil Generation 34 2027 Kanoelehua substation
Tawhiri
Generation
Wind Generation 21 2028 Kamaoa substation
HEP Fossil Generation 58 2031 Haina substation
System Resource Summary and Forecasted Demand (MW)
Fossil
Generation
Onshore
Standalone Wind
Geothermal
Generation
Grid-Scale Hybrid
Solar/BESS
Hydro DER System Peak Load
85.8 58.5 76 200 16.6 214 280
REZ Enablement
Interconnection sites for the 140 MW Stage 3 RFP projects and 48 MW onshore wind generation are as
following.
• Keamuku substation – 30 MW Stage 3 project
RFP Stage 3 Projects
REZ Project2029
REZ Project2029
D-189 Integrated Grid Planning Report
APPENDIX D – SYSTEM SECURITY STUDY
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2032
• Puueo substation – 30 MW
• Kanoelehua substation – 30 MW
• Ouli substation – 20 MW
• Poopoomino substation – 30 MW
Also, it is assumed that the interconnection of 48 MW wind generation from REZ development is at the
Keamuku substation and the interconnection of the 30 MW geothermal generation is at the Haina substation.
The estimated REZ enablment cost for the 48 MW onshore wind interconnected at the Keamuku substation is
$37.8 million.
Grid Needs - Transmission System Networks Expansion
The estimated cost for reconductoring L8100 is $10.9 million.
The alternative non-wire solution for deferring L6200 reconductor is to maintain minimum generation dispatch
requirement on east side of the system. The minimum MW generation dispatched from east side of the system
is calculated by following equation:
East side minimum generation (MW) = 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝑆𝑆𝑡𝑡𝑆𝑆𝑡𝑡𝑡𝑡 𝑡𝑡𝑡𝑡𝑡𝑡𝑙𝑙−174214−174 ∙20
If system total load is lower than 178 MW, there is no mimimum MW requirement of generation dispatched on
east side of the system.
Depending on the system total load and the East side generation resources chosen to meet this minimum
requirement, the East may require 28 MVAR of additional reactive power capability to resolve potential
North/East voltage violations. 14 MVAR at Kanoelehua and 14 MVAR at Puueo are recommended to be installed
(in addition to the assumed capability of Stage 3 resources at that location).
To mitigate undervoltage violation identifed on south side of system, it is recommend to have a resource
interconnected at Kamaoa substation with at least 24 MW generation capability.
When the 30 MW geothermal is installed at Haina in 2029, there will be a total of 88 MW of generation capacity
at Haina substation. During the time period between when the geothermal resource comes online and when
HEP is removed in 2031, operational mitigation will be needed such that the total generation at Haina
substation is limited to the existing capacity of 58 MW.
Grid Needs – System Stability Needs
Not studied.
Keamuku
Existing 69 kV Line
ReconductorExisting 69 kV Substation
Hinai Waikoloa
L8100
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Table A 22 Hawaiʻi Island Transmission System Grid Needs – High Load, Year 2036
Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2036
In addtion to previous system resource
changes, by 2035 the Hawaiʻi island
system will have another 30 MW geothermal generation, 30 MW firm
generation and 22 MW solar/BESS
generation from REZ development.
Accoriding to the forecast, system
annual peak load will be reached at
323 MW by 2036.
System Resource Changes since 2031
Development Generation Type MW Capacity GCOD Location
REZ Development Solar/BESS 22 2035 East side of Hawaiʻi island
system
Other Geothermal 30 2035 North side of Hawaiʻi island system
Other Firm 30 2035 East side of Hawaiʻi island
system
System Resource Summary and Forecasted Demand (MW)
Fossil
Generation
Onshore
Standalone Wind
Geothermal
Generation
Grid-Scale
Hybrid
Solar/BESS
Hydro DER System Peak Load
115.8 58.5 106 220 16.6 230 323
REZ Enablement
It is assumed that the geothermal generation in service in 2035 will be interconnected at Haina substation, and
the REZ generation will be interconnected at Pepeekeo substation (22 MW) in 2035 and the firm generation will
be interconnected at Kanoelehua substation (30 MW) in 2035.
RFP Stage 3
Projects
REZ Project
2029
REZ Project2029
REZ Project
2035Geothermal2035
Firm 2035
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Studied Resource Plan Studied Year
High Load Scenario Resource Plan 2036
For the 22 MW Solar/BESS interconnection at the Pepeekeo substation, the estimated cost for REZ enablement is
$24.5 million.
Grid Needs - Transmission System Networks Expansion
The estimated cost of reconductoring L8600 and L6200 is $121.5 million.
To mitigate undervoltage violations on the north side of the system, it is recommended to dispatch an East unit
(e.g., PGV, etc.) at 14 MW or higher.
To mitigate undervoltage violation on south and southwest side of the system, , it is recommended to have a
resource interconnected at Kamaoa with at least 24 MW active power generation capacity and 7.5 Mvar reactive
power capability.
To mitigate undervoltage violations on the west side of the system during dispatches with high east generation, it
is recommended to dispatch Keahole at 10 MW or higher.
Grid Needs – System Stability Needs
Not studied.
Kealia KeauouCaptain
Cook Kahaluu
L8600
PohakuloaWaikii Kaumana
Existing 69 kV Line ReconductorExisting 69 kV Substation
Keamuku
L6200
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Appendix E:
Location-Based Distribution
Grid Needs
Hawaiian Electric
Location-Based Distribution
Grid Needs
May 2023
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Contents
1. Introduction ............................................................................................................................................................................ E-5 1.1 Location-Based Grid Needs ................................................................................................................................................................................... E-7 2. Analysis.................................................................................................................................................................................... E-9 2.1 Screening Circuits and Transformers ................................................................................................................................................................. E-9 2.2 Screening Examples with No Potential Grid Needs ................................................................................................................................... E-10 2.2.1 Normal Condition ........................................................................................................................................................................................ E-11 2.2.2 Contingency Condition (N-1).................................................................................................................................................................. E-12 2.3 Hourly Grid Needs Analysis.................................................................................................................................................................................. E-13 2.3.1 LoadSEER ......................................................................................................................................................................................................... E-14 2.3.2 Scaling Method ............................................................................................................................................................................................. E-14 2.3.3 Hourly Grid Needs Analysis Example................................................................................................................................................... E-15 2.4 Hourly Grid Needs Analysis Summary ............................................................................................................................................................. E-16 3. Grid Needs ............................................................................................................................................................................ E-20 3.1 Solutions Assessment ............................................................................................................................................................................................. E-20 3.1.1 Traditional Solution Selection ................................................................................................................................................................. E-22 3.1.2 Base Scenario ................................................................................................................................................................................................. E-23 3.1.3 High Load Customer Technology Adoption Bookend Scenario .............................................................................................. E-24 3.1.4 Low Load Customer Technology Adoption Bookend Scenario................................................................................................ E-27 3.1.5 Fast Customer Technology Adoption Scenario ............................................................................................................................... E-29 3.1.6 Traditional Solutions Summary .............................................................................................................................................................. E-31 3.1.7 Base Scenario Summary ............................................................................................................................................................................ E-32 3.1.8 High Load Customer Technology Adoption Bookend Scenario Summary ......................................................................... E-34 3.1.9 Low Load Customer Technology Adoption Bookend Scenario Summary ........................................................................... E-36 3.1.10 Fast Customer Technology Adoption Bookend Scenario Summary ...................................................................................... E-38 3.2 Hourly Grid Needs ................................................................................................................................................................................................... E-39 3.2.1 Hourly Grid Needs Example .................................................................................................................................................................... E-40 4. Summary and Next Steps ................................................................................................................................................... E-41 5. Workbook Index .................................................................................................................................................................. E-42
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Figures
Table 1-1. Forecast Layer Mapping of Modeling Scenarios and Sensitivities .................................................... E-7 Table 2-1: Substation Transformer Screening Example – No Grid Needs ......................................................... E-11 Table 2-2: Circuit Screening Example – No Grid Needs ............................................................................................ E-11
Table 2-3: Substation Transformer Screening Example – Normal Condition ................................................... E-12
Table 2-4: Circuit Screening Example – Normal Condition ..................................................................................... E-12 Table 2-5: O‘ahu Hourly Grid Needs Summary – Substation Transformers ...................................................... E-16 Table 2-6: O‘ahu Hourly Grid Needs Summary – Circuits ........................................................................................ E-17 Table 2-7: Hawai‘i Island Hourly Grid Needs Summary – Substation Transformers ...................................... E-17
Table 2-8: Hawai‘i Island Hourly Grid Needs Summary – Circuits......................................................................... E-18
Table 2-9: Maui Island Hourly Grid Needs Summary – Substation Transformers .......................................... E-18 Table 2-10: Maui Island Hourly Grid Needs Summary – Circuits .......................................................................... E-19 Table 3-1: Grid Needs Assessment Summary ............................................................................................................... E-21 Table 3-2: O‘ahu Grid Needs and Traditional Solutions Using the Base Scenario – Normal Condition. E-23
Table 3-3: O‘ahu Grid Needs and Traditional Solutions Using the Base Scenario – Contingency Condition (N-1).............................................................................................................................................................................................. E-23 Table 3-4: Hawai‘i Island Grid Needs and Traditional Solutions Using the Base Scenario – Contingency Condition (N-1) ........................................................................................................................................................................ E-24
Table 3-5: Maui Island Grid Needs and Traditional Solutions Using the Base Scenario – Contingency
Condition (N-1) ........................................................................................................................................................................ E-24 Table 3-6: O‘ahu Grid Needs and Traditional Solutions Using the High Load Scenario – Normal Condition .................................................................................................................................................................................... E-25 Table 3-7: O‘ahu Grid Needs and Traditional Solutions Using the High Load Scenario – Contingency
Condition (N-1) ........................................................................................................................................................................ E-25
Table 3-8: Hawai‘i Island Grid Needs and Traditional Solutions Using the High Load Scenario – Contingency Condition (N-1) .............................................................................................................................................. E-26 Table 3-9: Maui Island Grid Needs and Traditional Solutions Using the High Load Scenario – Contingency Condition (N-1) .............................................................................................................................................. E-27
Table 3-10: O‘ahu Grid Needs and Traditional Solutions Using the Low Load Scenario – Normal Condition .................................................................................................................................................................................... E-27 Table 3-11: O‘ahu Grid Needs and Traditional Solutions Using the Low Load Scenario – Contingency Condition (N-1) ........................................................................................................................................................................ E-28
Table 3-12: Hawai‘i Island Grid Needs and Traditional Solutions Using the Low Load Scenario –
Contingency Condition (N-1) .............................................................................................................................................. E-28
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Table 3-13: Maui Grid Needs and Traditional Solutions Using the Low Load Scenario – Contingency
Condition (N-1) ........................................................................................................................................................................ E-28
Table 3-14: O‘ahu Grid Needs and Traditional Solutions Using the Fast Scenario – Normal ConditionE-29 Table 3-15: O‘ahu Grid Needs and Traditional Solutions Using the Fast Scenario – Contingency Condition (N-1) ........................................................................................................................................................................ E-30 Table 3-16: Hawai‘i Island Grid Needs and Traditional Solutions Using the Fast Scenario – Contingency
Condition (N-1) ........................................................................................................................................................................ E-30
Table 3-17: Maui Island Grid Needs and Traditional Solutions Using the Fast Scenario – Contingency Condition (N-1) ........................................................................................................................................................................ E-31 Table 3-18: Minimum Grid Needs Solutions Identified ............................................................................................. E-32
Table 3-19: Minimum Grid Needs Solutions Identified – Cost Summary (Wires Solutions) ....................... E-32
Table 3-20: Kewalo 7 Capacity Need (kW) ..................................................................................................................... E-40
Table 3-21: Kewalo 7 Circuit Energy Need (MWh) ...................................................................................................... E-40 Table 3-22: Kewalo 7 Circuit Need (Hours) .................................................................................................................... E-40 Table 3-23: Kewalo 7 Circuit Maximum Number of Calls Per Year ....................................................................... E-40
Table 4-1: Grid Needs Summary ........................................................................................................................................ E-41
Table 5-1: Location-Based Distribution Grid Needs Workbook Index ................................................................ E-42
Table 5-2: November 2021 Forecast Update Workbook Index ............................................................................. E-42
Figure 1-1: Stages of the Distribution Planning Process ............................................................................................ E-5
Figure 1-2 Location-Based Distribution Grid Needs Identification Stages .......................................................... E-8 Figure 2-1 Analysis Stage of the Distribution Planning Process .............................................................................. E-9 Figure 2-2: Summary of Screening and Hourly Analysis Process .......................................................................... E-10 Figure 2-3: Hourly Grid Needs Example – Kewalo 7 Circuit (Year 2026) ............................................................ E-15
Figure 2-4: Hourly Grid Needs Example – Kewalo 7 Circuit (Year 2027) ............................................................ E-16
Figure 3-1: Solution Options Stage of the Distribution Planning Process ......................................................... E-20
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1 Introduction
This document describes the development of the location-based distribution grid needs that are
derived from the Distribution Planning process and will be used as part of the Integrated Grid Planning
(“IGP”) process. The Distribution Planning Process is comprised of four stages: forecast, analysis, solution options, and evaluation.
1. Forecast Stage: Develop circuit-level forecasts based on the corporate demand forecast.
2. Analysis Stage: Determine the adequacy of the distribution system.
3. Solution Options Stage: Identify the grid needs requirements.
4. Evaluation Stage: Evaluation of solutions.
Figure 1-1: Stages of the Distribution Planning Process
On November 5, 2021, the Companies submitted their Location-Based Distribution Forecasts (“November 2021 Forecasts”) in the IGP Grid Needs Assessment Methodology Review Point filed under Docket No. 2018-0165.1 That document described the first stage, the Forecast Stage. It included the
methodology to develop substation transformer and circuit location-based forecasts in accordance with
the Distribution Planning Process described in the Distribution Planning Methodology document, updated to address the Technical Advisory Panel comments and questions.2 On March 3, 2022, the
1 See Hawaiian Electric Exhibit 3 – Location-Based Distribution Forecasts filed on November 5, 2021 in Docket No. 2018-0165, Instituting a Proceeding to Investigate Integrated Grid Planning.
2See Hawaiian Electric Companies’ Grid Needs Assessment Methodology Review Point, Exhibit 1 Distribution Planning Methodology, filed on November 5, 2021 in Docket No 2018-0165.
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Commission stated it “is satisfied with how Hawaiian Electric described the purpose and functionality of
its modeling tools and accepts Hawaiian Electric’s explanation of the modeling tools it uses…”.3
This document describes the subsequent process (see “Analysis” in Figure 1-1) to identify the grid needs required based on the November 2021 Forecasts. For this analysis, the adequacy of the electric distribution system is assessed by comparing the location-based distribution forecasts against the distribution planning criteria described in the Distribution Planning Methodology to determine if the
distribution circuits and substation transformers can serve the forecasted load growth (includes layers
for distributed energy resources, electric vehicles, energy efficiency, and time of use). If the planning criteria is not met, grid needs required to meet the planning criteria are identified. This process differs from the hosting capacity grid needs which assesses each circuit’s ability to accommodate DER growth specifically and as described in the Distribution DER Hosting Capacity Grid Needs.4 These two analyses
have the potential to overlap in requirements, since both consider contributions from DER to different
extents; however, in this current planning horizon there were no circuits found with differing grid needs for the location-based distribution forecast and DER hosting capacity.
This Distribution Planning Process is incorporated into the IGP process as it uses the corporate forecasts
that include planned electrical demand and DER developed through IGP as an input to the distribution
planning analyses to identify distribution grid needs. These distribution grid needs are then used as an input into the IGP process which will select portfolios of solutions to address resource, transmission, and distribution needs.
The location-based distribution forecasts filed in November 2021 were developed using the corporate
forecasts and scenarios provided in the Hawaiian Electric Revision to Updated and Revised Inputs and
Assumptions (“August Update”) filed on August 19, 2021.5 The forecasts were based on three scenarios to provide a range of higher and lower loads: the Base, High Load Customer Technology Adoption Bookend, and the Low Load Customer Technology Adoption Bookend. On March 3, 2022, the Commission requested a fourth scenario, Fast Customer Technology Adoption, to “reflect a plausible
future aligned with the State’s RPS and emissions reductions goals”.6
The corporate forecasts include specific layers for the underlying load growth, distributed energy resources (“DER”), energy efficiency (“EE”), and electric vehicles (“EV”)7. These layers that are provided at
3 See Order No. 38253 issued on March 3, 2022 in Docket No. 2018-0165, Approving, with Modifications, Hawaiian Electric’s Revised Inputs and Assumptions.
4 See Hawaiian Electric Companies’ Grid Needs Assessment Methodology Review Point, Exhibit 4 Distribution DER Hosting Capacity Grid Needs, filed on November 5, 2021 in Docket No 2018-0165.
5 See Hawaiian Electric Revision to Updated and Revised Inputs and Assumptions filed on August 19, 2021 in Docket No 2018-0165.
6 See Order No. 38253 issued on March 3, 2022 in Docket No. 2018-0165, Approving, with Modifications, Hawaiian Electric’s Revised Inputs and Assumptions
7 This analysis uses the forecast for light duty electric vehicles but does not consider the forecast for eBus.
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the system level are disaggregated to create a total demand forecast for each substation transformer
and circuit. The four scenarios and the associated corporate forecast layers are summarized below.
Table 1-1. Forecast Layer Mapping of Modeling Scenarios and Sensitivities
No. Modeling Case DER Forecast EV Forecast EE Forecast TOU Load Shape
1 Base Base Forecast Base Forecast Base Forecast Managed EV Charging
2
High Load Customer Technology Adoption Bookend
Low Forecast High Forecast Low Forecast Unmanaged EV Charging
3
Low Load Customer Technology Adoption Bookend
High Forecast Low Forecast High Forecast Managed EV Charging
4 Fast Customer Technology Adoption High Forecast High Forecast High Forecast Managed EV Charging
Since the November 2021 Forecasts were developed, the Company has received various service
requests for new loads and the November 2021 Forecasts were updated to reflect these changes. The analysis herein references the updated forecasts that are referred to as the November 2021 Forecast Update in this document.8
1.1 Location-Based Grid Needs
The overall process and methodology, using modeling tools such as LoadSEER9 to develop the grid needs driven by location-based demand forecasts is provided herein. Since this report addresses the location-based grid needs specifically, the distribution planning process figure discussed at the Stakeholder Technical Working Group meeting in June 202110 was streamlined to show details related
only to this analysis and is shown in Figure 1-2. Potential wires and non-wires alternative (“NWA”)
8 The updated forecasts are voluminous and therefore not provided in this report in table format. The files are available on the Company website in Excel workbooks. See Section 5 for a description of the files provided.
9 See Hawaiian Electric, Distribution Planning Methodology, November 2021 for an overview of the LoadSEER and Synergi models.
10 See Hawaiian Electric, Distribution Planning Methodology, November 2021 for descriptions of the distribution planning criteria.
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solutions opportunities using the Non-Wires Opportunity Evaluation Methodology11 will be evaluated
separately as part of the IGP process.
The distribution planning criteria establishes technical guidelines to ensure the distribution system has adequate capacity to serve load growth and reliability (e.g., back-tie capability) for the Company’s customers. Thus, planning for operation under both normal and contingency conditions is necessary as described in the Distribution Planning Methodology.
Figure 1-2 Location-Based Distribution Grid Needs Identification Stages
The following steps are used to identify substation transformers and circuits with planning criteria
violations in the study period based on the forecast scenarios described above:
5. Determine the demand forecast (kW) by substation transformer and circuit.
6. Screen substation transformers and circuits for analysis.
7. Perform hourly grid needs analysis.
8. Identify solution options.
The first step above was described in the November 2021 Forecasts. That process developed the net
peak forecast by substation transformer and circuit. Initially, when the distribution planning process started in year 2021, the study period spanned the next ten years (year 2021 through 2030). For the purposes of this report, the study period was adjusted to align with the current year and spans year 2023 through 2030. This report focuses on steps 2 and 3 to describe the analysis to identify the grid
needs resulting from the demand forecasts.
11 The Non-Wires Opportunity Evaluation Methodology was filed in the Grid Needs Assessment (Nov. 2021, Dkt. No. 2018-0165). An updated methodology is provided in Appendix F: NWA Opportunity Evaluation Methodology March 2023 Update of this filing to reflect the first time applying this methodology in the IGP cycle and additional feedback received from the Technical Advisory Panel such as defined thresholds for the NWA evaluation criteria.
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2 Analysis
Figure 2-1 Analysis Stage of the Distribution Planning Process
This section describes steps 2 and 3 used to identify circuits and transformers that violate the
distribution planning criteria indicating a grid need:
1. Determine the demand forecast (kW) by substation transformer and circuit.
2. Screen transformers and circuits for analysis.
3. Perform hourly grid needs analysis.
4. Identify solution options.
Planning criteria violations occur when there is existing or forecasted thermal loading or voltage levels
on the Company’s circuits or substation transformers that are outside of the acceptable range identified in the Distribution Planning Methodology.12 An assessment for planning criteria violations was conducted for both normal condition and contingency (N-1) condition.
2.1 Screening Circuits and Transformers
Initially, substation transformers and circuits are screened to determine if there are violations based on
the forecasted annual peak demand. If there is insufficient capacity to serve the forecasted demand,
12 Distribution planning criteria applied to 46 kV and below for circuits on O‘ahu and 12 kV and below for circuits on Hawai‘i Island, Maui, Lānaʻi, and Moloka‘i. Distribution substation transformer planning criteria applied to 46 kV to 12 kV transformers.
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additional hourly analysis is performed to determine if there is a grid need. This process is summarized
in the following figure.
Figure 2-2: Summary of Screening and Hourly Analysis Process
The steps described in this section to select the substation transformers and circuits for analysis were repeated for each of the forecast scenarios: Base, High Load Customer Technology Adoption, Low Load
Customer Technology Adoption, and Fast Customer Technology Adoption.
The screening process flags substation transformers and circuits for planning criteria violations to determine if there is a potential for identifying a grid need. The thermal rating or equipment rating is compared against the respective annual forecast in the November 2021 Forecast Update. Transformers and circuits are selected for further analysis if the forecast is greater than the thermal or equipment
rating. This comparison is done for each year of the forecast to determine in what year(s) the violation(s) occur.
If the Demand Forecast by Transformer is less than the Transformer Rating or the Demand Forecast by Circuit is less than the Equipment Rating, there are no potential grid needs and no further analysis is
required.
2.2 Screening Examples with No Potential Grid Needs
For the following substation transformer, the total demand forecast for that transformer is lower than the transformer rating for the entire period. Similar to the circuit example above, there are no potential grid needs and no further analysis required.
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Table 2-1: Substation Transformer Screening Example – No Grid Needs
Substation Transformer Equipment Rating (MVA)
Demand Forecast by Transformer (MW) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
KEWALO 1 12.5 5.997 6.045 6.613 6.621 6.625 6.607 6.618 6.603 6.625 6.614
For the following circuit, the total demand forecast is lower than the equipment rating for the entire
period. Therefore, there are no potential grid needs and no further analysis is required.
Table 2-2: Circuit Screening Example – No Grid Needs
Circuit Equipment Rating (MVA) Demand Forecast by Circuit (MW) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
KEWALO 1 9.1 2.077 2.109 3.330 3.330 3.314 3.308 3.306 3.304 3.302 3.297
The screening process is performed for operation under normal conditions and operation under contingency conditions with separate criteria for each type.
2.2.1 Normal Condition
The screening criteria to flag substation transformers and circuits for planning criteria violations and subsequent analysis is based on the normal equipment rating (e.g., thermal rating). Circuits are selected
for analysis if the thermal rating of the main conductor out of the substation under normal conditions is
lower than the total demand forecast for that circuit (i.e. “Demand Forecast by Circuit”). Substation transformers are selected for analysis if the equipment rating13 is lower than the total demand forecast for that transformer (i.e. ”Demand Forecast by Transformer”). This comparison is done for each year of the forecast to determine in what year(s) the violation(s) occur.
In general, analysis occurs if:
• Substation Transformer: Demand Forecast by Transformer (MW) is greater than the Transformer Rating (MVA)14
• Circuits: Demand Forecast by Circuit (MW) is greater than Equipment Rating (MVA)15
13 Equipment rating is the larger rating with fans operating (“FA”) if applicable; otherwise, the rating with fans off (“OA”) is provided. Equipment rating is the highest installed nameplate capacity rating (OA/FA) of the distribution substation transformer (MVA).
14 Highest installed nameplate capacity rating (OA/FA) of the distribution substation transformer. If available, a 0% loss of life rating is used for normal conditions.
15 Thermal rating of the main conductor out of the substation under normal conditions.
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If the Demand Forecast by Transformer is less than the Transformer Rating or the Demand Forecast by
Circuit is less than the Equipment Rating, there are no grid needs and no further analysis is required.
If a transformer or circuit is flagged for analysis, the hourly grid needs are determined using the approach described in Section 2.3.
Normal Condition Screening Example
An example of the substation transformer selection process is shown below for the Kewalo T3
substation transformer on O‘ahu using the Base Scenario. The 50 MVA Equipment Rating is compared
against the Demand Forecast by Circuit (MW) for each year of the forecast (years 2021 through 2030). From year 2027 through 2030, the forecast is higher than the Equipment Rating as shown highlighted in orange. Therefore, the transformer is selected for further analysis.
Table 2-3: Substation Transformer Screening Example – Normal Condition
Substation Transformer Equipment Rating (MVA) Demand Forecast by Transformer (MW) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Kewalo T3 50 24.483 25.171 24.995 32.411 36.316 45.101 59.946 60.019 60.049 60.074
An example of the circuit selection process is shown below for the Kewalo 7 circuit on O‘ahu using the Base Scenario. The 17 MVA Equipment Rating is compared against the Demand Forecast by Circuit (MW) for each year of the forecast (years 2021 through 2030). From year 2026 through 2030, the forecast is higher than the Equipment Rating as shown highlighted in orange. Therefore, the circuit is
selected for further analysis.
Table 2-4: Circuit Screening Example – Normal Condition
Circuit Equipment Rating (MVA) Demand Forecast by Circuit (MW) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Kewalo 7 17.0 8.459 8.775 8.631 10.143 12.491 19.016 34.547 34.688 34.659 34.628
2.2.2 Contingency Condition (N-1)
Because there may be various switching options for contingency conditions, it isn’t feasible to evaluate each N-1 loading scenario against equipment ratings. Instead, the initial screening criteria to flag transformers and circuits for planning criteria violations under contingency conditions (N-1) is to compare the forecast against 75% of the equipment rating. Seventy-five percent of equipment rating
was selected based on engineering judgement to select transformers and circuits for more detailed analysis. The equipment with demand exceeding the 75% threshold would be limited in the amount of backup capacity that it provides in a contingency scenario. This estimate was shown to be rather
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conservative since at most 64 out of 351 transformers and 90 out of 635 circuits were flagged for
further analysis in a scenario16, which is about 18% and 14%, respectively.
Transformers and circuits are selected for analysis if Demand Forecast by Transformer or Demand Forecast by Circuit is greater than 75% of the respective Equipment Rating. This comparison is done for each year of the forecast to determine in what year(s) the violation(s) occur.
In general, analysis occurs if:
• Substation Transformer: Demand Forecast by Transformer (MW) is greater than 75% of
Transformer Rating (MVA)17
• Circuits: Demand Forecast by Circuit (MW) is greater than 75% of Equipment Rating (MVA)18
If the Demand Forecast by Transformer is less than 75% of the Transformer Rating or the Demand Forecast by Circuit is less than 75% of the Equipment Rating, there are no grid needs and no further
analysis is required.
If a transformer or circuit is flagged for additional analysis, the hourly grid needs are determined using the approach described in Section 2.3.
2.3 Hourly Grid Needs Analysis
Once a substation transformer or circuit is identified for further analysis using the screening criteria
described in Section 2.1, the next step is to perform a more detailed analysis to determine if there is a criteria violation and if there is, define the hourly grid needs in technology-neutral terms: capacity (MW), energy (MWh), and duration (hours). This is done by creating an hourly (“8760”) profile19 derived from the annual peak demand forecast using the November 2021 Forecast Update. The 8760 profile is
compared against the equipment rating to determine the hourly grid needs as was described above in
the screening process using the annual forecast.
The capacity (kW) need or magnitude of the overload is calculated by the greatest difference between the forecasted demand and the equipment rating. The annual energy requirement (MWh) is calculated by summing the magnitude of overload hours in a calendar year. Lastly, the duration (hours) is
calculated based on the maximum hours in a single day where there are overloads.
16 The highest number of flagged transformers and circuits occurred in the High Load Customer Technology Adoption Bookend case, or Scenario 2.
17 Highest installed nameplate capacity rating (OA/FA) of the distribution substation transformer. If available, a 1% loss of life rating is used for contingency conditions.
18 Thermal rating of the main conductor out of the substation under normal conditions.
19 An 8760-hour profile represents all 365 days of the year at a 1-hour resolution.
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Defining the hourly grid needs is similar in concept for all islands, but performed using different tools.
As mentioned in the November 2021 Forecasts, LoadSEER was used to develop the location-based
forecasts for O‘ahu, but was unavailable for the neighbor island modeling.20 Thus, LoadSEER was used to perform the analysis to determine the hourly grid needs for O‘ahu. A process to create similar 8760 profiles for the neighbor islands was developed using a scaling method. These two processes are described in the following sections.
2.3.1 LoadSEER
The 8760 profiles are developed using LoadSEER and are based on the annual demand forecasts.21
LoadSEER creates an 8760 profile of the forecasted demand for each transformer and/or circuit from years 2023 to 2030. Similar to the screening process described in Section 2.1, the hourly forecasted demand (kW) is compared against the equipment rating. If the forecasted demand is greater than the equipment rating, that hour is noted as having an overload.
2.3.2 Scaling Method
In the absence of LoadSEER modeling to develop 8760 profiles, a scaling method is used to mimic the
process done in LoadSEER to create hourly demand forecasts by circuit and transformer.
This process starts with the historical hourly profile for the circuit used to determine the circuit peak loads.22 The unitized profiles for EV, PV, BESS, EE, and load were extracted from LoadSEER and scaled to the allocated values determined in the location-based forecast. The resulting profiles for each layer
were then added to the base load profile to get the hourly forecasted demand shape for each year. This
is the profile that is compared to the equipment rating to determine the grid need. To get the
transformer hourly forecasted demand, the shapes for each feeder fed from that transformer are summed together.
This process was completed for both normal and contingency conditions.
20 The implementation of LoadSEER for the neighbor islands is targeted for early 2023 as reported in Exhibit 2 of Hawaiian Electric’s Quarterly DER Technical Report filed on December 28, 2022 in Docket No 2019-0323.
21 The process to derive the 8760 profiles is described in Hawaiian Electric Exhibit 3 – Location-Based Distribution Forecasts filed on November 5, 2021 in Docket No. 2018-0165, Instituting a Proceeding to Investigate Integrated Grid Planning.
22 Id, Section 2.1.
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2.3.3 Hourly Grid Needs Analysis Example
Using the example discussed in Section 2.2.1, the Kewalo 7 circuit on O‘ahu was selected for further analysis in the Base Scenario. The hourly forecasted demand (8760 profile) was compared to the equipment rating for each hour of each year in the analysis timeframe. A sample day with an overload is
shown in the plots below for two different years. The red line represents the forecasted demand (kW)
and the dashed gray line represents the equipment rating (kW) for the circuit. The red shaded area is the overload.
The earliest year the overload occurs is in year 2026. In the chart below, on this particular day
forecasted in year 2026, the plot illustrates an overload duration of approximately two hours (from hour
20 to hour 21) with a capacity need of approximately 2,000 kW and energy requirement of about 3,000
kWh.
Figure 2-3: Hourly Grid Needs Example – Kewalo 7 Circuit (Year 2026)
The forecasted overload for this circuit grows in the following year. In the chart below, on this day
forecasted in year 2027, the plot illustrates an overload duration of approximately 17 hours (from hour
8 to hour 24) with a peak capacity need of approximately 17,500 kW and energy requirement of
164,000 kWh.
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Figure 2-4: Hourly Grid Needs Example – Kewalo 7 Circuit (Year 2027)
2.4 Hourly Grid Needs Analysis Summary
The number of substation transformers and circuits flagged for hourly analysis and the grid needs identified are summarized in the following tables by island. Mitigation options for the identified grid needs are discussed further in Section 3.
O‘ahu
The table below is a summary of the transformers that were identified for hourly analysis. Through the
hourly analysis, the transformers with grid needs were identified.
Table 2-5: O‘ahu Hourly Grid Needs Summary – Substation Transformers
Substation Transformer
Normal Contingency Identified For Hourly Analysis Grid Need Identified Identified For Hourly Analysis Grid Need Identified Scenario 1 (Base) 5 2 31 8
Scenario 2
(High Load) 12 3 61 12
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Scenario 3 (Low Load) 7 3 29 6
Scenario 4 (Fast Adoption) 10 4 39 8
The table below is a summary of the circuits that were identified for hourly analysis. Through the hourly analysis, the circuits with grid needs were identified.
Table 2-6: O‘ahu Hourly Grid Needs Summary – Circuits
Circuits Normal Contingency Identified For Hourly Analysis Grid Need Identified Identified For Hourly Analysis Grid Need Identified Scenario 1
(Base) 8 3 46 9
Scenario 2 (High Load) 20 6 84 20
Scenario 3 (Low Load) 8 3 42 7
Scenario 4 (Fast Adoption) 12 5 58 12
For O‘ahu, an hourly grid need analysis was performed on 472 transformers and circuits that were
identified in the four scenarios for both normal and contingency conditions. Of these, 111 grid needs were identified through the analysis across all four scenarios.
Hawai‘i Island
The tables below is a summary of the transformers that were identified for hourly analysis. Through the
hourly analysis, the transformers with grid needs were identified.
Table 2-7: Hawai‘i Island Hourly Grid Needs Summary – Substation Transformers
Substation Transformer
Normal Contingency Identified For Hourly Analysis Grid Need Identified Identified For Hourly Analysis Grid Need Identified Scenario 1 (Base) 2 0 2 0
Scenario 2
(High Load) 2 0 2 0
Scenario 3 (Low Load) 2 0 2 0
Scenario 4 (Fast Adoption) 2 0 2 1
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The table below is a summary of the circuits that were identified for hourly analysis. Through the hourly
analysis, the circuits with grid needs were identified.
Table 2-8: Hawai‘i Island Hourly Grid Needs Summary – Circuits
Circuits Normal Contingency Identified For Hourly Analysis Grid Need Identified Identified For Hourly Analysis Grid Need Identified Scenario 1 (Base) 0 0 5 3
Scenario 2
(High Load) 0 0 5 3
Scenario 3 (Low Load) 0 0 5 3
Scenario 4
(Fast Adoption) 0 0 5 3
For Hawai‘i Island, an hourly grid need analysis was performed on 36 transformers and circuits that were identified in the four scenarios for both normal and contingency conditions. Of these, 13 grid needs
were identified through the analysis.
Maui Island
The tables below is a summary of the transformers that were identified for hourly analysis. Through the hourly analysis, the transformers with grid needs were identified.
Table 2-9: Maui Island Hourly Grid Needs Summary – Substation Transformers
Substation Transformer
Normal Contingency Identified For Hourly Analysis Grid Need Identified Identified For Hourly Analysis Grid Need Identified Scenario 1
(Base) 0 0 1 0
Scenario 2 (High Load) 0 0 1 0
Scenario 3
(Low Load) 0 0 1 0
Scenario 4 (Fast Adoption) 0 0 1 0
The table below is a summary of the circuits that were identified for hourly analysis. Through the hourly
analysis, the circuits with grid needs were identified.
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APPENDIX E – LOCATION-BASED
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Table 2-10: Maui Island Hourly Grid Needs Summary – Circuits
Circuits Normal Contingency Identified For Hourly Analysis Grid Need Identified Identified For Hourly Analysis Grid Need Identified Scenario 1
(Base) 0 0 1 1
Scenario 2 (High Load) 0 0 1 1
Scenario 3
(Low Load) 0 0 1 1
Scenario 4 (Fast Adoption) 0 0 1 1
For Maui Island, an hourly grid need analysis was performed on 8 transformers and circuits that were
identified in the four scenarios for both normal and contingency conditions. Of these, 4 grid need was identified through the analysis.
Lānaʻi
No substation transformers or circuits were flagged for hourly analysis on Lānaʻi. Therefore, no grid needs are identified.
Moloka‘i
No substation transformers or circuits were flagged for hourly analysis on Moloka‘i. Therefore, no grid needs are identified.
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APPENDIX E – LOCATION-BASED
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3 Grid Needs
Figure 3-1: Solution Options Stage of the Distribution Planning Process
This section describes the last step to identify distribution grid needs:
1. Determine the demand forecast (kW) by substation transformer and circuit. 2. Screen substation transformers and circuits for analysis.
3. Perform hourly grid needs analysis.
4. Identify solution options.
3.1 Solutions Assessment
Solutions are identified for substation transformers and circuits requiring mitigation resulting from the hourly grid needs analysis. As described in Section 2, solutions are required if the equipment rating or transformer rating is lower than the demand forecast. The year(s) where the forecast is higher than the
equipment rating are the year(s) where there is a grid need and mitigation is required.
As described in the Distribution Planning Methodology, a traditional solution will be defined for each grid need identified and include:23
■ Substation: Transformer asset identification
■ Circuit: Feeder asset identification
23 Hawaiian Electric, Distribution Planning Methodology, November 2021 at 20.
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■ Distribution Service Required: Distribution capacity or distribution reliability (back-tie) service
■ Primary Driver of Grid Need: Defines whether the identified grid need is primarily driven by DER growth, demand growth, other factor(s), or a combination of factors
■ Operating Date: The date at which traditional infrastructure must be constructed and energized, in advance of the forecasted grid need to maintain safety and reliability
■ Equipment Rating: Equipment’s rated capacity
■ Peak Load: Peak loading on asset for given year
■ Deficiency: Deficiency divided by the rating for each of the forecasted years
■ Traditional Solution: Traditional solution identified for mitigation (Solution Options)
■ NWA Qualified Opportunity: Defines whether the grid need is a qualified opportunity for further
evaluation based on technical requirements and timing of need
■ Cost Estimate: Estimated cost to provide traditional solution identified
The location-based distribution grid needs assessment tables shown in the following sections are
simplified and do not include all the fields defined above as some are not applicable for these grid needs, or the fields are consistent for all islands for all years. The following fields are applicable to all islands and are not replicated in the tables in the subsequent sections:
■ Distribution Service Required: Distribution capacity or distribution reliability (back-tie) service
■ Primary Driver of Grid Need: Demand growth
A summary of the total number of circuits and transformers requiring grid needs is shown below for
each scenario. The number of grid needs is highest in the High Load Scenario followed by the Fast
Customer Technology Adoption Scenario. The number of grid needs are lower in the Base and Low
Load Scenarios. Some grid needs may be required in two or more scenarios.
Table 3-1: Grid Needs Assessment Summary
Island Total Substation Transformers
Total Circuits
Total (Tsf and Ckt)
Total Grid Needs
Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load)
Scenario 4 (Fast Adoption) O‘ahu 204 393 597 22 42 19 29
Hawai‘i Island 82 148 230 3 3 3 4
Maui Island 62 93 155 1 1 1 1
Lana‘i 1 3 4 - - - -
Moloka‘i 2 8 10 - - - - Total (All Islands) 351 645 996 26 46 23 34
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3.1.1 Traditional Solution Selection
Once the hourly grid needs analysis is performed and the grid needs are defined in technology-neutral terms, wires solutions that meet the grid needs are identified. This provides a baseline comparison for future evaluation of solution options in the IGP process. The following procedure is used to select the
traditional solution that best mitigates the grid need; this is typically the least-cost traditional solution.
The solution development process is similar for both normal and contingency conditions.
The following options are assessed and typically progress from evaluating the simpler, lower-cost solution first, then to more complex, highest-cost solutions if necessary:
1. Circuit or transformer load balancing or load shifting 2. Sectionalizing load 3. Circuit reconductoring 4. Installing new infrastructure (i.e. new circuit, transformer, or substation which may include an upgrade or additional unit installed)
The first option to eliminate a circuit or transformer overload is to assess if load balancing is feasible by assessing available capacity on adjacent circuits for load shifting capability. In other words, can a
portion of or the entire load (MW/MVA) be transferred to another circuit or transformer using existing
sectionalizing devices to eliminate the overload on the circuit or transformer of study. Load balancing is the first option as it’s typically a low- or minimal cost solution.
The second option is to sectionalize load in the area if load balancing is not feasible. This is done by installing a switch that transfers the entire load or a portion of the load to another circuit or transformer
to eliminate the overload. In some cases, installing one or more switches to create multiple section ties
may be required to eliminate the overload.
The third option is to evaluate reconductoring if load balancing and sectionalizing is not feasible. Upgrading cables in the overloaded section is evaluated to determine if the overload is eliminated. If so, the type and length of cable required is selected.
Lastly, if none of the first three options are feasible in eliminating the overload, new infrastructure is
evaluated. This may include new circuiting, the installation of a new transformer and/or a new substation. This is typically the costliest solution.
High-level cost estimates for circuit and transformer mitigations based on unit cost information from
previous similar projects are provided.
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APPENDIX E – LOCATION-BASED
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3.1.2 Base Scenario
The grid needs by transformer and circuit identified by island using the Base Scenario are provided in the following tables.
O‘ahu
Table 3-2: O‘ahu Grid Needs and Traditional Solutions Using the Base Scenario – Normal Condition
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
KEWALO T3 KEWALO 7 Capacity 2026 New circuits
KEWALO T3 N/A Capacity 2027 New substation transformer
WAIPIO 1 N/A Capacity 2025 New substation transformer
WAIPIO 1 WAIPIO 1 Capacity 2027 New circuit
WAIPIO 1 WAIPIO 2 Capacity 2026 New circuit
Table 3-3: O‘ahu Grid Needs and Traditional Solutions Using the Base Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
CEIP 3 CEIP 46 Reliability 2025 Reconductor
IWILEI T3 IWILEI 9 Capacity, Reliability 2023 New circuits
KAMOKILA 2 N/A Reliability 2027 Circuit line extension
KAPOLEI 2 KAPOLEI 4 Reliability 2026 Circuit line extension
KEWALO T3 KEWALO 7 Reliability 2027 New circuits
KEWALO T3 N/A Reliability 2027 New substation transformer
KUILIMA 2 N/A Reliability 2028 New substation transformer
WAHIAWA 3 (138kV) N/A Reliability 2028 New substation transformer and circuit
WAHIAWA 3 (138kV) WAHIAWA-WAIMANO Reliability 2026 New substation transformer and circuit
WAIAU A N/A Reliability 2024 Split bus
WAIAU B N/A Reliability 2024 Split bus
WAIPIO 1 N/A Reliability 2025 New substation transformer
WAIPIO 1 WAIPIO 1 Reliability 2026 New circuit
WAIPIO 1 WAIPIO 2 Reliability 2026 New circuit
WAIPIO 2 N/A Reliability 2025 New substation transformer
WAIPIO 2 WAIPIO 3 Reliability 2026 New circuit
WAIPIO 2 WAIPIO 4 Reliability 2026 New circuit
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APPENDIX E – LOCATION-BASED
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Hawai‘i Island
There are no grid needs for Hawai‘i Island in the Base Scenario under normal condition.
Table 3-4: Hawai‘i Island Grid Needs and Traditional Solutions Using the Base Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
HALAULA HALAULA 2 Reliability (back-tie) 2023 New switch and recircuiting
HONOMU HONOMU 1 Reliability (back-tie) 2023 Voltage conversion and tie
OOKALA OOKALA 11 Reliability (back-tie) 2023 Voltage conversion and tie
Maui Island
There are no grid needs for Maui in the Base Scenario under normal condition.
Table 3-5: Maui Island Grid Needs and Traditional Solutions Using the Base Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
HUELO Huelo 74A/Huelo Reliability (back-tie) 2023 Upgrade substation transformer
Lana‘i
There are no grid needs for Lānaʻi in the Base Scenario.
Moloka‘i
There are no grid needs for Moloka‘i in the Base Scenario.
3.1.3 High Load Customer Technology Adoption Bookend Scenario
The grid needs by transformer and circuit identified by island using the High Load Customer
Technology Adoption Bookend Scenario are provided in the following tables.
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APPENDIX E – LOCATION-BASED
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O‘ahu
Table 3-6: O‘ahu Grid Needs and Traditional Solutions Using the High Load Scenario – Normal Condition
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
CEIP 3 CEIP 46 Capacity 2025 Reconductor
KAMOKILA 2 N/A Capacity 2029 Circuit line extension
KEWALO T3 KEWALO 7 Capacity 2026 New circuits
KEWALO T3 N/A Capacity 2027 New substation transformer
PUUNUI 2 HEIGHTS Capacity 2029 Reconductor, voltage regulator, and fuse resizing
WAIAU A WAIAU-MILILANI Capacity 2028 New substation transformer and circuit
WAIPIO 1 N/A Capacity, 2025 New substation transformer
WAIPIO 1 WAIPIO 1 Capacity, 2027 New circuit
WAIPIO 1 WAIPIO 2 Capacity, 2026 New circuit
Table 3-7: O‘ahu Grid Needs and Traditional Solutions Using the High Load Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
CEIP 2 CEIP 3 Reliability 2028 Circuit line extension
CEIP 3 CEIP 46 Reliability 2023 Reconductor
EWA NUI 1 EWA NUI 1 Reliability 2029 Circuit line extension
EWA NUI 2 EWA NUI 2 Reliability 2025 New substation transformer and circuit
FORT WEAVER 1 FORT WEAVER 2 Reliability 2028 New circuit
FORT WEAVER 1 N/A Reliability 2028 New substation transformer
HAUULA HAUULA Reliability 2028 Reconductor
HOAEAE 1 HOAEAE 1 Reliability 2029 New switch
IWILEI T3 IWILEI 9 Reliability 2023 New circuits
KAHUKU KAHUKU Reliability 2028 Reconductor
KAMOKILA 2 KAMOKILA 4 Reliability 2030 Circuit line extension
KAMOKILA 2 N/A Reliability 2025 Circuit line extension
KANEOHE 1 HEEIA Reliability 2029 Transfer load
KAPOLEI 2 KAPOLEI 4 Reliability 2025 New substation transformer and circuit
KAPOLEI 2 N/A Reliability 2027 Circuit line extension
KEWALO T3 KEWALO 7 Reliability 2027 New circuits
KEWALO T3 N/A Reliability 2027 New substation transformer
KUILIMA 2 N/A Reliability 2026 New substation transformer
KUNIA MAKAI 1 N/A Reliability 2028 New switch and transfer load
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APPENDIX E – LOCATION-BASED
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Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
MAKAHA 2 N/A Reliability 2030 New switch
WAHIAWA 3 (138kV) N/A Reliability 2028 New substation transformer and circuit
WAHIAWA 3 (138kV) WAHIAWA-WAIMANO Reliability 2025 New substation transformer and circuit
WAIALUA 2 KAENA PT Reliability 2023 Reconductor
WAIAU A N/A Reliability 2024 Split bus
WAIAU A WAIAU-MILILANI Reliability 2026 New substation transformer and circuit
WAIAU B N/A Reliability 2024 Split bus
WAIPIO 1 N/A Reliability 2024 New substation transformer
WAIPIO 1 WAIPIO 1 Reliability 2026 New circuit
WAIPIO 1 WAIPIO 2 Reliability 2026 New circuit
WAIPIO 2 N/A Reliability 2024 New substation transformer
WAIPIO 2 WAIPIO 3 Reliability 2026 New circuit
WAIPIO 2 WAIPIO 4 Reliability 2026 New circuit
Hawai‘i Island
There are no grid needs for Hawai‘i Island in the High Load Scenario under normal condition.
Table 3-8: Hawai‘i Island Grid Needs and Traditional Solutions Using the High Load Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
HALAULA HALAULA 2 Reliability (back-tie) 2023 New switch and recircuiting
HONOMU HONOMU 1 Reliability (back-tie) 2023 Voltage conversion and tie
OOKALA OOKALA 11 Reliability (back-tie) 2023 Voltage conversion and tie
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APPENDIX E – LOCATION-BASED
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Maui Island
There are no grid needs for Maui in the High Load Scenario under normal condition.
Table 3-9: Maui Island Grid Needs and Traditional Solutions Using the High Load Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
HUELO Huelo 74A/Huelo Reliability (back-tie) 2023 Upgrade substation transformer
Lana‘i
There are no grid needs for Lānaʻi in the High Load Scenario.
Moloka‘i
There are no grid needs for Moloka‘i in the High Load Scenario.
3.1.4 Low Load Customer Technology Adoption Bookend Scenario
The grid needs by transformer and circuit identified by island using the Low Load Customer Technology Adoption Bookend Scenario are provided in the following tables.
O‘ahu
Table 3-10: O‘ahu Grid Needs and Traditional Solutions Using the Low Load Scenario – Normal Condition
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
KEWALO T3 KEWALO 7 Capacity 2026 New circuits
KEWALO T3 N/A Capacity 2027 New substation transformer
WAHIAWA 3 (138kV) N/A Capacity 2028 New substation transformer and circuit
WAIPIO 1 N/A Capacity 2026 New substation transformer
WAIPIO 1 WAIPIO 1 Capacity 2027 New circuit
WAIPIO 1 WAIPIO 2 Capacity 2027 New circuit
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APPENDIX E – LOCATION-BASED
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Table 3-11: O‘ahu Grid Needs and Traditional Solutions Using the Low Load Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
CEIP 2 CEIP 3 Reliability 2023 Circuit line extension
IWILEI T3 IWILEI 9 Reliability 2023 New circuits
KEWALO T3 KEWALO 7 Reliability 2023 New circuits
KEWALO T3 N/A Reliability 2023 New substation transformer
KUILIMA 2 N/A Reliability 2028 New substation transformer
WAIAU A N/A Reliability 2023 Split bus
WAIAU B N/A Reliability 2027 Split bus
WAIPIO 1 N/A Reliability 2027 New substation transformer
WAIPIO 1 WAIPIO 1 Reliability 2029 New circuit
WAIPIO 1 WAIPIO 2 Reliability 2024 New circuit
WAIPIO 2 N/A Reliability 2024 New substation transformer
WAIPIO 2 WAIPIO 3 Reliability 2024 New circuit
WAIPIO 2 WAIPIO 4 Reliability 2026 New circuit
Hawai‘i Island
There are no grid needs for Hawai‘i Island in the Low Load Scenario under normal condition.
Table 3-12: Hawai‘i Island Grid Needs and Traditional Solutions Using the Low Load Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required Operating Date Traditional Solution
HALAULA HALAULA 2 Reliability (back-tie) 2023 New switch and recircuiting
HONOMU HONOMU 1 Reliability (back-tie) 2023 Voltage conversion and tie
OOKALA OOKALA 11 Reliability (back-tie) 2023 Voltage conversion and tie
Maui Island
There are no grid needs for Maui in the Low Load Scenario under normal condition.
Table 3-13: Maui Grid Needs and Traditional Solutions Using the Low Load Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
HUELO Huelo 74A/Huelo Reliability (back-tie) 2023 Upgrade substation transformer
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APPENDIX E – LOCATION-BASED
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Lana‘i
There are no grid needs for Lānaʻi in the Low Load Scenario.
Moloka‘i
There are no grid needs for Moloka‘i in the Low Load Scenario.
3.1.5 Fast Customer Technology Adoption Scenario
The grid needs by transformer and circuit identified by island using the Fast Customer Technology Adoption Scenario are provided in the following tables.
O‘ahu
Table 3-14: O‘ahu Grid Needs and Traditional Solutions Using the Fast Scenario – Normal Condition
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
CEIP 2 CEIP 3 Capacity 2025 New switch
KEWALO T3 KEWALO 7 Capacity 2026 New circuits
KEWALO T3 N/A Capacity 2027 New substation transformer
WAHIAWA 3 (138kV) N/A Capacity 2026 New substation transformer and circuit
WAIAU A N/A Capacity 2030 New substation transformer and circuit
WAIAU A WAIAU-MILILANI Capacity 2029 New substation transformer and circuit
WAIPIO 1 N/A Capacity 2026 New substation transformer
WAIPIO 1 WAIPIO 1 Capacity 2027 New circuit
WAIPIO 1 WAIPIO 2 Capacity 2026 New circuit
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Table 3-15: O‘ahu Grid Needs and Traditional Solutions Using the Fast Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
CEIP 2 CEIP 3 Reliability 2027 Circuit line extension
CEIP 3 CEIP 46 Reliability 2027 Reconductor
IWILEI T3 IWILEI 9 Reliability 2027 Reconductor
KAMOKILA 2 N/A Reliability 2023 New circuits
KAPOLEI 2 KAPOLEI 4 Reliability 2026 Circuit line extension
KEWALO T3 KEWALO 7 Reliability 2026 Circuit line extension
KEWALO T3 N/A Reliability 2027 New circuits
KUILIMA 2 N/A Reliability 2027 New substation transformer
WAHIAWA 3 (138kV) N/A Reliability 2029 New substation transformer
WAHIAWA 3 (138kV) WAHIAWA-WAIMANO Reliability 2029 New substation transformer and circuit
WAIAU A N/A Reliability 2026 New substation transformer and circuit
WAIAU A WAIAU-MILILANI Reliability 2024 Split bus
WAIAU B N/A Reliability 2028 New substation transformer and circuit
WAIPIO 1 N/A Reliability 2024 Split bus
WAIPIO 1 WAIPIO 1 Reliability 2024 New substation transformer
WAIPIO 1 WAIPIO 2 Reliability 2026 New circuit
WAIPIO 2 N/A Reliability 2026 New circuit
WAIPIO 2 WAIPIO 3 Reliability 2024 New substation transformer
WAIPIO 2 WAIPIO 4 Reliability 2026 New circuit
Hawai‘i Island
There are no grid needs identified for Hawai‘i Island in the Fast Scenario under normal condition.
Table 3-16: Hawai‘i Island Grid Needs and Traditional Solutions Using the Fast Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
HALAULA HALAULA 2 Reliability (back-tie) 2023 New switch and recircuiting
HONOMU HONOMU 1 Reliability (back-tie) 2023 Voltage conversion and tie
OOKALA OOKALA 11 Reliability (back-tie) 2023 Voltage conversion and tie
WAIKOLOA N/A Reliability 2030 New circuit and tie
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APPENDIX E – LOCATION-BASED
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Maui Island
There are no grid needs identified for Maui in the Fast Scenario under normal condition.
Table 3-17: Maui Island Grid Needs and Traditional Solutions Using the Fast Scenario – Contingency Condition (N-1)
Substation Transformer Circuit Distribution Service Required
Operating Date Traditional Solution
HUELO Huelo 74A/Huelo Reliability (back-tie) 2023 Upgrade substation transformer
Lana‘i
There are no grid needs for Lānaʻi in the Fast Scenario.
Moloka‘i
There are no grid needs for Moloka‘i in the Fast Scenario.
3.1.6 Traditional Solutions Summary
The traditional solutions listed above in Sections 3.1.2 through Section 3.1.5 include one solution for
each circuit and transformer with a grid need. However, there are situations where a traditional solution
is a common solution that could solve multiple grid needs simultaneously.
For example, in Table 3-2 and Table 3-3, a new circuit is identified as a solution for the Waipio 1 circuit under normal condition in year 2027 and for the Waipio 3 circuit under contingency condition in year 2026. Each new circuit has a cost estimate of approximately $2.9M. If a new circuit is installed in the
area to mitigate the Waipio 3 contingency overload, which occurs in the earlier year, that new circuit
would also solve the overload projected for Waipio 1 circuit.
The list of traditional solutions was reviewed for any situations where mitigation would provide a common solution. This resulted in a shorter list of resulting wires projects (i.e. minimum wires solutions).
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DISTRIBUTION GRID NEEDS
Table 3-18: Minimum Grid Needs Solutions Identified
Island Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load) Scenario 4 (Fast Adoption)
O‘ahu 12 25 10 14
Hawai‘i Island 3 3 3 4
Maui 1 1 1 1
Lānaʻi - - - -
Moloka‘i - - - -
Total 16 29 14 19
The total cost of distribution upgrades needed for the minimum wires solutions is summarized below.24
Table 3-19: Minimum Grid Needs Solutions Identified – Cost Summary (Wires Solutions)
Island Scenario 1 (Base) Scenario 2 (High Load) Scenario 3 (Low Load) Scenario 4 (Fast Adoption)
O‘ahu $47,173,000 $67,576,000 $48,201,000 $56,103,000
Hawai‘i Island $2,680,000 $2,680,000 $2,680,000 $3,153,000
Maui $63,000 $63,000 $63,000 $63,000
Lānaʻi - - - -
Moloka‘i - - - -
Total $49,916,000 $70,319,000 $50,944,000 $59,319,000
3.1.7 Base Scenario Summary
The minimum wires solutions by island using the Base Scenario are provided in the following tables.
O‘ahu
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) CEIP 46 – Circuit Upgrade CEIP 3 CEIP 46 2025 Reconductor $3,930,000
Iwilei – New Circuits (25 KV) IWILEI T3 IWILEI 9 2023 New circuits $3,960,000
Kamokila 2 – Line Extension KAMOKILA 2 N/A 2027 Circuit Line Extension $1,913,740
24 Cost estimates were prepared in Q4 2022 and will be updated as more detailed engineering design is completed.
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Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) Kapolei 4 – Line Extension KAPOLEI 2 KAPOLEI 4 2026 Circuit Line Extension $2,091,012
Kewalo – New Transformer and Circuits (25 KV)
KEWALO T3 KEWALO 7 2026 New circuits $4,865,000
KEWALO T3 N/A 2027 New substation transformer
$6,404,000
Kuilima – Transformer Upgrade
KUILIMA 2 N/A 2028 Upgrade substation transformer
$3,160,000
Ewa Nui – New Transformer and Circuits
WAHIAWA 3 (138kV) WAHIAWA-WAIMANO 2026 New substation transformer and circuits
$15,012,000 WAIAU A N/A 2024
Waipio – New Transformer and Circuits
WAIPIO 1 N/A 2025 New substation transformer
$2,880,000
WAIPIO 1 WAIPIO 1 2027 New circuit $2,957,000 WAIPIO 1 WAIPIO 2 2026
Total $47,173,000
Hawai‘i Island
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $)
Halaula – Recircuiting
HALAULA HALAULA 2 2023 New switch and recircuiting
$65,000
Honomu – Voltage Conversion
HONOMU HONOMU 1 2023 Voltage conversion and tie
$999,000
Ookala – Voltage Conversion
OOKALA OOKALA 11 2023 Voltage conversion and tie
$1,616,000
Total $2,680,000
Maui Island
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) Huelo – Transformer Upgrade
HUELO Huelo 74A/Huelo 2023 Upgrade substation transformer
$63,000
Total $63,000
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DISTRIBUTION GRID NEEDS
Lana‘i
There are no grid needs for Lānaʻi in the Base Scenario.
Moloka‘i
There are no grid needs for Moloka‘i in the Base Scenario.
3.1.8 High Load Customer Technology Adoption Bookend Scenario
Summary
The minimum wires solutions by island using the High Load Customer Technology Adoption Bookend
Scenario are provided in the following tables.
O‘ahu
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) CEIP 3 – Line Extension CEIP 2 CEIP 3 2028 Circuit line extension $5,072,000
CEIP 46 – Circuit Upgrade CEIP 3 CEIP 46 2023 Reconductor $3,930,000
Ewa Nui 1 – Line Extension EWA NUI 1 EWA NUI 1 2029 Circuit line extension $149,000
Ewa Nui – New Transformer and Circuits
EWA NUI 2 EWA NUI 2 2025 New substation transformer and circuit
$3,634,000
Fort Weaver – New Transformer and Circuits
FORT WEAVER 1 FORT WEAVER 2 2028 New circuit $1,109,000
FORT WEAVER 1 N/A 2028 New substation transformer
$3,160,000
Hauula – Circuit Upgrade HAUULA HAUULA 2028 Reconductor $780,000
Hoaeae 1 – Circuit Upgrade HOAEAE 1 HOAEAE 1 2029 New switch $25,000
Iwilei - New Circuits (25 KV) IWILEI T3 IWILEI 9 2023 New circuits $3,960,000
Kahuku – Circuit Upgrade KAHUKU KAHUKU 2028 Reconductor $187,000
Kamokila 2 – Line Extension KAMOKILA 2 N/A 2025 Circuit line extension $2,480,000
Heeia – Load Transfer KANEOHE 1 HEEIA 2029 Transfer load $26,000
Kapolei – New Transformer and Circuits
KAPOLEI 2 KAPOLEI 4 2025 New substation $3,684,000
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APPENDIX E – LOCATION-BASED
DISTRIBUTION GRID NEEDS
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) transformer and circuit
Kewalo - New Transformer and Circuits (25 KV)
KEWALO T3 KEWALO 7 2026 New circuits $4,865,000
KEWALO T3 N/A 2027 New substation transformer
$6,404,000
Kuilima – New Transformer
KUILIMA 2 N/A 2026 New substation transformer
$2,970,000
Kunia Makai – Circuit Upgrade
KUNIA MAKAI 1 N/A 2028 New switch and transfer load
$26,000
Makaha 2 – Circuit Upgrade MAKAHA 2 N/A 2030 New switch $26,000
Heights – Circuit Upgrade
PUUNUI 2 HEIGHTS 2029 Reconductor, voltage regulator, and fuse resizing
$473,000
Ewa Nui – New Transformer and Circuits (46kV)
WAHIAWA 3 (138kV) WAHIAWA-WAIMANO 2025 New substation transformer and circuit
$15,012,000
Kaena PT – Circuit Upgrade WAIALUA 2 KAENA PT 2023 Reconductor $17,000
Waiau – Bus Upgrade WAIAU A N/A 2024 Split bus $965,000
Waipio – New Transformer and Circuits
WAIPIO 1 N/A 2024 New substation transformer
$2,790,000
WAIPIO 1 WAIPIO 1 2026 New circuit $2,916,000
WAIPIO 1 WAIPIO 2 2026 New circuit $2,916,000
Total $67,576,000
Hawai‘i Island
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $)
Halaula 2 – Circuit Upgrade
HALAULA HALAULA 2 2023 New switch and recircuiting
$65,000
Honomu 1 – Circuit Upgrade
HONOMU HONOMU 1 2023 Voltage conversion and tie
$999,000
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APPENDIX E – LOCATION-BASED
DISTRIBUTION GRID NEEDS
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $)
Ookala 11 – Circuit Upgrade
OOKALA OOKALA 11 2023 Voltage conversion and tie
$1,616,000
Total $2,680,000
Maui Island
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) Huelo – Transformer Upgrade
HUELO Huelo 74A/Huelo 2023 Upgrade substation transformer
$63,000
Total $63,000
Lana‘i
There are no grid needs for Lānaʻi in the High Load Scenario.
Moloka‘i
There are no grid needs for Moloka‘i in the High Load Scenario.
3.1.9 Low Load Customer Technology Adoption Bookend Scenario
Summary
The minimum wires solutions by island using the Low Load Customer Technology Adoption Bookend Scenario are provided in the following tables.
O‘ahu
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) CEIP 3 – Line Extension CEIP 2 CEIP 3 2028 Circuit line extension $5,072,000
Iwilei – New Circuits (25 KV) IWILEI T3 IWILEI 9 2023 New circuits $3,960,000
Kewalo – New Transformer and Circuits (25 KV)
KEWALO T3 KEWALO 7 2026 New circuits $4,865,000
KEWALO T3 N/A 2027 New substation transformer
$6,404,000
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APPENDIX E – LOCATION-BASED
DISTRIBUTION GRID NEEDS
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $)
Kuilima – New Transformer
KUILIMA 2 N/A 2029 New substation transformer
$3,260,000
Ewa Nui – New Transformer and Circuits (46kV)
WAHIAWA 3 (138kV) N/A 2028 New substation transformer and circuit
$15,012,000
Waiau – Bus Upgrade WAIAU A N/A 2024 Split bus $965,000
Waipio – New Transformer and Circuits
WAIPIO 1 N/A 2024 New substation transformer
$2,790,000
WAIPIO 1 WAIPIO 1 2026 New circuit $2,916,000
WAIPIO 1 WAIPIO 2 2027 New circuit $2,957,000
Total $48,201,000
Hawai‘i Island
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $)
Halaula 2 – Circuit Upgrade
HALAULA HALAULA 2 2023 New switch and recircuiting
$65,000
Honomu 1 – Circuit Upgrade
HONOMU HONOMU 1 2023 Voltage conversion and tie
$999,000
Ookala 11 – Circuit Upgrade
OOKALA OOKALA 11 2023 Voltage conversion and tie
$1,616,000
Total $2,680,000
Maui Island
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) Huelo – Transformer Upgrade
HUELO Huelo 74A/Huelo 2023 Upgrade substation transformer
$63,000
Total $63,000
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APPENDIX E – LOCATION-BASED
DISTRIBUTION GRID NEEDS
Lāna‘i
There are no grid needs for Lānaʻi in the Low Load Scenario.
Moloka‘i
There are no grid needs for Moloka‘i in the Low Load Scenario.
3.1.10 Fast Customer Technology Adoption Bookend Scenario Summary
The minimum wires solutions by island using the Fast Customer Technology Adoption Bookend
Scenario are provided in the following tables.
O‘ahu
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) Industrial – Line Extension BARBERS PT TANK FARM 2 INDUSTRIAL 2027 Circuit line extension $5,072,000
CEIP 3 – Circuit Upgrade CEIP 2 CEIP 3 2025 New switch $23,000
CEIP 46 – Circuit Upgrade CEIP 3 CEIP 46 2027 Reconductor $3,930,000
Iwilei - New Circuits (25 KV) IWILEI T3 IWILEI 9 2023 New circuits $3,960,000
Kamokila 2 – Line Extension KAMOKILA 2 N/A 2026 Circuit line extension $1,858,000
Kapolei 4 – Line Extension KAPOLEI 2 KAPOLEI 4 2026 Circuit line extension $2,091,000
Kewalo – New Transformer and Circuits (25 KV)
KEWALO T3 KEWALO 7 2026 New circuits $4,865,000
KEWALO T3 N/A 2027 New substation transformer $6,404,000
Kuilima – New Transformer KUILIMA 2 N/A 2029 New substation transformer $3,260,000
Ewa Nui – New Transformer and Circuits (46kV)
WAHIAWA 3 (138kV) N/A 2026 New substation transformer and circuit
$15,012,000
Waiau – Bus Upgrade WAIAU A N/A 2024 Split bus $965,000
Waipio – New Transformer and Circuits
WAIPIO 1 N/A 2024 New substation transformer $2,790,000
WAIPIO 1 WAIPIO 1 2026 New circuit $2,916,000 WAIPIO 1 WAIPIO 2 2026 New circuit $2,957,000
Total $56,103,000
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APPENDIX E – LOCATION-BASED
DISTRIBUTION GRID NEEDS
Hawai‘i Island
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $)
Halaula 2 – Circuit Upgrade
HALAULA HALAULA 2 2023 New switch and recircuiting
$65,000
Honomu 1 – Circuit Upgrade
HONOMU HONOMU 1 2023 Voltage conversion and tie
$999,000
Ookala 11 – Circuit Upgrade
OOKALA OOKALA 11 2023 Voltage conversion and tie
$1,616,000
Waikoloa – New Circuit WAIKOLOA N/A 2030 New circuit and tie $473,000
Total $3,153,000
Maui Island
Project Substation Transformer Circuit Operating Date Traditional Solution Cost Estimate (Nominal $) Huelo – Transformer Upgrade
HUELO Huelo 74A/Huelo 2023 Upgrade substation transformer
$63,000
Total $63,000
Lana‘i
There are no grid needs for Lānaʻi in the Fast Scenario.
Moloka‘i
There are no grid needs for Moloka‘i in the Fast Scenario.
3.2 Hourly Grid Needs
For the grid needs identified earlier in Section 3.1.2 through Section 3.1.5, solution requirements are
defined in technology-neutral terms (e.g., amounts of energy, time(s) of day, and days of the year). The hourly grid needs summary includes:
• Substation: Transformer asset identification
• Circuit: Feeder asset identification
• Capacity: Amount of power required to mitigate the grid need
• Energy: Amount of energy required to mitigate the grid need
• Delivery Time Frame: Months/hours when the planning criteria violations occur
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APPENDIX E – LOCATION-BASED
DISTRIBUTION GRID NEEDS
• Duration: Length of time of the grid need
• Maximum Number of Calls Per Year: Maximum number of days in the year requiring mitigation.
A complete list of the hourly grid needs for each circuit and transformer is available in the Distribution Grid Needs Workbook.25 An example of the data provided in the workbook is explained below.
3.2.1 Hourly Grid Needs Example
Hourly overloads identified in each year are aggregated and the corresponding grid needs are shown in
the following tables. The Kewalo 7 circuit has a forecasted capacity (MW) need from year 2026 through
2030. The need ranges from about 2 MW starting in year 2026 and grows to about 17.5 MW in years 2027 through 2030.
Table 3-20: Kewalo 7 Capacity Need (kW)
Circuit Equipment Rating (MVA)
Demand Forecast by Circuit (MW) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Kewalo 7 17.0 0 0 0 0 0 2.039 17.57 17.711 17.682 17.651
The corresponding energy need (MWh) for years when the circuit is overloaded is shown below.
Table 3-21: Kewalo 7 Circuit Energy Need (MWh)
Circuit Equipment Rating (MVA) Demand Forecast by Circuit (MWh) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Kewalo 7 17.0 0 0 0 0 0 3.3 166.6 168.5 168.1 167.7
The number of hours each year when the circuit is overloaded is shown below.
Table 3-22: Kewalo 7 Circuit Need (Hours)
Circuit Equipment Rating (MVA)
Demand Forecast by Circuit (Hours) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Kewalo 7 17.0 0 0 0 0 0 5 19 19 19 19
The maximum number of calls each year is shown below.
Table 3-23: Kewalo 7 Circuit Maximum Number of Calls Per Year
Circuit Equipment Rating (MVA) Maximum Number of Calls Per Year 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Kewalo 7 17.0 0 0 0 0 0 34 365 365 365 365
25 The hourly grid needs are voluminous and therefore not provided in this report in table format. The complete list of distribution grid needs is available on the Company website in an Excel workbook. See Section 5.
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DISTRIBUTION GRID NEEDS
4 Summary and Next
Steps
Using the location-based forecasts for substation transformers and primary distribution circuits, grid
needs to serve load growth through year 2030 are identified in this analysis. During this process, 351
substation transformers and 645 circuits were assessed across all five islands and less than 5% have grid needs identified. A summary of the grid needs by scenario are shown below. This list includes
Table 4-1: Grid Needs Summary
Scenario Description Total Grid Needs (All Islands) Total Cost ($)
1 Base 16 $49.9 M
2 High Load Customer Technology Adoption 29 $70.3 M
3 Low Load Customer Technology Adoption 14 $50.9 M
4 Fast Customer Technology Adoption 19 $59.3 M
Consistent with the Non-Wires Opportunity Evaluation Methodology, cost estimates are developed for
traditional wires solutions identified to solve distribution grid needs. These estimates will be used as an input to evaluate if the grid need may qualify as a favorable NWA opportunity, and if so, be procured as part of the overarching IGP process where a portfolio of solutions will be selected to address the identified grid needs.
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APPENDIX E – LOCATION-BASED
DISTRIBUTION GRID NEEDS
5 Workbook Index
The grid needs assessment, hourly grid needs, and revised location-based forecasts for each scenario by
island are available on the Company’s website in Excel workbooks as the tables are too voluminous to
provide in table format herein.26
A summary of the workbooks is provided below.
Table 5-1: Location-Based Distribution Grid Needs Workbook Index27
No. Workbook28 1 Location-Based Grid Needs (EXCEL)
Table 5-2: November 2021 Forecast Update Workbook Index
Island No. Scenario Workbook29 O‘ahu 1 Base Oahu Location-Based Forecasts Scenario 1 (EXCEL)
2 High Load Customer Technology Adoption Bookend Oahu Location-Based Forecasts Scenario 2 (EXCEL)
3 Low Load Customer Technology Adoption Bookend Oahu Location-Based Forecasts Scenario 3 (EXCEL)
4 Fast Customer Technology Adoption Oahu Location-Based Forecasts Scenario 4 (EXCEL) Hawai‘i Island 1 Base Hawaii Island Location-Based Forecasts Scenario 1 (EXCEL)
2 High Load Customer Technology Adoption Bookend Hawaii Island Location-Based Forecasts Scenario 2 (EXCEL)
26 See https://www.hawaiianelectric.com/clean-energy-hawaii/integrated-grid-planning/stakeholder-and-community-engagement/key-stakeholder-documents
27 Includes grid needs assessment and hourly grid needs.
28 File name as it appears on the Company website.
29 File name as it appears on the Company website.
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Island No. Scenario Workbook29
3 Low Load Customer Technology Adoption Bookend Hawaii Island Location-Based Forecasts Scenario 3 (EXCEL)
4 Fast Customer Technology Adoption Hawaii Island Location-Based Forecasts Scenario 4 (EXCEL)
Maui Island 1 Base Maui Location-Based Forecasts Scenario 1 (EXCEL)
2 High Load Customer Technology Adoption Bookend Maui Location-Based Forecasts Scenario 2 (EXCEL)
3 Low Load Customer Technology Adoption Bookend Maui Location-Based Forecasts Scenario 3 (EXCEL) 4 Fast Customer Technology Adoption Maui Location-Based Forecasts Scenario 4 (EXCEL)
Lānaʻi 1 Base Lanai Location-Based Forecasts Scenario 1 (EXCEL)
2 High Load Customer Technology Adoption Bookend Lanai Location-Based Forecasts Scenario 2 (EXCEL)
3 Low Load Customer Technology Adoption Bookend Lanai Location-Based Forecasts Scenario 3 (EXCEL)
4 Fast Customer Technology Adoption Lanai Location-Based Forecasts Scenario 4 (EXCEL) Moloka‘i 1 Base Molokai Location-Based Forecasts Scenario 1 (EXCEL)
2 High Load Customer Technology Adoption Bookend Molokai Location-Based Forecasts Scenario 2 (EXCEL)
3 Low Load Customer Technology Adoption Bookend Molokai Location-Based Forecasts Scenario 3 (EXCEL)
4 Fast Customer Technology Adoption Molokai Location-Based Forecasts Scenario 4 (EXCEL)
Appendix F:
NWA Opportunity Evaluation
Methodology
Hawaiian Electric
Non-Wires Opportunity Evaluation
Methodology
March 2023 Update
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Contents
Appendix F: NWA Opportunity Evaluation Methodology........................................................................................................................................... i 1 Introduction ................................................................................................................................................................................ 3 1.1 Industry Survey ................................................................................................................................................................................................................ 5 1.1.1 Industry Survey Findings ................................................................................................................................................................................. 6 1.1.2 Stakeholder Feedback ...................................................................................................................................................................................... 9 1.2 T&D Non-Wires Alternatives ................................................................................................................................................................................... 11 1.2.1 NWA Definition ................................................................................................................................................................................................. 11 1.2.2 NWA Grid Services .......................................................................................................................................................................................... 11 1.2.3 T&D Capacity Deferral ................................................................................................................................................................................... 12 1.2.4 Distribution Reliability (Back-Tie) .............................................................................................................................................................. 12 1.3 NWA Opportunity Evaluation Methodology .................................................................................................................................................... 13 1.3.1 Overview .............................................................................................................................................................................................................. 13 1.3.2 Opportunity Evaluation Methodology .................................................................................................................................................... 14 1.4 Case Examples ............................................................................................................................................................................................................... 24 1.4.1 Step 1: NWA Opportunity Screen ............................................................................................................................................................. 24 1.4.2 Step 2: NWA Opportunity Sourcing Evaluation .................................................................................................................................. 27 1.4.3 Step 3: Action Plan .......................................................................................................................................................................................... 32
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
1 Introduction
As it strives to provide 100 percent renewable energy by 2045, Hawaiian Electric (Company) faces a
comprehensive transformation of our five electric power grids. Attaining our state’s renewable energy
goals represents uncharted territory for both short-term and long-term resource planning. Performing the analyses necessary to attain this goal is a complicated resource planning process, requiring new tools and new processes. This report defines and explains the methodology involved in evaluating grid needs as possible non-wires alternatives opportunities. This process is essential to support the
transformation to a clean energy future that leverages the continuous advancement in power
technology.
The Company believes customers should have opportunities to deliver energy and other services to the electrical distribution system (commonly referred to as the distribution grid). In addition, the Company believes it should enable significant numbers of diverse providers to participate, and should facilitate
competition to the benefit of all customers. By using a broad definition of distributed energy resources
(DER), which include a variety of asset types, the Company is providing an increasing number of customers with the opportunity to participate in the DER marketplace. Expanding opportunities for DER services is essential to meeting renewable energy needs without sacrificing the reliable delivery of
electricity, which customers deem a top priority.
This strategy is consistent with the Commission’s direction to fully and fairly consider non-transmission
alternatives (NTA) and non-distribution alternatives (NDA), otherwise known as non-wires alternatives (NWA), when evaluating transmission and distribution (T&D) system upgrades.1 The Commission also indicated that it will scrutinize whether NWA “solutions, regardless of ownership, are evaluated as part
of any economic justification for new utility distribution system investment projects in the same fashion
as it currently evaluates NTAs with respect to new transmission projects.”2
In 2019, the Commission reiterated its expectation that the distribution planning process “must transition and evolve accordingly, such that the locational benefits of customer-sited distributed energy resources are included and evaluated on a comparable basis as utility-sited NDAs as part of any
economic justification for distribution system upgrades.3 The Commission further directed the Company
to “strive to make their non-wires alternatives analysis more transparent and thorough.”4
1 HPUC Docket No. 2018-0055, Decision and Order No. 36288 Ka'aahi Substation, filed May 3, 2019, at 22.
2 HPUC Docket No. 2015-0070, Decision and Order No. 33584, filed March 11, 2016, at 46.
3 HPUC Docket No. 2018-0055, Decision and Order No. 36288 Ka'aahi Substation, filed May 3, 2019, at 22.
4 HPUC Order No. 36725 Docket No. 2018-0165, Proceeding To Investigate Integrated Grid Planning, filed November 4, 2019, at 9.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Additionally, the Company is expanding options for broad DER participation necessary to grow a viable
market, and for customers to directly benefit from competition. The Company’s strategy is to offer a
range of proven and innovative options to expand access for all customers—not just for a few.
This approach recognizes that the market for NWAs is nascent but represents a tangible opportunity for reducing customer costs and enabling a lower-carbon electricity grid.5 As such, procurements may not
fully enable a range of DER-based solutions. The Company’s approach to NWAs specifically includes consideration of pricing through customer rates and programs in addition to procurement opportunities. This will enable customers to better manage their electricity use and provide grid services. As a result, the Company believes that customers, DER developers, and aggregators will have
the potential to fully realize the value of DER for Hawai‘i.
The Company has engaged, and will continue to engage, with customers and stakeholders to seek input and feedback on the Integrated Grid Planning (IGP) development and subsequent planning and sourcing. As part of the IGP development effort, the Distribution Planning Working Group (DPWG) is to inform and educate stakeholders on various aspects of distribution planning at the Company, and to
afford stakeholders opportunities to collaborate on and co-develop the Company’s methodologies to
identify distribution grid needs as well as a framework to evaluate NWA opportunities. As described in the Distribution Planning Methodology report, grid needs will be identified through the distribution planning process and then evaluated for NWA opportunity suitability as discussed in this Non-Wires
Opportunity Evaluation Methodology report.
The DPWG deliverables, as described in the IGP Workplan accepted by the Commission,6 include
identifying NWA opportunities and the related information requirements to effectively and efficiently procure and evaluate potential solutions. However, the need for an NWA opportunity evaluation
methodology was not identified in the original IGP Workplan.7 The Company and stakeholders
subsequently recognized the need to incorporate a screening process, based on the leading industry practices and practical considerations, into the IGP and annual distribution planning cycles. This Non-
Wires Opportunity Evaluation Methodology report addresses this additional scope and deliverable
discussed by the DPWG.
Specifically, this Non-Wires Opportunity Evaluation Methodology report discusses the Company’s industry survey and stakeholder feedback on best practices for NWA opportunity evaluation and sourcing, defines NWAs and grid services, presents the Company’s NWA opportunity evaluation
methodology, and provides case examples that the Company and stakeholders used to jointly validate
the proposed NWA opportunity evaluation methodology. Two of the case examples were used in the Company’s IGP Soft Launch, which was conducted to demonstrate the distribution planning process
5 M. Dyson, J. Prince, et al., “The Non-Wires Solutions Implementation Playbook,” Rocky Mountain Institute, 2018.
6 HPUC Order No. 36218, Accepting the IGP Workplan and Providing Guidance, Docket No. 2018-0165.
7 HECO, IGP Workplan, December 2018 filed December 14, 2018 in HPUC Docket No. 2018-0165 https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/dkt_20180165_20181214_igp_workplan.pdf.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
from circuit-level load forecasting to solution evaluation to defer an actual capital investment to solve a
grid need. The two examples used in the soft launch were the Ho`opili and East Kapolei cases, later
described in Section 5.3. Through that effort, the Company gained invaluable experience that will help improve the full-scale IGP planning and sourcing effort. This report reflects a key milestone in the Company’s efforts to comply with the Commission’s guidance regarding systematic and transparent consideration of NWAs, leveraging industry best practices, and stakeholder engagement.8
March 2023 update. This Non-Wires Opportunity Evaluation Methodology is being submitted with the IGP Grid Needs Assessment and Solution Evaluation Methodology (Dkt. No. 2018-0165, dated March 31, 2023) and supersedes previously filed versions. This update incorporates the Company’s
learnings from recent NWA activities, as well as discussions with the IGP TAP. Notable updates include
1) additional definition to the NWA sourcing evaluation (Section 1.3.2) to classify whether potential solutions are considered favorable, moderate, or unfavorable across the various dimensions, and 2) additional case examples of experiences with the NWA process (Section 1.4).
1.1 Industry Survey
In 2019, the Company engaged the Pacific Energy Institute to conduct an industry survey9 of best
practices for NWA opportunity evaluation and sourcing in seven states (including California, Connecticut, Hawaii, Maine, New Hampshire, New York, and Rhode Island) as well as to review documents prepared by several organizations, including Rocky Mountain Institute (RMI),10 Northeast
Energy Efficiency Partnerships,11 Smart Electric Power Alliance (SEPA),12 and ICF.13 Additionally, an NWA
workshop was held on March 26, 2019,14 where the Company sought to learn from experienced
practitioners (that is, utility and DER solution providers). The industry survey findings are summarized in Section 2.1.
The Company also held 10 stakeholder working group meetings in 2019 where stakeholders discussed
NWA services definitions, distribution grid needs identification, NWA opportunity evaluation, and information requirements. Stakeholder feedback is summarized in Section 2.2.
8 HPUC Order No. 33584, Maui Elec. Co., Ltd., Docket No. 2015-0070, filed March 11, 2016, at 45-46, and HPUC Order No. 36288, Ka'aahi Substation application, Docket No. 2018-0055, at 22-25.
9 P. De Martini and A. De Martini, NWA Opportunity Evaluation Survey of Current Practice, Pacific Energy Institute, March 2020.
10 M. Dyson, J. Prince, et al., “The Non-Wires Solutions Implementation Playbook,” Rocky Mountain Institute, 2018..
11 Northeast Energy Efficiency Partnerships, State Leadership Driving Non-Wires Alternatives Projects and Policy, 2017.
12 SEPA, PLMA and E4The Future, Non-Wires Alternatives: Case Studies From Leading U.S. Projects, November 2018.
13 ICF presentation in Michigan PSC workshop, June 2019 https://www.michigan.gov/documents/mpsc/062719_PDF_Presentations_660616_7.pdf.
14 IGP Soft Launch WG Meeting speaker presentations: https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/soft_launch/20190326_igp_soft_launch_wg_meeting_presentation_materials.pdf.
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1.1.1 Industry Survey Findings
Based on the industry survey and observations of industry analysts, the use of NWAs for distribution grid needs is at an early stage. The industry is still learning and refining approaches to improve on the early mixed success to-date.15 However, commonalities are emerging from these early states’ and
utilities’ lessons learned that provide valuable insights for Hawai‘i’s success.
The Company has considered the following key findings from this survey in the development of its NWA opportunity evaluation process:
The NWA opportunity evaluation should be integrated into standard, open, and transparent utility
planning processes to encourage the effective engagement of market participants to best meet regulatory and utility-level objectives.16
Traditional (T&D) planning processes can better support NWA solutions if screening criteria are used to
determine when alternatives should be considered for a given need.
Information should be shared with stakeholders regarding an NWA opportunity, including engineering analysis, performance requirements, and other data needed to assess the opportunity.
Evaluation of opportunities is done on a technology agnostic, comparable basis as part of the economic
justification for distribution system upgrades.17
Evaluation processes focus on identifying high-confidence recommendations for DER solicitations that are likely to result in successful, cost-effective investment deferrals.18
NWA opportunities to date have initially addressed grid needs for capacity increases.
Reliability, voltage/reactive power, and resilience have been identified for future consideration.
The type of T&D need, time frame for in-service date, and reference T&D project cost are common
criteria used by all states surveyed to evaluate NWA opportunities.
Not all T&D capital projects are suited for an NWA opportunity. T&D capital projects involving break-
fix, outage replacements, aging infrastructure replacement, infrastructure relocation, or customer service connections should be excluded.
Procurements may not be best suited for all NWA opportunities (for example, smaller value projects
and/or reaching certain customer classes), instead other programmatic options may be considered,
such as:
15 Reported California initial NWA procurement results and ICF 2019.
16 M. Dyson, J. Prince, et al., “The Non-Wires Solutions Implementation Playbook,” Rocky Mountain Institute, 2018and SEPA, PLMA and E4The Future, 2018.
17 HPUC Order No. 36725 Docket No. 2018-0165, Proceeding To Investigate Integrated Grid Planning.
18 CPUC Decision on the Distribution Investment and Deferral Process (D.18-02-004).
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Targeted energy efficiency (EE)/demand-side management programs are employed.
DER services tariffs are under discussion in a few states.
States and utilities should first consider no-cost (capital) operational options (for example, circuit reconfiguration and phase balancing) as well as low-cost grid technology alternatives (for example, sensing and analytics, and power flow controllers) as an alternative to traditional capital projects.
Additionally, the survey identified several themes regarding the evaluation criteria. As noted above, the
type of T&D need, timing for in-service date, and reference T&D project cost are common criteria. The
type of grid needs and the related performance requirements are considered. The timing for in-service includes consideration of the procurement/program development process, regulatory approval, and implementation timelines. Project cost is based on the capital cost of the traditional wires project.
However, the application of these criteria differs among states and utilities. The states in the Northeast
have clearly defined the types of T&D projects that are suitable for NWA opportunities and have
defined minimum thresholds for timing and project cost. These minimums have been developed through stakeholder discussions and consideration of the timing in that state. An example is provided in Figure F-1.
Figure F-1: National Grid’s New York NWA Opportunity Evaluation Criteria
Like New York, as shown in Figure F-1, California also employs these three criteria and adds two:
forecast uncertainty of timing and scope, and market assessment. California’s evaluation is focused on whether an NWA procurement should be pursued and uses a tiered prioritization approach to identify the ripest opportunities (Tier 1), opportunities that may be less certain (Tier 2), and opportunities that
are not suitable for NWAs (Tier 3). This is illustrated in the Southern California Edison (SCE) example in
Figure F-2. As seen in other states, California utilities each have their own version of the criteria and a
slightly different prioritization tier structure.
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Figure F-2: SCE NWA Opportunity Prioritization
The California NWA evaluation methodology offers useful additional criteria to evaluate opportunities as compared to the states in the Northeast. However, the California methodology is overly complex in its attempt to quantify the metrics. In practice, California’s prioritization is effectively based on a smaller
set of factors similar to the northeastern states.19 That is, the T&D grid need requirements (including
timing), related grid service, and project-related avoided cost were used to determine whether a procurement makes sense. The California process is also singularly focused on evaluating procurement
opportunities, so it does not consider alternative sourcing options, such as programs.
The Company does think the use of the California metrics for forecast certainty and market assessment
are useful in the context of considering alternative NWA sourcing options involving programs and pricing, or reconsideration of procurement at a later date.
Based on the insights drawn from the industry survey and practitioners, simplicity and flexibility appear
to be important considerations in developing NWA opportunity evaluation criteria. Simplicity is
important in terms of the ability to implement a fair and repeatable process, and to provide clarity to the market. Flexibility is important in terms of allowing opportunities to pursue viable NWAs through sourcing means other than all-or-nothing procurements. For example, consideration should be given to the role that programmatic options may provide for opportunities that might otherwise not make sense
economically for a procurement. The Company has incorporated these findings into its approach.
19 See https://www.pge.com/en_US/for-our-business-partners/energy-supply/electric-rfo/wholesale-electric-power-procurement/2019-didf-rfo.page?ctx=large-business
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1.1.2 Stakeholder Feedback
As mentioned at the beginning of Section 2, the Company held 10 stakeholder working group meetings in 2019 where stakeholders discussed NWA services definitions, distribution grid needs identification, NWA opportunity evaluation, and information requirements. These discussions included the findings
from the industry survey and NWA workshop, discussed in Section 2.1. This stakeholder engagement
also included using specific grid needs in Ho‘opili and East Kapolei as case examples to shape the IGP Soft Launch.
Importantly, these discussions considered the development of the IGP methodology to identify and
assess NWA opportunities as a key step in the handoff from grid needs to NWA sourcing (for example,
procurements and programs). Stakeholders’ input and feedback is reflected in the NWA opportunity
evaluation process and criteria. The stakeholder feedback received in the DPWG and Soft Launch working group meetings is summarized in the following sections.20
The Company also presented the NWA Methodology along with more detailed evaluation threshold
criteria and additional sample evaluations to the Technical Advisory Panel (TAP) on November 16, 2022 and received generally positive feedback.
1.1.2.1 Overall Process
Stakeholders shared that the NWA opportunity evaluation process needs to be transparent and less
restrictive with respect to screening criteria at this initial stage in Hawai‘i to open up the potential
market for procurements. Stakeholders also shared that a technology agnostic approach to assessing opportunities is needed and that it is important to not prejudge what the market may provide.
Stakeholders support consideration of other sourcing mechanisms beyond procurement (programs, tariffs) and flexibility in sourcing to achieve the most cost-effective outcome. This includes the potential
to participate in multiple non-conflicting grid services opportunities. Additionally, the IGP process
should continue to reassess projects in subsequent planning cycles that are initially assessed as uncertain because of the constant changing nature of the distribution system. The T&D grid needs and NWA opportunity evaluations and supporting analysis should be shared publicly as part of the IGP process.
1.1.2.2 Defining Grid Needs
The output of the distribution planning process is a set of grid needs. Stakeholders should have sufficient information on these needs to consider potential solutions and understand the application of the evaluation criteria. This includes technical performance requirements, including quantity (MW,
MWh), dispatch frequency and time (month/day/hour), duration, and in-service date. The supporting
engineering analysis, and a description and technical details of the wires solution are also desired (for
20 Drawn from DPWG minutes: https://www.hawaiianelectric.com/clean-energy-hawaii/integrated-grid-planning/stakeholder-engagement/working-groups/distribution-planning-and-grid-services-documents
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example, information on type of infrastructure location, timing, and avoided cost). Stakeholders
suggested simplifying the requirements to the extent possible to allow for more potential NWA
solutions.
1.1.2.3 Opportunity Criteria
Stakeholders appreciate the simplicity of the three-criteria approach used by the states in the Northeast but also like aspects of the California prioritization model. Stakeholders suggested using clearly defined
metrics for minimum timing for in-service date and project economics criteria for procurements, as
follows:
■ Timing: in-service date – minimum of 2 years to provide enough time to run a procurement and
regulatory process, and install NWAs
■ Project economics: minimum of $1 million capital project cost threshold for NWA procurements
Stakeholders also suggested consideration of greenhouse gas emissions reductions and other societal criteria (for example, community impact) in prioritizing NWA opportunities. The question of whether to consider greenhouse gas emissions was not resolved in the working group discussion, but stakeholders recognized that greenhouse gas benefits are important, but not necessary, for NWA opportunity
sourcing evaluation. Stakeholders suggested that NWA societal value considerations may be better
suited to evaluating the specific proposed NWA solutions resulting from procurements/programs as is done in New York. The recommendation is for this issue to be taken up in the Solution Evaluation and Optimization Working Group.
1.1.2.4 Sourcing Options
Stakeholders noted that across the industry, NWAs have largely not been successful thus far.
Stakeholders recognize that procurements are one type of NWA sourcing mechanism and that programs and pricing options should be considered as well. A programmatic approach that looks to fulfill more global power system needs was suggested. Programs also may be easier for customers to understand. Stakeholders agree that an NWA program, as with procurements, must be cost-effective for
all customers.
During the Soft Launch discussion regarding Ho‘opili, stakeholders recognized the NWA procurement challenge for new real estate developments: that NWA solutions may need to be sited and ready to go at the same time the house is built. Stakeholders suggested that a programmatic approach (including EE and other DER) through the collaboration of the real estate developer and the Company may be the
best option.
Additionally, stakeholders seek to maximize the potential participation opportunities for NWAs and grid services in the aggregate. For example, a stakeholder shared that a $50,000 per year NWA opportunity may not be worth a procurement or program, but it may have potential after being aggregated with other potential grid services opportunities.
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1.2 T&D Non-Wires Alternatives
The definitions of NWA and grid services presented in this section, including the specific wording for
each of the terms, are derived from the industry research and stakeholder input and feedback discussed in Section 2.
1.2.1 NWA Definition
NWAs generally are non-traditional solutions that may defer, delay, or avoid traditional T&D investments (for example, a new substation or feeder). Non-traditional solutions can include a single solution or a combination of solutions at the grid-scale or distribution level, such as solar photovoltaic (PV), other renewable generation, energy storage, EE, and demand response (including price responsive
demand). The following NWA definition was developed in concert with the DPWG:
An electricity grid project that uses non-traditional transmission and distribution (T&D) solutions, such as distributed generation (DG), energy storage, energy efficiency (EE), demand response (DR), and grid software and controls, to defer or avoid the need for conventional transmission and/or distribution infrastructure investments.
This definition adapts several aspects developed by Navigant,21 the US Department of Energy,22 and
others.23
1.2.2 NWA Grid Services
A wide range of grid services are needed as Hawai‘i decarbonizes the electricity sector with ultimately more than half its resources at the edge of the system. Already, DERs have the opportunity to provide bulk system ancillary services, including frequency response, replacement reserves, and regulation on a technology agnostic basis.24 Additionally, in support of the IGP planning cycle and Commission
direction,25 the Company has identified and defined initial T&D NWA services in technology agnostic
terms, building on the work developed for the Demand Response portfolio in Docket No. 2015-0412.
An example of where the Company will apply the NWA evaluation process are the projects identified
though the distribution planning process, as described in the Distribution Planning Methodology report. Using the outline detailed in this report, these projects are candidates to be evaluated for NWA opportunity.
Specifically, these initial NWA services are focused on those with the greatest potential value involving
T&D capital deferral services (for example, distribution capacity deferral and reliability services). Capital
21 B. Feldman, Non-Wires Alternatives: What's up next in utility business model evolution, UtilityDive, July 12, 2017.
22 Electricity Advisory Committee, Recommendations on Non-Wires Solutions, US Department of Energy, October 17, 2012.
23 SEPA, PLMA & E4TheFuture, “Non-wires Alternatives: Case Studies from Leading US Projects”, 2018.
24 See Docket No. 2015-0412, Decision and Order No. 35238, issued on January 25, 2018.
25 HPUC Order No. 33584, Maui Elec. Co., Ltd., Docket No. 2015-0070, filed March 11, 2016, at 45-46.
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deferral is the primary focus of the Federal Energy Regulatory Commission for transmission26 and the
leading states’ use for distribution, as found in the industry survey discussed in Section 2.
The service descriptions and definitions in Sections 3.2.1 and 3.2.2 are based on IGP stakeholder input and feedback leveraging references from California’s Competitive Solicitation Working Group.27
1.2.3 T&D Capacity Deferral
T&D capacity deferral opportunities involve the potential to defer capital investment that may
otherwise be needed to address grid needs that are identified through area capacity analysis and/or
hosting capacity analysis. This may include deferring substations, new lines/reconductoring, transformers, and other equipment by reducing forecast loading of the infrastructure to within ampacity/load ratings under normal operating conditions. Loading in this context relates to the current
and/or power (bi-directional) carrying capability of specific conductor, transformer, and/or other
equipment. Therefore, increases in forecast loading may arise from new loads and/or energy injections
from distributed resources (that is, reverse power flow).
The following definition of T&D capacity service was developed with the DPWG to describe these types of opportunities:
A supply and/or a load modifying service that DERs provide as required via reduction or increase of power or load that is capable of reliably and consistently reducing net loading28 on desired transmission and/or distribution infrastructure. T&D capacity service can be provided by a single DER and/or an aggregated set of DERs that reduce the net loading on a specific distribution infrastructure location coincident with the identified operational need in response to a control signal from the utility. This definition combines both NTAs and NDAs into a single service in recognition of the potential to yield optimized benefits across T&D opportunities from NWA solutions.
1.2.4 Distribution Reliability (Back-Tie)
In addition to NWA opportunities under normal grid operating conditions, there are potential opportunities under contingent conditions. Contingent operating conditions involve emergency reconfigurations of the distribution system that result in transferring the load (that is, bi-directional
current/power) from one circuit/transformer to another to mitigate an outage. These contingent
opportunities arise when combined loading exceeds the emergency ampacity/power rating of the conductor, transformer, and/or other equipment. This is a reliability-oriented service because it enables
26 E. Watson and K. Colburn, Looking Beyond Transmission, Public Utilities Fortnightly, April 2013.
27 California Competitive Solicitations Framework Working Group https://drpwg.org/sample-page/ider/.
28 Net loading refers to the net amount of bi-direction current on specific grid infrastructure.
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safe transfer of one circuit/transformer’s load to another during an emergency by creating sufficient
headroom or reducing the transferring load to within emergency ratings.
The following definition of distribution reliability service was developed in the DPWG:
A supply and/or load modifying service capable of improving local distribution reliability under abnormal conditions. Specifically, this service reduces contingent loading of grid infrastructure to enable operational flexibility to safely and reliably reconfigure the distribution system to restore customers.
This type of distribution service is relatively new in the industry; the Company’s procurement for this service in the IGP Soft Launch was one of the first, if not the first. In a future IGP cycle, the Company
may evaluate a wider set of T&D NWA services. For example, voltage support and resiliency services
may be identified and defined through the process of documenting the T&D needs and services requirements. Resiliency services are currently being discussed in the Resiliency Working Group and through Docket No. 2018-0163, which is intended to produce a Microgrid Services Tariff.
1.3 NWA Opportunity Evaluation Methodology
1.3.1 Overview
The Company has considered the NWA opportunity evaluation approaches and lessons learned from
other states as well as stakeholder feedback to develop a holistic methodology. The multi-state lessons and stakeholder feedback support RMI’s recommendation that “traditional planning processes can better support non-wires solutions if screening criteria are used to determine when alternatives should be considered for a given need.”29
The Company intends to use such a common NWA opportunity evaluation framework to identify T&D projects that are most likely to be suitable for NWA solutions. This evaluation methodology is intended to provide greater clarity, certainty, and transparency to the market going forward. Such criteria
incorporated into the IGP process will also facilitate systematic consideration of NWAs by T&D planners
going forward as directed by the Commission. The goals of this NWA opportunity evaluation methodology are as follows:
■ Identify all potential candidate T&D projects that may be cost-effectively deferred through the identified and defined DER services.
■ Productively engage the market for NWAs by helping DER aggregators and developers efficiently
allocate resources to the best opportunities.
29 M. Dyson, J. Prince, et al., “The Non-Wires Solutions Implementation Playbook”, Rocky Mountain Institute, 2018.
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Further, Commission guidance and stakeholder feedback outlined the following objectives in the
development of an NWA opportunity evaluation framework:
■ Adopt/adapt leading practices to develop candidate T&D NWA opportunity evaluation.
■ During initial NWA opportunity screens, create over-inclusive, rather than overly restrictive, candidate
NWA project shortlists.
■ Use a simple initial NWA opportunity screen to identify shortlist candidate opportunities and assess sourcing options (procurement, programs, and pricing).
■ Remember that not all NWA opportunities make economic sense to source via competitive procurement. Therefore, price signals through rate design and DER programs will also be considered to achieve the most affordable solutions for customers.
These goals and objectives shaped the development of the NWA opportunity evaluation methodology described in Section 4.2. The Company believes that this opportunity screen and prioritization approach
will support development of an NWA market. Recognizing that NWA procurements and use are at a
relatively nascent stage of implementation across the industry, the Company expects this evaluation methodology to evolve as the industry collectively gains more NWA experience. This NWA opportunity evaluation methodology is not meant to be an NWA solution evaluation as would be done in a
procurement; rather this is an assessment of the potential T&D projects that qualify for an NWA
opportunity.
1.3.2 Opportunity Evaluation Methodology
The Company has developed a three-step methodology that incorporates 1) an initial NWA opportunity
screen, 2) an NWA opportunity sourcing evaluation and 3) an action plan. The initial opportunity screen is intended to quickly and simply identify “qualified” and “non-qualified” T&D opportunities based on technical requirements. The opportunity sourcing evaluation in the second step further evaluates and prioritizes the “qualified” opportunities in terms of the grid project avoided cost (economics), timing of
need, and performance requirements to support a procurement. This three-step approach, shown in
Figure F-3, is based on leading practices from states in the Northeast and from California as well as stakeholder feedback tailored to Hawai‘i’s needs.
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Figure F-3: NWA Opportunity Evaluation Methodology
This methodology is designed to identify a wider set of potential NWA opportunities than
methodologies in other states. Step 1 does not include a dollar threshold, unlike the states in the
Northeast; instead, program or pricing options may be considered viable in the Step 2 evaluation. The incorporation of program and pricing options in the Step 2 sourcing evaluation is for those opportunities considered too financially small for procurement. Step 2 methodology also includes a clearly defined minimum dollar threshold for procurements identified by stakeholders that is similar in
approach to that of the states in the Northeast. This is a more transparent method than the overly
complex California approach30,31 that also effectively uses the project capital avoided cost as the
primary economic threshold. The resulting T&D action plan in Step 3 is intended to enable a range of
potential NWA sourcing options via procurement, programs, and pricing consistent with another RMI
recommendation.32
1.3.2.1 Step 1: NWA Opportunity Screen
The intent of the NWA opportunity screen is to categorize all T&D capital budget projects by applying a
technical screen and to identify those T&D projects that are most suitable for further NWA opportunity
evaluation. As discussed with stakeholders and identified by other states, certain T&D projects with the greatest NWA opportunity include the following three grid needs categories:
1. Expanding distribution system capacity to meet load and/or hosting capacity needs (that is, new substation, new feeders, reconductoring)
2. Ensuring a reliability requirement for circuit back-tie upgrade deferral
3. Enhancing system resilience33
30 Pacific Gas & Electric, Request for Approval to Issue Competitive Solicitations for Distributed Energy Resource (DER) Procurement for Electric Distribution Deferral Opportunities. November 15, 2019. CPUC Advice Letter 5688-E.
31 Southern California Edison, Southern California Edison Company’s Request for Approval to Launch the 2020 Distribution Investment Deferral Framework, November 15, 2019 Solicitation. CPUC Advice Letter 4108-E.
32 M. Dyson, J. Prince, et al., “The Non-Wires Solutions Implementation Playbook”, Rocky Mountain Institute, 2018, page 39.
33 Reliability scoped to be redundant, such as a second feeder and its associated infrastructure, would be qualified opportunities. However, hardening, or physically strengthening critical infrastructure, would not be considered a qualified opportunity.
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As the Company has identified in the IGP, consistent with best industry practices, these types of T&D
needs may be met by new NWA grid services, including T&D capacity deferral service, reliability back-
tie service, and resiliency service. The Soft Launch pursued procurement of distribution capacity deferral and reliability back-tie services. The Company’s reliability back-tie service is a first for the industry. These three types of T&D needs will form the initial screen.
Conversely, certain T&D projects cannot, or are unlikely to, be deferred or avoided by DER. These
“required” projects include those necessary to comply with public works or other customer requests,
such as the following:
■ Line/pole relocation or undergrounding due to street widening, relocation clauses, or overhead-to-
underground conversions
■ Emergency and preventative equipment and infrastructure replacement to restore power after outages,
avoid outages, avoid catastrophic failures, and ensure public safety
■ Replacement of physical apparatus, such as circuit breakers, relays, and transformers, because of asset
condition
■ Replacement of damaged or failed equipment/poles/conductor
■ New customer requests for new physical connection to the electric grid
The Step 1 screen will categorize all T&D opportunities in the Company’s capital budget into two
groups based on the project type:
■ T&D projects with an NWA opportunity involving one or more of the three grid needs categories
described earlier in this section.
■ T&D projects that address “required” needs outside of the three NWA opportunity categories. This step can be done in conjunction with the Company’s annual capital budgeting process to ensure that consistency is applied across the enterprise. Those T&D projects identified as required in this initial screen will be pursued as utility wires solutions in the appropriate regulatory approval procedure (that is, general rate case or a cost recovery mechanism such as a GO7 application).
Focusing on the most viable NWAs by categorizing opportunities by these specific capital project types
is employed in every state currently pursuing NWAs.
1.3.2.2 Step 2: NWA Opportunity Sourcing Evaluation
The Company, through the use of NWAs, seeks to expand options for broad participation in support of growing a viable DER market to meet Hawai‘i’s goals. It is also important for all customers to directly benefit from the use of DER. As such, the Company’s approach is to consider a range of competitive
market-based procurement, program, and pricing options to expand access for all customers—not just
for a few. This approach is different than what California and other states consider in their NWA procurement-focused opportunity evaluations.
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While the Company’s methodology adapts aspects of California’s34 evaluation criteria, it is done here in
the context of assessing other sourcing options, such as programs and retail pricing, as well as procurements on the basis of favorable, uncertain, or unfavorable attributes. The implied precision of California’s complex quantitative approach, in practice, does not identify more NWA procurement
opportunities than the simpler methods employed in other states. Based on the six mainland states
surveyed, NWA opportunities for procurement averaged approximately 1 to 2 percent of all T&D capital
projects35 and about 5 to 10 percent of initially screened distribution upgrade projects.36
The Company is adapting elements of the California approach as such elements are useful in
considering sourcing options other than procurements. Therefore, the intent of this second step is to
evaluate candidate T&D NWA opportunities in greater detail to identify those with the highest likelihood of success and related solution sourcing options. This NWA opportunity sourcing evaluation is technology agnostic, consistent with the Company’s IGP process.
The following three criteria is used to evaluate NWA opportunities:
■ Timing of the grid need
■ Performance requirements in relation to operational performance requirements of the identified T&D grid need
■ Project economics in terms of the deferral value of a qualified T&D capital project and any other relevant avoided costs to determine sourcing options
The following criteria were considered to evaluate NWA opportunities but is currently not included in
the evaluation due to lack of quality market data, and to broaden the NWA opportunities that can move
to Step 3. These criteria may be reassessed with further NWA experience and market responses to future RFPs.
■ Forecast certainty of the forecasted growth driving the grid need
■ Market assessment based on the potential for successful NWA procurement versus programs or retail
pricing options in the immediate local area related to the grid need
Each grid project will be assessed in relative terms within each criterion. The criteria are further explained below.
Timing
Timing of the grid need is an important factor. Sufficient lead time is required to allow for a
procurement (including contract negotiations) or program development, regulatory approval, and NWA solution deployment by the in-service date, as required by the forecasted operational date, to meet the
34 California PUC Decision on the Distribution Investment and Deferral Process (D.18-02-004).
35 California utilities’ distribution deferral opportunities reports for 2018 and 2019 are consistent with this finding.
36 P. De Martini and A. De Martini, NWA Opportunity Evaluation Survey of Current Practice, Pacific Energy Institute, March 2020
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grid need. Based on the Company’s experience with sourcing other grid services, and consistent with
stakeholder feedback and industry practice, a starting point of a 2-year lead time is used.
One lesson learned from the industry survey was that the time needed for NWA procurement contract negotiations and subsequent regulatory approval are key factors in the time required. In addition, depending on the complexity of the contingent wires solution in the event the NWA sourcing does not yield a viable solution, more lead time may be needed. The minimum timing threshold may be adjusted
as the Company, the market, and the Commission learn from future NWA opportunities.
Timing criteria are defined as follows:
Favorable:
o 2-5 year lead time Moderate or Uncertain:
o Greater than 5 year lead time Unfavorable:
o Less than 2 year lead time Grid needs with lead times greater than 5 years are considered Moderate or Uncertain and will be
reassessed during the next IGP cycle.
Performance Requirements
The performance requirements criterion will be used to determine whether NWA solutions can reasonably meet the performance requirements of the identified grid need (capacity expansion, reliability back-tie, or resiliency). Projects that target critical needs with high operational risks are more
likely to require more stringent performance requirements and contract terms for NWA solutions. In
general, opportunities with more lenient requirements are more viable for NWAs. For example, if the
opportunity has a smaller peak capacity, shorter duration needs, and fewer calls, then the ability to meet the performance requirements will be considered more favorable for an NWA.
Performance criteria are defined as follows:
Favorable:
o Capacity: Up to 5 MW and
o Duration: Up to 4 hours Moderate or Uncertain:
o Capacity: > 5 MW and < 10 MW or
o Duration: > 4 hours and < 8 hours Unfavorable:
o Capacity: 10 MW and larger
o Duration: 8 hours or more
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The grid need will be clearly described as illustrated in Figure F-4, along with supporting engineering
and operational analyses as provided in the Soft Launch37 and case examples38 discussed with the
DPWG in August and October 2019.
Figure F-4: Example Engineering Analysis and Performance Requirements
Projected Hourly Needs Summary
These performance requirements are intended to provide as complete a picture as possible of the grid
need and operational performance required of solutions to transparently inform stakeholders.
Project Economics
The project economics criterion will be used to evaluate opportunities for procurement, programs, and/or pricing, and to identify opportunities that are unlikely to be cost-effective. The project economics include the deferral value of a qualified T&D capital project and any other relevant avoided
costs. Based on stakeholder feedback, projects with an economic value (that is, capital cost) of $1
million or greater will be seen as favorable in this criteria. Projects with an economic value less than $1
37 DPWG Meeting August 8, 2019 “Review of Soft Launch Opportunity” presentation: https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/distribution_planning/20190808_dpwg_meeting_presentation_materials.pdf.
38 DPWG Meeting October 9, 2019 “Review of T&D NWA Opportunity Identification & Evaluation Process” presentation: https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/distribution_planning/20191009_dpwg_meeting_presentation_materials.pdf.
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million may be considered for targeted DER programs to address specific NWA needs consistent with
the Company’s Advanced Rate Design Strategy.39
Project Economic criteria are defined as follows:
Favorable: $1M and above Moderate or Uncertain: Between $500K and $1M Unfavorable: Less than $500K
Forecast Certainty
Forecast certainty criterion is important to avoid investment in grid needs that may be premature or not
required if the forecasted load growth does not materialize. However, this forecast certainty criterion is currently not used to evaluate grid needs because the Company has yet to determine the evaluation metrics for this. The Company may consider qualitative factors in the future such as, but not limited to, the following:
• Favorable: If the forecasted load growth is driven by actual electric service requests received, which may signal higher certainty of developer plans driving a grid need.
• Moderate or Uncertain:
o If the forecasted load growth is driven by conceptual or high-level master plans, which may signal moderate certainty of developer plans.
o If the forecasted load growth is driven by spatial allocation of the Company system-wide growth forecast, which may signal moderate certainty of growth in an area.
Market Assessment
The market assessment criterion is used to assess the following two aspects in terms of procurement/program sourcing options:
■ Technical potential based on the number of customers available for behind-the-meter solutions and land availability for ahead-of-the-meter solutions
■ Supplier and solution diversity to ensure competitiveness and reliability
The opportunity for a DER-based alternative is dependent on sufficient existing or new customers and/or land availability in the appropriate locations associated with the circuits and/or substation(s) to
develop an NWA solution sufficient to meet an identified grid need. Also, as procurements are intended to foster competitive solutions, it is beneficial to identify whether sufficient customers and/or land opportunity exists to support competitive proposals from more than one provider. These factors may be used to evaluate the potential success of an NWA procurement/program and any mitigation
39 Hawaiian Electric Companies, Advanced Rate Design Strategy, September 25, 2019. https://www.hawaiianelectric.com/documents/clean_energy_hawaii/grid_modernization/dkt_2018_0141_20190925_cos_ARDS.pdf
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measures that may be needed to realize a successful outcome for customers. For instance, as proposed
by stakeholders, an NWA program may provide a better outcome for a new residential development
than a procurement.40
However, currently the Company lacks quality market data to properly assess this criteria. Therefore
this criteria is not used in this evaluation. This criteria may be reassessed based on market response to
future RFPs.
1.3.2.3 Step 3: Action Plan
The NWA opportunity sourcing evaluation discussed in Section 4.2.2 results in a T&D action plan that assigns specific T&D projects to one of three action plan tracks. The assigned action plan track will
provide the path the Company will use to pursue a solution. Competitive procurement is the primary
means of sourcing opportunities $1 million or greater. However, based on stakeholder discussion in the
DPWG, the Company sought to expand the potential for NWAs by including the option for programs and pricing for opportunities under $1 million and for those opportunities that do not lend themselves to procurement, such as new real estate developments. As such, this sourcing approach adapts the
California model by explicitly incorporating the option for programs and pricing options in Track 2 to
expand the potential for NWA solutions for grid needs less than $1 million in economic value.41 The
three tracks are as follows:
■ Track 1: Procurement of favorable NWA opportunities (that is, greater than $1 million in economic value with in-service need in 2 to 5 years) with performance requirements that can reasonably be met by NWAs.
■ Track 2: Reassess if factors indicate reevaluating in the future for potential procurement (that is, moderate/uncertain or favorable performance and economic criteria and timing greater than 5 years); or a program or pricing if the economic value is less than $1 million but greater than $500K and
potential timing of need is favorable (2 to 5 years) for customer adoption.
■ Track 3: Non-qualified opportunities that have criteria (for example, performance, timing, or
economics) that cannot be reasonably met by NWA solutions. In these instances, the wires solution will
be implemented.
The action plan will include a summary list of T&D project opportunities evaluated and the proposed course of action on solutions for each grid need. In addition, the supporting evaluation for each NWA opportunity will be discussed.
40 Stakeholder comments on programmatic approach for NWA in DPWG meetings beginning in July 17, 2019 meeting: https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/distribution_planning/20190717_dpwg_meeting_summary_notes.pdf
41 Note that in the Northeast and California, the utilities employ demand side management programs funded by existing customer public surcharges to mitigate grid needs before pursuing NWA procurements.
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Figure F-5: T&D NWA Opportunity Evaluation
Track Timing Overall Performance Economics
1 Favorable Favorable or Moderate/Uncertain Favorable
2 (Pricing) Favorable Favorable or Moderate/Uncertain Moderate/Uncertain
2 (Reassess) Moderate/Uncertain Favorable or Moderate/Uncertain
3 One or more are Unfavorable
Figure F-5 identifies potential distribution opportunities in one of the three tracks described above,
along with a corresponding color code—green (favorable), yellow (uncertain), and red (unfavorable)—to highlight the assessment of each criterion to indicate why the opportunity was placed into the given track.
1.3.2.4 Contingency Plan
The primary goal of action plans Track 1 and Track 2, as mentioned in section 4.2.3, is to pursue
successful deferral of the grid project with a NWA. However, for the Company to meet its obligation to provide electric service, there may be a need to develop a contingency plan based on grid investment or another alternative to ensure that the in-service date and lead time to implement those solutions may be met.
During NWA procurement and/or program implementation, solicitation/program development, NWA
deployment/customer adoption, or NWA commercial operation, several scenarios may occur that could cause the NWA solution to not viably solve the grid need. For example, if there are no cost-effective NWA bids that meet the distribution need, or if contracts are not approved by the Commission,
implementation of the Company’s contingency solution will be needed. This contingency solution may
include the wires project originally intended for deferral. For this reason, it will be necessary to continue
preliminary engineering solution development activity, such as wires project engineering and other related activity. This challenge was discussed with the IGP TAP on November 16, 2022,42 which the TAP suggested the Company also assess the risk of a non-performing NWA, and the impact should be
considered in identifying NWA opportunities.
As the NWA process and market mature, a framework may need to be developed that covers contingency planning for NWAs similar to what has been developed for competitive bidding of
42 See https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/technical_advisory_panel/20221116_tap_feedback.pdf
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
generation.43 As part of the Competitive Procurement Working Group within the IGP process, the
Company is revising the competitive bidding framework to cover procurement of NWAs. Modifications to contingency planning will be covered by those revisions as well as processes and procedures to facilitate the procurement of NWAs.
If NWA bids meet most of the distribution need, but not all of the need required for a full deferral, the
Company may develop short lead time mitigation alternatives that supplement the NWA portfolio for the total solution where feasible. Depending on how early in the procurement process the shortcoming is known and the amount that will be insufficient, the Company may initially attempt to use NWAs as a contingency measure to supplement the deficiency or may consider smaller wires solutions and/or
operational constraints to temporarily remedy a deficiency. If a cost-effective solution does not exist,
the Company may need to pursue the contingency plan’s alternative solution. This may include operating solutions, up to pursuing the initial traditional solution. For example, if an NWA solution can resolve a distribution line overload, but the location leaves a portion unmitigated, that smaller remaining portion may still be reconductored to supplement the NWA solution. Such contingency
solutions may require the Company to seek expedited approval by the Commission.
If the NWA provider is unable to install NWAs according to the contract, the Company may develop short lead time mitigation alternatives that supplement the NWA portfolio for the total solution where feasible in accordance to the wire solutions development44 steps. The supplemental solution would be
the least complex solution that addresses the shortcoming. This could include an operating solution, like switching, that uses existing equipment or load balancing. If a cost-effective NWA mitigation solution does not exist, the Company may pursue the contingency solution.
If the NWA fails during field commissioning or underperforms during operations based on
commissioning and performance verification protocols agreed to in the contract, the Company will
determine emergency limitations, if applicable, and will work with system operations on potential grid reconfiguration or load drop for all scenarios above. The Company will determine the reason for NWA underperformance, assess any equipment damage or outage impacts, assess whether new mitigation is required, and determine expedited solution options. If issues such as these arise and result in adverse
impacts on reliability (that is, system average interruption duration index and system average
interruption frequency index metrics), then any associated impacts on performance incentives/penalties must also be considered.
The absolute latest a decision can be made for a distribution project intended for deferral is directly
after final design is complete and before the scheduling, permitting, and construction of the project
begins. This varies depending on the project being deferred, but typically distribution projects that do
not require permitting require a project commencement decision to be made at least 12 to 48 months
43 See, Decision and Order No. 23131 filed on December 9, 2006 in Docket No. 03-0372, Instituting a Proceeding to Investigate Competitive Bidding for New Generating Capacity in Hawaii. Available at, http://files.hawaii.gov/dcca/dca/dno/dno2006/23121.pdf
44 Seethe Distribution Planning Methodology report, Section 6.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
prior to the need date (as described in the Distribution Planning Methodology report, Section 5.3). The
timing of the contingency decision process may change over time as the Company continues to
understand the impact of scheduling traditional and DER solutions in parallel.
Cost recovery of preliminary engineering costs for contingency solutions is another issue that may need to be raised with the Commission in the future. The Company acknowledges that the issue of preliminary engineering costs that are expended to produce contingency or parallel plans to third-party
contracted NWA services may be discussed in the performance-based regulation proceeding as part of
the discussion on adjustments to the major project interim recovery mechanism.
1.4 Case Examples
The Company shared several identified grid needs with stakeholders at the October 9, 2019, DPWG
meeting for the purpose of jointly validating the proposed NWA opportunity evaluation methodology
with real examples.45 These real T&D projects have been identified and scoped by the Company for
consideration. These illustrative projects were discussed with stakeholders to refine the NWA opportunity evaluation methodology and to jointly assess each opportunity. For this reason, a representative set of examples that includes projects that are typically screened out of NWA
consideration in California and the Northeast were included for the DPWG discussion. As such, this list is
not the complete list of potential grid projects, nor does it represent a final list of evaluated NWA
opportunities as is found in the California Distribution Deferral Opportunity Report, for example. However, the results of the DPWG’s feedback and application of this methodology in the Soft Launch and in the DPWG meetings is consistent with the California and Northeast approaches to identifying
viable NWA opportunities for procurement.46 The following includes example projects discussed during
the October 9, 2019 DPWG meeting47. Additional example projects discussed during the November 2022 TAP presentation48 on the NWA opportunity evaluation process are also included.
1.4.1 Step 1: NWA Opportunity Screen
Several case example T&D projects were discussed with stakeholders. The projects presented in this section are examples of capital projects that do not represent viable NWA opportunities and, as such,
would be screened out in Step 1 of the process. The projects that passed Step 1 screening are discussed
under Step 2 in Section 5.2.
45 October 9, 2019, DPWG meeting presentation, see slides 19-54
https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/distribution
_planning/20191009_dpwg_meeting_presentation_materials.pdf.
46 Note: In 2019, PG&E and SCE identified a combined total of over 800 grid needs that were screened to only 10 projects (6 for SCE and 4 for PG&E) for
NWA procurement. This is consistent with the experience in the Northeast.
47 October 9, 2019, DPWG Meeting Summary Notes
https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/distribution
_planning/20191009_dpwg_meeting_summary_notes.pdf.
48 November 16, 2022, DPWG Meeting Summary Notes IGP Technical Advisory Panel Distribution Grid Needs Assessment & Non-Wires Alternatives
(hawaiianelectric.com)
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
1.4.1.1 Salt Lake Boulevard Overhead Line Relocation
This project involved an overhead (OH) to underground (UG) line conversion and relocation of Salt Lake
Boulevard OH lines requested by public works, as illustrated in Figure F-6.
Figure F-6: Salt Lake Boulevard Overhead Line Relocation
This project involved relocating a portion of an existing line; therefore, the alternative is to remove that line. This means that downstream loads would need to be removed from the grid. Stakeholder consensus in the meeting was that this type of project is not a feasible NWA opportunity. This type of
project requested by public works would be put into the non-qualified category in Step 1.
1.4.1.2 Waiau-Mililani 46 kV OH to UG Conversion
A customer requested OH to UG conversion projects for betterment in support of the Koa Ridge Development, as shown in Figure F-7. The scope of work includes installation of OH transitions and UG electrical facilities and then removal of existing OH electrical facilities once UG facilities are energized.
The total project cost is $6.5 million, with the developer contributing the majority of the funding
through contributions in aid of construction (CIAC). The Company’s cost after the customer’s contributions is about $800,000. In-service dates vary between 2020 and 2021.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Figure F-7: Waiau-Mililani 46 kV OH to UG Conversion
Stakeholders agreed that this type of customer-requested betterment OH to UG conversion project is not a feasible NWA opportunity. Customer-requested betterment conversion projects will be put into the non-qualified category in Step 1.
1.4.1.3 Waiau 46 kV GIS Bus Replacement
This project is proposed to replace the existing deteriorated 46 kV air-insulated switchyard with a new
46 kV gas-insulated substation (GIS). This major 46 kV switching station provides service to Waiau, Ewa, Mililani, Pearl City, and Waipahu through eight sub-transmission lines with a total bus load (2018) of 92 MW. Findings from Black & Veatch‘s Waiau 46 kV Substation Engineering Study dated 2013 are as
follows:
■ Substation that is well beyond its design life (66+ years in marine environment)
■ Bus configuration that creates risk of major outage and is expensive to operate
■ Severely corroded steel structure
■ Inadequate grounding system creating potential hazard to public
■ Aged, obsolete, and unreliable equipment providing unreliable service
■ Inadequate housing for modern protective relays
The scope of work includes installing a new 46 kV GIS ring bus (circuit breakers are connected to form
a ring, with isolators on both sides of each breaker) and constructing a new 46 kV control house, with
provisions for future 138 kV relays, as shown in Figure F-8. The estimated project cost is $60 million to $80 million, with an in-service date of September 2024.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Figure F-8: Waiau 46 kV GIS Bus
Stakeholder consensus was that this type of aging infrastructure project is not an NWA opportunity
because there is not a viable approach to avoid the ring bus and breaker replacement. Also, the 46 kV
substation bus provides system benefits by allowing renewable projects and DER to export renewable energy to other parts of the grid in support of Hawai‘i’s 100 percent renewable objective. As such, this project would be screened out in Step 1.
The three example projects screened out in Step 1, which include line relocation, line OH to UG
conversion, or bus replacement of aging infrastructure, represent projects where the alternative is to
remove that section of the line or bus. This means that downstream loads would either result in losing a backup source or need to be removed from the grid.
1.4.2 Step 2: NWA Opportunity Sourcing Evaluation
The following case example T&D projects that passed Step 1 screening were discussed with the IGP Technical Advisory Panel on November 16, 2022 in the joint application of the Step 2 evaluation criteria.
1.4.2.1 Koa Ridge
Koa Ridge Development in Central O‘ahu near Mililani, built by Castle & Cooke Hawai‘i, includes 3,500
new homes, a medical center, commercial and light industrial development, parks, and schools. The
developer estimated an additional 40.7 MW of load at the completion of the development. Additional distribution capacity would be needed by 2025 to address the new development growth, as shown in Figure F-9.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Figure F-9: Waipio Substation and Koa Ridge Load Forecast
The load growth will result in an overload of substation transformers under normal and emergency
conditions, as presented and discussed with the stakeholders.
The proposed wires T&D project is to install a 10 MVA 46-12 kV transformer and associated equipment at Waipio Substation with an estimated cost of $2.9 million, with an in-service date of 2025.
The Koa Ridge project is categorized as an expansion of distribution system capacity in Step 1. The
following is the assessment for Step 2:
■ Performance Requirements: Performance requirements are a potential challenge given the long-duration and high-magnitude overloads, and given the results of the Soft Launch (see Section 5.3) it is uncertain if a procurement will be successful (red).
■ Timing: The in-service date is more than 2 years away (Green).
■ Economic Assessment: The T&D project cost is greater than $1 million (Green).
Due to the large performance needs to address the projected overloads with capacity needs greater
than 10 MW and duration longer than 8 hours, this Koa Ridge project’s overall performance needs is deemed to be unfavorable and placed into Track 3 which indicates a non-qualified NWA opportunity that cannot be reasonably met by NWA solutions and the wires solution is to be implemented.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
1.4.2.2 CEIP 46 Sub-tranmission Circuit Reconductoring
The CEIP 46 sub-transmission system serves a large portion of mid-west O‘ahu from Ewa to Kapolei. It
also serves as the backup in contingency scenarios to the Kahe, Ewa Nui, and Waiau sub-transmission
systems. See Appendix A for map of the service area. There are a number of new loads forecasted to be served from the CEIP 46 sub-transmission system. The load for these projects total approximately 53 MW of new load growth. Additional distribution capacity would be needed by 2025 to address the load
growth.
The proposed T&D project is to reconductor a section of the CEIP 46 sub-transmission circuit and associated equipment at an estimated cost of $3.93 million, with an in-service date of 2025
The load growth will result in an contingency overload of the current carrying capacity of the cable/conductor. This project is categorized as ensuring a reliability requirement for circuit back-tie
upgrade deferral in Step 1. The following is the assessment for Step 2:
■ Performance Requirements: Performance requirements are considered favorable given a potential
challenge given its short-duration and low-magnitude overloads (Green).
■ Timing: The in-service date is more than 2 years away (Green).
■ Economic Assessment: The T&D project cost is greater than $1 million (Green).
Due to all evaluation criteria being favorable this project is placed into Track 1.
1.4.2.3 Kakaako and Ala Moana Development Areas
New residential/commercial projects have been proposed in the Kakaako and Ala Moana area due to the Transit-Oriented Development (TOD) Special District Design Guidelines, which promote “intense
and efficient use of land” near the rail stations, as shown in Figure F-10. The Company received six TOD-
related service requests in the Ala Moana area, and two more appeared to be in development per news reports and feedback from the City. The Ala Moana TOD need was previously identified as a Track 2 opportunity because the performance requirements and timing were uncertain. The opportunity would be reconsidered in the next planning cycle based on further information on the need, including
refinement of performance requirements, timing of in-service date(s), and scoping and estimation of a
wires solution. Since then, several projects have not materialized and the refinement of the forecast shows more growth in the Kakaako area instead.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Figure F-10: Kakaako and Ala Moana Area
The Kakaako area under development is focused between Kamakee Street and Keawe Street and is
served by a 25 kV distribution system fed by the Kewalo Substation (in Kakaako), Kamoku Substation
(near Iolani School), and /or Iwilei Substation. With the projected loads based on service requests and developer plans, overloads will occur as illustrated in Figure F-11 and Figure F-12.
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Figure F-11: Kewalo T3 Yearly Peak Forecast
Figure F-12: Kewalo T3 2027 Peak Day Overload
0
10
20
30
40
50
60
70
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Lo
a
d
(
M
W
)
Year
Yearly Peak Normal Capacity Emergency Capacity
0
10000
20000
30000
40000
50000
60000
70000
0 5 10 15 20 25
Lo
a
d
(
k
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)
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
The proposed wires T&D project is to install a 50 MVA 138-25 kV transformer at Kewalo Substation and
extend new circuits to the Kakaako development area at an estimated cost of $22 million, with an in-
service date of 2026.
The Kewalo T3 project is a qualified NWA opportunity based on the Step 1 criteria. The project is considered expansion of the distribution system capacity.
The following is the assessment from Step 2:
■ Performance Requirements: Transformer loading requirements are favorable (Green).
■ Timing: The in-service date is more than 2 years away (Green).
■ Economic Assessment: The T&D project cost is greater than $1 million (Green).
Based on the evaluation criteria this project is placed into Track 1.
1.4.3 Step 3: Action Plan
The following are example steps the Company took to seek NWA solutions for projects that were placed in Track 1. The Company conducted a Soft Launch and several Expression of Interests (EOI) to demonstrate the grid needs assessment, NWA opportunity evaluation, sourcing process, and solution evaluation methods for NWAs by using real-world examples. These examples also allowed the
Company to gain experience identifying needs for resource choices while being subjected to an
evaluation and construction time line. The lessons learned in the Soft Launch and EOIs are being used to help inform development of the full-scale IGP planning and sourcing effort.
1.4.3.1 IGP Soft Launch RFP – Ho‘opili and East Kapolei Area
The Company identified two T&D NWA opportunities to source through a competitive procurement as
part of the IGP Soft Launch. These two opportunities were effectively identified as Track 1 opportunities
to pursue for procurement. The following discussion summarizes the opportunities and results.
Ho‘opili is a mixed-use master-planned community developed by D.R. Horton in west O‘ahu located north of Ewa Beach and east of Kapolei, as shown in Figure F-13. The plans for this new community include 11,750 new residential homes, 7 community and recreation centers, over 200 acres of
commercial farms and community gardens, up to 3 million square feet of commercial space, and 5
Department of Education public schools. In addition to Ho‘opili, there are currently over 20 additional customer service requests in the area with completion dates within the next few years. Due to an
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
estimated load growth of 83.4 MWA, overloads under contingency conditions are forecasted to occur in
2022, with normal overload conditions beginning in 2023.
Figure F-13: Planned Ho‘opili Development
The load growth will result in an overload of substation transformers and distribution circuits under normal and emergency conditions, as shown in Figures F-14 and F-15. From these overloads, two NWA opportunities were identified. The first NWA opportunity was to defer the Kapolei 4 Circuit Extension project with a commercial operation date (COD) of February 1, 2022. The second NWA opportunity was
to defer the Ho‘opili Substation project with a COD of January 1, 2023.
Figure F-14: Summary of Normal Overloads
Deferral Opportunity Equipment MW Peak Operational Date Delivery Months Delivery Hours Duration (Hr) Max # of Days MWH
Ho‘opili Substation Kaloi 1 Tsf 4.7 Jan 2023 Jan–Dec 1PM–11AM 10 365 21.5
Kaloi 3 Ckt 0.3 Aug 2023 Aug–Oct 7PM–9PM 2 69 0.4
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Figure F-15: Summary of Contingency Overloads
Deferral Opportunity Equipment MW Peak Operational Date Delivery Months Delivery Hours Duration (Hr) Max # of Days MWH
Kapolei 4
Circuit
Extension
Kapolei 2
Tsf 3.5 Feb 2022 Jan–Dec 5PM–11PM 6 365 11.4
Ho‘opili
Substation
Ewa Nui 2
Ckt 5.1 Jan 2023 Jan–Dec 11AM–12AM 13 365 30.9
Kaloi 1 Tsf 9.7 Jan 2023 Jan–Dec 6AM–8AM,
9AM–12AM 17 365 62.8
Kaloi 3 Ckt 2.6 Jan 2023 Jan–Dec 5PM–11PM 6 365 8.5
Kamokila 4
Ckt 1.0 May 2023 Jan–Dec 5PM–10PM 5 226 2.9
Figure F-16 shows the loading of the peak day by month on the Kaloi #1 Transformer in the year 2023.
Figure F-17 shows the associated grid need for Kaloi #1 Transformer. These, along with graphic
representation for all other overloads, were identified in the RFP, Appendix J, for NWA services for the Ho‘opili Area, dated November 8, 2019.
Figure F-16: Kaloi #1 Transformer Loading – Monthly Peak Day in 2023
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
Figure F-17: Kaloi #1 Transformer Overload
The most cost-effective T&D project proposed for comparison to an NWA solution is the construction
of a new substation site and associated equipment located in the Ho‘opili development. This would
result in minimal distribution circuit installation costs because of the location of new loads to serve. Estimated costs for this project are approximately $12.7 million with provisions for up to four 46-12 kV, 10/12.5 MVA distribution transformers to allow for future load growth in the area.
The IGP Soft Launch RFP process resulted in low response from the market. Because of insufficient
response to the RFP to meet the performance and operations requirements for either of the deferral opportunities, the Company, in consultation with the Independent Observer, decided not to move forward with the IGP Soft Launch RFP. As a result, the Company is moving forward with the identified traditional solution. As indicated in Hawaiian Electric’s Ho‘opili Area Study dated 2019, the proposed
project will allow for the timely installation of critical infrastructure to the electrical system, which will
provide necessary capacity to serve projected loads and provide essential reliable power under contingency conditions.
Although a traditional solution will be initially pursued for the Ho‘opili area, future NWA opportunities remain to enable Ho‘opili’s growth. The Company will evaluate the viability of a programmatic DER
effort for the Ho‘opili and East Kapolei area to reduce longer-term needs for distribution upgrades in
the area. The Company will reevaluate options as load grows (around 2024 or 2025) and will determine if future NWA opportunities become available. The Company has also recognized the challenge and need of exploring ways to cost-effectively mitigate the impact of large new real estate development
loads.
The Company was one of the first, if not the first, to procure for a distribution reliability (back-tie)
service nationally and gained valuable experience while proceeding through the Soft Launch process. The Company will continue to improve the IGP process going forward and will conduct future NWA
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APPENDIX F –NWA OPPORTUNITY EVALUATION METHODOLOGY
procurements for distribution opportunity based on lessons learned from the Soft Launch. Some
lessons learned that will be applied to the IGP process include the following49:
■ Leverage the NWA evaluation framework developed by the DPWG to determine opportunities best
suited for procurements
■ Continue to pursue market solutions to acquire least cost, best fit solutions for customers, but consider tariff and program options to complement procurements
■ Continue discussion in examining opportunities to capture multiple services from resources at longer-duration contracts
■ Pursue standard form RFP for NWAs and streamline the process for short lead time/near-term needs.
Expression of Interest for NWA Opportunities
In the years 2022 and 2023, EOIs were issued for three T&D NWA opportunities which were identified
as Track 1 opportunities based on the NWA methodology. The objective of the EOIs were to identify
interested parties who are able to develop cost competitive utility-scale renewable projects or aggregating DER/EE projects in specific locations to fulfill grid service performance requirements. As part of the EOIs, the performance requirements, net present value (NPV) of the deferral or avoidance cost of the traditional wires solution, and a map of the areas where the NWA projects are required were
provided.
The information obtained from responses would help the Company determine if there are viable cost competitive NWA projects, to move forward with issuance of an RFP or alternative means of procurement, subject to approval by the Hawaiʻi Public Utilites Commission. The following discussions summarizes the opportunities and results.
Ewa Nui B Transformer NWA
The Company forecasts significant load growth in central O‘ahu in the coming years. The load is
forecasted to increase by approximately 70 MVA by 2030 triggering overloads beginning in 2026 during a contingency condition. Therefore, the Company has identified a capacity and reliability grid need and issued an EOI in 2/2023 to developers or aggregators who are capable of developing utility-scale
renewable projects or aggregating DER/EE in the Central O‘ahu area.
The traditional wires solution consists of installing a new 80MVA 138-46kV transformer and associated
equipment at Ewa Nui Substation with a new 46kV circuit. This solution is preliminarily estimated to cost $15.0M.
To address these grid needs, the Company sought capacity (MW) and energy (MWH) annual grid needs
shown in Figure F-18 to defer the need for the wires project by five years.
49 March 9, 2020, DPWG Presentation Slides https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeholder_engagement/working_groups/soft_launch/20200309_igp_soft_launch_wg_presentation_materials.pdf.
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Figure F-18: Annual Grid Needs
2026 2027 2028 2029 2030 Capacity (MW) 7.2 9.5 12.2 15.1 16.5
Energy (MWH) 8.5 15.5 31.1 65.0 87.8
This project is intended to defer a T&D solution to provide capacity to the 46 kV system for five years. The NPV of the deferral value is: $7.0M.
The Company did not receive any responses to this EOI and will be pursuing the traditional wires
solution.
CEIP 46 Reconductoring NWA
The Company forecasts significant load growth in west O‘ahu from Ewa to Kapolei areas in the coming years. The load is forecasted to increase by approximately 53 MVA by 2030 triggering overloads of existing electrical infrastructure beginning in 2025 during a contingency condition. Therefore, the Company has identified a capacity and reliability grid need and issued an EOI in 2/2023 to developers
or aggregators who are capable of developing utility-scale renewable projects or aggregating DER/EE in
the Ewa and Kapolei areas of O‘ahu.
The traditional wires solution consists of installing approximately 520 ft of new 1500KCM cables parallel to existing cables and reconductoring approximately 1.91 miles of 556 conductor to 795 conductor.
This solution is preliminarily estimated to cost $3.93M.
To address this grid need, the Company sought the aggregate NWA amount of 5.71MW/13.9MWH in
2025 for the expected 30-year lifespan of a wires project to avoid the cost of the wires project. Figure F-19 shows the capacity (MW) and energy (MWH) annual grid needs.
Figure F-19: Annual Grid Needs
2025 2026 2027 2028 2029 Capacity (MW) 5.71 5.71 5.71 5.71 5.71
Energy (MWH) 13.9 13.9 13.9 13.9 13.9
This project is intended to avoid a T&D solution to provide capacity to the 46 kV system. The NPV to avoid the wires project is $4.57M.
The Company did not receive any responses to this EOI and will be pursuing the traditional wires
solution.
Kewalo T4 Transformer NWA
The Company forecasts significant load growth in the Kakaako and Kewalo area in the coming years. The forecasted load growth totals approximately 30 MVA by 2030 triggering normal and contingency overloads of existing electrical infrastructure beginning in 11/2025. Therefore, the Company identified a
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capacity and reliability grid need and issued an EOI in 3/2023 to developers or aggregators who may be
interested and capable of developing utility-scale renewable projects or aggregating DER/EE in the
Kakaako and Kewalo areas of O‘ahu.
The traditional wires solution consists of installing a 138-25 kV, 50 MVA transformer and associated equipment at Kewalo Substation and four new 25 kV circuits. The solution is preliminarily estimated to cost $22M.
To address these grid needs, the Company sought aggregate NWA amounts for two scenarios below.
Figure F-20 shows the capacity (MW) and energy (MWH) annual grid needs.
1. 2.0MW/3.3MWH in 2025-2026 to defer the wires project by one year; or
2. 2.0MW/3.3MWH in 2025-2026 and 17.7MW/168.5MWH in 2027 to avoid the need for the wires
project.
Figure F-20: Annual Grid Needs
11/2025 2026 2027 2028 2029 2030 Capacity (MW) 2.0 2.0 17.6 17.7 17.7 17.7 Energy (MWH) 3.3 3.3 166.6 168.5 168.1 167.7
The NWA is intended to defer or avoid a T&D solution to provide capacity to the distribution system.
The approximate NPV for the two NWA scenarios were:
1. NPV to defer the wires project by one year: $3.17M.
2. NPV to avoid the wires project: $25.6M
The Company is currently waiting for responses.
Appendix G:
Revised Framework for
Competitive Bidding
INTEGRATED GRID PLANNING
FRAMEWORK FOR COMPETITIVE BIDDING Adopted on June 30, 2022 STATE OF HAWAII PUBLIC UTILITIES COMMISSION
G-2 Integrated Grid Planning Report
APPENDIX G – REVISED FRAMEWORK FOR COMPETITIVE BIDDING
STATE OF HAWAII
PUBLIC UTILITIES COMMISSION INTEGRATED GRID PLANNING FRAMEWORK FOR COMPETITIVE BIDDING
June 30, 2022 I. DEFINITIONS As used in this Framework, unless the context clearly requires otherwise: "Affiliate" means any person or entity that possesses an “affiliated interest” in a utility as defined by Section 269-19.5, Hawaiʻi Revised Statutes (“HRS”), including a utility’s parent holding company but excluding a utility’s subsidiary or parent which is also a regulated utility. "Agreement" means an agreement or contract for an electric utility to purchase a System Resource from a third party, pursuant to the terms of this Framework. "CIP Approval Requirements" means the procedure set forth in the Commission's General Order No. 7, Standards for Electricity Utility Service in the State of Hawaii, Paragraph 2.3(g), as modified by In re Kauai Island Util. Coop., Docket No. 03-0256, Decision and Order No. 21001, filed on May 27, 2004, and In re Hawaiian Elec. Co., Inc., Hawaii Elec. Light Co., Inc., and Maui Elec. Co., Ltd., Docket No. 03-0257, Decision and Order No. 21002, filed on May 27, 2004. "In general, [the] commission's analysis of capital expenditure applications involves a review of whether the project and its costs are reasonable and consistent with the public interest, among other factors. If the commission approves the [electric] utility's application, the commission in effect authorizes the utility to commit funds for the project, subject to the proviso that 'no part of the project may be included in the utility's rate base unless and until the project is in fact installed, and is used and useful for public utility purposes."' Decision and Order No. 21001, at 12; and Decision and Order No. 21002, at 12. "Code of Conduct" means a written code developed by the host electric utility and approved by the Commission to ensure the fairness and integrity of the competitive bidding process, in particular where the host utility or its Affiliate seeks to advance its own System Resource proposal in response to an RFP. The "Code of Conduct" is more fully described in Part IV.H.9.c of the Framework.
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"Commission" means the Public Utilities Commission of the State of Hawaiʻi.
"Competitive bid" or "competitive bidding" means the mechanism established by this Framework for acquiring a future System Resource or a block of System Resources by an electric utility. "Consumer Advocate" means the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, State of Hawaiʻi. "Contingency Plan" means an electric utility's plan to provide either temporary or permanent solutions to address a reliability or statutory need (including, for example, the need to comply with reliability standards as discussed in Hawaiʻi Revised Statutes (“HRS”) §§ 269-0141 through 269-0144 and with the State of Hawaiʻi’s Renewable Portfolio Standards law, as codified in HRS §§ 269-91 through 269-95) as may result from an actual or expected failure of an RFP process to produce a project selected in an RFP or a viable project proposal (including any project not completed or delayed). The utility's Contingency Plan may be different from the utility's bid. The term "utility's bid," as used herein, refers to a utility's proposal advanced in response to a System Resource need that is addressed by its RFP. "Electric utility" or "utility" means a provider of electric utility service that is regulated by and subject to the Commission's jurisdiction pursuant to Chapter 269, Hawaiʻi Revised Statutes. "Framework" means the Integrated Grid Planning Framework for Competitive Bidding adopted by the Commission in Docket No. 2018-0165, on June 30, 2022. “Grid Needs” means the specific grid services (including but not limited to capacity, energy and ancillary services) identified in the Grid Needs Assessment, including transmission and distribution system needs that may be addressed through a Non-Wires Alternative. Grid Needs that are subject to the Framework generally does not apply to utility equipment (i.e., transmission and distribution infrastructure, flexible AC transmission devices, materials, etc.) that are normally procured through the utility’s procurement process for goods and services. “Grid Needs Assessment” means the process step in the IGP where the technical analyses are conducted to determine the generation, transmission, and distribution grid service(s) needs to meet state policy objectives, reliability standards, among other
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goals, and presented to the Commission for review and approval or acceptance. “IGP” or “Integrated Grid Planning” means an electric utility's planning process that aims to integrate the Grid Needs Assessment planning analyses with the sourcing of market-based solutions, which may include competitive bidding, to meet near and long-term customer needs. "Independent Observer" means the neutral person or entity retained by the electric utility or Commission to monitor the utility's competitive bidding process, and to advise the utility and Commission on matters arising out of the competitive bidding process, as described in Part III.C of the Framework. “Non-Wires Alternative” means an electricity grid project that uses non-traditional transmission and distribution (T&D) solutions, such as distributed generation (DG), energy storage, energy efficiency (EE), demand response (DR) and grid software and controls, to defer or avoid the need for conventional transmission and/or distribution infrastructure investments. "Provider" means a System Resource provider that is not subject to the Commission's regulation or jurisdiction as a public utility including, for example, developers and aggregators. "PURPA" means the Federal Public Utility Regulatory Policies Act of 1978, as amended. "QF" means a cogeneration facility or a small power production facility that is a qualifying facility under Subpart B of 18 Code of Federal Regulations §§ 292.201 - 292.211. See also 18 Code of Federal Regulations § 291.201(b)(l) (definition of "qualifying facility"). "RFP" means a written request for proposal issued by the electric utility to solicit bids from interested third-parties, and where applicable from the utility or its Affiliate, to supply a future System Resource or a block of System Resources to the utility to meet the utility’s Grid Needs pursuant to the competitive bidding process. “System Resources” are the specific resources that will be acquired to meet the Grid Needs.
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II. CONTEXT FOR COMPETITIVE BIDDING A. USE OF COMPETITIVE BIDDING 1. This Framework applies to electric utilities regulated by and subject to the Commission's jurisdiction pursuant to Chapter 269, Hawaiʻi Revised Statutes and any participants in any competitive bidding process that this Framework is applied to. 2. Competitive bidding, unless otherwise determined by the Commission, is established as the required mechanism for acquiring System Resources necessary to meet the Grid Needs. The following conditions and possible exceptions apply: a. Competitive bidding will benefit Hawaiʻi when it: (i) facilitates an electric utility's acquisition of System Resources in a cost-effective and systematic manner; (ii) offers a means by which to acquire new System Resources that are overall lower in cost, better performing or installed sooner than the utility could otherwise achieve; (iii) does not negatively impact the reliability and resilience or unduly encumber the operation or maintenance of Hawaiʻi's unique island electric systems; (iv) promotes electric utility system reliability by facilitating the timely acquisition of needed System Resources and allowing the utility to adjust to changes in circumstances; (v) is consistent with the IGP process; and (vi) is consistent with Hawaiʻi's renewable energy portfolio standards. b. Under certain circumstances, to be considered by the Commission in the context of an electric utility's request for waiver under Part II.A.3, below, competitive bidding may not be appropriate. These circumstances include: (i) when competitive bidding will unduly hinder the ability to add needed System Resources in a timely fashion; (ii) when the utility and its customers will benefit more if the System Resource is owned by the utility rather than by a third-party (for example, when system reliability or safety will be jeopardized by the utilization of a third-party resource); (iii) when more cost-effective or better performing System Resources are more likely to be acquired more efficiently through different
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procurement processes; or (iv) when competitive bidding will impede or create a disincentive for the achievement of IGP goals, renewable energy portfolio standards or other government objectives and policies, or conflict with requirements of other controlling laws, rules, or regulations. c. Other circumstances that could qualify for a waiver include (but are not limited to): (i) the expansion or repowering of existing utility generating units or other System Resources; (ii) the acquisition of near-term System Resources for short-term needs; (iii) the acquisition of power from a non-fossil fuel facility (such as a waste-to-energy facility) that is being installed to meet a governmental objective; (iv) the immediate acquisition of System Resources needed to respond to an emergency situation; or (v) the lack of a sufficient market to support a competitive procurement. d. Furthermore, the Commission may waive this Framework or any part thereof upon a showing that the waiver will likely result in the acquisition of a System Resource, leading to a lower cost to the utility's general body of customers, increase the reliability of a utility’s system to the utility's general body of customers, facilitate the transition to renewable generation, or is otherwise in the public interest.
e. This Framework does not apply to any procurements ongoing, any existing programs or tariffs, or any projects submitted for approval to the Commission before this Framework was adopted, such as the Kalaeloa Partners, L.P. 208 MW project (which is the subject of Docket 2011-0351), the Hu Honua Bioenergy, LLC 21.5 MW project (which is the subject of Docket No. 2017-0122), the Puna Geothermal Venture 46 MW project (which is the subject of Docket No. 2019-0333), the Paeahu Solar LLC 15 MW project (which is the subject of Docket No. 2018-0433) and projects selected pursuant to the utility’s RFPs for Variable Renewable Dispatchable Generation Paired with Energy Storage (Docket Nos. 2017-0352 and 2019-0178). f. This Framework also does not apply to System Resources with respect to: (i) System Resources with a net output of 5 MW or less on the island of Oʻahu, 2.5 MW or less on the islands of Maui and
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Hawaiʻi, and 250 kW or less on Molokaʻi and Lānaʻi; (ii) System Resources at substations and other sites installed by the utility on a temporary basis to help address reserve margin shortfalls or to enhance resiliency during emergency operations; (iii) customer-sited, utility-owned System Resources that have been approved by the Commission; (iv) System Resources under 1 MW installed for "proof-of-concept" or demonstration purposes; (v) extensions of an Agreement for three years or less on substantially the same terms and conditions as the Agreements and/or on more favorable terms and conditions if it can be demonstrated that the extensions are in the public interest; (vi) modifications of an Agreement to acquire additional firm capacity or firm capacity from an existing facility, or from a facility that is modified without a major air permit modification if it can be demonstrated that the modifications are in the public interest; and (vii) renegotiations of Agreements in anticipation of their expiration, approved by the Commission. g. When a competitive bidding process will be used to acquire a future System Resource or a block of System Resources, the System Resources acquired under a competitive bidding process must meet the needs of the utility in terms of the reliability of the System Resource, the characteristics of the System Resource required by the utility, and the control the utility needs to exercise over operation and maintenance of such System Resource in order to reasonably address system integration and safety concerns. 3. The procedure for seeking a waiver is as follows: a. For all proposed projects included in, or consistent with, identified Grid Needs developed through a Grid Needs Assessment that have not yet been filed with the Commission for approval or acceptance as of the effective date of this Framework, and are subject to the Framework pursuant to the terms set forth herein, any waiver request shall be submitted to the Commission for approval no later than the time the application for approval of such project is submitted to the Commission.
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b. An electric utility that seeks a waiver shall take all steps reasonably required to submit its application for waiver as soon as practicable such that, in the event the Commission denies the request, sufficient time remains to conduct competitive bidding without imprudently risking system reliability.
c. In no event shall a Commission decision granting a waiver be construed as determinative of whether an electric utility acted prudently in the matter.
d. Proposed projects included in, or consistent with, a Grid Needs Assessment conducted prior to the effective date of this Framework, proposed projects procured under a previously approved or accepted mechanism, or projects being submitted under approved programs and/or tariffs, shall not be required to seek a waiver of this Framework and this Framework shall not apply to such projects. 4. Exemption - ownership structure of an electric utility. Upon a showing that an entity has an ownership structure in which there is no substantial difference in economic interests between its owners and its customers, such that the electric utility has no disincentive to pursue new projects through competitive bidding, the Commission will exempt such entity from this Framework. B. SCOPE OF COMPETITIVE BIDDING 1. An electric utility's Grid Needs identified in a Grid Needs Assessment that is reviewed and approved or accepted by the Commission, shall inform the proposed scope of any RFP, or group of RFPs to be developed for the identified System Resources to be procured. This Framework defines which System Resource or block of System Resources are subject to competitive bidding. 2. Competitive bidding shall enable the comparison of a wide range of System Resource options that are capable individually or as a portfolio of meeting the specific requirements of the RFPs. 3. Each electric utility shall take steps to provide notice of its RFPs, and to
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encourage participation from a full range of prospective bidders. PURPA qualifying facilities, Providers, the host utility, and its Affiliates, and other utilities shall be eligible to participate in any RFP seeking System Resources. 4. Competitive bidding processes may vary, provided those processes are consistent with this Framework. An electric utility may establish a separate process (such as a "set side” (for example, a special program approved by the Commission, i.e. the Phase 2 Community Based Renewable Energy tariff program for projects under 250 kW)," separate RFP process, or standard form RFP) to acquire System Resources where such mechanisms or processes are deemed more suitable to meet IGP objectives. 5. RFP processes shall be flexible and shall not include unreasonable restrictions on sizes and types of projects considered, taking into account the appropriate Grid Needs identified in a Grid Needs Assessment. C. RELATIONSHIP TO INTEGRATED GRID PLANNING 1. The Grid Needs Assessment, presented to stakeholders and the Commission for review and comment, shall identify Grid Needs. The identified Grid Needs applicable to each electric utility shall continue to be used to set the strategic direction of resource planning by the electric utilities. In order for competitive bidding to be effectively and efficiently integrated into a utility's IGP process, stakeholders must work cooperatively to identify and adhere to appropriate timelines, which may from time to time need to be expedited. 2. This Framework is intended to complement the IGP process. 3. A determination shall be made by the Commission as to whether a competitive bidding process shall be used to acquire a System Resource or a block of System Resources that are identified as Grid Needs in the Grid Needs Assessment. Actual competitive bidding for System Resources will normally occur after the Grid Needs are identified, reviewed and accepted or approved by the Commission.
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4. Integration of competitive bidding into the IGP process. The general approach to integration has four parts, in sequence: a. The electric utility conducts a Grid Needs Assessment, which will identify those Grid Needs for which the utility proposes and recommends to procure through competitive bidding or other mechanisms or processes, and those resources for which the utility seeks a waiver from competitive bidding. b. The Commission accepts, approves, modifies, or rejects the Grid Needs Assessment and the Grid Needs recommended to be acquired through this Framework. c. The electric utility conducts a competitive bidding process, for System Resources to meet all or a portion of the Grid Needs recommended for competitive bidding identified in the Grid Needs Assessment step of the IGP process; such competitive bidding process shall include the advance filing of a draft RFP with the Commission. d. The electric utility selects a winner from the bidders. But see Part II.C.6, below, concerning the process when there are no bidders worth choosing. 5. An evaluation of bids in a competitive bidding process may reveal desirable projects that were not included in the Grid Needs identified through the Grid Needs Assessment. These projects may be selected if it can be demonstrated that the project is consistent with an approved or accepted Grid Needs Assessment and that such action is expected to benefit the utility and/or its customers. 6. An evaluation of bids in a competitive bidding process may reveal that the acquisition of any of the requested System Resources in the bid will not assist the utility in fulfilling its obligations to its customers. In such a case, the utility may determine not to acquire such System Resources and shall notify the Commission accordingly. D. MITIGATION OF RISKS ASSOCIATED WITH COMPETITIVE BIDDING
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1. To carry out its competitive bidding obligations consistently with its resource sufficiency obligations, the electric utility must conduct, or consider conducting, two types of activities: self-build and contingency planning. The utility's self-build obligation is addressed in Parts VI.A.1, VI.C and VI.E, below. The electric utility's contingency planning activities are discussed in Part II.D.2 below. 2. In consideration of the isolated nature of the island utility systems, the utility may use a Contingency Plan option to address a near-term reliability or statutory need as results from an actual or expected failure of an RFP process to produce a viable project proposal, or of a project selected in an RFP. The electric utility shall use prudent electric utility practices to determine the nature, amount, and timing of the contingency planning activities and take into account (without limitation) the cost of contingency planning and the probability of third-party failure. The electric utility's Contingency Plan may differ from that proposed in the electric utility's self-build bid. For each project that is subject to competitive bidding, the electric utility shall submit a report on the cost of contingency planning upon the Commission's request. 3. The electric utility may require bidders (subject to the Commission's approval with other elements of a proposed RFP) to offer the utility the option to purchase the project under certain conditions or in the event of default by the seller (i.e., the bidder), subject to commercially reasonable payment terms. III. ROLES IN COMPETITIVE BIDDING A. ELECTRIC UTILITY 1. The role of the host electric utility in the competitive bidding process shall include: a. Designing the solicitation process, establishing evaluation criteria consistent with its overall IGP process, and specifying timelines; b. Designing the RFP documents and proposed forms of
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Agreements and other contracts; c. Implementing and managing the RFP process, including communications with bidders; d. Evaluating the bids received; e. Selecting the bids for negotiations based on established criteria; f. Negotiating contracts with selected bidders; g. Determining, where and when feasible, the interconnection facilities and transmission and distribution upgrades necessary to accommodate new System Resources; h. Competing in the solicitation process with a self-build option at its discretion; if approved by the Commission; and i. Providing the Independent Observer with all requested information related to the relevant procurement. 2. Access to Utility Sites. The utility shall consider, on a case-by-case basis before an RFP is issued, offering at its sole discretion one or several utility-owned or controlled sites to bidders in an applicable competitive bidding process. The utility shall consider such factors as:
a. The anticipated specific non-technical terms of potential proposals. b. The feasibility of the installation. Examples of the factors that may need to be examined in order to evaluate the feasibility of the installation may include, but are not be limited to the following:
(i) Specific physical and technical parameters of anticipated non-utility installations, such as the technology that may be installed, space and land area requirements, topographic, slope and geotechnical constraints, fuel logistics, water requirements, number of site personnel, access requirements, waste and emissions from
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operations, noise profile, electrical interconnection requirements, and physical profile; and
(ii) How the operation, maintenance, and construction of each installation will affect factors such as security at the site, land ownership issues, land use and permit considerations (e.g., compatibility of the proposed development with present and planned land uses), existing and new environmental permits and licenses, impact on operations and maintenance of existing and future facilities, impact to the surrounding community, change in zoning permit conditions, and safety of utility personnel. c. The utility's anticipated future use of the site. Examples of why it may be beneficial for the utility to maintain site control may include, but are not limited to the following: (i) to ensure that System Resources can be constructed to meet system reliability requirements; (ii) to retain flexibility for the utility to perform crucial contingency planning for a utility owned option to back-up any potential unfulfilled commitments, if any, of third-party developers of System Resources; and (iii) to retain the flexibility for the utility to acquire the unique efficiency gains from expansion of existing transmission and distribution facilities or combined-cycle conversions and repowering projects of existing utility simple-cycle combustion turbines and steam fired generating facilities, respectively. d. The effect on competitive forces of denying bidders the ability to use the site, taking into account whether the unavailability of adequate sites for non-utility bidders gives the electric utility a competitive advantage.
e. Where the utility has chosen not to offer a site to a third-party, the electric utility shall present its reasons, specific to the project and sites at issue, in writing to the Independent Observer and the Commission.
f. Where the utility is using a utility-owned (in fee simple) site in a self-build option, the utility shall offer that utility-owned site to bidders, unless it is demonstrated to the Independent
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Observer and the Commission that doing so would be
unreasonable.
3. The utility shall submit to the Commission for review and approval (subject to modification if necessary), a Code of Conduct described in Part IV.H.9.c, below, with the draft RFP. The utility shall follow the Code of Conduct prior to the commencement of the RFP drafting even while such Code of Conduct is pending before the Commission
for review and approval. 4. The utility shall ensure third party bidders be provided the same type of information to develop proposals as is provided to those
developing self-build or Affiliate-bid proposals.
B. HAWAII PUBLIC UTILITIES COMMISSION 1. The primary role of the Commission is to ensure that: (a) each competitive bidding process conducted pursuant to this Framework is fair in its design and implementation so that selection is based on the merits; (b) System Resources selected through competitive bidding processes are consistent with the Grid Needs identified in the Commission approved/accepted Grid Needs Assessment; (c) the electric utility's actions represent prudent practices; and (d) throughout the process, the utility's interests are aligned with the public interest even where the utility has dual roles as designer and participant. 2. The Commission may review, and at its option, approve or modify, each proposed RFP before it is issued, including any proposed form of contracts and other documentation that will accompany the RFP. The Commission may determine in certain applications that it may pre-approve a form RFP in lieu of approving each individual RFP. If a form RFP is approved, any modifications to such form, other than insertion of the specific Grid Needs being procured, would require approval by the Commission.
3. The Commission shall be the final arbiter of disputes that arise among parties in relation to a utility's competitive bidding process, to the extent described in Part V, below.
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4. The Commission shall review, and approve or reject, the contracts
that result from competitive bidding processes conducted pursuant to this Framework, in a separate docket upon application by the utility in which the expedited process in Part III.B.7 shall not apply. In reviewing such contracts, the Commission may establish review
processes that are appropriate to the specific circumstances of each solicitation, including the time constraints that apply to each commercial transaction. 5. If the utility identifies its self-build project for Grid Needs as superior to third party bid proposals, the utility shall seek Commission approval in keeping with established CIP Approval Requirements.
6. The Commission shall review any complaint that the electric utility is not complying with the Framework, pursuant to Part V. 7. Timely Commission review, approval, consent, or other action described in this Framework is essential to the efficient and effective execution of this competitive bidding process. Accordingly, to expedite Commission action in this competitive bidding process, whenever Commission review, approval, consent, or action is required under this Framework, the Commission may do so in an informal expedited process. The Commission hereby authorizes its Chair, or his or her designee (which designee, may be another Commissioner, a member of the Commission staff, Commission hearings officer, or a Commission hired consultant), in consultation with other Commissioners, Commission staff, and the Independent Observer, to take any such action on behalf of the Commission. C. INDEPENDENT OBSERVER 1. An Independent Observer is required whenever the utility or its Affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders) in response to a need that is addressed by its RFP, or when the Commission otherwise determines. Unless otherwise determined by the Commission, an Independent Observer will monitor the competitive bidding process and will report on the progress and results to the Commission, sufficiently early so that the Commission is
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able to address any defects and allow competitive bidding to occur in time to meet the utility’s Grid Needs. Any interaction between a utility and bidder, including a utility’s self-build team or Affiliate during the course of a solicitation process, beginning with the preparation of the RFP, shall be closely monitored by the Independent Observer. Specific tasks to be performed by the Independent Observer shall be identified by the utility in its proposed RFP and as may be required by the Commission. 2. Independent Observer obligations. The Independent Observer will have duties and obligations in two areas: Advisory and Monitoring. a. Advisory. The Independent Observer shall: (i) Certify to the Commission that at each of the following steps, the electric utility's judgments created no unearned advantage for any bidder, or, when applicable, the electric utility or any Affiliate: (1) Pre-qualification criteria; (2) RFP; (3) Model Agreements to be attached to the RFP; (4) Selection criteria; (5) Evaluation of bids; (6) Final decision to purchase System Resources or proceed with self-build option when applicable; and (7) Negotiation of contracts. (ii) Advise the electric utility on its decision-making during, and with respect to, each of the electric utility's actions listed in the preceding item; (iii) Review stakeholder comments submitted in response to draft RFP and model Agreements and advise the utility on the consideration of proposed changes that
may improve the process or results of the RFP;
(iv) Report immediately to the electric utility's executive in charge of ensuring compliance with this Framework, and the Commission, any deviations from the
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Framework or violations of any procurement rules;
(v) After the electric utility's procurement selection is completed, provide the Commission with: (1) An overall assessment of whether the goals of the RFP were achieved, such goals to include without
limitation the attraction of a sufficient number of bidders and the elimination of actual or perceived utility favoritism for its own or an Affiliate's project; and (2) Recommendations for improving future competitive bidding processes.
(vi) Be available to the Commission as a witness if required
to evaluate a complaint filed against an electric utility for non-compliance with this Framework, or if required in a future regulatory proceeding if questions of prudence arise. b. Monitoring. The Independent Observer shall: (i) Monitor all steps in a competitive bidding process, beginning upon Commission’s approval or acceptance of the Grid Needs Assessment; (ii) Monitor communications (and communications protocols) with bidders;
(iii) Monitor adherence to Codes of Conduct; (iv) Monitor contract negotiations with bidders; (v) Monitor all interactions between the electric utility and any bidder during all events affecting a solicitation process; and
(vi) Report to the Commission on monitoring results during
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each stage of the competitive process sufficiently early so that the Commission can correct defects or eliminate uncertainties without endangering project milestones. 3. The Independent Observer shall have no decision-making authority, and no obligation to resolve disputes, but may offer to mediate between disputing parties. 4. The Independent Observer shall provide comments and recommendations to the Commission, at the Commission's request, to assist in resolving disputes or in making any required determinations under this Framework. 5. Independent Observer qualifications. The Independent Observer shall be qualified for the tasks the observer must perform. Specifically, the Independent Observer shall: a. Be knowledgeable about, or be able rapidly to absorb knowledge about, any unique characteristics and needs of the electric utility; b. Be knowledgeable about the characteristics and needs of small, non-interconnected island electric grids, and be aware of the unique challenges and operational requirements of such systems; c. Have the necessary experience and familiarity with utility modeling capability, transmission and/or distribution system planning, operational characteristics, and other factors that affect project selection; d. Have a working knowledge of common operational, technical and contract terms applicable to System Resources as well as appropriate contract negotiation processes applicable to System Resource procurement; e. Be able to work effectively with the electric utility, the Commission, and its staff during the bid process; and f. Demonstrate impartiality.
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6. Selection and contracting. As ordered or directed by the Commission, the electric utility or the Commission shall: (a) identify qualified candidates for the role of Independent Observer (and also shall consider qualified candidates identified by prospective participants in the competitive bidding process); (b) comply with further orders or direction from the Commission as to the final list of qualified candidates; and (c) select an Independent Observer from among the final list of qualified candidates. The contract with the Independent Observer shall be acceptable to the electric utility and the Commission, and provide, among other matters, that the Independent Observer: (a) report to the Commission and carry out such tasks as directed by the Commission, including the tasks described in this Framework; (b) cannot be terminated and payment cannot be withheld without the consent of the Commission; and (c) can be terminated by the Commission without the utility's consent, if the Commission deems it to be in the public interest in the furtherance of the objectives of this Framework to do so. In the event the electric utility contracts with the Independent Observer, and accrues carrying costs on the deferred costs at the utility’s allowance for funds used during construction (“AFUDC”) rate, applied monthly on the deferred costs (including AFUDC), the utility shall recover prudently incurred Independent Observer costs and related carrying costs upon Commission approval through a Commission approved regulatory process or mechanism. 7. As part of the RFP design process, the utility shall develop procedures to be included in the RFP by which any participant in the competitive bidding process may present to the Commission, for review and resolution, positions that differ from those of the Independent Observer (i.e., in the event the Independent Observer makes any representations to the Commission upon which the participant does not agree). IV. THE REQUEST FOR PROPOSALS PROCESS A. GENERAL 1. Competitive bidding shall be structured and implemented in a way that facilitates an electric utility's acquisition of System Resources identified in a utility's Grid Needs Assessment. Direct costs and benefits incurred
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or received by the utility and its customers shall be taken into account in the bid evaluation and selection process. 2. Competitive bidding shall be structured and implemented in a flexible and efficient manner that promotes electric utility system reliability by facilitating the timely acquisition of needed System Resources and allowing the utility to adjust to changes in circumstances. a. The implementation of competitive bidding cannot be allowed to negatively impact reliability of the electric utility system. b. The System Resources acquired under a competitive bidding process must meet the needs of the utility in terms of the reliability of the System Resources, the characteristics of the System Resources required by the utility, and the control the utility needs to exercise over operation and maintenance in order to minimize system integration concerns.
3. The competitive bidding process shall ensure that proposals and bidders are judged on the merits, without being unduly burdensome to the electric utilities or the Commission.
a. The competitive bidding process shall include an RFP and
supporting documentation by which the utility sets forth the requirements to be fulfilled by bidders and describes the process by which it will: (i) conduct its solicitation; (ii) obtain consistent and accurate information on which to evaluate bids;
(iii) implement a consistent and equitable evaluation process; and (iv) systematically document its determinations. The RFP shall also describe the role of the Independent Observer and bidders' opportunities for challenges and for dispute
resolution.
b. When a utility advances its own project proposal (i.e., in competition with those offered by bidders) or accepts a bid from an Affiliate, the utility shall take all reasonable steps, including any steps required by the Commission, to mitigate concerns over an unfair or unearned competitive advantage
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that may exist or reasonably be perceived by other bidders or stakeholders. 4. If a Provider or Affiliate proposal is selected as a result of the RFP process, one or more contracts are the expected result. Proposed forms of Agreements and other contracts that may result from the RFP process shall be included with each RFP. The RFP shall specify whether any opportunity exists to propose or negotiate changes to the proposed form of Agreement or contract.
B. DESIGN OF THE COMPETITIVE BIDDING SOLICITATION PROCESS 1. The competitive bidding solicitation process shall include the following: a. Design of the RFP and supporting documents; b. Issuance of the draft and final RFP; c. Development and submission of proposals by bidders; d. A "multi-stage evaluation process" to reduce bids down to a short list and/or "award group" as appropriate for a particular RFP (i.e., a process that may include, without limitation: (i) receipt of the proposals; (ii) completeness check; (iii) threshold
or minimum requirements evaluation; (iv) initial evaluation including price screen/non-price assessment; (v) selection of a short list; (vi) detailed evaluation or portfolio development; and (vii) selection of final award group for contract negotiation);
e. Contract negotiations (when a third-party bid is selected); and f. Commission approval of any resulting contract or selected self-build project if required by the Commission. 2. The RFP shall identify any unique system requirements and provide information regarding the requirements of the utility, important resource attributes, desired options and criteria used for the evaluation. For example, if the utility values dispatchability or operating flexibility, the
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RFP shall: (a) request that a bidder offer such an option; and (b) explain how the utility will evaluate the impacts of dispatchability or operational flexibility in the bid evaluation process. 3. The RFP (including the response package, proposed forms of Agreements and other contracts) shall describe the bidding guidelines, the bidding requirements to guide bidders in preparing and submitting their proposals, the general bid evaluation and selection criteria, the risk factors important to the utility, and, to the extent practicable, the schedule for all steps in the bidding process. 4. The utility may charge bidders a reasonable fee, to be reviewed by the Independent Observer, for participating in the RFP process. 5. Other Content of RFP. The RFP shall also contain: a. The circumstances under which an electric utility and/or its Affiliates may participate; b. An explanation of the procedures by which any person may present to the Commission positions that differ from those of the Independent Observer; and c. A statement that if disputes arise under this Framework, the dispute resolution process established in this Framework will control. 6. The process leading to the distribution of the RFP shall include the following steps (each step to be monitored and reported on by the Independent Observer), unless the Commission modifies this process for a particular competitive bid: a. The utility designs a draft RFP, then files its draft RFP and supporting documentation with the Commission;
b. The Commission holds a status conference, where the utility presents the details of the RFP and interested parties (which may include potential bidders) are provided the opportunity to ask questions regarding the draft RFP;
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c. Interested parties submit comments on the draft RFP to the
utility and the Commission;
d. The utility determines, with advice from the Independent Observer, whether and how to incorporate recommendations from interested parties in the draft RFP; e. The utility submits its final, proposed RFP to the Commission for its review and approval (and modification if necessary)
according to the following procedure:
(i) The Independent Observer shall submit its comments and recommendations to the Commission concerning the RFP and all attachments, simultaneously with the
electric utility's proposed RFP.
(ii) The utility shall have the right to issue the RFP if the Commission does not direct the utility to do otherwise within thirty (30) days after the Commission receives the proposed RFP and the Independent Observer's comments and recommendations. 7. A pre-qualification requirement is a requirement that a bidder must satisfy to be eligible to bid. A pre-qualification process may be incorporated in the design of some bidding processes, depending on the specific circumstances of the utility and its resource needs. Any pre-qualification requirements shall apply equally to independent bidders, the electric utility's self-build bid, and the bid of any utility's Affiliate. 8. As part of the RFP design process, the utility shall develop and specify the type and form of threshold criteria that will apply to all bidders, including the utility's self-build proposals. Examples of potential threshold criteria include requirements that bidders have site control,
maintain a specified credit rating, and demonstrate that their proposed technologies are mature.
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9. The RFP design process shall address credit requirements and
security provisions, which apply to: (a) the qualification of bidders; and (b) bid evaluation processes.
10. The utility shall have the discretion to modify the RFP or solicit additional bids from bidders after reviewing the initial bids, provided that such discretion is clearly identified in the RFP and any modification is reviewed by the Independent Observer and
submitted to the Commission along with the Independent Observer's comments. The electric utility may issue the modified RFP thirty (30) days after the Commission has received these materials, unless the Commission directs otherwise. 11. All involved parties shall plan, collaborate, and endeavor to issue the final RFP within ninety (90) days from the date the electric utility submits the draft RFP to the Commission. C. FORMS OF CONTRACTS 1. The RFP shall include proposed forms of Agreements and other contracts, with commercially reasonable terms and conditions that properly allocate risks among the contracting parties in light of circumstances. The terms and conditions of the contracts shall be specified to the extent practical, so that bidders are aware of, among other things, performance requirements, pricing options, key provisions that affect risk allocation (including those identified in sub-paragraph 2 below), and provisions that may be subject to negotiation. Where contract provisions are not finalized or provided in advance of RFP issuance (e.g., because certain contract provisions must reflect features of the winning bidder's proposal such as technology or location), the RFP shall so indicate. 2. The provisions of a proposed contract shall address matters such as the following (unless inapplicable): (a) reasonable credit assurance and security requirements appropriate to an island system that reasonably compensates the utility and its customers if the project sponsor fails to perform; (b) contract buyout and project acquisition provisions; (c) in-service date delay and acceleration provisions; and (d) liquidated damage provisions that reflect risks to the utility and its customers.
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APPENDIX G – REVISED FRAMEWORK FOR COMPETITIVE BIDDING
3. The RFP shall specify which terms in the proposed forms of contract, if any, are not subject to negotiation or alternative proposals, subject to approval of the RFP by the Commission. Bidders may submit alternative language as part of their bids, provided that any such variation is not inconsistent with any identified Grid Needs. D. ISSUANCE OF THE RFP AND DEVELOPMENT OF PROPOSALS 1. Each electric utility shall take steps to provide notice of its RFPs to, and encourage participation from, the full community of prospective bidders.
2. Bidders may be required to submit a "notice of intent to bid" to the electric utility. 3. The electric utility shall develop and implement a formal process to respond to bidders' questions.
4. The electric utility may conduct a bidders' conference. 5. The electric utility shall provide bidders with access to information through a website where it can post documents and information.
6. The process shall require all third-party bids to be submitted by the deadline specified in the RFP, except that the utility’s self-build bid shall be submitted one day in advance.
7. Bids may be deemed non-conforming if they do not meet the RFP requirements or provide all of the material information requested in an RFP. At the utility's discretion, in consultation with the Independent Observer, the utility may elect to: (i) consider a non-conforming bid as eligible in the RFP provided it is not inconsistent with any identified Grid Needs; (ii) give proposals that are non-conforming additional time to remedy their non-conformity; or (iii) decline to consider any bid that is non-conforming. E. BID EVALUATION / SELECTION CRITERIA
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APPENDIX G – REVISED FRAMEWORK FOR COMPETITIVE BIDDING
1. The utility, monitored by the Independent Observer, shall compare bids received. 2. The evaluation criteria and the respective weight or consideration given to each such criterion in the bid evaluation process may vary
from one RFP to another.
3. The bid evaluation process shall include consideration of differences
between bidders with respect to proposed contract provisions, and differences in anticipated compliance with such provisions, including but not limited to provisions intended to ensure: a. System Resource and electric system reliability; b. Appropriate risk allocations; c. Counter-party creditworthiness; and
d. Bidder qualification. 4. Proposals shall be evaluated based on a consistent and reasonable set of economic and fuel price assumptions, to be specified in the RFP. 5. Both price and non-price evaluation criteria, shall be described in the RFP, and shall be considered in evaluating proposals. 6. In evaluating competing proposals, all relevant incremental costs to the electric utility and its customers shall be considered. These may include transmission costs, distribution costs and system impacts, and the reasonably foreseeable balance sheet and related financial impacts of competing proposals. 7. The impact of service(s) from System Resources that a utility already has on its system, in terms of reliability and dispatchability, and the impacts that increasing the amount of service(s) from new System Resources may have, in terms of reliability and dispatchability, shall be taken into account in the bid evaluation. The RFP shall specify the methodology for considering this effect. Such methodology shall not cause double-counting with the financial effects discussed in sub-paragraph 6, above,
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APPENDIX G – REVISED FRAMEWORK FOR COMPETITIVE BIDDING
and sub-paragraph 8, below. 8. The impact of System Resource costs on the utility's balance sheets, and the potential for resulting utility credit downgrades (and higher borrowing costs), may be accounted for in the bid evaluation. Where the utility has to restructure its balance sheet and increase the percentage of more costly equity financing in order to offset the impacts of purchasing service(s) from a third party owned System Resource on its balance sheet, this rebalancing cost shall also be taken into account in evaluating the total cost of a proposal for a new System Resource if third party owned, and it may be a requirement that bidders provide all information necessary to complete these evaluations. The RFP shall describe the methodology for considering financial effects. 9. The type and form of non-price threshold criteria shall be identified in the RFP. Such threshold criteria may include, among other criteria, the following: a. Project development feasibility criteria (e.g., siting status, ability to finance, environmental permitting status, commercial operation date certainty, engineering design, fuel supply status, bidder experience, participant acquisition strategy, conformance with utility information assurance and security policies and reliability of the technology); b. Project operational viability criteria (e.g., operation and maintenance plan, financial strength, environmental compliance, and environmental impact); c. Operating profile criteria (e.g., dispatching and scheduling, coordination of maintenance, operating profile such as ramp rates, and quick start capability); and d. Flexibility criteria (e.g., in-service date flexibility, expansion capability, contract term, contract buy-out options, fuel flexibility, and stability of the price proposal). 10. The weights for each non-price criterion shall be fully specified by the utility in advance of the submission of bids, as they may be based on
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APPENDIX G – REVISED FRAMEWORK FOR COMPETITIVE BIDDING
an iterative process that takes into account the relative importance of
each criterion given system needs and circumstances in the context of a particular RFP. The Commission, however, may approve of less than full specification prior to issuance of the RFP. Since the subjectivity inherent in non-price criteria creates risk of bias and diminution in bidders' trust of the process, the RFP must specify likely areas of non-price evaluation, and the evaluation process must be closely monitored and publicly reported on by the Independent Observer.
F. EVALUATION OF THE BIDS 1. The evaluation and selection process shall be identified in the RFP, and may vary based on the scope of the RFP. In some RFP processes, a multi-stage evaluation process may be appropriate. 2. The electric utility shall document the evaluation and selection process for each RFP process for review by the Commission in approving the outcome of the process (i.e., in approving an
Agreement or a utility self-build proposal).
3. A detailed system evaluation process, which uses models and methodologies that are consistent with those used in the utility's Grid Needs Assessment, may be used to evaluate bids. In anticipation of such evaluation processes, the RFP shall specify the data required of
bidders.
G. CONTRACT NEGOTIATIONS 1. There may be opportunities to negotiate price and non-price terms to enhance the value of the contract for the bidder, the utility, and its
customers. Negotiations shall be monitored and reported upon by
the Independent Observer.
2. The electric utility may use competitive negotiations among short-listed bidders. H. FAIRNESS PROVISIONS AND TRANSPARENCY
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APPENDIX G – REVISED FRAMEWORK FOR COMPETITIVE BIDDING
1. The competitive bidding process shall judge all bidders on the merits only. 2. During the bidding process, the electric utility shall treat all bidders, including any utility Affiliate, the same in terms of access to
information, time of receipt of information, and response to questions. 3. A "closed bidding process" is generally anticipated, rather than an "open bidding process." Under one type of closed bidding process,
bidders are informed through the RFP of: (a) the process that will be used to evaluate and select proposals; (b) the general bid evaluation and selection criteria; and (c) the proposed forms of Agreements and other contracts. However, bidders shall not have access to the utility's
bid evaluation models, the detailed criteria used to evaluate bids, or information contained in proposals submitted by other bidders.
4. If the electric utility chooses to use a closed process: a. The utility shall provide the Independent Observer, if an Independent Observer is required, with all the necessary information to allow the Independent Observer to understand the model and to enable the Independent Observer to observe the entire analysis in order to ensure a fair process; and b. After the utility has selected a bidder, the utility shall meet with the losing bidder or bidders to provide a general assessment of the losing bidder's specific proposal if requested by the
losing bidder within seven (7) days of the selection.
5. The host electric utility shall be allowed to consider its own self-bid proposals in response to Grid Needs identified in its RFP. 6. Procedures shall be developed by the utility prior to the initiation of
the bidding process to define the roles of the members of its various
project teams, to outline communications processes with bidders, and to address confidentiality of the information provided by bidders. Such procedures shall be submitted in advance to the Independent
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Observer and the Commission for comment.
7. If the IGP process indicates that a competitive bidding process will be used to acquire a System Resource or a block of System Resources to meet all or a portion of the Grid Needs, then the utility will indicate, in the submittal of its draft RFP to the Commission for review, which of the RFP process guidelines will be followed, the reasons why other guidelines will not be followed in whole or in part, and other process steps proposed based on good solicitation practice; provided that the Commission may require that other process steps be followed. 8. If proposed, utility self-build projects or other utility-owned projects, or projects owned by an Affiliate of the host utility, are to be compared against third party proposals obtained through an RFP process. The Independent Observer shall monitor the utility's conduct of its RFP process, advise the utility if there are any fairness issues, and report to the Commission at various steps of the process, to the extent prescribed by the Commission. Specific tasks to be performed by the Independent Observer, including those as may be prescribed by the Commission, shall be identified by the utility in its proposed RFP submitted to the Commission for approval. The Independent Observer will review and track the utility's execution of the RFP process to ascertain that no undue preference is given to an Affiliate, the Affiliate's bid, or to self-build or other utility-owned facilities. The Independent Observer's review shall include, to the extent the Commission or the Independent Observer deems necessary, each of the following steps, in addition to any steps the Commission or Independent Observer may add: (a) reviewing the draft RFP and the utility's evaluation of bids, monitoring communications (and communications protocols) with bidders; (b) monitoring adherence to codes of conduct, and monitoring contract negotiations with bidders; (c) assessing the utility's evaluation of Affiliate bids, and self-build or other utility-owned projects; and (d) assessing the utility's evaluation of an appropriate number of other bids. The utility shall provide the Independent Observer with all requested information. Such information may include, without limitation, the utility's evaluation of the unique risks and advantages associated with the utility self-build or other utility-owned projects, including the regulatory treatment of construction cost variances (both underages and overages) and costs related to equipment performance, contract terms offered to or required of bidders that affect
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the allocation of risks, and other risks and advantages of utility self-build or other utility-owned projects to consumers. The Independent Observer may validate the criteria used to evaluate Affiliate bids and self-build or other utility-owned facilities, and the evaluation of Affiliate bids and self-build or other utility-owned facilities. In order to accomplish these tasks, the utility, in conjunction with the Independent Observer, shall propose methods for making fair comparisons (considering both cost and risks) between the utility-owned or self-build facilities and third-party facilities.
9. Where the electric utility is responding to its own RFP, or is accepting bids submitted by its Affiliates, the utility will take additional steps to avoid self-dealing in both fact and perception. a. The following tasks shall be completed as a matter of course (i.e., regardless of whether the utility or its Affiliate is seeking to advance a proposal), including: (i) the utility shall develop all bid evaluation criteria, bid selection guidelines, and the quantitative evaluation models and other information necessary for evaluation of bids prior to issuance of the RFP; (ii) the utility shall establish a website for disseminating information to all bidders at the same time; and (iii) the utility shall develop and follow a Procedures Manual, which describes: (1) the protocols for communicating with bidders, the self-build team, and others; (2) the evaluation process in detail and the methodologies for undertaking the evaluation process; (3) the documentation forms, including logs for any communications with bidders; and (4) other information consistent with the requirements of the solicitation process. b. The following tasks shall be completed whenever the utility is seeking to advance a System Resource proposal, including: (i) the utility shall submit its self-build bid one day in advance of the deadline specified in the RFP, and provide substantially the same information in its proposal as other bidders; (ii) the utility shall follow the Code of Conduct; and (iii) the utility shall implement appropriate confidentiality agreements prior to the issuance of the RFP to guide the roles and responsibilities of utility personnel. c. The Code of Conduct shall be signed by each utility employee involved either in advancing the self-build project or implementing the competitive bidding process, and shall require
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that: (i) Whenever staffing and resources permit, the electric utility shall establish internally a separate project team to undertake the evaluation, with no team member having any involvement with the utility self-build option; (ii) During the RFP design and bid evaluation process, there shall be no oral or written contacts between the employees preparing the bid and the electric utility's employees responsible for bid evaluation, other than contacts authorized by the Code of Conduct and the RFP;
(iii) Throughout the bidding process, the electric utility shall treat all bidders, including its self-build bid and any electric utility Affiliate, the same in terms of access to
information, time of receipt of information, and response to questions.
d. A company officer, identified to the Independent Observer and the Commission, shall have the written authority and obligation to enforce the Code of Conduct. Such officer shall certify, by affidavit, Code of Conduct compliance by all
employees after each competitive process ends. e. Further steps may be considered, as appropriate, or ordered by the Commission. 10. Where the utility seeks to advance its proposed facilities in addition to, or instead of other developers’ bids in its RFP, its proposal must satisfy all the criteria applicable to non-utility bidders, including but not limited to providing all material information required by the RFP, and being capable of implementation. 11. Bids submitted by Affiliates shall be held to the same contractual and other standards as projects advanced by other bidders.
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APPENDIX G – REVISED FRAMEWORK FOR COMPETITIVE BIDDING
I. TRANSMISSION INTERCONNECTION AND UPGRADES 1. A winning bidder has the right to interconnect its System Resource to the electric utility's transmission and distribution system, and to have that transmission and distribution upgraded as necessary to accommodate the output of its System Resource. 2. With respect to procedures and methodologies for: a. Designing interconnections; b. Allocating the cost of interconnections; c. Scheduling and carrying out the physical implementation of interconnections; d. Identifying the need for transmission and distribution upgrades; e. Allocating the cost of transmission and distribution upgrades; and f. Scheduling and carrying out the physical implementation of transmission and distribution upgrades;
the electric utility shall treat all bidders, including its own bid and
that of any Affiliate, in a comparable manner. 3. Upon the request of a prospective bidder, the electric utility shall provide general information about the possible interconnection and transmission and distribution upgrade costs associated with project locations under consideration by the bidder.
4. To ensure comparable treatment, the Independent Observer shall review and monitor the electric utility's policies, methods and
implementation and report to the Commission. V. DISPUTE RESOLUTION PROCESS
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APPENDIX G – REVISED FRAMEWORK FOR COMPETITIVE BIDDING
The Commission will serve as an arbiter of last resort, after the utility,
Independent Observer, and bidders have attempted to resolve any dispute or
pending issue. The Commission will use an informal expedited process to resolve the dispute within thirty (30) days, as described in Part III.B.7. There shall be no right to hearing or appeal from this informal expedited dispute resolution
process. The Commission encourages affected parties to seek to work cooperatively to resolve any dispute or pending issue, perhaps with the assistance of an Independent Observer, who may offer to mediate but who has no decision-making authority. The utility and Independent Observer shall conduct informational meetings with the Commission and Consumer Advocate to keep each apprised of issues that arise between or among the parties. VI. PARTICIPATION BY THE HOST UTILITY A. Where the electric utility is addressing a system reliability issue or statutory requirement, the utility shall develop one or more project proposals that are responsive to the System Resource need identified in the RFP.
B. If the utility opts not to propose its own project, the utility shall request and
obtain the Commission's approval. In making this request, the utility shall demonstrate why relying on the market to provide the needed resource is prudent. C. Where the RFP process has as its focus something other than a reliability-based need, the utility may choose (or decline) to advance its own project proposal. D. If the RFP process results in the selection of non-utility (or third-party) projects to meet a system reliability need or statutory requirement, the utility shall develop and periodically update a Contingency Plan to address the risk that the third-party projects may be delayed or not completed. In this situation, the electric utility shall separately submit, to the extent practical, a description of such activities and a schedule for carrying them out. Such
description shall be updated as appropriate.
1. The plans may include the identification of milestones for such projects, and possible steps to be taken if the milestones are not met.
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2. Pursuant to the plans, it may be appropriate for the utility to proceed
to develop a utility-owned project or projects until such action can no longer be justified as reasonable. The utility-owned project(s) may differ from the project(s) advanced by the utility in the RFP process, or the resource(s) identified in its Grid Needs Assessment. 3. The contracts developed for the RFP process to acquire third-party resources shall include commercially reasonable provisions that
address delays or non-completion of third-party projects, such as provisions that identify milestones for the projects, seller (i.e., bidder) obligations, and utility remedies if the milestones are not met, and may include provisions to provide the utility with the option to
purchase the project under certain circumstances or events of default by the seller (i.e., the bidder). E. A utility may submit more than one proposal or may supply options for a specific proposal as dictated by the RFP needs, such as submitting variations
of a proposal and/or offering options in a proposal. VII. RATEMAKING A. The costs that an electric utility reasonably and prudently incurs in designing and administering its competitive bidding processes are recoverable through rates to the extent reasonable and prudent.
B. The costs that an electric utility incurs in taking reasonable and prudent steps to implement Contingency Plans are recoverable through the utility's rates, to the extent reasonable and prudent, as part of the cost of providing reliable service to customers. C. The reasonable and prudent costs that are part of an electric utility's Contingency Plans shall be accounted for similar to costs for planning other capital projects (provided that such accounting treatment shall not be determinative of ratemaking treatment):
1. Contingency Plans capital project costs would be accumulated as
construction work in progress, and AFUDC would accrue on such
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costs. If the Contingency Plans capital project costs, as implemented,
result in the addition of planned resources to the utility system, then the costs incurred and related AFUDC would be capitalized as part of the installed resources (i.e., recorded to plant-in-service) and added to rate base. The costs would be depreciated over the life of the resource addition. Subject to Commission approval, the contingency plans capital project, including operations and maintenance expenses, deferred costs, and taxes, shall be recovered through the EPRM mechanism, REIP surcharge or other recovery mechanism, or
other Commission approved regulatory process or mechanism.
2. If implementation of the Contingency Plans capital project is terminated before the resources identified in such plans are placed into service, the costs incurred and related AFUDC included in
construction work in progress would be transferred to a miscellaneous deferred debit account and the balance would be amortized to expense over five years (or a reasonable period determined by the Commission), beginning when rates that reflect
such amortization expense are approved by the Commission in a regulatory process or mechanism. Carrying charges, based on the AFUDC rate, would apply monthly for the costs in the miscellaneous deferred debit account and included in the miscellaneous deferred debit account until the onset of amortization. 3. Cost for Contingency Plans non-capital projects shall be deferred in a deferred debit account, and accrue carrying charges at the AFUDC rate; AFUDC applied monthly on the deferred costs (including AFUDC). The utility shall recover prudently incurred costs for Contingency Plans non-capital projects and related carrying costs upon Commission approval through a Commission approved regulatory process or mechanism. D. Utility-owned or self-build projects will be cost-based, consistent with traditional cost-of-service ratemaking, wherein prudently incurred capital costs including associated AFUDC and/or carrying costs are included in rate base; provided that the evaluation of the utility's bid must account for the possibility that the operational costs actually incurred, and recovered from customers, over the project’s lifetime, will vary from the levels assumed in
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the utility's bid. The utility will not, however, be allowed to recover any
capital costs that exceed the bid amount. Any utility-owned project selected pursuant to the RFP process will remain subject to prudence review in a subsequent proceeding with respect to the utility's obligation to prudently implement, construct or manage the project consistent with the objective of providing reliable service at the lowest reasonable cost. Subject to Commission approval, the utility-owned or self-build project costs, including operations and maintenance expenses, deferred costs, and taxes, shall recovered through the MPIR adjustment mechanism, REIP surcharge, or
other Commission approved regulatory process or mechanism.
VIII. QUALIFYING FACILITIES A. For any resource to which the competitive bidding requirement does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a QF at avoided cost upon reasonable terms and conditions approved by the Commission. B. For any resource to which the competitive bidding requirement does apply, the utility shall apply to the commission to waive or modify the time periods described in Hawaii Administrative Rules § 6-74-lS(c) (1998) for the utility to negotiate with a QF pursuant to the applicable provisions of Hawaii Administrative Rules § 6-74-lS(c) (1998), and upon approval of the Commission, the utility's obligation to negotiate with a QF shall be deferred pending completion of the competitive bidding process.
1. If a non-QF is the winning bidder: a. A QF will have no PURPA right to supply the resource provided by a non-QF winning bidder. b. If a non-QF winner does not supply all the capacity needed by the utility, or if a need develops between RFPs that will not be satisfied by an RFP due to a waiver or exemption, a QF, upon submitting a viable offer, is permitted to exercise its PURPA
rights to sell at avoided cost. The Commission's determination
of avoided cost will be bounded by the price level established by
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the winning non-QF.
2. Where the winning bidder is the utility's self-build option, a QF will not have a PURPA right to supply the resource provided by the utility's self-build option. 3. If a QF is the winning bidder, the QF has the right to sell to the electric utility at its bid price, unless the price is modified in the contract negotiations that are part of the bidding process.
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Appendix H:
Comments on
Draft IGP Report
H-2 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
1 Comments on
Draft IGP Report
Provided in this section is a compilation of comments received from the public, PUC staff and technical
advisory panel in response to the Draft Integrated Grid Plan filed on March 31, 2023. We received
comments through our website at, https://hawaiipowered.com/igpreport/, through public comments filed in Docket No. 2018-0165 and other comments through email. To notify the public of the Draft Integrated Grid Plan and invite submission of comments, we issued a press release on April 3, 2023 (available at, https://www.hawaiianelectric.com/hawaiian-electric-seeks-public-comment-on-draft-
integrated-grid-plan-a-pathway-to-a-clean-energy-future) inviting the public to submit comments
through April 21, 2023. We promoted the issuance of the Integrated Grid Plan on social media, and local print and news media also ran stories inviting public comments to the report.1
1. Public Comments
Public comments were collected through the Public Utilities Commission’s online public comment tool, as well as Hawaiian Electric’s online comment form on the IGP viewing website. All comments are weighted equally and Hawaiian Electric does not favor comments from one platform over the other.
Public Question/Comment Hawaiian Electric Response
Maui has some of the most sacred, beautiful mountains and valleys in the world. Please do not place anymore wind turbines on Maui. Follow what Kauai has done (no wind turbines) in their successful renewable energy plan. Wind turbines are not only large, loud, eyesores that destroy the beauty of natural landscapes, they are responsible for killing birds, including Nene. Consider renewables like solar panels instead. Mahalo nui loa.
As we recognize the importance of such locations, we’ll continue to engage communities and require developers to do so as part of the procurement process in identifying the locations and types of projects. Section 10.4 outlines some of the ways we have ensured that communities mutually benefit from large-scale renewable projects.
1. The plan should include customer incentives for demand side management. Recently, we have been asked on Hawaii Island to curtail electric use on several occasions. Customers have responded to these requests. It would be prudent to formally institute a program by which customers are rewarded for curtailing demand. 2. Incentives to customers for installing/upgrading battery systems should be expanded to ail islands. This would reduce grid demand
We are currently working with the Public Utilities Commission and other stakeholders to develop new programs that will be available on all islands and will provide incentives to customers to bring a battery energy storage system to provide services to the grid. These programs should also help to mitigate calls for conservation on Hawaii Island. We hope to introduce these new programs toward the end of this year.
1 See for example, https://bigislandnow.com/2023/04/04/hawaiian-electric-seeks-community-comment-on-pathway-to-clean-energy-future/, https://mauinow.com/2023/04/03/hawaiian-electric-seeks-public-comment-on-draft-integrated-grid-plan/, https://www.kitv.com/video/news/hawaiian-electric-wants-the-publics-thoughts-about-its-integrated-grid-plan/video_3dd82b3a-91bf-5e32-8784-ac5e9746d2c9.html, https://www.staradvertiser.com/2023/04/07/editorial/our-view/editorial-heco-plan-needs-input-from-public/, https://www.staradvertiser.com/2023/04/04/hawaii-news/hawaiian-electric-seeks-public-input-on-clean-energy-plan/, https://www.staradvertiser.com/2023/04/19/editorial/island-voices/column-speak-up-now-on-clean-energy-grid-plan/, https://www.bizjournals.com/pacific/inno/stories/news/2023/04/04/hawaiian-electric-seeks-public-comment.html
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Public Question/Comment Hawaiian Electric Response
and could be instituted quickly and without significant planning/processing.
I echo the concerns of affordability and reliability. When reading the executive summary, I was have more questions:
- How do you build redundancy in the distribution grid? - How do you compensate people for off peak use? - Do you have a way to storage excess energy production?
- What is DER? It is a significant part of the renewable energy production. - How do you address off grid production? - How do you address all the nuclear capacity on ships at Pearl Harbor?
-The distribution grid generally is planned such that if one distribution substation fails or is out of service we have sufficient capacity to supply a neighborhood with a neighboring substation. We are in the process of modernizing the grid to provide more flexibility and reliability to the distribution grid. -Currently we have a single rate for energy consumption. However, later this year, we will roll out more options for customers where rates vary based on the time of electricity use, more information is available at: https://www.hawaiianelectric.com/products-and-services/save-energy-and-money/shift-and-save
-Yes. We have customer programs to store excess energy production such as Battery Bonus, we also have large-scale battery energy storage projects coming online soon.
-DER stands for distributed energy resources and is typically referred to rooftop solar and/or battery energy storage. It could also include energy efficiency, demand response and electric vehicles.
-Off-grid homes are not connected to the grid; therefore, we do not plan to serve those loads, we continue to encourage customers to connect to the grid which helps to keep rates affordable for all. -The ships in Pearl Harbor are not interconnected to the grid so they do not impact our planning and operations. Assuming existing generation sources do not increase the cost of power, these sources must not go offline unless and until the new "green" source of power is online, dependable, and lower's the cost of electricity. The shuttering of the Coal Plant on Oahu is a prime example of poor planning and increasing the cost of power to Hawaii residents. Going renewable is a laudable coal, but making Hawaii electric consumers bear the cost is unacceptable!
Keeping electricity affordable is a main tenet of our Integrated Grid Plan. Currently, we believe that solar, wind and energy storage resources will help to lower cost of electricity relative to fuel oil; however, we do balance new “green” resources with cost and reliability of firm generating resources. In the case of the coal plant, state law mandated its closure by the end of 2022.
1) HECO Stage 3 Maui RFP calls for large utility grade systems to be placed at various locations in Maui. However, the minimum threshold for these projects is fixed at 2.5 MW. This is very high considering paucity of land around existing commercial businesses. 2) All Interconnection Agreements which provide some sort of credit for exported kWh is capped at 100 kW AC. This cap should be eliminated as the export credit is a billing credit and the customer should buy the power at market/retail rate during the billing period from utility to get the benefit from this export credit. 3) Standard Interconnection Agreements do not have a cap presently, but the exported kWh get no credit and thus it is a free source of power to the utility.
We work closely with energy stakeholders and the Public Utilities Commission on providing options for rooftop solar programs to customers. Our Interconnection Agreements and solar programs go through the regulatory process and ultimately approved by the Public Utilities Commission.
I like the idea but do not hear anything on the cost to us current paying our electric bills. Will the bills increase over time while this transition is happening? Will they go down once we no longer use fossil fuel? These are things to consider.
Please see Section 9 of the report. While utility rates may rise in the near-term transition to clean energy, they will be lower and less volatile than if we continue to rely on fossil fuels. Our projections show that customer bills may remain relatively stable and/or flat over the long-term.
First: You use acronyms that are not defined anywhere in the presentation making it difficult to do serious analysis, by the public. Second: You are planning for "Offshore Wind" by 2035 and that technology is suspect of causing negative environmental impacts on the US Mainland East Coast AND the ocean and sub surface structures, currents and ocean patterns have not been studied sufficiently in Hawaiian waters. Our waters are deeper, our currents are stronger and our state is in the middle of a Federal Ocean Preservation Sanctuary.
Please see the Abbreviations and Glossary section at the beginning of the report. While offshore wind is a resource that is part of the plan because of its projected cost and ability to provide high capacity factor energy; the actual projects and technologies will depend on the energy market/procurement process and community engagement. The Integrated Grid Plan is a roadmap and guide and not a definitive plan of actual projects or technologies. We appreciate your concerns with
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
Third: Distributed Generation (DG) is not designed or explained in your system yet. I am a big supporter of DG, but the design specifics are critical, and currently HECO looks at roof-top and commercial PPAs for solar and DG as an asset for their benefit, not a private asset that they don't control. Fourth: Your over reliance on Solar/Battery and "Hybrid Wind" Ignore the fact that current prices for raw materials for the manufacture are finite, the costs for those systems are under-represented based on future supply/demand reality. Also missing is the plan for replacement cost or recycling of components at the end of a 20-30 year life expectancy. Fifth: You should be focusing on base-load renewables like geothermal that could be built into your planned sectors and NOT solar or wind that will need tons of permitting, easements and wasting land, and money. Solar and wind should be focused on remote communities and designed as distributed "Community" generation. The former AES Coal Fired plant could become geothermal (IN PLACE!!!) and use the steam turbine and ELECTRICAL INFRASTRUCTURE in place rather than getting new easements, environmental impact studies, etc.
Lastly: The assumptions you make regarding transportation ignore hydrogen fuel cell technology, ignore the private sector cost to install chargers, recognize changes in last-mile and mode shift county plans likely to be employed with AI. Most critically, the plan ignores the need to produce aviation fuels and liquid maritime fuels, resulting in Hawaii, once again, importing large amounts of energy in the form of fuel for the military and commercial aviation and shipping (including local commercial fishing operations). Producing aviation fuel alone could add 200 MW to your firm generation requirements. I have lots more, to contribute, but this is a small box.
respect to offshore wind development. Hawaiian Electric’s long-term planning to reach 100% renewable energy by 2045 has always assumed multiple technologies would be needed, potentially including offshore wind. We understand there will be many concerns, and any proposed projects will be required to undergo extensive environmental reviews. Community engagement and a thorough analysis of on-shore and offshore impacts will also be required. Please see Section 6 and 11.1. Distributed energy resources are an essential component of our future plans. Our cost projections for solar and wind are sourced from the National Renewable Energy Laboratory Annual Technology Baseline that takes into count various factors for projecting costs into the future. Regarding recycling of clean energy equipment, we address this issue in Section 2.6 of the final report. Please see new Section 6.9.5 for a discussion on future and emerging technology options. We assume electrification of light duty vehicles and electric buses in our Integrated Grid Plan. In future iteration of IGP, we will examine the impact to the electricity sector on economywide decarbonization efforts in other sectors as you mention. Those will potentially lead to significantly higher loads than studied in this iteration of the plan.
Strongly oppose. Thank you for your time to submit comments.
So...how high are the consumer rate going to increase? Double? Triple? Please see Section 9 of the report. While we expect utility rates may rise in the near-term transition to clean energy, they will be lower and less volatile than if we continue to rely on fossil fuels. Our projections show that customer bills may remain relatively flat over the long-term.
Why is nuclear not even mentioned? New smaller technology is coming available in this plan’s timeline that is similar to the naval nuclear reactors already present in the islands. This would mitigate the land area constraints and provide a carbon free base power solution.
Although small modular nuclear reactors are a promising technology, we did not consider it in our plans at this time because Article XI, Section 8 of the State Constitution prohibits nuclear fission power generation without prior approval by the legislature – “No nuclear fission power plant shall be constructed or radioactive material disposed of in the State without the prior approval by a two-thirds vote in each house of the legislature.” Accordingly, nuclear fission generation is not currently included in our plans.
Good day. I recommend you speak to us. We have brought forth new technology ideal for green grid integration. Key Attributes of Genoptic’s Smart Solal Panels: Genoptic Solar Tech’s division has an integrated panel with multiple design and performance attributes. In comparison with other’s systems, there are significant technological innovations of the Genoptic Solar Tech system: Harvesting, housing, converter, and energy storage integrated with every panel. This permits higher efficiency and elimination of most need of a solar specialist, reducing labor cost and time,
Thank you for your comment. Our plan involves issuing competitive procurements for new resources. Through those procurements we seek proposals for developers that identify specific technologies and locations of projects that are evaluated with the potential for a power purchase agreement with the utility subject to Public Utilities Commission approval.
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Public Question/Comment Hawaiian Electric Response
just two connections and an inverter are required at the electrical panel by a junior electrician further reducing cost and time of installation,
improves the efficiency by 18%, and accomplish the energy production in less space, and with fewer panels and less billable goods, and significant cost reduction.
integrates batteries (1, 2 or 3) permit incremental and exact energy storage needs to be met. Competitors require additional large purchases to increase storage, whereas Genoptic can provide small incremental low-cost increases in battery capacity to meet need. Technology is integrated to handle load from major appliances such as air conditioners and hot tubs unlike some competitors. This integration extends operational life of the system significantly. Our thermal chamber testing indicates 77% efficiency after 30 years.
batteries are bidirectional and permit the system owner (you) to earn an income in net metered markets. operates at maximum efficiency from -30C to +90C. Competitor’s lithium batteries require optimal 15C operating temperature. Competitor battery systems are typically warrantied for 10 years. Genoptic’s system is expected to have a much longer life expectancy. Much longer life expectancy of batteries significantly reduces long term system cost. the small, lightweight panels can be installed by a single person, instead of a crew, in hours, instead of days, and without craning equipment and further reducing cost.
IP 68, FCC and UL Rated. The panel technology incorporates technology from Genoptic’s sign division which has the most outdoor LED signs in Canada and boasts a long-term failure rate of just 2% despite extreme Canadian weather. Integrated intelligent software learns and optimizes operation for maximum efficiency.
Any system failures generate a repair ticket and the system is designed for easy repair if required. Applicable to commercial, residential, and utility farm scale applications. Genoptic Solar Tech does not require thermal cooling of densely packed batteries of some systems and this improves efficiency and reduces risk of fire dramatically. Integration of componentry eliminates multiple potential failure points. Our system can is applicable to off grid locations, and may be ideal for microgrid and virtual power plant scenarios.
We can create a utility, or cooperate with an existing utility with our system management software. We can provide no upfront cost solutions that integrate with your utility. Genoptic LED Inc. Darryl Copeland BSAgEc, BSGeog Business Development Lead C: 403.620.1158
O: 403.726.9260 Email: Darryl@genoptic.com Website: www.genoptic.com
Solar Division: www.genopticsolartech.com Head Office: #18- 6000 72 AVE SE Calgary, AB T2C-5C3
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
Look into nuclear plants on the west coast. New ones are smaller and safer. A second area to look into is green hydrogen.
The big island should expand its geothermal operations..
Although small modular nuclear reactors are a promising technology, we did not consider it in our plans at this time because Article XI, Section 8 of the State Constitution prohibits nuclear fission power generation without prior approval by the legislature – “No nuclear fission power plant shall be constructed or radioactive material disposed of in the State without the prior approval by a two-thirds vote in each house of the legislature.” Accordingly, nuclear fission generation is not currently included in our plans. Green hydrogen is also a promising technology to assist in decarbonizing the State’s economy. While hydrogen was not considered in our plans due to the nascent and uncertain market for production, storage, and utilization of green hydrogen, including high costs, we continue to track hydrogen technologies, drivers, and policies. We continue to engage with various stakeholders on the issues and development steps for green hydrogen in Hawaii. We have added a new Section 6.9.5 to discuss future and emerging technology options. We are open to expansion of geothermal and invite prospective developers of geothermal plants to submit bids through our competitive procurements. The next step in the Integrated Grid Planning process is to issue a competitive procurement in 2024.
The IPG states that customers and community participation is essential. HEI is the sole provider of electricity on Oahu and should lead by example. Your Kailua baseyard has had a new roof for over a year. I am still waiting for solar panels to be put up. And why can't HEI put in batteries to supplement the evening usage? If you want community participation, HEI should spearhead getting solar panels installed at competitive rates rather than what the solar companies agreed upon. At $1,000 per panel, the up front cost is too costly in this time of inflation and low wages. Many families have to decide whether to put food on the table and pay the mortgage or spend $20-40,000 for a solar/battery system. As most retirees, I don't need the tax credit and don't have that kind of monies on hand or want to go into more debt! Panels cost about $200 each and a lot of the installation is modular. In speaking with a California battery rep, they are in agreement, that only the solar companies are making money. If it was affordable like split air condition systems, I would see a whole lot more homes with solar systems especially if NEM was reinstated. HEI should ask UH for geothermal, wind and/or water turbine solutions. We have volcanos, wind and ocean currents. Let's see if we can put them to use. We constantly state that we have some of the brightest students. Why don't we tap them for ideas. Who knows, one student might have the world-wide solution but will move to the mainland after graduation. Maybe someone can improve on the solar panels and/or battery storage. With our size, we should be the leader in clean energy! Mahalo.
Hawaii Natural Energy Institute (HNEI) currently serves on our IGP Technical Advisory Panel and Hawaiian Electric personnel continues to engage with researchers at the University of Hawaii on renewable energy and grid technologies. As an example, we interface with researchers at UH’s Hawaii Groundwater and Geothermal Resources Center (HGGRC) to further assess geothermal resource characterizations in Hawaii and R&D opportunities. In addition, we interface with HNEI to track ocean wave demonstrations at the U.S. Navy Wave Energy Test Site (WETS) off Marine Corps Base Hawaii, Kaneohe Bay on Oahu.
This is a comment on the IGP, 2.1.4 “Secure Reliability through Diverse Energy Sources and Technologies.” The Plan barely addresses the question of how to fill in weather gaps. This is a major issue, even if the entire system never reaches
The plan identifies a firm renewable need to address weather gaps. We analyzed multiple weather years in a probabilistic analysis to determine the needs of the grid (i.e., generation shortfalls) during periods of poor weather. This is discussed in detail in Section 12. Appendix D also discusses system stability issues like inertia, and
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
100% renewable. There is either a need for a lot of integrated, on-demand, generation, or, at a minimum, a guaranteed backup for a 100% loss of solar and wind production (a situation which happens at least once every winter). No matter what, HECO on Oahu will need to be able to meet 100% of peak demand, whether it is for an hour or a week. The Plan refers to unknown future firm renewable sources, but doesn’t address what these might be. I don’t think HE should kick the can down the road by saying it will wait and see what comes up. It is deflective to use that as an excuse for not analyzing the need and potential ways of meeting it within the timeline.
In its recent RFP, HE asks for proposals which also guarantee a liquid fuel supply, an obvious requirement. The only liquid that fits the bill is biodiesel. But neat biodiesel is not a renewable fuel that will be able to power the roughly 1,500 KW of on-demand capacity needed in dire weather situations. There is biodiesel “fuel”, typically 80% Diesel #2, which doesn’t really qualify as “non fossil”. And there is “neat” biodiesel, which is 100% produced from waste collection and purpose-grown crops. The ability to run a major power plant on neat biodiesel is still unknown, and I am unable to find one in this country that runs continuously on it. The term “biodiesel capable” is misleading to the public. It mostly applies to truck and other reciprocating diesel engines, and is always defined as 80/20 biodiesel fuel. Although it is true that some reciprocating engines are running on neat biodiesel, the number remain small and often just for backup. If HECO is going to rely on 1,500KW of neat biodiesel backup by 2045, it needs to show an analysis of that part of its Plan now. The public should not be deceived into thinking such exotic fuels such as hydrogen or fusion are going to arrive anytime soon.
Beyond the physical ability to burn neat biodiesel is the issue of a reliable supply. This is a significant issue that HE cannot just pass off to would-be suppliers or assume it can consistently source, transport, and store the required amounts to run 1,500KW for a week or more, ad infinitum. The amount which can be produced locally is small and unreliable. Neat biodiesel has already been imported here from South America, a considerable logistical challenge, risking quality of the product landed in Hawaii. Thousands of containers of neat biodiesel would have to arrive in a continuous, uninterruptable chain for biodiesel to be a reliable backup. This scenario does not inspire confidence in the ability of HECO to keep the lights on in our renewable source future.
Be that as it may, the future supply of neat biodiesel will certainly rely mostly on growing crops in massive acreage for that purpose, as we do today for the ethanol in gasoline. This practice has been controversial for over a decade in Congress, but the corn ethanol lobby has been able to defeat efforts to stop subsidizing it and mandating its use. The crops for biodiesel production would be soy, canola, and other oil-producing plants, grown, harvested, and refined on a scale well beyond that of ethanol, neither of which have been shown to be carbon-neutral. The likelihood of Hawaii being able to get a commitment of supply in a future biodiesel world is highly unlikely.
promising technology such as grid-forming inverters. As we learn more about inverter-based resources we will adjust our plans to ensure the grid remains stable.
Also, to clarify currently our Scofield Generating Station and Airport generators run on 99.9% biodiesel.
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
The Plan does not address the need for “spinning generation”, as defined in HE’s current RFP. My understanding is that this does not relate only to on-demand backup capacity, but also to “grid inertia”. The technical requirement for this is beyond me, but I believe there is a minimum requirement for generation by a “spinning machine” to keep a grid powered by inverted resources working properly. This requirement speaks to a need for a renewable fuels capability that runs constantly at some minimal level, and should be explained and forecast. The Plan does not address all future means of supplying firm renewable carbon-neutral power, probably because it is politically incorrect. However, this is at the expense of good planning and an understanding of the real issues of dependability. While it may be that someday we will have a fusion reactor here, or an endless supply of hydrogen, those are probably a century away or longer. If the reality is that at least HECO will be generating consistent power at some minimal level, up to peak demand for an unknown number of days, on fossil fuels, that should be spelled out with rigorous analysis, including the potential to replace those fossil fuels at some point in the future. The Plan states, “By adding many variable, inverter-based resources in various locations, new challenges will arise in ensuring the security of the system.” An “inverter-based resource” is a low voltage DC to high voltage AC converter, which is applicable to wind, solar, and batteries. An inverter doesn’t create electricity, and batteries are clearly not a utility-scale backup. This is misleading when it comes to system dependability. I do not understand how these things can be represented as “ensuring the security of the system”.
The plan outlined in the draft is intriguing and represents a significant movement towards renewable energy, which is something the planet desperately needs. This plan is one of several at the forefront of the major push towards turning energy green. The involvement of all stakeholders, from the government to homeowners, increases the chances of success for the plan. Additionally, transparency during the plan's development can help make the plan move smoothly with fewer complications in local communities. Encouraging people to install batteries and solar panels on their roofs can help reduce the grid's load during peak energy consumption times, particularly for larger homes that consume substantial amounts of energy throughout the day. However, one crucial aspect not addressed in the draft is what HECO intends to do with the waste produced from renewable energy systems in the future, such as old or unusable solar panels. Proper disposal and recycling methods must be implemented to minimize the environmental impact. Investing in research and development to improve the efficiency and longevity of renewable energy systems can also help reduce waste production in the long run.
We address recycling of clean energy equipment in Section 2.6 of the final report.
Response to Section 2.1.2 It is encouraging to see that HECO recognizes the need for a long lead time renewable RFP. Technologies such as offshore wind will require different considerations and procurement processes than HECO's past RFPs, and they are needed to provide the resource diversity and resilience that a 100%-solar portfolio may lack.
1.The plan is to develop a long-term RFP to be issued in 2024 based on the needs identified in the IGP.
2. The 2,114 GWh of generation from the offshore wind was based on a production simulation output. In the simulation, the offshore wind was assumed to have a capacity factor of around 60% for the
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
Response to Section 2.2.1 Please clarify the assumptions used to determine the 2,114 GWh of generation. For 400 MW of OSW, this would equate to a net capacity factor of about 60.3%, which is much higher than previous studies have estimated. Since on-site studies of the wind resource are still pending, it may be preferable to assume a range of NCFs from 45-55% and refer to a range or project capacities from 400-500 MW. These combinations could still yield 2,114 GWh/year and may provide more flexible expectations. Response to Section 6.9.1 Please clarify the assumptions used to estimate the CapEx projections for offshore wind. Do cost assumptions include on-shore interconnection or harbor upgrades for construction? Also why does the CapEx for offshore wind increase dramatically between 2035 and 2036. If the increase is related to the end of ITC, is there a similar impact for other technologies? Response to Section 6.9.1
It appears that Figure 6-11 (LCOE projections) is a duplicate of Figure 6-10. Unless we misread, please provide an updated Figure 6-11.
Response to Section 8.1 Please clarify why, in the Land-Constrained scenario, less offshore wind capacity (400 MW) is selected relative to the Base scenario (509 MW). To address both the 400 MW and 509 MW scenarios discussed in the report, it may be more accurate to refer to range like, "approximately 400-500 MW" of OSW, where it makes sense to do so. Response to Section 8.2.2
The capacity of OSW that provides the lowest LCOE will depend on several factors, including the maximum single point of failure, capacity at the POI, the need for system upgrades. To address both the 400 MW and 509 MW scenarios discussed in the report, it may be more accurate to refer to range like, "approximately 400-500 MW" of OSW.
Response to Section 11.2.3 It is encouraging to see that HECO is aware of the unique challenges of long-term resource solicitation and procurement. Firm pricing, site control, technical details, RFP schedules, and PPA terms are all important items that require tailored consideration for long-term resources such as offshore wind.
east side of Oʻahu. This was based on data provided by NREL in their offshore wind study (see, page 60 of the PDF, page 48 of the report at https://www.boem.gov/sites/default/files/documents/regions/pacific-ocs-region/environmental-science/BOEM-2021-070.pdf). Ultimately proposals submitted by developers in the procurements will help to flush out differences in uncertain assumptions and the market. 3. The CapEx includes expenses for turbine, development, engineering & management, substructure and foundation, port and staging, array cable costs, interconnection costs, assembly and installation, and plant decommissioning. See page 45 of the above referenced report.
The increase in cost in 2036 is due to the end of the ITC. Onshore Wind and Grid Scale PV also have a slight increase in their capital cost due to reductions in their ITC.
4. This figure was inadvertently a duplicate and has been updated to the correct graph. 5. In the Land Constrained scenario, it was assumed that the Offshore Wind would be limited to 400MW based on stakeholder feedback. There was no limit enforced in RESOLVE in the Base case. 6. Report revised to reflect 400-500 MW range. 7. See response to item #1
The power grid needs to have firm sources of power in order to assure the reliability of uninterrupted power. There are only a few ways to provide for firm power, namely, fossil fuels, biomass, and nuclear. Battery backup has a limited amount of power. The total cost of going to 100% renewable will bankrupt this State.
We believe that the grid will need firm renewable sources of power. We have examined this issue in detail in Section 12 of the report.
Hawaii is one of the best places in the world to use Wave Energy, a clean, CONSTANT, reliable renewable energy. Wave Energy Converters are already testing at the WETS off-shore of Marine Corps Base Hawaii in Kaneohe. This technology must be included in Hawaiian Electric’s Draft Integrated Grid Plan. Due to NOAA satellites, Wave Energy can be tracked and forecasted, making it possible for the utility to make adjustments during the scant times the resource becomes unavailable. Thus Wave Energy is determined to be a “constant power source”.
We support all forms of renewable energy. We encourage any technology that has a bon-a-fide proposal to participate in requests for proposals for new generation. While the Plan outlines certain technologies, the actual technologies and locations that will interconnect to the grid will be based on the market (and developers) submitting proposals through our requests for proposals that compete against other technologies on price and non-price factors. Please note that a threshold requirement in our requests for proposals is that a proposed technology must have successfully reached commercial operations in commercial applications (i.e., a power purchase agreement) at the scale being proposed. This is to
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
ensure that the technology proposed is viable and can reasonably be relied upon to meet the objectives of the request for proposals.
Please also see Section 6.9.5 for a discussion on future and emerging technology options.
The current “Going Green Plan” will be a disaster for Hawaii. Just one example would be the destruction of proposed Wind Farms by a Hurricane. Not to mention when the destroyed parts make landfall.
Solar blanketing potential agricultural land is another collateral damage disaster. There are other promising developments like modular nuclear and hydrogen fuel that would work for the islands. Carbon dioxide is not going the threaten the human race. The levels during the Jurassic period when life forms were so robust that their remnants became the carbon energy sources so plentiful in America today. Let’s slow down, take a breath and use our logic to solve the problem.
We acknowledge that emerging technologies, such as green hydrogen, are promising technologies to decarbonize Hawaii’s energy sector and economy. Therefore, we continue to assess the various issues, both technical and policy-related, and market readiness of emerging firm generation technologies. We have added a new Section 6.9.5 to discuss future and emerging technology options.
Every day we're reading about our challenges in renewable energy, reducing food imports supporting local farmers, challenges reducing fossil fuels, our carbon footprint, water usage and land for residential housing. One solution is enforcing double usage for every acre of agriculture and solar farming. It is called "AGRIVOLTAIC." Like Kaiser clinics with rooftop solar in their parking lots (double usage), agrivoltaic is the same concept. Combining land usage for ag and solar power, freeing up land for housing. Agrivoltaic’s partial solar panel ‘shade’ reduces water consumption from excessive open farming water evaporation. Plants grown under panels draw moisture up that cool solar panels, increasing power generation vs overheated panels. Partial panel-shade result in leafy plants to search out sunshine, extending size of leaves (researched on cabbage) increasing production. Solar and Ag farmers can share land lease, reducing their lease costs, adding to their profits, perhaps taxed more to pay for costs elevating existing solar farm panels so farmers have room to grow taller vegetables besides low lying leafy vegetables. Low lying solar farms continue to pop up on ag land all over Oahu. Our State's challenges in power, land, water, food, reducing imports (carbon footprint) must be reduced by mandatory double usage of land for energy and agriculture. Agrivoltaic is being applied worldwide and UH has been actively doing research on agrivoltaic's benefits to Hawaii as well. Current solar farms need to be transitioned to Agrivoltaic farming. Immediate action is a 'must.' Let’s have less talk and more action now.
We recognize the issue of limited land availability in Hawaii and the competition of this land for energy, agriculture, housing, and other end uses. While not all solar and wind projects are built on ag land, we are in favor of multiple uses of ag land where applicable to provide the highest value to our customers. Also, we encourage the use of brownfield lands for renewable energy projects in our RFPs. Regarding agrivoltaics, we encourage this type of dual use applications. In fact, the charitable foundation of our parent company, HEI, awarded a $25,000 grant in 2021 on behalf of Hawaiian Electric to the Hawaii Agriculture Research Center (HARC) to help fund HARC’s “Agrivoltaic R&D Center” to conduct research that supports synergistic development of agriculture (soil and hydroponic crops) and solar generation on the same land. This center, located at the Clearway Mililani Solar I project site, works with hydroponics and crops and ground covers between and under the panels to find solutions that benefit both the agriculture and solar industries.
In the 2022-2023 Sustainability Report, under "Adding Renewables," it was stated that HECO launched a request for proposals for "firm" renewable resources such as geothermal or biofuel to guarantee predictable quantities of said resources. With the Campbell Industrial Park generating station producing biofuel in Oahu and geothermal resources on Hawaii Island from Puna Geothermal Venture, what other options are you hoping to pursue in terms of “reliability”? As oil prices hit a high in 2022, what other alternatives have been considered in order to make energy more economically accessible and less environmentally hurtful to residents of Hawaii? With 113 MW of oil generated at Campbell
The current request for proposals (“Stage 3 RFP”) will allow us to test the market for firm renewable options to ensure generation reliability. We are open to all forms of viable renewable options subject to the guidelines of our requests for proposals. The Integrated Grid Plan outlines the resources and grid infrastructure (i.e. transmission and distribution) that is needed to integrate renewables and scale for growing population, housing and electrification of transportation.
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Public Question/Comment Hawaiian Electric Response
Industrial Park and a contract capacity to access 38 MW from PGV and Palailai Solar farm produces 3 MW of power, although not as ample as solar farms, these seem like dependable resources. How would alternative resources be distributed to and shared by customers on other islands without manufacturing plants? After the 1990 multi-year research project concluded that transmitting geothermal electricity from Big Island across Hawaii was feasible but at great environmental impacts, how do you suggest we share these resources? As Oahu is the most densely and largely populated island in Hawaii, do you have a target goal to raise the percentage of populous and infrastructure relying on renewable energy rather than fossil fuels?
I strongly oppose the implementation of HECO's IGP. I believe this plan will leave Oahu vulnerable to power outages and also cause significant damage to our environment. The plan MUST incorporate the use of fossil fuel or nuclear energy as a base load and backup for renewables.
The Integrated Grid Plan identifies pathways to achieve the state mandated 100% renewable energy goal. Section 9 also demonstrates that remaining on fossil fuel may ultimately be more expensive than transitioning to 100% renewable energy.
Put a nuclear power plant on Kahoolawe. We will not meet the 2045 goal otherwise.. Although small modular nuclear reactors are a promising technology, we did not consider it in our plans at this time because Article XI, Section 8 of the State Constitution prohibits nuclear fission power generation without prior approval by the legislature – “No nuclear fission power plant shall be constructed or radioactive material disposed of in the State without the prior approval by a two-thirds vote in each house of the legislature.” Accordingly, nuclear fission generation is not currently included in our plans. Hawaii will not be able to be 100% on renewable energy as we are an island with very limited resources. Wind and sun are not fully sustainable for HECO to be able to supply the entire island. Let’s be honest, nature does not belong to HECO but will somehow make a profit from it. The residents of Oahu and businesses will end up paying for IGP when we least can afford for one company to make a profit from us. Renewable energy would be great if we had it, but look around we DON’T. Our legislators need to use Wisdom and Knowledge as our Lord did in creating the Universe. Jpf
As a point of clarification, Hawaiian Electric does not profit from power purchase agreements (contracts) that it signs with independent power producers to provide wind and solar energy. The cost of the energy paid to independent power producers is passed through to customers without any “markup” or “profit” by the utility.
The integrated Grid Plan talks about creating a clean energy grid by resources from Hawaii for Hawaii by 2045, however very little of Hawaii’s own resources are projected to be harnessed by 2045. Today, 4.4% of the grid’s electricity comes from solar and it is projected to rise to 50.1% by 2030 – just 7 years from now. Another major change is having 17.7% electricity from offshore wind farms. I think solar generation for the smaller scale needs such as homes and communities are a great resource, although it is not truly a resource from Hawaii. However, I do not think offshore wind farms are a good resource moving into the future. They are a massive undertaking, both financially and physically. They are also subject to expensive, dangerous maintenance and repair operations. Offshore wind puts not only marine life in danger, but it can also change the face of the seabed and can potentially change migration patterns of birds. While an offshore wind turbine might pay for itself after a year, it is estimated to only last around 19 years after that. Then they must be replaced; many used wind blades from onshore wind turbines have already been laying around in various places around Hawai’I collecting dust and not being recycled, so how would this be any different? Hawaiian Electric should look closer into wave powered technology which has a significantly smaller footprint than wind turbines. For example, the Wave Energy Company is piloting a program at the port of L.A. for their Eco Wave Power. It has already been
We appreciate your concerns with respect to offshore wind development. Hawaiian Electric’s long-term planning to reach 100% renewable energy by 2045 has always assumed multiple technologies would be needed, potentially including offshore wind. We understand there will be many concerns, and any proposed projects will be required to undergo extensive environmental reviews. Community engagement and a thorough analysis of on-shore and offshore impacts will also be required.
We are open to new and other technologies such as wave energy. If these technologies are commercially viable and can be done at scale we encourage these projects to participate in future request for proposals to be part of our renewable energy portfolio.
H-12 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
successfully used in other places around the world and could be an asset for Hawaii since the Islands are surrounded by water.
This is why wind turbines at sea is a bad idea. We are going to lose billions like the light rail. Do’'t do it. AdChoices Popular Mechanics Popular Mechanics Giant Wind Turbines Keep Mysteriously Falling Over. This Should’'t Be Happening.
Turbine failures are on the uptick across the world, sometimes with blades falling off or even full turbine collapses. A recent report says production issues may be to blame for the mysterious increase in failures. Turbines are growing larger as quality control plans get smaller. The taller the wind turbine, the harder they fall. And they sure are falling. Wind turbine failures are on the uptick, from Oklahoma to Sweden and Colorado to Germany, with all three of the major manufacturers admitting that the race to create bigger turbines has invited manufacturing issues, according to a report from Bloomberg.
Multiple turbines that are taller than 750 feet are collapsing across the world, with the tallest—784 feet in stature—falling in Germany in September 2021. To put it in perspective, those turbines are taller than both the Space Needle in Seattle and the Washington Monument in Washington, D.C. Even smaller turbines that recently took a tumble in Oklahoma, Wisconsin, Wales, and Colorado were about the height of the Statue of Liberty.
Turbines are falling for the three largest players in the industry: General Electric, Vestas, and Siemens Gamesa. Why? “It takes time to stabilize production and quality on these new products,” Larry Culp, GE CEO, said last October on an earning call, according to Bloomberg. “Rapid innovation strains manufacturing and the broader supply chain.”
Without industrywide data chronicling the rise—and now fall—of turbines, we’re relying on industry experts to note the flaws in the wind farming. “We’re seeing these failures happening in a shorter time frame on the new turbines,” Fraser McLachlan, CEO of insurer gCube Underwriting, told Bloomberg, “and that’s quite concerning.”
The push to produce bigger wind-grabbing turbines has sped production of the growing apparatuses. Bloomberg reports that Siemens has endured quality control issues on a new design, Vestas has seen project delays and quality challenges, and GE has seen an uptick in warranty costs and repairs. And this all comes along with uncertain supply chain issues and fluctuating material pricing.
We appreciate your concerns with respect to wind development. Hawaiian Electric’s long-term planning to reach 100% renewable energy by 2045 has always assumed multiple technologies would be needed, potentially including offshore wind. We understand there will be many concerns, and proposed projects of any technology will be required to undergo extensive environmental reviews as appropriate. Community engagement and a thorough analysis of on-shore impacts will also be required.
In terms of performance of renewable projects, contracts we sign with producers of wind energy have strict performance standards and requirements and protect customers from deficiencies in performance. While our current agreements with Independent Power Producers do not address disposal of clean energy materials directly, it requires that the seller of energy, upon termination of their power purchase agreement with the Company, to remove the Company-Owned Interconnection Facilities and developer-owned interconnection facilities, if requested by the Company. The Company may not require removal if such facilities are needed to serve other system requirements.
H-13 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
With heights stretching taller than 850 feet, blades 300 feet long, and energy generation abilities ratcheting up accordingly, the bigger the turbine, the more energy it can capture. But the bigger the turbine, the more that can go wrong—and the farther it falls.
This plan will increase the utility cost to the consumer. Taxpayers are having a difficulty paying its monthly bills for everything. I oppose this plan.
We are very cognizant to keep electricity affordable for all customers. We are exploring options and solutions for low and moderate income customers through an Energy Equity proceeding with the Public Utilities Commission. More information to participate in this proceeding can be found at: https://puc.hawaii.gov/energy/equity/
As outlined in Section 9, we also believe the Integrated Grid Plan would result in lower energy rates compared to the status quo of remaining on fossil fuel generation.
I vote NO on this plan, it makes no sense and the cost will be passed on to the consumers. I have already seen an increase in my bill since the coal plant closed, and I have a solar system on my roof. There has got to be a better way
We have several renewable projects in the pipeline that are lower in cost compared to the current cost of oil. We are focused on bringing those projects online as quickly as possible to provide some electric rate relief to customers. Please see Section 9 of the report. While we expect utility rates may rise in the near-term transition to clean energy, the new projects will help to keep rates lower and less volatile than if we continue to rely on fossil fuels.
1. The 2015 Legislature passed a law mandating that 100% of our electricity come from renewable resources by 2045. 2. Hawaiian Electric Company spent many years and decided that our electrical grid had to be improved to make it reliable. 3. Where are our state government “common sense” leaders? They decided to make a law mandating the state to accomplish this “dream”. 4. Every smart citizen in our state knows that weather is unpredictable and cannot provide a reliable source of energy for making electricity yet our elected representatives passed a law to make Hawaiian Electric Company accomplish this requirement. 5. Paragraph 2.1.4 of the Draft Report states that an entire electrical system cannot be dependent on weather generating sources. An entire new clean energy source needs to be found to provide energy for making electricity. Our elected leaders are the laugh of the nation, because of their decision to mandate 100% renewable electricity for our state even though we (the ordinary citizens) know there is no technology that can do it now. 6. Why didn’t our experts tell our elected representatives that we don’t have any idea where we can get 100% of our electricity from renewable resources? 7. The draft report listed the dates when our fossil fuel generators will be put out of service. There is no mention, in the draft report, about how Hawaiian Electric will provide backup electrical power when all of our PV panels are destroyed by storms or war and there are no generators to provide electricity. 8. The hardening of our electrical grid, as presented in the draft report, is like building the cart before getting the horse. The grid will survive but there will be no electric source. 9. Nuclear power plants have been installed in our US Navy ships for many years and should be considered on source of power to make our electricity but the current law mandating 100% renewable energy must be repealed. Opponents to using nuclear power and fossil fuels must provide solutions instead of just complaining.
Section 7.4 discusses solar and wind plant resilience with respect to floods and sea level rise. Further evaluation in the future could include an assessment of independent power producer PV and Wind plant resilience with respect to other threats such as wind. We have acknowledged this in Section 7.4. We will also continue to evaluate ways to improve our generation reliability analyses to include extreme events as described in this comment. As future renewable technologies (i.e., “reliable source”) become available we can include those in future analyses.
H-14 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
10. Fossil fuels and men are essential for our armed forces to win wars. We need fossil fuel generators to back up our electrical system when our power grids are damaged.
11. Wind turbines should not be installed in the ocean because they can easily be damaged and difficult to repair while in ocean. Maintenance costs must be considered when picking any energy source for our electricity. 12. If a reliable energy source is found, I suggest that electrical cables be installed connecting all of our islands whereby another islands electrical system can provide some electricity to another island if needed. I feel that implementing this program is a great idea, but I could not find anything about the disposal of equipment after it’s lifecycle has expired. Solar panels have a 20-30 year lifespan. What is the plan to dispose of the 27,000 acres of solar panels, plus all the rooftop solar panels needed to power Oahu? I also noticed the use of biofuels could consume as much as 10% of the power on Oahu if land is constrained. Bio fuels are renewable fuels that are made from plant matter. These types of fuel still provide carbon emissions when burned. What will the impact be from these carbon emissions? I understand carbon emissions will be reduced by 50% when using bio fuels compared to fossil fuels. Will that be enough to make a direct impact on climate change? I like the concept of having these bio fuel plants to provide firm generation of electricity when environmental and weather issues affect solar and wind generated power production. I can see firm power generation being used pretty heavily during times of no sunshine for weeks on end like it is in upper Puna district during the winter months. I also like the idea of having multiple facets of power generation. Has offshore wave powered generation been looked at as an option? eia.gov estimates that 64% of the United states power generation could come from waves. The power generation from waves around the islands could possibly produce a large amount of the power needs for the islands. I think this avenue of approach should be considered if it has not already been researched. I noticed you want to fortify the grid to allow charging stations at the workplace and at home. Who pays for the charging of cars and how would the price compare to the use of fossil fuel vehicles? What happens when there is not enough charging spaces to charge vehicles in a timely manner? I have seen lines for charging stations in California with 15 cars waiting in line for hours to charge their vehicles. Also have you thought of placing solar panels as parking lot roofs? I am not sure how many acres of parking lot space is available but that could be land that could serve a dual purpose of power generation and parking. The shade would be greatly appreciated for smoldering hot car interiors.
We address disposal of clean energy equipment in Section 2.6 of the final report.
We understand that the referenced EIA statistic represents the theoretical annual energy production of waves off the coasts of the U.S. The actual potential for wave energy in Hawaii will be dependent on the pace and scale of wave technology development (currently at the demonstrate stage) and availability of suitable project sites, including factors such as the wave resource available at the sites and ability of wave energy project developers to secure applicable permits and interconnection approvals. We are open to new and other technologies such as wave energy. If these technologies are commercially viable and can be done at scale we encourage these projects to participate in future request for proposals to be part of our renewable energy portfolio. Under most circumstances, electric vehicle (EV) drivers are responsible for paying to charge their vehicles. The fuel cost per mile for an EV relative to the fuel cost per mile for an internal combustion engine (ICE) vehicle depends on many factors, including the price of electricity, the price of gasoline, and each vehicle’s fuel efficiency. As a useful reference, the Idaho National Laboratory’s Advanced Vehicle Testing Activity offers a chart (https://avt.inl.gov/sites/default/files/pdf/fsev/costs.pdf) comparing the energy costs per mile for electric and ICE vehicles. While many EV drivers choose to charge at home, others rely heavily on public charging infrastructure to support their charging. For the latter group, there may be times where the available public chargers are either in use, under repair, or simply not available. In those instances, drivers typically wait for a charging station to become available, or travel to another nearby station. As a best practice, drivers are encouraged to charge their vehicles whenever, and wherever they find an available charger – even if their battery is not depleted. By charging opportunistically, drivers can minimize the likelihood of finding themselves desperately in need of a charger in case one is not immediately available. Your plan to go so called ‘completely green’ is ill founded and devoid of any scientific merit.
The Earth has gone through an untold eras of heating & cooling off; it will continue to do so. Tell me how many degrees that the climate will cool by from your actions of ridding fossil fuels in Hawaii; for that matter in all the US. Fact is you can’t. Plans to rush in with poorly thought out solutions is a joke.
Our plans are guided by the state mandated goal to achieve 100% renewable energy by 2045, and the state target to achieve 50% carbon reduction by 2030 and net negative carbon reduction by 2045 across the entire economy. We believe that the Integrated Grid Plan could achieve those goals at lower cost compared to alternatives. The Integrated Grid Plan is also a flexible roadmap that we can adjust as circumstances change.
H-15 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
I suggest you wake up to the realities. All that you your plan is set out to do will be far reaching economic damage and imperil our once great country… this while the rest of the world continues to build coal fire plants and the like. Hi our playing with fire Aloha, Every year before hurricane season our leaders say we should prepare for the worst and hope for the best. Converting our grid to only wind and solar will leave us terribly vulnerable in the event of a hurricane. And if china cant or refuses to sell us more panels to rebuild the grid think of the negative repercussions we are intentionally subjecting ourselves to. We closed the coal plant which supplied about 18% of our electricity. Can anyone tell us what measurable impact it had on our climate? It might feel good but it accomplished absolutely nothing. Think also how you are going to charge all the cars for the condo owners on the island. Will it be by appointment only? what if someone doesn't remove their car on time. Who settles that dispute? Can the grid actually supply the energy to charge the cars at night when people are home in addition to the existing power needs? What is the plan to dispose of solar panels when they need replaced? and the EV batteries for cars when they expire after 5+ years. where are we going to put them? It appears this forced change will put us into a worse experiment than the $3.5 billion train fiasco we have been going through for the past 15 year–- only worse. It’s another case of Ready, fire, aim..“"There are too many questions to answer before we proceed but some politicians are hell bent on telling us they did something even though it doesn't and can't work with the existing information. It would be better to think nuclear than solar at this time.
A key part of our plan reflects that we cannot solely rely upon wind and solar resources. We must take advantage of energy storage resources and firm generation in order to ensure reliability. This is outlined in Section 12 of the report. We also recognize that we will need more generating resources to ensure that we are able to charge all of the electric vehicles we expect customers will adopt in the next 20 years, and have evaluated those scenarios in our report; for example the high load scenario. We also plan to introduce electric rates that encourage customers to charge their vehicles during times when the grid is not stressed (i.e., during the daytime when there is an abundance of solar available.).
We address disposal of clean energy equipment in Section 2.6 of the final report. Although small modular nuclear reactors are a promising technology, we did not consider it in our plans at this time because Article XI, Section 8 of the State Constitution prohibits nuclear fission power generation without prior approval by the legislature – “No nuclear fission power plant shall be constructed or radioactive material disposed of in the State without the prior approval by a two-thirds vote in each house of the legislature.” Accordingly, nuclear fission generation is not currently included in our plans.
Achieving 100% dependence on renewables is unrealistic and guarantees that we will experience interrupted power. Wind farms are a blight on the environment and kill birds, there isn't enough land for solar without covering the whole island, and battery technology is too expensive. Stick with a mix of fossil fuel with some solar and biomass.
Our plan outlines a mix of diverse resources to ensure that we are not dependent on a single source like wind or solar. We recognize a diverse portfolio will include forms of firm generation to ensure reliability.
We acknowledge the sensitivities to wind turbines and have set up processes within our procurements and with our developers to continue to engage communities prior to development of any future projects. The climate on earth has been changing in cycles for billions of years. we know of 5 ice ages with the internal combustion engine and the populace and animals do better in the warm cycles. CO2 levels have been higher and lower than they are now. CO2 is essential for plants to grow and give us oxygen to breathe. In the many books I have read o this the last CO2 level from Mauna Kea was 444 parts per million which is satisfactory. Should the level decrease to around 150 parts per million all plant life on earth dies! If you look around your house an office you would be hard pressed to find items not made from oil in some form. Furniture, computers, phones, furniture, articles in your car, clothing, printers, glasses, etc. Let's not jump the gun and get us in a rut again like we did with the train. One big storm here and we are in big trouble.
We are actively working to make the grid more resilient. We have outlines our initial plans to adapt the climate change and harden the grid in Section 7 of the report.
RESPONSE TO THE HECO INTEGRATED GRID PLAN March 2023
We are guided by state policies such as state mandates for the electric utility to achieve 100% renewable energy by 2045 along with a statewide goal for the entire economy to achieve net negative carbon emissions by 2045. However, notwithstanding those policy
H-16 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
The basic concern with the plan is the overall assumption that a carbon-less electrical generation system is the scientifically appropriate policy goal for Hawaii to combat changes in our climate. Hawaii needs to take a closer look at and analysis of the science that led to this assumption. This document will highlight some of the facts relative to this issue and will then discuss each in more detail. It will end with recommendations for HECO and the State of Hawaii to consider. What we know today: 1. Average global temperatures (AGT) have been slowly rising, more noticeably since the start of our industrial revolution. The rise has been decreasing in the last 2 decades. 2. The concentration of carbon dioxide (CO2) in the atmosphere has been rising steadily during the same period at a relatively constant rate. 3. While there have been periods of some correlation between the AGT and CO2, data and actual observations have not indicated any causal relationship--changes in CO2 that cause a predictable and similar change in AGT.
4. Catastrophic predictions based on the output of climate models have not occurred. 5. Discussions criticizing the use of fossil fuels have focused almost entirely on the emission of CO2 into the atmosphere and have ignored the benefits that the use of fossil fuels have provided humanity. Rising Global Temperatures
1. Global temperatures are increasing, but because of many different causes: natural variations in earth’s orbit around the sun, changes in solar and cosmic radiation reaching the earth, volcanic eruptions, ocean temperature variations (some caused by extremes like El Nino and La Nina), and changes in the concentrations of greenhouse gases in the atmosphere. 2. Water vapor (H2O) is the primary greenhouse gas (absorbs infrared radiation emitted by the earth towards space and retransmits some of it into space and some back towards earth). Water vapor is the primary greenhouse gas and represents 1-5% of our atmosphere.
a. There is approximately 100 times more H2O in the atmosphere than CO2. Carbon dioxide is, basically, a trace atmospheric gas. The amount of methane, another greenhouse gas, in the atmosphere, is even smaller. b. The greenhouse effect is essential to life on Earth. Without it, our average temperature on earth would approximate -18oC (-0.4oF). 3. Changes in the greenhouse effect caused by variations in CO2 concentrations are relatively insignificant and immeasurable when compared to it’s natural, cyclical variations. 4. The gradual warming of the earth over the last few centuries is natural. Geologically, we are still recovering from a mini ice age and temperatures are supposed to increase. Rising concentrations of Carbon Dioxide in the atmosphere
1. Concentrations of CO2 have been rising steadily, more so after the industrial revolution.
goals, our Integrated Grid Plan demonstrates that using other forms of generating resources, such as, wind, solar, battery energy storage, and firm generation, can make electricity more affordable for customers compared to the Status Quo of relying on imported fossil fuel.
In Section 12, we assess the risks of relying on only solar and wind resources and show that other forms of generation will be needed such as firm renewable sources.
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
2. There are a number of reasons for the rise, only one of the many is CO2 emissions resulting from human activity, i.e., the burning of fossil fuels.
3. Properties of Carbon Dioxide a. CO2 represents less than .04% of the total atmosphere or about 450ppm (parts per million) --97% is natural and 3% due to human activity. b. Hawaii’s CO2 emissions are 0.4% of US emissions and less than 0.1% of the world’s emissions. c. HI’s emissions impact less than 1% of temperature variations—insignificant when looking at the global temperature variations that occur naturally. d. Water vapor, not CO2, is the major greenhouse gas. The impact of water vaper is many times greater than the impact of carbon dioxide. e. CO2 is not a pollutant—it is the building block for plants and, indirectly, becomes food for animals as well. If global CO2 concentrations fall to about 150ppm or 0.02%, plants will not be able to survive. f. Some of the benefits of increased CO2 in our atmosphere that we have already witnessed are greater plant growth, increased agricultural productivity and food supplies, and less human deaths attributed to climate (more people die from cold rather than hot weather).
Correlation/Causation between AGT and CO2 Concentrations 1. Changes in the CO2 concentrations in the atmosphere will have an insignificant and almost unmeasurable effect on our global temperature and on changes to our climate. 2. Lots of data available today verify that while concentrations of CO2 have been steadily rising since the start of the industrial revolution, there has not been a similarly consistent rise in global temperatures. a. If we go further back in time, there are many periods where there is little correlation between carbon dioxide concentrations and global temperatures. b. Also visible in that data is what is called the “lag in CO2 concentrations”—many periods show that increases in carbon dioxide follow increases in temperature, not the other way around. 3. Bottom line: while there have been periods in history when the rises in AGT and CO2 have seemingly increased together, those periods of correlation do not indicate causation. There is no evidence that changes in CO2 concentration cause a corresponding change in global temperatures.
Predictions of Catastrophic Events due to CO2 -Driven Climate Changes 1. Over at least the past 2-3 decades, many individuals and organizations have predicted catastrophic events—species extinction, increases in tropical cyclones (hurricanes, typhoons, willy willies), massive rises in sea levels, etc. None have occurred that can be correlated to CO2 concentrations using real data and observations.
2. Essentially all of the predictions are based on the output from computerized climate models that even the developers of the models admit over-forecast temperatures. Some of those
H-18 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
developers also admit that models needed to be “adjusted,” at times, to produce “better” results that comply with the climate-based conclusions that were desired.
3. Those models are based on the “presumption” that CO2 increases that result from human activity (use of fossil fuels) cause like increases in AGT with catastrophic results.
a. It should not be surprising that models built with that presumption would naturally conclude that CO2 was the problem. b. Most of those models have predicted temperature changes that have not occurred. Those models had to be mathematically modified to produce results that were more consistent with the hypotheses that the developers were trying to prove. These procedures are not consistent with normal scientific methodology. 4. With the unreliability of climate model output, it should not be surprising that the predicted catastrophes have not occurred. Use of Fossil Fuels
1. Drawbacks from burning fossil fuels: a. Air Pollution. The burning of Fossil Fuels has produced air pollution in the past. The use of coal was the primary culprit. Recent changes in coal plants have significantly reduced the amount of atmospheric pollutants. b. US use of coal as a fuel is decreasing in favor of natural gas, a much “cleaner” fuel. As the US moved to use more and more natural gas, American CO2 emission levels have lowered even as the use of natural gas increased. c. Increased human use of fossil fuels has led to increased CO2 emissions.
2. Benefits from using Fossil Fuels—Human Flourishing and Climate Mastery a. Cheap, reliable source of energy that is cleaner as we reduce use of coal and increase use of natural gas. The availability of fossil energy sources has allowed humanity to flourish and has enhanced our quality of life.
b. Energy from fossil fuels has made possible the significant advances in technology, industry, transportation and agriculture that we have experienced, especially since the start of the industrial revolution. c. Medical innovations have also depended on the availability of cheap, reliable energy available from the use of fossil fuels. Climate related deaths, worldwide, have been dramatically reduced. d. Our developed nations have been able to adapt to changes in the climate because of the availability of cheap, reliable energy. Using fossil fuels has made possible our “mastery” of climate and its changes.
e. There is no reason to believe that humanity cannot continue to use fossil fuels to mitigate and adapt to the impacts of climate changes.
Implications for Hawaii’s Energy Policies. Hawaii’s energy planning and HECO’s IGP are based on the assumption that increasing the concentration of CO2 will cause catastrophic increases in global temperatures. As a result, they have set the reduction of CO2 emissions as the requirement to reduce the impact of our ever-changing climate.
H-19 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
1. We need to stop hypothesizing that the reduction of CO2 emissions is the action needed to negate changes in the climate. That relationship is not supported by data. Reducing emissions to keep our environment cleaner and reduce pollution can be a reasonable goal for Hawaii’s policies, but we should not include the stopping of climate change as an expected benefit of those policies. 2. Net “0” goals and reduction of CO2 emissions should no longer be expected to impact global temperatures and changing climate. 3. Our policies should focus on: a. Cheap energy. Keep the costs down for the public. Look at all of the costs when evaluating energy sources. Industry and tourism also thrive from using cheap energy. b. Reliable energy.
i. Solar and Wind are not reliable energy sources. Battery storage capacity is not close to what we would need even with projected storage projects. Also, there are factors like the amount of land required, installation and maintenance costs, infrastructure, connectivity, etc. ii. In addition, “greener” energy sources (except for nuclear, hydro-electric, and geothermal) need to be backed up by fossil fuel generation to keep energy availability reliable. Simultaneously maintaining and operating two or more different types of energy sources is inefficient and expensive. Taxpayers will bear the cost of those policies. c. Renewable Energy i. OK if the goal is keeping the environment cleaner. We should not expect that what we do will significantly change our climate.
ii. We should not dismantle our fossil fuel capabilities in favor of renewables until we have the renewable systems in place that can produce energy as reasonably and as reliably.
BOTTOM LINE: REDUCING OUR CO2 EMISSIONS WILL NOT IMPACT GLOBAL TEMPERATURES OR THE CHANGING CLIMATE. WE SHOULD, THEREFORE, NOT FOCUS OUR POLICIES ON CONTROLING CO2 EMISSIONS SHOULD, INSTEAD, FOCUS ON PROVIDING ENERGY THAT IS CHEAP, RELIABLE, AND AS GREEN AS PRACTICABLE.
I support plan I for and implementing a clean /renewable energy plan for our state. I have read various reviews and commentaries of HECO’s proposed IGP. Most recently info from the Practical Policy Institute of Hawaii and have serious concerns about HECO’s IGP. I agree that the IGP as it stands today is not practical, reasonably achievable or affordable. I urge the State Gov., HECO and qualified private sector organizations to go back to the table and come up with a different plan that can succeed for the people of Hawaii.
We acknowledge that our plan is ambitious, the Integrated Grid Plan provides a “target” for us, collectively, as a state to accomplish that also complies with state policies. We are also aware of some of the practical realities that may arise with regards to issues like land use and have also evaluated scenarios like the “Land-Constrained” scenario on Oahu as described in Section 6.8 and Section 8.
I support all types of energy not just green energy, otherwise we will be priced out of Hawaii. Thank you
Thank you for your comment.
Since the critical raw materials (metals) necessary to manufacture initial global demand and future replacement of solar, wind and battery systems are insufficient we should be looking to develop geothermal on all islands, starting with Hawaii Island.
Further geothermal project development is heavily dependent on identifying and characterizing the geothermal resource (heat and/or hot fluid and associated permeability). Further assessment of the geothermal resource of all the Hawaiian Islands is needed to support
H-20 Integrated Grid Planning Report
APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
The foregoing statement can be supported by data provided by the Geological Survey of Finland and specifically in this presentation made by the report's author at the University of Queensland in Australia in August of 2022. https://smi.uq.edu.au/event/session/11743
geothermal energy development. The University of Hawaii’s Hawaii Groundwater and Geothermal Resources Center has done geothermal resource characterizations across the islands and continue to seek more funding to do follow-on assessments, including well drilling. For more information, see HGGRC’s “Hawaii Play Fairway Project” website at: https://www.higp.hawaii.edu/hggrc/projects/hi-play-fairway/
Adding solar and offshore wind will devastate the ecological beauty of this island, use much arable farmland and ruin rate payers financially. I'd rather you hang tight for 5 more years and get on board with mini nuke plants or fusion or more scrubbers for your existing power plants
We are not planning to transition to 100% renewable energy overnight, there will be future opportunities to integrate newer technologies in the future as they become available.
Hawaiian Electric’s long-term planning to reach 100% renewable energy by 2045 has always assumed multiple technologies would be needed, potentially including offshore wind. We understand there will be many concerns, and any proposed projects will be required to undergo extensive environmental reviews. Community engagement and a thorough analysis of on-shore and offshore impacts will also be required.
Although small modular nuclear reactors are a promising technology, we did not consider it in our plans at this time because Article XI, Section 8 of the State Constitution prohibits nuclear fission power generation without prior approval by the legislature – “No nuclear fission power plant shall be constructed or radioactive material disposed of in the State without the prior approval by a two-thirds vote in each house of the legislature.” Accordingly, nuclear fission generation is not currently included in our plans.
Basics weather we like all the challenges and consequences or not.... We have to make a huge changes. And it’s going to cost a lot.
It needs to be firm long-term energy structure. Viable firm sources Geothermal
Hydroelectric THATS IT Every option has large start up costs for projects. After that these 2 stay have the lowest costs of operation and lowest cost per kw. Why have every lawmaker and policy maker looking at our big trouble not seen this? cate I am a very strong solar advocate but the long term solution is just these two!
Geothermal energy is a clean firm generation option for Hawaii; however, further commercial project development is highly dependent on the identification and characterization of the geothermal resource, including locations that can be developed for projects. We are aware of the work that the University of Hawaii’s Hawaii Groundwater and Geothermal Resources Center is doing in this area. We are also tracking the development of emerging geothermal technologies and potential application in Hawaii. Hydroelectric generation is a potential renewable energy resource in Hawaii. How “firm” this resource can be is dependent on the availability of the water source and flows. Based on Hawaii’s current water resources, the potential for inline hydroelectric generation is somewhat limited. Pumped storage hydroelectric is a commercial technology that can provide multiple hours of stored energy. Project development in Hawaii will be dependent on suitable geology, available water sources, and availability of permittable project locations.
1. The 100% standard should be explained more clearly. What does it include/exclude (e.g. transportation sector)? Does achieving 100% of renewable electricity generation by 2045 mean that oil-burning plants will be completely phased out by then?
2. What is the penalty (and to whom) for not achieving this 100% renewable standard by 2045? 3. What is the comparative cost of renewables to carbon-based generation? 4. The report generally is very well done. Please identify the report authors. 5. The feasibility and likelihood of the attaining the 5-year targets should be clarified -- e.g. additional onshore and offshore wind.
The 100% renewable energy standard is codified in State law under Hawaii Revised Statute § 269-92. All electric generation provided by Hawaiian Electric must be renewable by 2045, with incremental steps in 2030 and 2040. Pursuant to this law, oil-burning plants and other fossil fuels would not be allowed after 2045. Under State law, the Public Utilities Commission has the authority to impose penalties on Hawaiian Electric for non-compliance with the renewable portfolio standard law.
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How realistic is the attainment of these targets? There should be a more detailed schedule of actions needed (and by when) to attain targets, including who is responsible for implementation.
6. Is there is minimum amount of firm energy (renewable or otherwise) required for grid stability? Conversely, is there a maximum amount of non-firm renewables that can be accommodated on a grid (to account for the variability and unreliability of renewables such as wind and solar)? What are these minimums and maximums, perhaps expressed as a range if there is not a set percentage. 7. For many of the important figures which are pie, bar or line graphs, please add labels or accompanying tables. While the graphics look nice, it's hard to associate the color legend to the graphic line, bar or slice. Examples include Fig. 1-4, Fig 2-2, 2-3, 6-10, 8-4, 8-5. Thank you for the opportunity to provide comments.
In Section 9 of the report, we project the cost of fossil fuel generation compared to the Integrated Grid Plan. Our plan is projected to lower cost compared to the Status Quo continuing on fossil fuels.
Our plan is ambitious over the near-term; however we recognize other scenarios are possible such as the Land-Constrained scenario discussed in Section 8. In Section 12, we discuss the amount of firm energy that is needed in our future plan. We believe firm energy is a key component to ensuring reliability over the long-term.
Thank you for the opportunity to comment on HECO’s IGP. My impression is that the plan is impractical, and many of the impacts would be unacceptable. My comments and questions pertain to the Oʻahu portion of the plan.
SCENARIO/PLAN DESCRIPTIONS: A clear description of the two Oʻahu scenarios (and the NI plans) would be very helpful to have early in the IGP report.
LARGE-SCALE SOLAR FARMS: The Plan states that 20,700 acres (32.3 sq. miles) of land on Oʻahu will be needed for large-scale solar farms by 2050. Using this much land for solar farms is unrealistic, especially given the policy by the North Shore Neighborhood Board in opposition to solar farms on good farmland. Why is there no map of the lands being considered for solar farms? Presumably, the 20,700 acres is for the Base Scenario. What is the acreage for the Land-Constrained Scenario, and why was it omitted? Given the large amount of land that would be used, why is there no discussion of the impact on residential development and housing prices, farming, ranching, views, etc.? ROOFTOP SOLAR: Table 6-18 indicates that there is a theoretical potential of over 4,934,292 acres available for rooftop solar on Oʻahu. This is 12.9 times the area of the entire island (382,490 acres). Was the incorrect 4.9 million acres used in any calculations in developing the IGP? What is the correct figure? Regarding the Land-Constrained Scenario, Figure 2-3 and Section 8.2.4.2 indicate a gradual and realistic increase in rooftop solar up to 2040. But in the 10-year period from 2040 to 2050, there appears to be over a 3.5-fold increase in capacity (the actual increase can’t be calculated because the 2040 data is missing from the summary). Is this 10-year increase realistic?
ONSHORE WIND TURBINES: Why is there no information provided on the proposed locations of wind farms, the number of wind turbines, heights, visual impacts, etc.?
OFFSHORE WIND TURBINES: Why is there no information provided on the proposed locations of offshore wind farms, numbers of wind turbines, heights, etc.? Currently, large 15-MW turbines are over twice as high as the tallest buildings in Honolulu, and would
Section 6.8 and Section 8.2 provide descriptions of the two Oahu scenarios. Section 3.5 earlier in the report also provides a description of the two Oahu scenarios. Section 6.9.2 discusses the types of land that have been excluded from our analysis for large-scale solar farms, which include Important Agricultural Land, Soil ratings of Class A and 90% of Class B and C land. The acreage of rooftops for the rooftop solar potential was corrected in the report due to a typo. The capacity for the rooftop solar potential was not affected. The Land-Constrained scenario reflects that in order to comply with 100% renewable energy in that scenario a lot of rooftop solar is needed by 2045. However, as we move toward 2045, there may be other technology advances that will allow us to comply with 100% renewable energy in 2045 with a different generation technology that does not require large amounts of land. The Plan allows us to adjust as we learn more about our renewable energy options in Hawaii.
The Integrated Grid Plan provides directional guidance on achieving 100% renewable energy. The actual locations and types of technologies that will interconnect to our grid will depend on the actual requests for proposals and competitive procurements where developers will propose projects for Hawaiian Electric to consider. The Plan is not prescriptive on the types of technologies or locations. We also note that as described in Section 10.4 and 10.5 we have been working to engage communities and have set requirements for developer to engage with communities as project types and locations are identified.
Land use for biofuels depends on the type of biofuel; however, if more solar, wind and energy storage resources can be brought online than future biofuel usage may be less than the amount of fossil fuel consumed today. Section 9 compares the cost of Status Quo to continue fossil fuel use versus our proposed plan.
Costs shifts due to customer programs was not evaluated in the IGP. The Public Utilities Commission has other on-going proceedings that may examine those issues in more detail for example, the
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Public Question/Comment Hawaiian Electric Response
be very visible even if located 12 miles offshore. Why is there no discussion of the impact on views, whales, shipping and boat travel, submarine travel and detection, fishing, etc.?
BIOFUELS: My understanding is the biofuels are expensive, use far more land than solar farms to generate the same amount of energy, and the processing facilities emit unpleasant odors. For the two Oʻahu scenarios, how much land and water would be required to produce biofuels? Where would the feedstock be grown? What would the impact on growing food and other crops on Oʻahu? For the HECO power plants, what is the projected cost of burning biofuels versus fuel oil or LNG? Why aren’t these issues addressed in the IGP?
LNG: Would LNG be cheaper than oil to fuel the HECO the power plants? If yes, then how much cheaper? Also would greenhouse-gas emissions be reduced if LNG were to be used? If yes, then how much less? Since LNG is widely used elsewhere, why is there no discussion of this option?
SHIFTING OF COSTS: To what extent are costs being shifted to home and business owners to pay for rooftop solar, and to taxpayers to finance subsidies for alternative energy? If these costs are significant, then the projected rates HECO will charge its customers reflects only a portion of the full costs to be paid by them. Why aren’t the full costs provided in the IGP? CLIMATE: If fully implemented, would the IGP affect local and global temperatures and climate? If yes, by how much? Given Hawaiʻi’s relatively small contribution to greenhouse gases, would the impact of the IGP on climate be large enough to be detected?
GUIDING PRINCIPLES: There is agreement that the production and delivery of energy should be affordable, reliable, and clean. But net-zero carbon emissions by 2045 and 100% generation of energy from renewable resources should not be achieved at the cost of our land and water environment, especially if there is no measurable impact on temperatures and climate. Why aren’t the tradeoffs discussed? Should more realistic goals be developed for carbon emissions and the generation of energy from renewable sources?
performance-based regulation, distributed energy resources, and/or energy equity proceedings.
We did not perform a global temperature impact analysis as part of the Integrated Grid Plan; however, we do assess the environmental impact of our proposed plan relative to Hawaii’s historical carbon emissions in Section 9.5. Our plans are guided by state policy to achieve net negative carbon emissions by 2045. We therefore evaluate tradeoffs within the confines of state policy.
Renewable resources - 100% - by 2045? No way. Consider the Stadium project, the Convention Center projects, the Rail project. The pace at with things get done in this state means Renewable Resources will not be up-and-running by 2045. So... PLEASE keep all remaining fossil fuel electrical generators online until renewables are up-and-running! AND for emergencies between now and then, restart the AEC plant a Campbell Industrial Park and keep it running at 10-20% of capacity, so it is ready to go when needed. Thank You.
We intend to retire generating resources, including fossil fuel plants, only once sufficient replacement resources are proven reliable and integrated onto the grid. This is to ensure that we will continue to deliver reliable electricity during the transition to 100% renewable energy.
The following comments pertain to Page 33 of the Draft IGP; see follow-on insert of text from our Star-Advertiser article of April 19, 2023 for related comments, notably relative to the Neighbor Islands’ preferred generation plans. While not stated anywhere in the Draft IGP, we view the pie charts on page 33 as begging a critical question: is 100% renewable power on Oahu feasible, considering land constraints, community
We acknowledge that our plans are ambitious and we also evaluate alternative pathways as pointed out in the comment. To that end, we outline external actions and risks that will need to be mitigated in Section 2.3 and Section 2.4 to successfully implement our Integrate Grid Plan. We have set forth a plan that we believe to be the lowest cost pathway based on current technologies.
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Public Question/Comment Hawaiian Electric Response
acceptability, reasonable DER assumptions, and affordability? Our view is that this is not a minor issue, but a fundamental one that cuts to the practicality of the 100%-renewables-by-2045 law. The comments which follow reference the percentages in the “pies” on page 33, in descending order of what we view are source-of-power “gaps” in the preferred plan generation mixes.
2022 Actual 2045 Base 2045 Land-Constrained A. Utility Solar Farms 5.5% 52.6% 20.7% 1. Issue: Acreage required to reach anywhere near 52.6% in 2045, considering conflicting land-use policies, cost considerations, and community acceptance.
2. Source of power gap: 31.9% 3. Determined by 52.6% in the Base Plan minus 20.7% in the Land-Constrained Plan.
B. Offshore Wind 0% 21.7% 21.6% 1. Issue: Community acceptability; the significant backlash to land-based windmills might be exceeded by backlash to floating or ocean floor-spouting windmills, due to visual blight and marine issues. 2. Source of power gap: 21.6%
3. Based on Land-Constrained Plan C. Customer DER 14.1% 17.1% 37.9% 1. Issue: Reasonably achievable? 2. Source of power gap: 9.7%, perhaps more
3. Current 37% rooftop penetration equates to 14.1% DER; doubling current penetration (perhaps unlikely in view of low-hanging fruit already “picked”) to 74% would presumably equate to 28.2% (9.7% derived by 37.9% minus 28.2%). D. Affordability 1. To assure continuation of reliable electricity, current oil-fired generation plants won’t be able to be retired until there are replacement power sources. The three source-of-power gaps listed above total a staggering 63%. It is clear that the extent of the diminishing “Non-Renewables” slices of the pie on page 33 is unreasonable. Thus, a discussion in the final IGP should address both affordability and extent-of-CO2 emissions issues relative to the likely options: a. Assuming that the 100% Renewables law is inviolable:
i. Biomass ii. Biofuel iii. Hydrogen iv. Other b. Should amendment to the 100% Renewables law be considered: i. Coal ii. Oil/Diesel iii. Natural Gas
2. The current “firm renewable” RFP process should bring to the fore both the cost of the various alternatives listed in 1.a. above
We are also open to other technologies that may resolve some of the potential issues described in this comment. We have added a new Section 6.9.5 to discuss future and emerging technology options.
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Public Question/Comment Hawaiian Electric Response
and, in addition, engender discussion and debate on the extent of “green” and land-use implications. Burning coal again would appear to be a non-starter. Should the Legislature refuse to amend the 2015 law, it is likely that we will slip towards 2045 with the least-optimal combination of cost and emissions: highest-emitting oil/diesel in combination with highest-cost thermal renewable option from 1.a. above. But this only highlights that the Legislature and the previous Governor have taken off the table an option that emits 30% less CO2 than oil and is likely to be less expensive than the 1.a. options above: natural gas, brought to Hawaii in the form of LNG. HECo stated, in 2016, that LNG could “save customers as much as $3.7 billion over 30 years, depending on future commodity prices.” But Gov. Ige was in opposition, causing withdrawal of the LNG proposal. Perhaps amend the law with respect to 1.b.iii only? 3. We’ve pointed out before that decarbonizing is a matter of trade-offs between “green” and affordability. In view of Hawaii’s ever-exacerbating cost of living, we ask, “to what extent should we keep increasing the financial burden on our citizens?”
In summary, our comments and analysis above speak more to what’s not stated in the IGP, but what should perhaps be reported back to the PUC by HECo. And by the PUC to the Legislature. HECo is caught in a tough spot; how can HECo possibly speak out that 100% renewable simply won’t work on Oahu when it has no choice but to follow the mandates of the PUC and the Legislature. But it would certainly be refreshing if the final IGP were to “tell it like it is.”
The plans call for 400MW of offshore wind on O‘ahu by 2035 is based on a feasibility study., which was deeply flawed for several reasons: Offshore wind infrastructure was only spec'd for Category 4 storms. With an increase in the intensity of storms, that the predictive models show will increase in the future, infrastructure should only be approved if they can withstand Category 5 storms.
The impacts of endangered species (whales and seabirds) was no accessed. It is well known that wind turbines "take" endangered seabirds and bats in Hawai`i. There are ecological and financial implications of this. No offshore wind infrastructure should be approved without an associated plan to minimize and mitigate take of endangered species. Any take of birds by offshore wind infrastructure would also be a violation of the migratory bird act.
Recent scientific research has shown that humpback whales use the ocean floor to exfoliate and remove parasites. No offshore wind infrastructure should be approved prior to scientific studies to determine whether or not the infrastructure will impact such whale behaviors. Impacts of offshore wind infrastructure on traditional and customary fishing practices of Native Hawaiians has not been assessed. The plan should not be approved until that is done, and the projects are shown to not have a negative impact on these T&C practices.
We appreciate your concerns with respect to offshore wind development. Hawaiian Electric’s long-term planning to reach 100% renewable energy by 2045 has always assumed multiple technologies would be needed, potentially including offshore wind. The federal government agreement with the state of California to develop areas on the Western Outer Continental Shelf to bring up to 4.6 gigawatts (4,600 megawatts) of floating offshore wind online is significant. We understand there will be many concerns, and any proposed projects will be required to undergo extensive environmental reviews. Community engagement and a thorough analysis of on-shore and offshore impacts will also be required.
The integrated plan is a good first step in reaching important goals for clean energy production. That being said this plan fails to address the costs of switching to renewable energy sources and seems overly ambitious as to when HECO expects to meet these
We acknowledge that our plan is ambitious. We outline some of the risks and changes needed to ensure successful implementation in Section 2.3 and 2.4. We also look at different scenarios to achieving
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Public Question/Comment Hawaiian Electric Response
goals. I don’t think reducing the carbon emissions of Hawaiian energy production by 70% in the next 7 years is feasible. This feels more like an attempt to gain public approval rather than a serious proposal. Reaching this goal has a huge dependence on the expansion of mostly solar power from both HECO and its customers.
Considering the shortage of qualified solar installers on the island, it is unlikely that this vast expansion in solar capacity will be met. The other thing that’s not addressed in this proposal is the cost of solar over its lifespan. Yes, it provides lower emissions than petroleum but it is not without costs. There is significant resource extraction that must be done to produce the aluminum, glass, and rare metals which are used t in photovoltaic panels. Each of these extractive industries is heavily reliant on fossil fuels and pose risks to the environment.
In addition, solar panels have a lifespan o fondly about 30 years meaning in the near future, there will be thousands of useless photovoltaic panels that we currently have no plan to deal with. They are difficult to recycle and often expensive for people to dispose of. If our energy needs expect to be met long term largely by photovoltaics, we need to develop better systems for the disposal and recycling of panels.
This plan seems overly dependent on “distributed energy resources”. Hawaii already has a huge problem with the cost of living, worsened by a high percentage of low-income households. These people cannot afford to invest in these future energy systems. Where does the $1.4 billion come from to pay for the distribution upgrades and renewable energy zone enablement costs? Should that cost fall on the consumers? Why is there no mention of a plan to reduce overall energy needs and use? Surely this must be an important part of achieving a sustainable future. It also seems like a big oversight of such a plan to not address the energy uses involved in transportation. That makes up a significant portion of Hawaii’s emissions and will need to be addressed.
I hope some of these comments are useful during your revision process. Thank you for taking the time to consider my thoughts and thank you for your efforts in moving Hawaii towards sustainability.
our carbon reduction goals in Section 3.5 and Section 8; for example, the Land-Constrained case on O’ahu.
We address disposal of clean energy equipment in Section 2.6 of the final report.
We agree that energy efficiency and conservation is key component to achieving our goals. We outline this important part of our plan in Section 2.1, “Widespread adoption of energy efficiency” which also includes conservation measures. We also outline efforts to advance energy equity and options for low income customers in Section 10 of the report. We will continue to explore options and solutions as part of a separate energy equity proceeding with the Public Utilities Commission. You may learn more information, including how to participate in this equity proceeding at: https://puc.hawaii.gov/energy/equity/
There is little reason to rely on fossil fuels at all. Jack Here said if 5% of the country is dedicated to growing hemp, we would have more than enough energy to meet our needs. But we don’t need 100% of our energy, just a small amount relatively to the past.
Right now we are getting energy from trash to energy. We could just as easily burn hemp and hemp oil. May be burnable in that old coal plant? Definitely could be burned in the trash to energy plant. Hemp oil could be burned in existing oil to energy plants. I do not know why we have to pay extra because we do not meet our goals. Hemp can easily make this up so why not do? Makes a lot more sense than burning slow growing trees.
We encourage any renewable energy resource that has a bon-a-fide proposal to participate in requests for proposals for new generation. While the Plan outlines certain technologies, the actual technologies and locations that will interconnect to the grid will be based on the market (and developers) submitting proposals through our requests for proposals that compete against other technologies on price and non-price factors.
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Public Question/Comment Hawaiian Electric Response
So why isn't this being considered? I do not consider it to be against the federal law to be a valid reason. Hemp and marijuana were made illegal, not because they are a health problem, but the competition it offered to the alcohol business, the nylon industry, and the paper industry.
So you along with all the other energy businesses should be pushing the federal government to end its stupid law against hemp and marijuana.
Aloha:
Please accept these comments from DKK Properties, LLC. We operate warehouses on Oahu and Maui and we are concerned that the draft IGP will not adequately control the cost of electricity in the short and medium term. Comments: There is a lot to like in the draft IGP once you get down to the level of the plan itself, including: The concept of REZs; The proposal for a standardized community benefit rate to allow projects to be compared on an apples to apples basis (but see comment below for additional details) The commitment to making new purchases from IPPs at fixed prices;
The generation mixture planned to achieve the RPS requirements; and The substantial community outreach by Hawaiian Electric that accurately identified affordability as the biggest concern of the company’s customers. With regard to item b above, it is not enough to simply say “$ 3,000 per MW”. Are we saying storage only projects are not required to provide community benefits? If a project were to use thin film solar the footprint to provide a Megawatt of electrical output will be much larger than standard pv. If the community benefit payment in connection with solar pv is due to view impacts, the footprint should factor into the analysis. The reality is that it would be far more helpful for the Company or the Commission to adopt a written list of standard assumptions or best practices that would cover the following topics: sizing to be DC; sizing to be adjusted based on inverter limits; minimum setbacks from neighbors; any adjustments for sites proposed on hillsides; accepted models for output and visual impacts; any inflation adjustments for the $ 3,000 figure; which neighbors would receive formal written notice of the project; and whether the community benefits fee would apply to offshore projects the same way as onshore projects. Off Grid Customer Migration needs to be discussed. Company admits that 1 in 20 of its potential customers are already meeting their energy needs elsewhere (Section 1.3) The migration of existing customers off the grid is not adequately addressed in the IGP. Will the company propose exit fees or other measures to keep enough customers on the grid to pay for all the grid improvements needed to connect more DER? The reality is that most community groups are not qualified to comment on such a detailed technical plan. If the company is
The community benefits outlined in Section 10.4 are an initial starting point. As we learn more from how these benefits are implemented, we intend to make adjustments to improve the process. This topic may also be further explored in the Public Utilities Commission’s energy equity proceeding (https://puc.hawaii.gov/energy/equity/). Note that storage only projects are held to the same $3,000 per MW minimum per year requirement.
The impacts of off grid customer migration are not explored in depth in the
Integrated Grid Plan; however, Hawaiian Electric continues to assess these
impacts, including in other relevant proceedings, such as through standby
charges in the Microgrid Services proceeding, and through advanced rate
designs (the Company’s proposed modifications to the standby charge were
not adopted for the Advanced Rate Design TOU Pilot but the Company
maintains that standby charges should still be considered in advanced rate
designs). Exit fees may be part of the mechanisms to ensure protection for
customers.
Hawaiian Electric clarifies that it has not requested, and is not looking for, any “super priority” status; nor is the Integrated Grid Plan a substitute for approval of individual projects and applications that Hawaiian Electric must submit to the Commission. Rather, Hawaiian Electric requests approval of the Integrated Grid Plan as a guiding strategy that all stakeholders, including the Commission, can work from for the near-term and as a way to measure our collective progress toward our goals. The Plan seeks to keep all stakeholders on the same page and provide a frame of reference for the many interrelated ongoing dockets, applications and future proceedings to allow all parties involved to agree upon, or at the very least understand, the basis for inputs, assumptions, and the future direction of grid plans.
In regards to fuel purchases, our fuel is sourced through a competitive RFP process where the companies select the lowest cost option. Our pricing is also indexed, so as world oil goes up and down, so does our pricing. As a result, we are obtaining fuel at the lowest cost available to us. Generally, linking the IGP plans to PBR ensures that the correct incentives are in place to bring new resources from the planning stage into the development. Otherwise, financial incentives may be misaligned and incentivize a different set of actions than what was planned or that is consistent with state policy and the Commission’s priorities. While some renewable projects from the recent RFPs withdrew, this was due to extraordinary circumstances arising from supply chain issues caused by a global pandemic. Lessons learned from this event could be used to tweak the alignment between PBR and IGP through ongoing revisions to the PIMs. The Integrated Grid
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Public Question/Comment Hawaiian Electric Response
serious about additional community input, some entity would need to provide funds to allow groups to hire engineers or other grid experts. This is a situation where Hawai’i lags other states in providing funds to groups involved in ratemaking and other PUC proceedings. The Biggest Problem with the IGP is how the Company Proposes to Use it. At the level of policy and structure, the proposed docket ‘superpriority’ for the IGP as a “foundational element” of other dockets is misguided. This plan does not deserve the requested superpriority status because it lacks any serious plan to reduce costs in the next few years. The Company went out of its way to obtain community feedback. The feedback was consistent across the islands. Affordability is the number one issue for customers. But the IGP refuses to incorporate smarter purchasing of oil into the plan even though in the short term it is the obvious way to lower customer bills. (a) Other businesses are involved in a transition similar to what Hawaiian Electric is doing. For example, Ford and GM have both indicated they are transitioning their product line away from fossil fuels. To understand what is missing from the IGP it might be easier to make an analogy What would the shareholders of GM and Ford say if they were told ‘from now on we are focusing only on the EV business and we don’t care about whether the remaining ICE business makes a profit anymore’. They would not accept such a plan, of course. Linking to the Performance Based Regulation docket is a mistake. The Company wants to link IGP to the Performance Based Regulation (PBR). With the benefit of hindsight it now seems clear that as a tool to control customer costs, the original PIMs were ineffective during the pandemic and the oil shock that followed the invasion of Ukraine. The PIMs previously approved by the Commission seem likely to require a redo. For example, no one can be proud that the utility well over $ 1 million to sign RFP contracts for big solar projects that were never built. Why link IGP to PBR at this point in time? Baked in TOU rates are a Mistake. The Company has used TOU rates as the default assumption in the IGP, but the pilot TOU rates from the Company have all been designed to benefit retired people over those still working. The Company suggests that evening rate (with its punitive costs) should apply until 9am the next morning. Working families can’t just choose to sleep in for better electric rates. People who are struggling to survive balancing multiple jobs do not have the luxury to change the time of day when they cook or do laundry to get a different rate on their electricity. Some day appliances will provide the functionality to automatically adjust to price signals from the Company, but in today’s world the TOU approach so far from the Company has helped affordability for the retired at the expense of those still working.
Plan also outlines infrastructure needs that may be considered more broadly in future multiyear rate plans.
Based on guidance provided by the Commission and stakeholders, time of use impacts were incorporated for customers with EV and DER and for non-DER/EV customers. The majority of peak reductions were assumed to be provided by customers with DER and EV that have the capability to load shift via a battery energy storage system. Much smaller peak load reductions were forecast to be provided by customers without these enabling technologies (i.e., behavioral changes). Further, the degree of time of use impact embedded in the forecasts varies. The base case assumed a more moderate time of use rate structure that the Company proposed; only the low load case assumed the more aggressive time of use rate that more closely corresponds to the Commission’s current direction to implement 1:2:3 ratio time of use rates.
Aloha Commissioners and Staff, The Public Utilities Commission (“Commission” or “PUC”) opened the Hawaiian Electric
In response to foundational and “super priority” please see above response.
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Public Question/Comment Hawaiian Electric Response
Companies (“HECO”) Integrated Grid Planning (“IGP”) proceeding on July 12, 2018.1 The IGP proceeding replaces the previous planning proceedings: Integrated Resource Planning (“IRP”), and Power Supply Planning (“PSP”). The HECO Draft IRP Plan (“Draft Plan”) was filed with the Commission on March 31, 2023. (Unless specified otherwise, references to the Draft Plan refer to Book 1). Comments are due by April 21, 2023. Life of the Land (“LOL”) is a Hawai`i non-profit public interest organization that emerged as an organization in February 1970, one month after the National Environmental Policy Act
became the law of the land and two months before the first Earth Day. Life of the Land has been active in over five dozen PUC proceedings over the past half century. Life of the Land asserts that every energy project has positive and negative economic, environmental, social, cultural, geographic, greenhouse gas, taxpayer and ratepayer impacts, and Life of the Land is concerned with the impacts, externalities and unintended side-effects of energy projects and programs.
Life of the Land asserts that HECO`s Draft Plan has both positive aspects and the need for clarifications and amendments for other parts of the IRP Plan.
Positive Aspects The Draft Report covers a wide range of complex issues.2 The layout of the Draft Plan allows a reader with utility knowledge to easily read through the document as the document is clear, has varying and readable print size, and contains clearly marked columns, tables, colors, pictures, boxes, and summaries. The document includes a table with nearly 100 abbreviations and a glossary that increases readability for readers with utility knowledge. Over the course of the past four years, HECO, with guidance from the PUC, created conditions that allowed for greater two-way flow of information. This is a step in the right
direction. The first page of the Executive Summary notes that we are all in the transformation to a fundamentally new reality.
We envision a clean energy future where customers have more choices, more reliable power, and more stable rates. By 2045, clean energy will be there when we need it: behind every light we turn on, each meal we share, and all the ways we get around. Electric
Hawaiian Electric is not aware of any laws, rules, or Public Utilities Commission orders indicating that approval of the Integrated Grid Plan would shift the burden of proof from the applicant to intervenors in future Commission proceedings. Regarding Affordability, the Integrated Grid Plan, provides pathways that are lowest cost over the long-term based on the inputs and assumptions that have been approved by the Public Utilities Commission. The lowest cost scenario is compared to the Status Quo of continuing to rely on fossil fuel in Section 9 of the report.
Specific programs related to low and moderate income customer participation in Hawaii Energy’s energy efficiency programs and community based renewable energy are possible topics to consider in the energy equity proceeding. With respect to energy efficiency programs, Hawaiian Electric does not administer the energy efficiency programs. For community solar low and moderate income projects, Hawaiian Electric may work with the subscriber organization of these projects to determine the amount of low and moderate income customers the program has the potential to reach. This may be reviewed as part of the individual project PPA application request for approval. Consistent with the Framework for Competitive Bidding, our requests for proposals are overseen by an Independent Observer (IO), and in some cases, an Independent Engineer (IE), who report to the PUC. It is the role of the IO and IE to ensure that the RFP is undertaken in a fair and unbiased manner, including monitoring all steps in the competitive bidding process as well as reviewing our proposal evaluation methodology and the evaluations themselves.
The acreage of land identified in the report represents the available land and renewable capacity that can be developed when constrained by high level screens for federal, state, and important agricultural lands. At the initial input development phase of IGP, it wasn’t clear how community acceptance may reduce the available potential so we took the approach that in the technical analyses, the less constrained potential would be used to identify the renewable energy zones and any integration costs. We also evaluated a scenario on Oahu reflecting stakeholder feedback that land constraints may prevent the technical potential for large-scale development.
Undergrounding transmission lines are extremely costly compared to hardening existing overhead facilities and would result in a small fraction of hardening completed for the same amount of spending. On the mainland, targeted undergrounding of overhead lines has shown to be a cost-effective extreme event hardening solution in heavily wooded areas with single-phase lateral taps. This is why the Companies proposed a targeted undergrounding program for four miles of distribution laterals on Oahu to validate cost assumptions and assess the cost-effectiveness of targeted distribution lateral undergrounding in Hawaii. The same cannot be said of undergrounding transmission lines. For example, a 2009 cost-benefit study prepared for the Public Utility Commission of Texas found that undergrounding transmission lines in the region would be extremely costly and would not be cost effective. These findings were reported despite the analysis considering the previous ten years of storm
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
cars and buses will get us where we need to go, with a backbone of vehicle chargers at the workplace and community centers. At home and at work, energy efficient appliances and equipment will electrify our daily lives. This clean energy transformation will advance social equity and benefit all customers and communities. Enhanced grid capacity will support growth in residential and commercial development, empowering a statewide expansion in affordable housing. In places with new energy facilities, host communities will thrive with benefit packages from developers. The future grid will look unlike any before, with customers playing a vital role in generating and storing energy. Customer-scale generation and battery storage in customers’ homes and communities will seamlessly connect to largescale generation through a modernized transmission system, providing a consistent stream of energy that can adapt to fluctuations in use. Sourcing energy from a diverse array of local, renewable resources will fortify Hawai‘i against global swings in oil prices, stabilizing utility costs for customers. [emphasis added] Concerns, Clarifications & Questions
“The Integrated Grid Plan is the culmination of more than 5 years of partnership with stakeholders and community members across the islands.”5 HECO took five years to develop the IRP Plan and to write the 900+ page report. The public has three weeks to review the report and file comments. Life of the Land`s critique of the IRP Draft Plan: (A) IS THE DRAFT PLAN FOUNDATIONAL? (1) Foundational References
(2) Burden of Proof (B) CUSTOMERS
(1) Affordability (2) Energy Equity (3) Community Benefits Packages
(4) Defection, Migration, Off-Grid (C) TRANSMISSION GRID (1) Hardening The Transmission Grid (2) Renewable Energy Zones
(3) Terminating Existing Renewable Energy Projects (D) PROCESSES
(1) The IRP, PSIP, IGP Process (2) HECO`s Key Policies: Climate Change, Bioenergy (3) Public Trust, Public Interest & Trust Properties
(4) Streamlining (5) Greenhouse Gas Analysis (A) IS THE DRAFT PLAN FOUNDATIONAL? HECO asserts that a modern grid is foundational to the IGP process, and that the IGP process is foundational to everything else. “We are also actively pursuing a grid modernization program that is foundational to realizing this Integrated Grid Plan.”
impacts on restoration and societal costs in Texas, which included eight tropical storms, three Category 1 hurricanes, two Category 2 hurricanes, and two Category 3 hurricanes between 1998 – 2008. The Companies intend to analyze the cost-effectiveness of undergrounding transmission lines in Hawaii using their hurricane resilience model that is currently being developed with Pacific Northwest National Labs. As outlined in the IGP, we will need both large-scale and small scale renewables to meet our goals, especially in a fully decarbonized economy. Therefore, we do not prefer one over the other; rather, we need both at-scale and low cost to ensure that electricity must remain reliable. Part of developing renewable energy zones is to enable the integration of large-scale resources while advancing energy equity as described in Section 10. With respect to rooftop solar we have also conducted analysis (Section 8) to determine distribution capacity upgrades needed to integrate higher amounts of rooftop solar. We make a planning assumption that projects with an existing Power Purchase Agreement in the planning horizon expire and allow the model to re-optimize, because there is no guarantee that the existing resource will be able to continue. This is to ensure we are adequately planning the system. Renewal of an existing PPA could occur through a competitive procurement which ensures that we are able to negotiate the best prices for our customers or through negotiations to amend its current PPA. The procurements will largely determine the actual type of technology and location of projects; whereas the Integrated Grid Plan provides a roadmap on how to achieve 100% renewable energy.
H-Power is not assumed to expire because it is a firm renewable source that also serves a larger societal benefit by diverting trash from the landfill. Other solar and wind PPAs were assumed to expire at the end of their contract term to allow the models to re-optimize the resource mix if a different resource could better meet grid needs in future years. Offshore wind is a valuable resource in a land constrained scenario as well as in the base scenario because it provides a high capacity factor resource at a relatively low cost of energy.
The Technical Advisory Panel prepares technical feedback and recommendations based on materials and analysis that the Company presents. The notes provided by the Technical Advisory Panel reflect the panel’s views and is not prepared by Hawaiian Electric. As shown in figure below, the majority of the Panel’s members are non-utility members; including, experts from industry organizations, national laboratories and academia.
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
“Operating the 50- to 75-year-old O‘ahu fleet, for example, with increased load ramping, low-load operation, and offline cycling accelerates the aging process, which has led to and will continue to cause increasing rates of forced outages and/or derations of firm capacity on a daily basis. [] These reliability risks must be urgently addressed—this is foundational to achieving the State’s decarbonization and renewable energy goals.” “Preventive measures are considered foundational to ensure that critical transmission lines, substations, and distribution circuits withstand threats to ensure that critical customers and facilities have power and facilitate rapid system recovery for all customers.” “Hawaiian Electric’s Initial T&D Resilience Program, shown in dark blue, represents the first phase of foundational hardening investments to increase the resilience of the system.”
“Hawaiian Electric’s initial Transmission and Distribution Resilience Program (Docket 2022- 0135) represents the first phase of foundational system hardening investment of approximately $190 million across the islands we serve, with the potential for a 50% match of federal funding.” In addition to foundational grid hardening discussed above, there is a need to incorporate greater grid operational awareness, control, and automated switching flexibility to enhance resilience and reliability.” [emphasis added]
HECO asserts that IGP trumps everything else. “A multitude of ongoing proceedings are currently before the Public Utilities Commission, in collaboration with Hawaiʻi energy stakeholders, intended to carry out the legislature’s policies. The Integrated Grid Plan is foundational to these interrelated proceedings because it sets forth a well vetted common set of assumptions and lays out future pathways as we move toward our decarbonization goals.” [emphasis added] (A1) Foundational References Life of the Land searched the Commission`s Data Management System (“DMS”) to figure out whether HECO had previously raised the issue that this filing would be foundational, and thus controlling over other proceedings and applications. HECO used the term on two other occasions: “The Companies are committed to seeing through the IGP process to establish foundational plans and then running its next set of procurements based on these results.” [emphasis added] “These reliability risks must be urgently addressed—this is foundational to achieving the state’s decarbonization and renewable energy goals.” [emphasis added] We found only a few documents by any other entity that used the term foundational within this proceeding:
. With respect to the procurement process, an Independent Observer and Independent Engineer oversee the Company’s process to ensure a fair process is conducted. The Independent Observer and Independent Engineer are chosen by the Public Utilities Commission. The list of key policies in Table 5-1 is not meant to be an exhaustive list of energy policy in Hawaii; but key policies that guide our planning processes and assumptions. However, we have added a couple of the policies to Table 5-1 as suggested in the comments. As an initial matter, HRS § 225P-5 applies to the State and State agencies, not to private companies; however, Hawaiian Electric takes mitigation and adaptation to climate change seriously. It has submitted an application to the Public Utilities Commission to adapt to climate change by hardening grid infrastructure as outlined in Section 7 and climate mitigation through its Climate Change Action Plan described in Section 1.2.1. These efforts will help the state make substantial progress toward meeting the requirements of HRS § 225P-5. Importantly, the Plan seeks to achieve the goals of § 225P-5 by achieving at least 50% GHG reduction by 2030 and net zero by 2045 compared to 2005 levels. With respect to GHG emissions and the Commission’s obligations under HRS § 269-6, we believe that the environmental analysis provided in Section 9.5 are sufficient for purposes of the Plan as supplemented by environmental analyses for individual projects. In the next steps of the Integrated Grid Planning process, such as issuing competitive procurements, developing projects, and seeking approval for individual projects, stakeholders and the commission will be afforded further opportunities to ensure alignment with HRS §§ 269-6 and 225P-5.
We agree with Life of the Land that streamlining is not intended to bypass any community or stakeholder engagement or processes, rather finding ways to be more efficient in the development and implementation of procurements and projects.
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
“Commission Order 35238 Guidance -- The commission directs the Companies to continue to embrace VoS [Value of Service] as a foundational component of the Companies' future planning and procurement efforts.” [emphasis added] “The Consumer Advocate would like to [] advance efforts to unbundle the costs of service into relevant, disaggregated detail. These unbundling efforts will be a foundational and integral part of evaluating various alternatives, whether it be supply side, demand response, energy efficiency, transmission, distribution, or any electric service, as part of the IGP process.” [emphasis added] The IGP Report presents a high-level outline [] These comments, therefore, address the IGP Report at a similarly high level, focused on foundational principles and concepts.” [emphasis added] “These comments discuss several foundational elements of integrated grid planning that are necessary to achieve a more customer-centric outcome, including: • Allowing meaningful outside review and input [] • Emphasizing DER procurement methods [] • Prioritizing flexibility.” [emphasis added] “Taking time to engage with stakeholders to get the foundational inputs right has been time well-spent, especially given that IGP represents a course shift from Hawaiian Electric's previous utility planning processes” [emphasis added] (A2) Burden of Proof
HECO appears to be implying that once the PUC has accepted the IGP as the foundational base, then if HECO files an application that is based on the IGP, anyone who intervenes to protect their interests will have the burden of proof to show that the IGP is not reasonable or that conditions have changed.
“To move from planning into implementation, we ask that the Public Utilities Commission: Approve the Integrated Grid Plan to serve as a foundational element for Hawaiian Electric and regulatory actions, including in interrelated dockets in the near term.” This idea of foundational supremacy is not new. HECO floated the idea in the Hawaii Clean Energy Initiative (“HCEI”) Energy Agreement (“Energy Agreement”) signed in October 2008. “In 2008, a memorandum of understanding between the State of Hawaiʻi and DOE launched the Hawaii Clean Energy Initiative, which laid out the foundational elements to achieving Hawaiʻi’s clean energy future. It envisioned that 60% to 70% of future energy needs would be provided by renewable energy, including energy efficiency.”
The Energy Agreement, if it had been accepted by the PUC, would have required the utility to file tri-annual Clean Energy Scenario Plans (CESP) with the PUC.
“If the Commission rejects all or parts of the CESP, there should be an explanation for non-approval and the implications of that non-
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
approval on the utility's asset investment and strategic choices for the upcoming three-year period. In order to continually reassess the CESP plan on a regular and timely basis, it is suggested that if the PUC has not issued a decision within a defined period, the plan is automatically deemed ʻapproved`."
HECO could choose which projects to advance. If an application submitted to the PUC could be loosely connected to the CESP, it would be presumed to be needed and the PUC permitting process would be expedited. The burden of proof would be shifted to intervenors to show that the application was not in the public interest. * Life of the Land asserts that the IGP Draft Plan is a HECO-centric, time-sensitive, snapshot of current assumptions and analysis is a rapidly changing environment. The Commission should treat the current HECO desire for a foundational document like how the Commission treated the concept in the 2008 era. HECO`s foundational concept should simply reflect HECO`s desires and not PUC policy.
(B) Customers HECO`s Executive Summary states, “This clean energy transformation will advance social equity and benefit all customers and communities. [] The future grid will look unlike any before, with customers playing a vital role in generating and storing energy.”
(B1) Affordability “Again and again throughout the planning process, we heard that affordability and reliability are of top concern and interest to our customers, echoing the comments in multiple customer surveys and focus groups conducted for the company.” There is no Modeling Scenario for Affordability, that is, for determining the future based with a primary emphasis on affordable rates. There are ten Modeling Scenarios: Base Electricity Demand, (2) Land Constrained, (3) High Electricity Demand, (4) Low Electricity Demand, (5) Faster Technology Adoption, (6) Unmanaged Electric Vehicles, (f) DER Freeze, (8) Electric Vehicle Freeze, (9) High Fuel Retirement, and (10) Energy Efficiency Resource.
Doug McLeod, the former Energy Commissioner County of Maui, submitted comments on April 10, 2023. "The Biggest Problem with the IGP is how the Company Proposes to Use it. At the level of policy and structure, the proposed docket ‘superpriority’ for the IGP as a “foundational element” of other dockets is misguided. This plan does not deserve the requested superpriority status because it lacks any serious plan to reduce costs in the next few years. The Company went out of its way to obtain community feedback. The feedback was consistent across the islands. Affordability is the number one issue for customers. But the IGP refuses to incorporate smarter purchasing of oil into the plan even though in the short term it is the obvious way to lower customer bills."
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
HECO asserted, “Although utility rates will rise in the transition to clean energy, they will be lower and less volatile than if we continue to rely on fossil fuels.”
“Our projections show that the transition to clean energy may reduce the overall energy burden for the typical residential customer on each island through 2050, compared to today's energy burden.” “Stakeholders stated that residential TOU load shift scenarios should be included in the IGP base forecast and bookend forecasts even if impacts are relatively small because it is likely that TOU rates will be implemented.”
“In collaboration with stakeholders, as documented in the March 2022 Inputs and Assumptions Report, we developed several scenarios to identify a range of potential grid needs. The scenarios test whether given uncertain futures the resource mix and direction of the lowest-cost portfolio would change. Table 6-16 describes the various scenarios we analyzed and presented in this report.” * Life of the Land asserts that one scenario that should have been examined is how low rates could be, if that was the primary goal of IGP. This would be useful in comparing alternative scenarios. (B2) Energy Equity “We have recently selected CBRE projects (also known as the Shared Solar program) through a competitive procurement for LMI community-based solar projects. [] While these projects may not provide an opportunity to every LMI customer that desires to participate in the renewable transition, it represents a start that will enable us to improve on and expand programs and choices for customers in the future.”
Over the years Life of the Land has raised the issue of differentiation: a program may be open to everyone, but everyone can’t be part of the program. This is true for rooftop solar and for CBRE.
* What percent of LMI customers currently participate in any HECO or Hawaii Energy program related to renewable energy, clean energy, and/or energy efficiency program?
* What percent of LMI customers could be served by the CBRE projections that exist and/or are in the pipeline?
(B3) Community Benefits Packages “By 2035, our plan calls for up to 1,640 MW of new renewable resources across our service territories.” “On O‘ahu alone, we will need nearly 3,200 MW of large-scale solar generation by 2050, built on 20,700 acres of land.” HECO is requiring renewable energy developers to include a Community Benefits Package (“CBP”) proposals. There are approximately two dozen required components in the CBP. HECO will review all proposals using a proprietary black-box model.
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
“Developing renewables and transmission will require community support and streamlined regulatory reviews, permitting, and execution.”
A major risk occurs if HECO`s focus is placing large systems in rural residential and agricultural places conflicts with community values. Under what conditions can the community say NO. How is HECO treating the CPB. * Allowing non-competitors to see the inner workings of the non-price black box would go a long way to easing community concerns. (The Commission rejected one approach suggested by Life of the Land.) * Large number of acres is confusing to many people. How many square miles of land are needed? What percent of non-conservation-zoned, non-military land is needed?
(B4) Defection, Migration, Off-Grid As alternative energy and storage sources continue to advance, there will be a tendency for large entities to self-generate relying on cheaper options and/or less polluting options while the utility continues to be bogged down with costly legacy equipment and overhead. The HECO Draft IGP limits the defection analysis to one reference for one commercial customer on Lāna`i. “No resort load scenario resource plan, year 2029 -- In this resource plan, it is assumed that a big part of system load will be off grid.” * The IRP Plan should include estimates for the percentage of customers and the percentage of the load that is currently off-grid, and how this may change due to the IRP Plan.
(C) Transmission Grid “The future grid will look unlike any before.”
(C1) Hardening the Transmission Grid HECO started to underground lines in urban Honolulu in the 1920s. The backbone of the O`ahu grid is the 138-kV Transmission lines. The first 138-kV line was installed in 1958. Today, the 138-kV transmission grid contains both overhead and underground lines. The PUC issued Decision and Order No. 10620, on May 8, 1990: “The Commission agrees that laying transmission lines underground promotes aesthetics and preserves scenic views. However, the utility has the responsibility to minimize the cost to ratepayers in
providing reliable electric service.... [T]he cost of placing transmission lines underground is very high and the burden of that cost ultimately falls upon the ratepayers. Thus, unless (1) there is a compelling reason (which outweighs the costs) to place the lines underground or (2) there is a stated public policy requiring the lines to be laid underground or (3) the ratepayers as a whole consent to bear the high cost of putting the lines underground, we do not believe that we should require HECO to place the transmission lines underground.
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
That placing the transmission lines overhead may obstruct one's view plane, in and of itself, is not sufficient cause to require the ratepayers to bear the cost of laying the lines underground.” HECO asserted in their grid hardening docket that there is more than one way of hardening the transmission grid. Reinforcing overhead lines and burying lines are two methods. HECO did not compare the two for cost, reliability, and/or resilience, now and in the future. Rather, 99% of HECO`s plans are reinforcing the overhead system. How underground compares with overhead hardening matters both in the short-run and in worsening conditions in the long-run.
(C2) Renewable Energy Zones As defined by HECO, a Renewable Energy Zone (“REZ”) is an area that may or may not have renewable energy but could have additional terrestrial-based, ground-based, commercial-scale, renewable energy systems based on existing or potential terrestrial transmission lines. Thus, REZs exclude large commercial shopping centers, parks, schools, and rooftops in urban areas as well as excluding ocean-based renewable energy systems. “A core part of the Integrated Grid Planning process was identifying potential future locations for renewable generation facilities and transmission and distribution infrastructure to power the grid with 100% clean energy. Hawaiian Electric partnered with the National Renewable Energy Laboratory (NREL) to estimate the potential for large-scale solar, wind, and distributed rooftop solar developed based on available land, potential capacity, and potential electricity generation for sites across the five islands.”
“If determined to be directionally cost-effective then developing renewable energy zones may be pursued further.” Large sections of the public have problems with utility efforts that focus most heavily on centralized generation instead of rooftop solar systems and localized ground mounted small wind turbines. The public perception is that the utility analysis favors large commercial systems based on HECO`s self-imposed limitations on what land can be included in the analysis. Rooftop solar has different cost structures, greenhouse gas emissions/kWh, employment, grid infrastructure requirements, and equity impacts when compared to centralized systems.
(C3) Terminating Existing Renewable Energy Projects HECO presents various scenarios. According to HECO, existing O`ahu wind and solar units total nearly 200 MW would be removed.
* Why remove and add renewable energy systems? Why not keep the non-controversial ones that currently exist? * Various scenarios include offshore wind of approximately 400-500 MW that could be added to the O`ahu grid. Is the need for offshore wind dependent on whether existing renewable energy contracts are renewed?
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
* “H-Power, New Firm” could be dispatched at 102 MW with a capacity of 211 MW. What is the unstated justification for considering the retirement of all older renewable energy projects except for H-Power? (D) Processes HECO asserted, “The Integrated Grid Plan is rooted in customer and stakeholder input. We endeavor to create customer value by: [] Coordinating solutions that provide the best value on a consolidated basis.” HECO stressed that an “independent” entity would assess the IGP process. “Technical Advisory Panel. This group provided an independent source of peer assessment for the technological and engineering considerations of planning for a Hawai‘i Powered future.” Life of the Land has often questioned what is meant by “independent.” Several other groups also questioned what “independent means.” ” Hawaiian Electric' approach of using a Technical Advisory Panel to provide "independent review" of the IGP process is inadequate and fails to leverage best practices and lessons learned in the IRP proceedings. First, unlike the diverse Advisory Group that the Commission solicited and selected in IRP, the Technical Advisory Panel is comprised of Hawaiian Electric's self-selected members that overly represent utility perspectives. Second, unlike the Independent Entity established in the IGP Framework, there is no independent body responsible for overseeing the stakeholder engagement process and for ensuring that IGP proceeds in a `timely and transparent` manner. Without these previously established and proven protective measures in place, there can be little confidence in the IGP process.” The PUC established the Independent Observer to oversee the company`s procurement process. “`Independent Observer` means the neutral person or entity retained by the electric utility or Commission to monitor the utility’s competitive bidding process, and to advise the utility and Commission on matters arising out of the competitive bidding process.”
“An Independent Observer is required whenever the utility or its Affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders) in response to a need that is addressed by its RFP, or when the Commission otherwise determines. Unless otherwise determined by the Commission, an Independent Observer will monitor the competitive bidding process and will report on the progress and results to the Commission, sufficiently early so that the Commission is able to address any defects and allow competitive bidding to occur in time to meet the utility’s Grid Needs.” * Life of the Land asserts that the Independent Entity can provide assurance to the PUC that the RFP process was fair. However, the public will have no assurance that the projects chosen will optimize state policies and/or minimize impacts.
(D1) The IRP, PSIP, IGP Process
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
The PUC issued Order No. 35569 (“Opening Order”) on July 12, 2018, “Instituting Proceeding to Investigate Integrated Grid Planning.” “Electric utilities use resource planning to identify long-term investments that can reliably meet electricity demand and public policy goals at reasonable cost.” “Resource planning for electric generation began in the late 1970s during an era of transition with declining electricity demand, rising costs, and new federal environmental regulations. The resource planning process provides forum for regulators, electric utilities, and stakeholders to evaluate the economic, environmental, and social benefits and costs of different investment options." [emphasis added] "Concerned about significant fluctuations in demand and energy growth rates, rising consumer energy prices in spite of relatively stable fuel costs, the emerging importance of environmental issues and cost-effective technologies and our unabated heavy dependency upon fossil fuel oil, the commission opened proceeding in January 1990 to implement integrated resource planning in the State of Hawaii.” [emphasis added] The IRP process was transformed into “Power Supply Improvement Plans” (“PSIP”) in the 2014-2017 era. Then PSIP was then transformed into Integrated Grid Planning.
On March 1, 2018, the HECO Companies filed an IGP Report with the commission. The IGP Report proposes an ambitious leap forward from traditional system planning. The HECO Companies propose to merge three separate planning processes generation, transmission, and distribution while simultaneously integrating solution procurement into this merged process, with the goal of identifying gross system needs, coordinating solutions, and developing an optimized, cost-effective portfolio of assets.” “With their IGP Report, the HECO Companies propose an ambitious and holistic new approach to power system planning. If implemented successfully, this new IGP process could accelerate the State's progress towards clean energy future.”
“The HECO Companies broadly categorize these inputs as: (1) Planning Requirements [] (2) Input Assumptions [] (3) Fixed Assumptions [] and (4) Customer Needs and Policy Goals.”
“The commission reaffirms the suspension of the IRP Framework requirements for the HECO Companies. At this time, the commission does not intend to order the HECO Companies to begin new IRP cycle. The commission is encouraged by the process proposed in the IGP Report, which builds upon efforts in the PSIPs and elsewhere to more fully integrate planning functions and reduce costs to customers, consistent with prior commission guidance. This evolution of traditional resource planning is necessary in light of the substantial changes underway in the electricity industry.” [emphasis added]
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
“Forecasts represent the foundation of the planning process. They allow planners to quantify the gaps between expected demand and supply that inform investment priorities to ensure the lights stay on. In addition to their central role in resource planning and rate cases, forecasts also influence the design of rate structures, customer programs, public policy, and utility risk mitigation strategies.” [emphasis added] “`Grid Needs Assessment` means the process step in the IGP where the technical analyses are conducted to determine the generation, transmission, and distribution grid service(s)needs to meet state policy objectives, reliability standards, among other goals, and presented to the Commission for review and approval or acceptance.” [emphasis added]
(D2) HECO’s Key Policies HECO provided a table of the “Key State Policies and Legislation That Drive Energy Planning.” HECO included 12 laws and two concurrent resolutions. A few laws were excluded from the table: Climate Change Two laws formed the basis of Hawaii Supreme Court decisions re climate change (Hu Honua 2019, Gas Company 2020). Excluded from the summary was Act 109 (2011) which required the PUC to “explicitly consider, quantitatively or qualitatively, greenhouse gas emissions,” and Act 234 (2007) that addressed greenhouse gas leakage in a global context.
Bioenergy
Also not included was Act 272 (2001) initiated the Renewable Portfolio Standard (“RPS”), and Act 162 (2006) altered the definition or renewable energy established in the RPS metric. In 2001, the definition of renewable energy included “biomass including municipal solid waste, biofuels or fuels derived entirely from organic sources.” To lure ethanol production to Hawai`i, the definition of renewable energy was broadened to include bioenergy made almost entirely from fossil fuel. Under this law, coal and petroleum-derived biofuel is considered 100% renewable energy. The utility has opposed fixing this corrupted definition.
(D3) Public Trust, Public Interest & Trust Properties HECO recognizes the climate change threat: “The frequency and intensity of hurricanes are expected to increase because of climate change. The effects of these threats are amplified by the significant geographic remoteness and isolation of Hawaiʻi.” HECO recognizes the need to urgently address climate change: “The 2021 international summit on climate change made clear that the actions we take this decade will determine whether humanity can slow or stop the warming of the planet.”
The HECO focus is preventing damage to electricity infrastructure: “Our work to modernize and decarbonize the grid has never been more urgent as the effects of climate change escalate and existing
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
electrical facilities and infrastructure age.” “Extreme weather hazards are projected to increase in frequency, intensity, and duration because of climate change. Failure to prepare for such events could result in power interruptions, damage to electricity infrastructure, significant economic disruption, and disruption to critical government and private-sector services.”
* The Draft Plan does not mention “public trust,” “public interest,” or “trust properties.” * The Draft Plan does not mention HRS §225P-5: “A statewide target is hereby established to sequester more atmospheric carbon and greenhouse gases than emitted within the State as quickly as practicable, but no later than 2045; provided that the statewide target includes a greenhouse gas emissions limit, to be achieved no later than 2030, of at least fifty percent below the level of the statewide greenhouse gas emissions in 2005.” [emphasis added]
The Hawai`i Supreme Court state in 2017: “We therefore conclude that HRS Chapter 269 is a law relating to environmental quality that defines the right to a clean and healthful environment under article XI, section 9 by providing that express consideration be given to reduction of greenhouse gas emissions in the decision-making of the Commission.” The Hawai`i Supreme Court state in 2022: “The statutes [] – HRS §§ 269-6(b) and 269-145.5(b) - reflect the core public trust principles: the State and its agencies must protect and promote the justified use of Hawaiʻi’s natural beauty and natural resources. Thus, when there is no reasonable threat to a trust resource, satisfying those statutory provisions fulfills the PUC’s obligations as trustee. But when a project poses a reasonable threat, the public trust principles require more from the PUC: the commission must assess that threat and make specific findings about the affected trust resource.”
* Life of the Land asserts that climate change impacts will be felt by all sectors of Hawaii. HECO seeks to minimize damage to its system and to comply with 2030 and 2045 legal requirements. HECO ignores HRS §225P-5. The Draft Plan will reduce GHG emissions, however, it is unclear whether the reduction is as “quickly as practicable.”
(D4) Streamlining Streamlining can be good when unnecessary redundancy is eliminated. For example, the City and County of Honolulu required a separate permit for each of dozens of concrete platforms for a single energy storage project. But streamlining is often meant to mean expedited processes, automatic approval, and certainty for developers at the expense of the community and the environment. High-level streamlining statements without specificity or details is a threat to the public and the public interest. HECO asserted, “Decarbonizing the electric grid by 2045 will depend on many conditions, actions, and policies beyond Hawaiian Electric. External conditions and actions that will support successful implementation include: [] Policies and Regulatory Conditions [] Policies that remove barriers to siting and permitting large-scale renewable
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APPENDIX H –COMMENTS ON DRAFT IGP REPORT
Public Question/Comment Hawaiian Electric Response
projects and transmission infrastructure. For example, a separate process or entity that coordinates or has the authority to approve a variety of permits needed to execute a renewable project. Flexibility in air permitting and mandates to manage reliability and transitions to renewable resource replacements.”
Any effort by the utility to encourage public comments is commendable. But efforts to limit or stop community intervention in regulatory proceedings fly in the face of efforts to involve communities in equity issues. HECO needs to shed its long history of centralized decision-making and to recognize that we must move forward together.
(D5) Greenhouse Gas Analysis HECO applied the 2030 requirement to the 2045 requirement: HECO: “Our grid planning is guided by laws and policies enacted by the Hawaiʻi State legislature, along with the multitude of interrelated proceedings before the Public Utilities Commission. Hawaiʻi continues to lead the nation in climate and environmental policies, particularly in the electricity sector. Overarching State policies that guide our grid planning include 100% renewable energy by 2045 and statewide greenhouse gas reductions of 50% by 2030 and net negative by 2045 compared to 2005 levels.” “Customers continue to stress the importance of affordability, and the State has set ambitious decarbonization targets to achieve economy-wide 50% carbon emissions reduction by 2030 and net negative carbon emissions reductions by 2045 compared to 2005 levels.”
State Law: “Considering both atmospheric carbon and greenhouse gas emissions as well as offsets from the local sequestration of atmospheric carbon and greenhouse gases through long-term sinks and reservoirs, a statewide target is hereby established to sequester more atmospheric carbon and greenhouse gases than emitted within the State as quickly as practicable, but no later than 2045; provided that the statewide target includes a greenhouse gas emissions limit, to be achieved no later than 2030, of at least fifty per cent below the level of the statewide greenhouse gas emissions in 2005.”
Certificate of Service I hereby certify that a copy of the foregoing document was e-filed with the Commission and emailed to the parties and participants on the [refer to original doc for contact information] Dear Honorable Commissioners,
Blue Planet Foundation, by and through its counsel Earthjustice, Hawai'i PV Coalition, and Hawai'i Solar Energy Association (the "Joint Parties") hereby submit comments on the Hawaiian Electric Companies' ("Hawaiian Electric's") Integrated Grid Plan ("IGP") Draft Report, filed on March 31, 2023.
The IGP working group meetings have functioned as public meetings. The initial working group members were made up of individuals with subject matter expertise on the specific working group issues but were not closed to others from participating. We have incorporated DER Parties’ feedback throughout the process, particularly with respect to DER. For example, our initial DER forecasts were substantially revised to reflect recommendations by the DER Parties to expand the pool of customers that could adopt DER leading to an expansion of the DER forecast and DER market, updates to assumed DER system costs, and future incentives. We also
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Public Question/Comment Hawaiian Electric Response
The IGP Draft Report Fails to Incorporate Stakeholder Feedback for Leveraging DERs
At the start of the IGP proceedings, Hawaiian Electric proposed that IGP working groups be open to a "limited number of people,"^ and then prevented interested stakeholders from participating in their desired working groups. After receiving requests to expand stakeholder access to the IGP proceedings,^ the Commission ordered Hawaiian Electric to provide all parties the opportunity to attend each IGP working group meeting.^ The Joint Parties have participated substantially in pertinent working group meetings, providing input along the way, yet many of our key recommendations and concerns have been largely rejected, particularly with respect to DERs. Although the IGP Draft Report includes significant improvements over prior planning efforts in this and other dockets, it continues to fall short of fully embracing and enabling customer DERs, as the Joint Parties have consistently urged and the Commission directed and envisioned nine years ago in the "Inclinations on the Future of Hawaii's Electric Utilities." The IGP Draft Report Fails to Accurately Account for and Optimize BYOD Programs Hawaiian Electric's inputs and assumptions do not accurately reflect the development costs or capacity services offered by Commission-approved BYOD programs. Additionally, the RESOLVE model is unable to select and build additional cost-effective BYOD resources. Although the inputs and assumptions do include a DER Aggregator PV + Storage resource, this reflects the entire anticipated development cost to the DER customers and results in an estimated cost per kW over a ten-year period of $6,433 more than the DER Parties' Phase 2 proposed pricing for BYOD Level 1 and 2, and $5,723 more than BYOD Level 3 in the DER docket. Similarly, the cost of utility-scale batteries is more expensive than the DER Parties' proposed BYOD pricing. These factors create modeling inaccuracies and result in more expensive plans that fail to recognize and capture the benefits that BYOD programs can provide to the ratepayers.
Hawaiian Electric should rerun the RESOLVE model to include Commission-approved BYOD capacity across all scenarios and allow the model to select additional BYOD capacity at the DER Parties' proposed pricing for BYOD programs. The resources that RESOLVE selects within this initial optimization run would then be included within all scenarios at the capacity levels selected by the model. Following this initial optimization step, Hawaiian Electric could continue with the current practice to "hand select planned resources" for their desired resource mix based on the scenarios as well as system stability analysis, and allow the model to build additional resources. By not including BYOD as a selectable resource and forcing the model to build new additional resources at capacities and dates selected by Hawaiian Electric, all scenarios are artificially constrained and not truly optimized.
The PLEXOS Model Improperly Allows for Curtailment of DERs
added a Faster Technology Adoption scenario as suggested by the DER Parties and directed by the Commission. Additional details can be found in the IGP Input and Assumptions.
The IGP report and resource plans are based on achieving affordable and reliable electricity at the lowest cost. DER is present in significant amounts as a forecast layer (through customer investment). For Oahu, we are forecasting DER load reductions of ~13,000 GWh by 2030 and ~37,000 GWh by 2045.Additionally, we modeled DER as a system resource that could be further optimized holistically as a system resource that can meet grid needs alongside other customer and supply side options. By treating DER as a system resource, with the ability to be dispatched, the IGP models and plans fully embrace its capabilities. We also note that with respect to BYOD programs, Hawaiian Electric has been fully engaged in the DER Docket proceeding in evaluating additional modeling scenarios and details to propose new program designs for future programs.
These forecasts include the cost of the resource itself plus other capex costs, including interconnection costs, embedded in NREL’s Annual Technology Baseline (https://atb.nrel.gov/electricity/2022/definitions#capitalexpenditures). Costs for REZ enablement were separately included as part of RESOLVE’s optimization (i.e., cost adder) so that the model would be able to build out lower cost renewable energy zones first.
Forecasted DER, modeled as a resource, includes customer sited BESS. Additional customer sited BESS could be built through the DER aggregator option that was available in RESOLVE. Managed charging of EVs was considered through the load forecast as a base assumption as suggested by the DER Parties. Section 2.1.4 also notes that as part of our Action Plan is to develop vehicle to grid standards. Two classes of DER were captured in PLEXOS when modeling DER as a resource. Existing DER was modeled as non curtailable. Future DER was modeled as controllable / curtailable under the expectation that future DER will need to provide similar dispatchability as large-scale resources. However, despite having this capability, the future DER is minimally curtailed.
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Public Question/Comment Hawaiian Electric Response
We have come to understand from our participation in working group meetings that Hawaiian Electric is "optimizing'" DERs by allowing the PLEXOS model to curtail behind-the-meter DERs. Hawaiian Electric has similarly claimed in their DPS Phase 3 modeling results in the DER docket that the value of BYOD 3, offering load build and load reduce capacity services, can be based on the IGP DER Freeze case, which assumes that behind-the-meter DERs are providing these services for free. Existing DER programs as well as the new Smart DER programs do not allow for curtailment, as Hawaiian Electric has allowed in its modeling, and this inaccurate assumption will limit the value of BYOD services and produce questionable resource optimization results. Hawaiian Electric should rerun the PLEXOS model without the assumption that all customer DERs can be curtailed.
The IGP Draft Report's Resource Assumptions Do Not Include Interconnection Costs of Utility-Scale Resources
It appears that Hawaiian Electric’s cost assumptions for utility-scale resources do not include Renewable Energy Zone and site-specific interconnection costs, which artificially lowers development costs for these resources and skews the modeling against customer BYOD programs. While we can understand that utility-scale development costs will vary by location, it is unreasonable to not include any of these costs in the inputs and assumptions.
The IGP Draft Report Does Not Account for Customer Standalone Storage or EVs as Potential Resources
There appear to be no assumptions for customer standalone storage or EV to home/grid services, which is unrealistic given the potential for resource adoption. The Inflation Reduction Act has expanded tax credits for standalone batteries and EVs. Moreover, while the current BYOD programs are targeting batteries that charge from onsite renewable generation, there will likely be future opportunities to expand BYOD programs to standalone batteries and EVs. Thus, Hawaiian Electric should consider customer adoption of these resources and how Advanced Rate Design can spur adoption of these technologies for grid and ratepayer benefits. We appreciate the opportunity to submit comments on the IGP Draft Report and look forward to continued engagement on these issues. I strongly oppose the IGP on Oahu because of the negative environmental impacts of the plan and the unreliability of the electric grid once completed. Oahu will see power interruptions and ugly development of our scarce land areas for transmission lines, solar farms, and windmill turbines. We must include firm electric generation including some fossil fuel plants and nuclear plants for base and peaking loads. The transition to all electric cars will be impossible without interim firm power provided by fossil fuels.
Hawaiian Electric recognizes that each community has a distinct character and resources are exceptionally valued to support island sustainability. We’ve learned the value of providing opportunities for impacted communities to share their views on projects and participate in effective community dialogue.
We view firm generation as an essential part to assuring reliability as we transition to more intermittent resources. We analyzed this topic in Section 12 of the report.
I look forward to seeing Hawaii move away from the use of non-renewable energy and rely more on renewable energy sources. With the increasing changes that come with climate change I feel it is vital for countries or states such as Hawaii who are at the
Thank you for your comment. We agree that community engagement is vital to achieving our goals. We outline some of the things we are doing to engage communities in Section 10. We will
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Public Question/Comment Hawaiian Electric Response
frontline of this crisis to be the trailblazers for decarbonization. The Hawai’i Powered project has great goals in order to decrease carbon emissions however community involvement is crucial to achieve all the set goals. It is important to show how the government or local agencies will help the people make the switch to renewable energy.
continue to engage the community as we move forward with our plans to achieve 100% renewable energy.
This plan will only increase utility rates. I oppose. PUC members should be replaced.
We believe that compared to the Status Quo of remaining on fossil fuels that our proposed plan may keep rates relatively flat and stable in the long-term. This is further described in Section 9. The integrated grid plan with focus on 100% renewable energy for Oahu is not an achievable goal without destroying Hawaii"s natural beauty. This is our golden egg for tourism. Surrounding a portion of the islands with inefficient, eye sore windmills will destroy the view plane of all sunsets tourists come to see. Stand at Kahuku High School, and get a panoramic view of how windmills have destroyed an entire communities view plane. Hundreds of people were arrested trying to prevent (albeit too late) these turbines to be brought too tall, too close to our beloved Kahuku community. They received NOTHING in return. I adamantly oppose ANY new windmill, on shore or offshore. We need to evaluate if a 2045 100% renewable date, which was "arbitrarily selected with NO economic basis on the cost /benefit. I say any supporter of wind publicly state he will put the first wind turbine in his own yard before he destroys the landscape of others. Not going to happen. We need to evaluate EXACTLY what the economic trade offs are to go 100% renewable when there is NO plan proposed that makes economic sense with out destroying our aina.
Hawaiian Electric recognizes that each community has a distinct character and resources are exceptionally valued to support island sustainability. We’ve learned the value of providing opportunities for impacted communities to share their views on projects and participate in effective community dialogue. Hawaiian Electric continues to update its community engagement and cultural resource preservation requirements using community feedback through our own engagement efforts. We heard from community members who wanted the company and developers we work with to improve transparency and community engagement from the start of the energy project development process. We also believe early and frequent engagement will help improve the success of renewable projects, and help us collectively achieve our state’s renewable energy and carbon neutrality goals.
On islands, particularly in densely populated areas on Oʻahu, utility-scale infrastructure and renewable projects are often sited close to homes and communities. Site selection is currently determined by landowners and developers reaching an agreement and bidding into a competitive bidding process. Hawaiian Electric supports processes and studies that help raise awareness of energy policy issues that must be addressed in order to meet the state’s renewable portfolio standard (RPS).
For future projects where communities are accepting of renewable projects, we are now requiring developers to provide financial community benefits to the surrounding communities as described in Section 10.4. This is a starting point and hope to improve on community benefit packages in the future. Time must be spent upfront communicating, building relationships and developing trust to get as comprehensive a view of the community as possible.
The report states that communities that bear the burden of hosting energy infrastructure, both in the past and future, should receive benefits. What may these benefits look like? How might they be funded? Providing an example of this might be helpful in order to make the report stronger.
The report states that since 2010, the company has nearly tripled the amount of renewable energy they generate. Is this in exact terms or relative to the electricity produced?
The report brings up the existing fossil-fuel generators on Hawai’i Island, Maui, and Oahu and the fact that they are 55 to 75 years old. Is there a plan to phase out these generators? Will these
As outlined in Section 10.4, we will be requiring developers of large-scale projects, to provide financial benefits to the surrounding communities. For community benefits to be meaningful, time must be spent upfront communicating, building relationships and developing trust in order to get as comprehensive a view of the community as possible. On islands, particularly in densely populated areas on Oʻahu, utility-scale infrastructure and renewable projects are often sited close to homes and communities. Some communities shoulder more of the infrastructure than others. We recognize each community has a distinct character with unique resources. We’ve worked hard to ensure that impacted communities have opportunities to share their views on projects and participate in effective community dialogue.
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Public Question/Comment Hawaiian Electric Response
generators be used for something else when they are no longer supplying the islands with electricity?
When discussing cuts in carbon emissions until 2030, emissions in 2005 are used as a baseline. The report states that a goal is to cut emissions by 70% by 2030, compared to 2005 levels. Using 2005 as a baseline year can make it hard to relate to. It was almost 20 years ago, during a time before the Iphone was invented and our reliance on electricity looked completely different. It might be more relevant to set the baseline year closer to today’s date. The report states that technology advancements are necessary in order to achieve net zero emissions. While this might be true, it is also pushing the problem of sustainable electricity production onto future generations and relying on the potential of something changing. I don’t think we should rely on solutions that are not yet created to help solve a problem that was to a large extent created using that same train of thought. We shouldn’t take potential future solutions into account when creating mitigation strategies, instead we should see them as a bonus that will help us solve a problem that we already made a plan for using the resources that are currently available to us. I think one big thing that I didn’t see in the report is the need for changes to our behavior in terms of electricity consumption. It is great to have technology that conserves energy but at the end of the day, if we consume less electricity, we can produce less electricity and thus automatically reduce carbon emissions. I think the report makes a strong case for what consumers can do in terms of small-scale electricity production to help this transition; however, I think the report needs to put more emphasis on the choices consumers make with the amount of electricity they use.
The amount of renewable energy as a percentage of the total energy produced has tripled since 2010.
Yes, we have a plan to phase out some of our oldest generators and replace them with a mix of resources that includes solar, wind, energy storage, and firm generation. An overview is shown in Figure 2-1 of the report. We agree that energy efficiency and conservation is key component to achieving our goals. We outline this important part of our plan in Section 2.1, “Widespread adoption of energy efficiency” which also includes conservation measures.
I'm writing to share my opinions about HECO's strategy to use only renewable energy by 2045. As a concerned citizen, I find HECO's dedication to sustainability encouraging and commend the business for its initiatives to lower carbon emissions. I am aware that there are a number of obstacles to overcome before we can succeed in this endeavor. The significant technical, economic, regulatory, and social challenges mentioned in your plan must be met head-on by all parties involved. Regarding technical difficulties, I value HECO's emphasis on energy storage and grid modernization. For the integration of renewable energy sources, a dependable and stable grid infrastructure is essential. Furthermore, the intermittent nature of renewable energy sources like wind and solar can be addressed with the development of energy storage technologies. The transition's economic difficulties are also noteworthy, and I am aware that substantial investments will be needed to create new infrastructure and technology. The cost of renewable energy is, however, going down, which gives me hope that this trend will continue as technology advances. Regarding the difficulties in obtaining the necessary licenses and approvals for new renewable energy initiatives and grid infrastructure upgrades, I am aware of Hawaii's complicated regulatory environment. I implore HECO to cooperate with oversight organizations in order to overcome these obstacles and fulfill its sustainability objectives.
We plan to continue our engagement with stakeholders external to Hawaiian Electric and rely on our stakeholder council to help us achieve our goals. We realize that this will take a tremendous effort by many people and organizations in the State to make 100% renewable energy a reality.
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Public Question/Comment Hawaiian Electric Response
Finally, I commend HECO for its efforts to encourage public awareness of renewable energy sources and energy-saving technologies. I support HECO's dedication to raising public awareness because I think that in order to meet the goal of 100% renewable energy, a cultural shift toward sustainability is required. In conclusion, I think that HECO's goal of using only renewable energy by 2045 is a step in the right direction. I implore HECO to keep addressing the issues mentioned in its plan and to cooperate with interested parties in order to realize this objective.
I think this report has a reality and provides great insight into the future of Hawai’i’s electricity. However, I have several questions about when Hawai’i, especially the Big Island of Hawai’i experiences a catastrophic natural disaster. I believe the Big Island is well known for its active volcanoes, which are capable of producing lava flows and ash, which potentially could dramatically affect the power generating equipment for solar energy, wind power, and geothermal energy plants. In case of such an emergency, how will the electricity be generated and provided to the public? Other than the volcanic activities, Hawai’i gets hit by hurricanes once in a while, which could damage solar panels or the wings of the windmills. If these damaged parts fly away and damage private property, such as houses and cars, would there be any compensation for the damage and repair? If the solar panels were owned privately, though were constructed as part of this plan, would the responsibility be on the owner’s side or will any incurred fees be covered by Hawaiian Electric?
As part of our resilience efforts, we will evaluate ways to improve system resilience for both generation resources and transmission and distribution infrastructure. Section 7 outlines several initiatives that we plan to address.
In the near-term, Hawaiian Electric has identified several no-regrets actions to harden the grid infrastructure on Hawaii Island (Section 7.4).
In the event of a tropical hurricane directly impacting the island of Oahu, a number of major existing generating units and solar units will be negatively impacted due to tidal surges in tsunami inundation zones where there are located (Kahe PP, CEIP, Kalaeloa). We are fortunate to have one fossil fuel generation station active and protected from tidal surges at Waiau PP located in Pearl Harbor; albeit in the process of being decommissioned. Additionally, the former Honolulu Power Plant building (located in Honolulu Harbor and adjacent substation is still available despite being decommissioned but w/ present technology, can be reactivated. Both of these units will provide firm electrical power to the island of Oahu. HECo made a major error by proposing/enacting the destruction of both environmentally protected units
We may deactivate or retire generating units at our existing facilities, especially those protected from natural disasters; however, that does not preclude future generation from being sited at these locations. This is a topic that Hawaiian Electric will continue to evaluate, especially with respect to resilience and the opportunity to leverage existing grid infrastructure.
LANA’I, 98% owned by one entity presents a unique challenge to residents. I am clear the plan does not fully address our unique needs.
We continue to work with the majority landowner and communities on Lāna‘i to identify the best path forward for the island. Our stakeholder council which we meet with throughout this process (Section 4.1) includes representation from the Lāna‘i community. Please also see Section 1.4.4.
Relying on intermittent renewable energy sources is a short-sighted strategy to mitigate carbon emissions. I is very likely these systems will not retain an affordable replacement cost as the entire planet competes for a supply that cannot meet even a single generation of demand.
Having directly asked HEI about whether there has been any research into the sustainability of these systems' economic viability into 2nd generation replacements, the answer was "No, we haven't."
We address disposal and recycling of clean energy equipment in Section 2.6 of the final report.
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Public Question/Comment Hawaiian Electric Response
My own research, which prompted the question, shows that the known recoverable supplies for the critical raw materials needed to manufacture these systems cannot meet the projected demand of a GLOBAL grid network needing that is racing to replace fossil fuels today and will need to begin the process of replacing these systems in between 15 years (for batteries) and 20-25 years (for PV panels) and 15-20 years (for wind turbines). As these systems are just being built, the option to recycle them in the future does not yet exist. Mining is the only viable source for their source materials. To be responsible, we must look at whole systems, their sustainability, their life cycles and the associated economics as we chart an unalterable course toward electrifying our economy into the future. Solar, Wind and batteries may be the popular, fast approach to decarbonization, however, our ability to continue doing that without risking the functionality of our economy in just one generation suggests that we look at systems with longer term life cycles such as geothermal power.
If this commentary resonates at all, I am willing and able to back up my statements with credible data, for which this is not an appropriate forum. I encourage you to follow up with the necessary research to ensure we are preparing for our broader longterm need vs. a siloed goal based on a single metric, carbon emissions. Dear Commission Members: The Grassroot Institute of Hawaii would like to offer its comments regarding Hawaiian Electric Co.’s proposed “Hawaii Powered Draft Integrated Grid Plan. The Institute acknowledges that the state’s renewable energy goals are well intended, but this plan would likely further raise Hawaii’s high cost of living.
Specifically, the plan calls for investing more than $15 billion in capital expenditures on Oahu, compared to the $7 billion it estimates that it would cost to maintain the status quo. Since Hawaii already has the highest electricity costs in the country, we are concerned that this additional infrastructure spending could cause Hawaii families significant financial harm. Additionally, we are concerned that limiting energy options could increase energy prices in Hawaii. HECO projects its plan could lower electricity rates, but that would be true only if oil prices increase dramatically over time, as the plan assumes. It is, however, possible that oil prices could decrease over time, which would leave residents with higher energy bills under the proposed plan. If this plan is to go forward, we suggest that HECO, the Public Utilities Commission and other stakeholders convene a working group to identify regulations that block deployment of new clean-energy technologies, such as slow permitting processes, excessive land-use restrictions and taxes that discourage new technology
In Section 2.3, we have identified similar policies or actions to identify regulations or processes that can potentially slow down deployment of clean-energy technologies. We hope to work with stakeholders to identify ways to improve processes.
We also are cognizant that new technologies may come along in the future. In order to ensure a reliable and low cost energy system, we must ensure those technologies have been commercially scalable and reliable and lower cost compared to alternatives. Through our competitive procurements and requests for proposals we encourage prospective developers to present proposals that can ultimately benefit our customers and communities.
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Public Question/Comment Hawaiian Electric Response
startups. Removing such barriers and allowing clean energy sectors to take hold more naturally could help mitigate the cost of these proposed power grid changes.
Thank you for the opportunity to submit comments.
As I am reading this proposal a few things immediately come to mind. First of all I would like to show appreciation for acknowledging that every industry needs to participate in this integrated plan. That being said, this document solely talks about what customers should do and how you should be doing things yourself to give back to the grid. Very little is said about policy implementation on large companies using large amounts of electricity. What should they be doing to decrease their consumption? If you wish for us to be “putting back into the grid” then those corporations better be paying us, except they will most likely be paying you for our power. Under “External Actions and Policies for Successful Implementation,” no specific suggestion is given for quite a large factor of Economic Conditions and Actions. How will we ease the supply chain and inflationary pressures? After 100% renewable energy is achieved, it certainly will happen, but what will be done until then? Another section that got my attention was the Climate Change Action Plan. “Statewide decarbonization will require collaboration across sectors, with transportation, agriculture, and other industries working to reduce and offset emissions.” (P.41) I assume this excludes the emissions from around 150 mainland flights departing and coming into the islands as well. I also assume you are excluding the emissions from the 170 average daily inner island flights. That is around 62,000 flights a year travelling solely between the islands. There is around 109 pounds of CO2 per passenger on a 200-mile flight. And you’re telling non-commercial consumers that we need to pull up our bootstraps. More pressure should be put on the travel industry to find a more sustainable way to travel. And the way to reach net zero carbon emissions by 2045 is not to save up to buy carbon credits for an offset.
Large customers have an equal role to play in achieving 100% renewable energy. We used assumptions that are consistent with a statewide study to identify energy efficiency potential. Many efficiency measures have been identified for large, commercial customers, which is available at: https://puc.hawaii.gov/wp-content/uploads/2021/02/Hawaii-2020-Market-Potential-Study-Final-Report.pdf We have been monitoring supply chain and inflationary effects on equipment pricing. Unfortunately, that is largely out of our control; though, part of the Integrated Grid Plan is to continue to issue request for proposals so that we can get the best competitive pricing for new energy resources.
The Integrated Grid Plan focuses on decarbonization of light duty vehicles and buses. We recognize that there are other sectors of the economy, particularly in aviation and marine transportation that must also decarbonize to meet state goals. We have started work to identify how decarbonization of those sectors may affect the electricity sector and will have more analysis on this topic in future iterations.
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1.1 Public Utilities Commission (PUC) Comments
Reference PUC Staff Question/Comment Hawaiian Electric Response
Chapter 1 – Executive Summary
At 12, 13, 17, 22, & 25 Helpful use of defining key terms (e.g., equity, energy equity, LMI) and speaking to frequently suggested alternatives/solutions (e.g., solar on all rooftops)
Acknowledged
At 14, Figure 1-1 Figure 1-1 is a great breakdown of today’s renewable energy resources, and it could be useful to add a scale to indicate the size of the renewable portfolio on each island (e.g., MWh of renewable energy generation per island/county), unless it negatively impacts the presentation of this breakdown.
Footnote added to reference the 2022 RPS report
At 23, Figure 1-3 It would be helpful to note that the Stage 3 additions include standalone BESS in the Hybrid Solar + Wind (as stated in the STWG meeting)
We have added a callout box for readers to better understand “hybrid solar” since it’s a key term used throughout the document.
At 23, Figure 1-3 It appears that not all existing fossil fuel plants are addressed in the “retirements/deactivation” portion of this timeline. Are these units assumed to not be retired and/or deactivated prior to 2050? Are there any unit conversions (i.e., to biodiesel or another generating source) that are not depicted in this timeline?
Remaining generating units are assumed converted biofuel in 2045. We clarify this in the figure.
At 21 “To grow the market for large-scale projects that also benefit host communities, we propose routine cyclical procurements with public input and community benefit packages from developers.” Where in the IGP does it describe the proposal? How frequent will these “routine” procurements be, and what does “cyclical” mean in this context?
This is discussed in Section 11.2, additional edits for clarity have been added as follows. “While the urgent timeline to meet climate goals may necessitate a large procurement in the near-term, we believe smaller procurements on a regular schedule instead of large procurements (i.e., Stage 2 and 3 RFPs) would lead to a smoother and efficient procurement and interconnection process because of the complexity and logistics to develop and execute projects in Hawai‘i.”
At 23, Figure 1-3 Since firm renewable procurements are designed to be “staggered” (300 MW in 2029 and 200 MW in 2032), it would be useful to reflect this in this figure. The current design makes it look like all 500 MW of firm renewables from the Stage 3 procurement are planned to be procured by 2030).
We did not want to add more complexity to the presentation of the current figure. Once we have clarity on Stage 3 projects, we will update the timeline graphic accordingly. The upper end of the Stage 3 target was 700 MW in total for Oahu.
Chapter 2 – Action Plan
At 27 In the discussion under “Keep rates lower than the status quo of fossil-fuel reliance,” Hawaii Electric makes the following statement: “Although utility rates will rise in the transition to clean energy...” I would update to “Although utility rate may/are likely to rise” to make that statement less definitive. It also is confusing because Hawaii Electric follows up with “Our projections show that customer bills may remain relatively flat...” This may be better explained in Sections 9 and 10.
Made the appropriate clarifications throughout that rates may rise in the near-term transition but stabilize over the long-term.
At 28 While HECO notes that widespread adoption of energy efficiency is needed to grow the marketplace, the discussion of energy efficiency is less present in the executive summary narrative, and could be emphasized alongside rooftop solar and distributed storage as a
Additional language added to Section 1.5.2
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Reference PUC Staff Question/Comment Hawaiian Electric Response
means to meet energy needs through customer resources.
At 28 Clarify whether the identified goals for distributed solar and storage, energy efficiency, and large-scale renewables are in addition to current deployment or inclusive of current deployment. For example, HECO’s sustainability report indicates that the existing amount of residential and commercial rooftop solar and energy storage systems as of 2022 is ~97k installations with 1,118 MW capacity, so the 2030 need would appear to be an increase of ~28k installations and 68 MW of capacity above current levels.
The EE and DER figures provided at pg 28 are cumulative 2030 totals from the IGP forecast. The EE, DER and large-scale renewable amounts shown in Figure 1-3 are provided as incremental additions from end of 2023 to end of 2030 in the forecast.
At 30 In the “Near-term actions to improve grid resilience” box, in addition to “Complete rollout of advanced metering infrastructure...” is a need to ensure the technologies, processes, and programs are in place to utilize that AMI beyond deployment.
Yes, this is the intent, added clarifications under “Actions we can take to begin increasing customer participation:”
At 31 Consider the role of new renewable energy technologies that may mature during the planning horizon, and whether there are opportunities for these emerging technologies to provide additional generation in a diverse energy portfolio.
Yes that’s the intent, we expanded the description to more than just inverters and system security. Future technologies would be included as they mature. In general our procurements are intended to be technology agnostic, at times we may prefer to specify a technology if critical reliability needs must be met.
At 32 For Figures 2-1 through 2-7, consider specifying whether this reflects results from the base case or other modeling. Clarified captions by adding (Base) to figure captions. These figures are based on the “Preferred Plans” in the IGP.
At 33, 34, 35 Clarify what projects are being referenced in “LMI and Phase 2 projects” for each island. Are these CBRE projects?
Yes, CBRE, made appropriate clarifications on these pages.
At 36 Consider the impact of federal policy action on codes & standards, which could reduce the scope and cost of utility funded efficiency programs.
The High Bookend EE sensitivity was based on the AEG Market Potential Study’s Achievable – High forecast which included potential future (new) state and federal codes and standards.
Chapter 3 – Introduction
At 40 Figure 3-2 appears to present duplicate charts for carbon emission goals by 2030 and by 2045. This was an error, graphic has been updated.
At 42 Figure 3-3 does a great job explaining not only that community engagement is ongoing throughout every step of the process, but also highlighting how engagement is incorporated into each step.
Acknowledged.
At 44 How were these pathways developed from the approved inputs and assumptions, which outlined about 10 modeling scenarios and sensitivities per island (base, high load, low load, DER freeze, EV freeze, EE freeze, land constrained, no state ITC for PV, low renewable generation, and high fuel price)?
Language was added to tie the pathways to the modeling scenarios in Section 6.8
Chapter 4 – Community and Stakeholder Engagement
At 51, Table 4-1 Hawaiian Electric states, “Before the COVID-19 pandemic, in early March 2020, we began our initial campaign of public outreach and engagement, connecting with 1,421 community members in person and online,” with 161 in-person.
We've amended this in section 4.2.2 to be clearer: Before the COVID-19 pandemic, in early March 2020, we began our initial campaign of public outreach and engagement, hosting in-person open houses and an online open house. The online open house was built to be
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What qualifies as connecting with community members online? interactive and featured informational graphics, links to additional resources and an embedded survey tool. A total of 1,260 people visited the online open house, and 161 attended the in-person open houses. The engagement goal of this outreach campaign was to connect with the public, provide a general overview of Integrated Grid Planning, and gather input on what is most and least important to consider as part of the planning process.
GENERAL Does Hawaiian Electric see current participants in public outreach and engagement as representative of all Hawaiian Electric customers? If yes, how so? If not, how do they differ?
Does Hawaiian Electric feel a need to increase to increase public participation and engagement in future grid planning and resource procurement? If so, how does Hawaiian Electric plan to do so?
We acknowledge the vast diversity of the communities we serve and recognize there will always be ways for us to make our engagement and outreach more accessible for all our customers. Throughout the development of the IGP, we worked to engage as many community members as possible by tailoring our communication strategies to each island and providing multiple ways for customers to receive information and share input, both online and in-person. Energy planning is complex, and we used various tools—data dashboard, blog posts, videos, community presentations and newsletters—to distill information and allow for multiple engagement points throughout the process. Digital materials were made accessible, written in plain language and supported by visuals. We also worked to include diverse customer interests through the Stakeholder Council, which included representatives of each county, commercial and industrial customers, consumer advocates and environmental advocates, among others. Moving forward, we plan to continue a balanced approach of providing in-person and digital opportunities to share information and gather input. Fostering dialogue through physical and digital mediums is a more inclusive and equitable approach to community engagement. This approach recognizes that some community members are unable to attend in-person meetings and prefer the flexibility of sharing input online, while others may not have internet access and prefer in-person interactions with the project team and handouts they can take home to review or share with others in their community. We also plan to focus outreach efforts on communities that might be most impacted by energy projects, increasing public participation around the development of Renewable Energy Zones (REZ) and potential future projects. One strategy to accomplish this is requiring developers to provide and implement community engagement plans that outline how they will seek to involve community members, provide opportunities for input and incorporate public feedback into the projects.
61 Hawaiian Electric states, “This key takeaway [public preference for reliability and affordability] informed our Integrated Grid Plan by reaffirming our dedication to finding clean energy solutions that also stabilize customer rates and ensure reliable power that people can count on.”
Public outreach and engagement also informed the following aspects of Integrated Grid Planning:
• In talking to communities about affordability, lower electric bills are top of mind. Affordability is connected to energy justice, ensuring that we preserve Hawai‘i’s environment, equitably
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Can Hawaiian Electric provide more specific and concrete examples of how public outreach and engagement informed Integrated Grid Planning?
distribute burdens and benefits of energy infrastructure and expand customer access to participation in energy generation, storage and efficiency. The IGP explores each of these in detail and, as discussed below and throughout the report, community partnership in the development of REZ is vital to our success. In the IGP, we develop the lowest-cost plans and assess bill impacts, evaluate tradeoffs with land constraints, provide additional analysis on the value of customer resources and examine how the energy market in Hawaii can be expanded.
• Customers expect reliable service. Many communities have expressed concerns about reliance on solar and wind and have consistently brought up consideration of other technologies. We address these comments through our detailed evaluation of the impacts of weather on typical grid operations. We dedicate Section 12 to closely examining these risks such that we can position the next phase of the IGP to acquire resources to shore up generation reliability.
• Refinements to our REZ map, which will shape the selection of future projects and competitive procurements. Community members’ insights about their own communities were instrumental in helping us understand challenges and opportunities for potential energy projects. Their comments showed us which locations may be best for future projects that benefit their host communities, and locations that may not feasible based on cultural significance, community use and technical aspects. We are currently in the process of reviewing all public comments and planning for continued community engagement about REZ locations.
• Ongoing updates to our community engagement and cultural resources preservation requirements. We’ve learned the value of providing opportunities for impacted communities to share their views on projects and participate in effective community dialogue. We heard from community members who wanted the company and developers we work with to improve transparency and community engagement from the start of the energy project development process. In communities where renewable projects are proposed, we are now requiring developers to provide financial community benefits to the surrounding communities as described in Section 10.4. This is a starting point, and we hope to improve benefit packages that directly address critical community needs in the future.
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62 “Together, public input and technical studies help inform a round of competitive procurements starting to be issued 2023.”
Suggest deleting “starting.”
We have amended this in the report, section 4.2.6.7.
At 64 The in-depth description of all the community and stakeholder engagement is super helpful and a great resource. Consider providing some reflection, either here or elsewhere in the report, regarding lessons learned from community engagement in the IGP process. Are there methods of explaining IGP and its technical aspects that were particularly effective? What are the strengths and weaknesses of the different formats for events that Hawaiian Electric explored? What improvements or changes to the community engagement process is Hawaiian Electric considering as we move forward?
We’ve learned the value of providing opportunities for impacted communities to share their views on projects and participate in effective dialogue with Hawaiian Electric team members. Time must be spent upfront communicating, building relationships and earning trust to develop projects that are reflective of community needs. Some of the strategies that we found most effective in explaining technical subjects and inviting input include:
• Tailoring our strategies to each island, recognizing that counties have unique needs, conditions and opportunities for decarbonization and public participation. Customizing our communications to each island was facilitated by Hawaiian Electric team members who served as island community and communications leads. These team members led efforts to foster relationships with local communities, acted as a point of contact for their island and helped focus our outreach to communities that might be most impacted by local energy projects. We will carry this approach forward to continue to engage communities on each island.
• As part of customizing our outreach to each island, we also found it meaningful to attend community events like fairs and festivals. This widens our outreach efforts as it reaches additional community members who may not attend a utility-specific public meeting. It also allowed us to support local initiatives for clean energy and sustainability outside of Hawaiian Electric and improve accessibility to our team by showing up and connecting with community members in places where they already were, rather than asking them to come to us. For example, attending local events was particularly effective for Hawaiʻi Island, where we have many rural communities and customers with limited internet access.
• Providing multiple avenues to engage with the IGP process, including a variety of in-person and online formats. We found that hosting in-person meetings and attending local events is especially important in rural communities, where internet access can be more limited. For example, during some of the community meetings we attended for the projects on Hawai‘i Island, we heard from community members who said they prefer face-to-face interaction and appreciate materials they could take home to review or share with others. When it came to online formats, we found that having
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various streams of digital content—including a blog, e-newsletter, short videos and social media posts—that all flowed to the Hawaiʻi Powered (website) hub for community engagement was an effective way to reach more people and provide clear, accessible and consistent information.
• Providing interactive, educational web modules to help explain technical topics like inputs and assumptions planning. Developing these digital “deep dives” on technical processes helped make complex information more accessible by using plain language, meaningful visuals and a web design that walked viewers through the content step by step. We also centered the narrative on the customer experience, conveying what is involved in the processes and why it matters for individuals. We also shared messaging from these web modules in handouts and presentation materials at in-person outreach events. Improvements we are considering as we move forward include:
• Enhancing our balanced approach of providing in-person and digital opportunities to share information and gather input. By offering physical and digital mediums to engage, we hope to continually improve the accessibility and inclusivity of our outreach.
o When it comes to in-person outreach, one of our intentions is to expand our efforts to reach certain communities that may have limited access to computers, smartphones and the internet. Our goal is to continue having in-person community conversations to build relationships, foster dialogue and develop projects that are reflective of community needs.
o When it comes to digital outreach, one of our intentions is producing more videos that explain technical subjects like REZ zones. This can help make complex topics more accessible and supplement written information online, in presentations and in print materials.
• Involving communities earlier and more often throughout the procurement process for energy projects, including requiring developers to provide and implement community engagement plans.
• Engaging more young people through partnerships with schools and STEM programs.
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Chapter 5 – Today’s Planning Environment
At 66 The format of Table 5-1 is a little confusing to understand the flow. Are the state policies in the right-hand column directly related to the strategies in the middle column? If so, perhaps make it clear which policies are related to which strategies.
Reformatted the table, it wasn’t meant to be that precise. It’s a grouping of policies organized by sector.
Chapter 6 – Data Collection At 72 Note that the DER forecast assumes a Battery Bonus program targeting 50 MW, which was changed earlier this year to a 40 MW cap per Company request. This many not significantly affect the forecast, however, as additional resources attributed in this forecast to Battery Bonus may relatively reflect BYOD Program resources, but should be addressed if feasible.
This should not significantly affect the outcome of the analyses; however, the forecast will be revised in future cycles of IGP .
At 72 The cumulative distributed PV capacity in Table 6-1 indicates a consolidated capacity of about 1,025 MW by 2025, whereas Hawaiian Electric’s 2022-2023 Sustainability Report indicates that as of the end of 2022, the cumulative solar capacity is 1,118 MW. Please explain the disconnect in the forecast and current capacity.
The 2022-2023 Sustainability Report cumulative solar capacity of 1,118 MW includes utility scale solar, CBRE and FIT, whereas the IGP DER forecast only includes the customer DER programs.
At 74 How were the price elasticity assumptions for TOU rates for the 3 sensitivities in Table 6-3 determined? The elasticities were from the SMUD SmartPricing Options Final Evaluation (September 2014) and the AEG/Brattle Group State of Hawaii Market Potential study (August 2020). Elasticity of –0.70 is consistent with the SMUD elasticity of substitution for non-Energy Assistance Program Rate residential customers on the default TOU rate. Elasticity of -0.045 was the lower bound of the range sited in the AEG/Brattle Group State of Hawaii Market Potential Study. These sources were chosen following a literature review comprised of the following studies and reports:
SMUD SmartPricing Options, September 2014 NV Energy Nevada Dynamic Pricing Trial, October 2015 KIUC TOU Solar Rate Pilot Program, May 2017
Hawaiian Electric Interim TOU Program, January 2020 UHERO Integrating Renewable Energy: A Commercial Sector Perspective on Price-Responsive Load-Shifting, July 2018 AEG/Brattle Group State of Hawaii Market Potential Study, August 2020. For more details, refer to Appendix B, Section 1.3.1
At 77 For Figure 6-4, is there a summary comparison of the cost (both energy and capacity) for energy efficiency bundles available?
Data on the energy efficiency bundles was provided in the IGP Key Stakeholder Documents, under the Energy Efficiency Supply Curves dropdown. See files posted on Nov. 9, 2021: Key Stakeholder Documents | Hawaiian Electric
At 78 Please define “light-duty,” “medium-duty,” and “heavy-duty” in the context of electric vehicles for reader comprehension.
We clarify these terms in this section.
At 82, Fig. 6-7 The process for converting sales forecasts into an hourly demand load forecast includes a Layers step for the Layer Shapes of DER, Battery Load Shift, EE, EoT, and Future
Yes, the forecasted EE hourly shapes were derived using AEG’s State of Hawaii Market Potential Study
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Layers. Please discuss whether the Layer Shape for EE are derived from the hourly load impacts provided in AEG’s State of Hawaii Market Potential Study, dated July 27, 2020.
At 86-87 For the resource costs data sources in Table 6-17, do the cost of the resources from different sources all include: electrical infrastructure and IC costs as well as O&M and land costs including land lease payments and land improvements?
As noted in the NREL ATB, all technologies include electrical infrastructure and interconnection costs for internal and control connections and on-site electrical equipment (e.g., switchyard, power electronics, and transmission substation upgrades). Similarly, all technologies also include site costs for access roads, buildings for operation and maintenance, fencing, land acquisition, and site preparation in the capital expenditures as well as land lease payments in the fixed costs for operations and maintenance. We have also added a locational adjustment for Hawaii as described in the approved Inputs and Assumptions (August 2021).
At 87, 88,
Fig. 6-10, 6-11
Please clarify the units for Figures 6-10 and 6-11. Please clarify whether these graphs are duplicate, and if not, what analysis each graph provides.
The units for Figure 6-10 and Figure 6-11 are provided in the caption. Figure 6-11 was inadvertently a duplicate. It has been updated to the correct graph.
At 89 Should the Technical Potential be adjusted for the need to upgrade distribution circuits to increase hosting capacity some of which is touched on in Section 8.2.5.1?
No adjustment needed, but added clarification: Technical potential is a metric that quantifies the maximum generation available from a technology for a given area and does not consider economic, market viability, or other technical constraints (e.g., hosting capacity, system stability, etc.). Chapter 7 – Resilience Planning
At 93 The report states, “Achieving a target level of resilience will depend on multiple integrated aspects of resilience including emergency response, generation/power supply resilience, transmission and distribution (T&D) resilience, system/grid operation resilience, cybersecurity, physical security, and business continuity.” Yet, this chapter seems to focus primarily on T&D resilience, which is just one of the seven aspects. Suggest that the current status and future plans regarding other aspects of resilience (emergency response, generation/power supply resilience, etc.) also be addressed in this Chapter. For example, regarding cybersecurity, what does this entail for Hawaiian Electric, what is currently being implemented, what is the plan and projected cost and projects for future improvements? Another example, for emergency response, how often does Hawaiian Electric perform emergency response drills, what other improvements, training, etc. are required?
Cybersecurity and emergency response is not necessarily in scope of the resilience section that focused on transmission and distribution facilities. However, the Company has a dedicated business unit to monitor and implement appropriate protections for Company operations. Additionally, as part of PBR, we report metrics related to critical load, National Incident Management System and Emergency Response Training. Additional information is available at: https://www.hawaiianelectric.com/about-us/performance-scorecards-and-metrics/resilience
At 93 HE prioritized the Hurricane /Flood/Wind combined threat as the top threat scenario to address. Again, regardless of the scenarios prioritized, all aspects of resiliency are needed to effectively handle such scenarios.
See above response.
At 95 1. Color coding of Figure 7-2 does not correspond with the language that describes the figure. 2. Figure 7-2 specifically focuses on T&D Resilience. Should there be similar metrics on the other resiliency aspects?
Language describing the figure has been updated.
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General Is HECO coordinating any resiliency planning with the IPP’s for the renewable generation facilities, or only for HECO-owned and operated generation facilities?
As renewable energy becomes a larger proportion of the generation mix, we are evaluating how to incorporate these IPP facilities into its overall resilience planning process. Hawaiian Electric already requires stringent performance standards, such as grid forming and black start which would allow these facilities to provide critical services in the event that the Company’s more traditional generators were not capable of doing so. In addition, we require a stringent cyber security review of all new facilities.
At 98, 7.4.1 Stated, “Hawaiian Electric's initial Transmission and Distribution Resilience Program (Docket 2022-0135) represents the first phase of foundational system hardening investment of approximately $190 million across the islands we serve, with the potential for a 50% match of federal funding.” This is a large ticket item, and again, this is only for physical T&D resilience improvements, with more to be identified. What are the plans and projected costs for the other aspects of resiliency? If not included in the IGP report, what is the reason? Or if included, but in other Chapters, please provide references.
Other aspects of the company and system were not in scope for IGP and the resilience working group. Other resilience measures the Company prepares for may require discussions with different stakeholders than the resiliency working group.
At 99, 7.4.3 In the application filed in Docket No. 2022-0135, the Companies noted a synergy between hardening and upgrading conductors belonging to HELCO's 6200 line and the planning goals for renewable energy. Do the Companies consider these kinds of synergies for all transmission hardening candidates? Hawaiian Electric also states that it is currently evaluating its wind speed design policies. Are Companies' current requirements for IPP interconnection facilities inline/consistent with the Companies’ hardening criteria?
Yes, the Companies considered synergies between resilience planning and other planning goals (such as net zero) when developing the transmission hardening plans for each company. For example, hardening the Maʻalaea-Puʻunēnē (to become Maʻalaea-Kanaha) line on Maui is also aligned with renewable energy goals, as this line was identified for reconductoring in the REZ study. While the Companies do not intend to reconductor Maʻalaea-Puʻunēnē as part of the initial hardening plan, the Companies intend to harden structures such that they will meet or exceed resilient wind design criteria with the larger conductor size contemplated by the REZ study.
The Companies’ current requirements for IPP interconnection facilities are consistent with the Companies’ hardening criteria. Any future updates to the Companies’ design policies will be reflected in the Companies’ design policies that are provided to IPP developers.
Chapter 8 – Grid Needs Assessment
At 104 “If REZ zones cannot be developed, future renewables may be delayed until technological advancements or aggregated DERs become more cost-effective. In this scenario, system stability is a concern with current state of customer-scale inverter technology”
Please specify, if known, what technological advancements are necessary, including what needs to change in inverter technology to enable DERs. What is HECO doing to address these changes?
From a system stability perspective, according to the latest findings, momentary cessation is the biggest concern with current state of customer-scale inverter technology. For our island systems, momentary cessation should be disabled or reduced to a much lower threshold than current Rule 14h SRD and IEEE 1547 standards, for both existing and future customer-scale inverter. The alternative option would be using sufficient grid-scale grid-forming resouce (e.g., GFM standalone BESS, GFM STATCOM) to mitigate customer-scale inverter momentary cessation issue. We are currently looking into this option. We have also been reaching out to customer-
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scale inverter OEM to address this issue. Currently; however, we have received limited feedback from inverter OEMs. None of major brand inverter OEM in our State has yet reponded to ourinquiries. It is important to know that detailed information regarding customer-scale inverter control and protection are very limited at this time, and mostly are proprietary information of OEM. We are also currently performing inverter testing in order to get more information. Other system stability related challenging may be identfied in future.
At 106 “The Maui system may require Transmission network expansion earlier, starting from the Stage 3 procurement, and the Oahu and Hawaii Island systems may require network expansion in later years” – have there been discussions with developers in Stage 3 about the network upgrades needed on Maui?
No. The transmission network expansions highly depend on locations of the Stage 3 awarded bids. Without knowing these locations, it is difficult to ascertain system upgrade requirements and discuss with developers regarding details of transmisson networks expansion. These issues will be part of the Stage 3 RFP process. In future procurements, one consideration is to be proactive about project location and transmission needs. As stated in the “Large-scale” Competitive Procurements section, we state, " Through our community engagement efforts and analysis to evaluate renewable energy zones, we are also considering different options to identify communities we can collaborate with to develop renewable energy zones to site future renewable projects. Pre-selecting locations or areas for renewable projects as part of the RFP has potential benefits, including to engage with communities early, plan and build infrastructure needed to enable or expand transmission capacity, and streamline the procurement process.” At 104 “Transmission non-wires alternatives can cost-effectively manage the buildout of this new transmission, though this may mean that less than the full technical potential for new variable renewables can be developed.” [Emphasis added]
Please explain why transmission NWAs may result in less than the full technical potential for development.
In the “Transmission and System Security Needs” section we clarify that non-wires alternative to defer transmission expansion could come in the form of energy storage with limiting interconnection AC size and possible longer hour duration, which results in less than REZ potential AC MW limit interconnected to the system. This would mitigate the transmission overloads that are observed in the transmission needs analysis. This is further articulated as part of the Preferred Plans.
At 105 Section 8.1 would benefit from clear table(s) that summarize the grid needs on each island, including the Preferred plans developed around the adjusted RESOLVE outputs. It should also clearly describe how these Preferred Plans were translated into the Preferred Plans described in Section 2.2, which aggregate solar and wind projects and include resources not selectable by RESOLVE (such as energy efficiency).
Add language at the end of Section 8.1 to describe changes made due to the results of the transmission needs analysis, RA analysis, and TAP feedback (4hr BESS) relative to RESOLVE plans. Additional information added to each island’s Preferred Plan section. We also hope the new area stacked charts are helpful to understand the components of the Preferred Plans.
At 105 “In 2030, the O’ahu and Maui Base scenarios and the O’ahu Land-Constrained scenario that include 450 MW of hybrid solar and some new firm renewable generation from the Stage 3 RFP achieve a loss of load expectation less than 0.1 day per year.” Given that the 2030 systems are already reliable assuming the Stage 3 procurements come online, why is so much additional capacity proposed in the preferred resource plans for 2030? Is it because of near-term economic savings (i.e., lower energy costs)? Is it because the model has foresight into future energy and capacity needs, and
Additional PV+BESS and onshore wind capacity is selected due to its low cost of energy. In the RESOLVE model, energy reserve margin Is not a binding constraint in 2030.
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the model sees it economic to build that capacity earlier intime? Something else? Please explain.
At 106 It could be helpful to include a “limitations” paragraph or section that discusses some of the limitations of the probabilistic resource adequacy analysis. For example, 5 weather years considered may not capture all types of extreme weather events that the actual grid may face. How is consideration of “tail end” extreme events incorporated into the GNA?
Paragraph was added to section 8.1.2 to note some of the limitations in the resource adequacy analysis. Tail events could be incorporated and used as the basis for the grid needs that should be procured. Alternatively, we point out in Section 12 the risks of higher load which also identifies certain needs. Ultimately along with stakeholders and the commission we would need to determine whether higher load forecasts (a risk) or tail events (another risk) should be used as a basis for procurements.
At 107 “GFM capability is critical to system stability. To mitigate risks, there is a minimum requirement of GFM resource capacity or “MW headroom” to maintain system stability within the planning criteria. GFM resource MW headroom is the available capacity before the GFM resource generation reaches its contract capacity. The MW headroom requirement is directly related to the amount of DG outputting on the system at a given time” How will GFM capacity and/or MW headroom be contracted? Such as specific GSPAs for frequency response? Does HECO have the flexibility to achieve its needed MW headroom under the RDG contracts?
Yes, the benefit of the current Renewable Dispatchable Generation contracts with hybrid solar plants is our ability to dispatch the resource to meet system needs, including system security needs as identified in IGP. In our Preferred Plan sections we describe that we simulate this in PLEXOS by maintaining headroom to be able to respond to an event (rather than using the entire charge of the BESS).
At 108 “It is worth noting that to identify transmission system capacity needs to accommodate future large-scale generation projects, distributed generation is not considered in the steady-state analyses” Please explain the rationale for not considering DG. Could the Companies have utilized the multiple DER scenarios to perform the steady-state analyses? What could considering multiple levels of DERs change about the analyses?
DER was excluded from developing the transmission need to consider the effects of a scenario with days of rain and/or clouds that limit the contributions from DER to capacity on the transmission lines. This happened in the recent years during Kona Low weather. By considering DER generation in the study, DER generation could reduce loading on the transmission by supplying part of load locally. Transmission line overloading issue could be smaller or mitigated. This study results would require measures (such as policies or programs) to make sure the studied DER generation capacity is always available. The clarification has been added to the section 8.1.4.1 Important Study Assumptions and Scope Limitations.
At 109-110 How are the different load scenarios and DER scenarios/benchmarking impacting the distribution grid needs (both hosting capacity grid needs and location-based grid needs)?
Generally the high load scenario has more load-driven grid needs and the high DER scenarios have more hosting capacity grid needs.
At 111, Table 8-1 It would be helpful to provide a brief explanation, rationale, or methodology for how the thresholds across the “Favorable”, “Moderate or Uncertain”, and “Unfavorable” categories were determined, as well as what “Market Assessment” is referring to here. There appears to be a typo under the Favorable column (0$-10%).
Deleted Market Assessment and Forecast Certainty from Table 8-1.
Needs updating, reference to Appendix F, section 1.3.2.2 The Project Economics and Operating Date (Timing) thresholds are based on stakeholder feedback and best industry practices. The Performance Requirements thresholds (MW and duration) were developed based on the Company’s previous experience with sourcing grid needs. The thresholds were created to be conservative to allow greater opportunity for potential NWAs to move forward to Step 3 of the evaluation. This threshold will be reassessed as the Company gains additional experience with grid needs sourcing.
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At 112, Table 8-2 Good use of scenarios to illustrate the differences in the NWA opportunity evaluation Acknowledged.
At 114, Figure 8-2 Please discuss why biomass and new firm renewable energy resources are selected in the high load scenario, but not the faster technology adoption scenario for Oahu.
Both the high load and faster technology adoption scenarios assume high EV growth, but the high load scenario assumes low EE and DER growth, while the high technology adoption assumes high EE and DER growth. As a result the high load scenario has a greater load than the high technology adoption scenario. The biomass and new firm resources are selected to provide energy and capacity, especially in the later years.
At 115 “We note that, because the DER aggregator resource is not selected until 2045 and 2050 when we must comply with the 100% renewable energy mandate, new advanced generation technologies could become available prior to 2045 that could accelerate the path to 100% renewable energy in a Land-Constrained scenario.” What types of advanced generation technologies might these be? What is HECO doing to explore/pursue those advanced technologies?
A new section 6.9.5 regarding emerging technologies has been added in response to stakeholder comments.
At 115 Why was the Land Constrained scenario not able to meet the 70% goal? Was this not a constraint in the RESOLVE model? Will the 70% emissions reductions be used in the RESOLVE model going forward?
GHG was not a constraint in RESOLVE. As a result, in the Land Constrained scenario, the consolidated GHG reduction was around 55%. A figure was added to section 9 to show the Consolidated GHG emissions when Oʻahu is Land Constrained.
To test the impact of achieving a 70% GHG reduction in 2030 in a Land Constrained scenario, a separate run was performed in RESOLVE using the RPS target as a proxy for GHG emissions. By setting the 2030 RPS target to 70%, we were able to see how the results in RESOLVE may change to achieve a 70% GHG reduction. The results shown in Chapter 8 highlight that RESOLVE will burn biofuel in a Land Constrained scenario when the RPS target in 2030 is 70%.
At 116 How can RESOLVE/overall modeling steps be improved such that it can analyze a High Fuel Retirement scenario that does not result in a system that exceeds 0.1 LOLE, or build in more constraints for reliability?
The high fuel retirement scenario could be further evaluated in a resource adequacy analysis to identify additional resources that would be needed to meet reliability. However, the curve fits examined in Section 12 largely cover the same types of scenarios where additional existing thermal generation is removed and identify what replacement capacity would be needed from PV+BESS or firm resources.
At 117, Figure 8-7 Are the RPS percentage numbers on top of the Annual Generation bar graph correct? Why doesn’t the High Fuel Retirement scenario increase the RPS amounts in 2030 and 2035?
Figure has been updated to correct RPS.
At 114, Figure 8-2 and 8-3 Why is DER+DBESS not shown in Figure 8-2, even though we can see DER+DBESS generation in Figure 8-3? Is all that generation coming from existing DER+BESS?
*Same question for Figures 8-16 and 8-17 (Hawai’i), Figures 8-26 and 8-27 (Maui), Figures 8-36 and 8-37 (Moloka’i), and Figures 8-45 and 8-46 (Lana’i)
Clarification inserted into text. Figure 8-2, and similar figures for other islands, shows the capacity of new resources selected by RESOLVE. Figure 8-3, and similar figures for other islands, shows the annual generation from all existing, planned, and selected resources. DER+DBESS refers to the forecasted DER and therefore is not selected by RESOLVE but is utilized as shown in Figure 8-3.
At 115, Figure 8-4 and 8-5 How are DER aggregated resources depicted in Figure 8-2, considering generation from these resources is Figure has been updated to show all new resources selected by RESOLVE.
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depicted in Figure 8-5, and the narrative indicates that the DER aggregator resource is selected started in 2045?
At 116, Figure 8-6 “In the High Fuel Retirement Optimization scenario, RESOLVE chooses to retire 570 MW of thermal capacity (see Figure 8-6).” Is the model retiring generation from specific plants? If so, it would be informative to indicate which ones. *Same question for endogenous retirements selected on Hawai’I at 139 and Maui at 151
To manage model complexity, thermal units with similar operating characteristics are bundled together. When RESOLVE chooses to retire thermal units, it retires capacity from the bundle and not an individual unit explicitly. For this reason, it is better to view the retirements as thermal capacity removed in aggregate than the retirement of a specific unit.
At 117, Table 8-3 It would be helpful to include the age of the units during the year the unit is proposed to be retired, so that the reader can have a clearer sense of how old these units are at the time, and to validate the retirement order.
Age of the units upon retirement was added to the Table 8-3.
At 117-119 This section (8.2.2) seems wordy and is not particularly intuitive. Instead of (or in addition to) the 8 bulleted scenarios, consider visually representing the content as a figure or table that includes the year, resource combinations, and whether those combinations meet the 0.1 LOLE standard.
Refer to table 8-4, 8-5 and Section 12 for tables that provide the probabilistic resource adequacy results.
At 119, 120, Table 8-5 Was a case evaluated in the probabilistic modeling considering the High Load RESOLVE portfolio under the High Load demand profile? If so, why wasn’t it included in Table 8-5? Additionally, are the resource additions suggested for the High electricity demand scenario described on p.120 informed by the RESOLVE High Load portfolio? *Same questions for Hawai’i at 141, Table 8-18 and Maui at 153, Table 8-27
A case was not evaluated using the High Load RESOLVE portfolio. Table 8-5 focused on the Base and Land Constrained resource plans to see how the Base resource plans performed and the risk that may occur if the load trended towards the high load forecast and we cannot procure additional resources quickly enough. The results of the RESOLVE load bookends showed that the same resources are largely built as the load forecast increases. This may mean that additional resources should be selected in future RFPs, above the target identified using the Base scenario, to ensure resource adequacy if the high load bookend were to occur. In other words, if this risk is deemed prudent to mitigate than the high scenarios can inform the needs to procure in future RFPs. The resource additions suggested on page 120 was based on the variable and firm curve fits presented in Appendix C and looked at how much additional resources may be needed to meet 0.1 LOLE if the load were to increase towards our high load forecast.
At 119 “In the 2035 probabilistic resource adequacy analysis, however, the 153 MW combined cycle was assumed not to be installed to test whether this firm generator is needed for resource adequacy.” Since the RESOLVE Land-Constrained scenario without the 153 MW combined cycle still meets the 0.1 LOLE standard, it would be helpful to understand why RESOLVE is building this capacity that does not seem needed. Is there an economic-driven reason (rather than a capacity-driven reason)?
Initially, RESOLVE was allowed to build fossil fuel thermal units. In the Land Constrained case, with less available potential to develop other renewable resources, a new thermal unit with improved heat rates would lower energy cost if on fossil fuel. However, new thermal unit additions were assumed to be on biodiesel for the PLEXOS analyses and after the resource adequacy cases were conducted, this combined cycle unit was removed because it was not needed for reliability.
At 120, 121, Figure 8-8 and 8-9
Please explain what analysis/learnings are available from Figures 8-8 and 8-9, including any key points that help inform preferred plans or other outcomes of IGP.
Figure 8-8 and Figure 8-9 are the energy profiles under the Status Quo scenario. The transition to 100% renewables will necessitate a change in how the firm thermal generators on our system operate. Renewable resources and storage will reduce our reliance on existing fossil generators to serve load. This is shown in the daily energy profiles and operational
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statistics in this section. Reducing dependance on fossil generators will improve reliability given that our fossil generators are currently over 60 years old, as shown in Appendix C, and experiencing higher outage rates. The analysis in Section 9 also shows that utility rates will be lower than if we continue to rely on fossil fuels.
At 123, Figure 8-14 and 8-15 Please provide a description of how units were categorized as “Baseload”, “Cycling”, and “Peaking” and what types of technologies those include. *Same question for Hawai’I at 144, Figure 8-24 and 8-25; Maui at 156, Figure 8-24 and 8-35; Moloka’i at 169-170, Figure 8-44 and 8-45; and Lana’i at 177 at Figure 8-54 and 8-55.
Appendix C shows which thermal generators are categorized as “Baseload”, “Cycling”, or “Peaking”. Language was added to the document to clarify.
At 123, Figure 8-14 Confirm that “New” generators represent peaking units, and if not, what they do represent. New generators include thermal generators procured through the Stage 3 RFP and selected by RESOLVE. On Oʻahu, the new generators from Stage 3 were modeled as 6-50MW CT and 1-208MW CC, and the new generator selected by RESOLVE in the Land-Constrained case was modeled as a 1-153MW CC. On Maui, the new generators from Stage 3 were modeled as 2-8MW ICE.
Language was added to the document to clarify. At 125 Retrofitting of existing GFL IBR inverters is discussed in Section 8.2.4.2 for the Land Constrained Scenario but should retrofit be limited to that scenario? (The recommendation from 2021 System Stability Study (p. v) is that when there is opportunity, current GFL IBR plants be converted to GFM IBR plants).
No, retrofitting existing grid-following inverter-based resources should be considered in all scenarios. Clarificaiton is added in Section 8.2.4.1.
At 130-133 The maps include the geographic locations of proposed new resources. Please explain how these locations were determined and if they are indicative of preference of locations of future procurements.
Those are the locations represent locations of projects that were awarded (but withdrew) during RFP Stage 1 and 2, or locations where capacity is currently available to host projects.
At 130 If Land-Constrained Scenario requires much less transmission network expansion, is there significantly more distribution network upgrades needed to enable more DERs? How do the distribution network upgrades compare to the cost of the transmission upgrades in other scenarios? On the whole, which is more cost effective (transmission buildout vs distribution buildout)?
The distribution analysis looked out to a 5-year timeframe for hosting capacity and 10-year timeframe for load-driven grid needs. Distribution upgrade costs beyond year 2030 were not included for any of the scenarios. However, under the land-constrained scenario with significant additions of DER in 2045, we expect significant transmission and distribution upgrade costs to be needed. At 134, Table 8-7 & 8-8 How does the DER adoption compare between the faster technology adoption and the land-constrained cases, and were the distribution grid needs costs associated with greater DERs considered in the land-constrained cases?
Distribution grid needs through year 2030 were identified in this analysis. Since the land-constrained scenario uses the Base DER Forecast (Table 6-16), the distribution grid needs for the land constrained case would be similar to the Base scenario through year 2030 which has fewer grid needs than the Faster Technology Adoption scenario. Additional distribution upgrade costs beyond 2030 to accommodate the aggregated DER added in the land-constrained scenario were not determined.
At 134, 8.2.5.1 Hawaiian Electric states that most circuits have sufficient hosting capacity or could accommodate the 5-year hosting capacity without infrastructure investments. Does Hawaiian Electric also evaluate upgrading circuits that have little or no hosting capacity as these circuits may indicate circuits/areas that are willing and able to add DER
The Company evaluates all distribution circuits for DER and load capability and those circuits that have more forecasted DER adoption than available hosting capacity were identified as a hosting capacity grid need. Throughout the IGP process the Company adopted a less
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but for the lack of hosting capacity? (According to HECO's Oahu Locational Value Map (LVM), there are a significant number of areas with only up to 5% available Hosting Capacity.) Also, although the Draft Report states that most of the 384 circuits have sufficient DER hosting capacity, please explain why the LVM appears to show a significant number of locations in the Central and Leeward districts that have a certainty rating indicating a grid need.
conservative calculation for hosting capacity. That revised calculation is in the process to be reflected in LVM. The grid need certainty rating in LVM represents grid needs driven by load
At 135, Table 8-9 Earliest NWA opportunity is in 2025, how soon will a procurement be coming? For the 2025 NWA opportunity (Transformer CEIP3 / Circuit CEIP 46), an EOI was released on 2/6/2023. The Company did not receive any responses therefore a procurement for this specific opportunity will not be issued. Our EOI / RFP strategy is outline in Section 10 under NWA Competitive procurement. At 135 If an item is in Track 1 of the Base, shouldn't it also be in Track 1 of the High Load Bookend? For example, Transformer CEIP 3.
The year the overload occurs is dependent upon the forecast scenario. For this specific case, Transformer CEIP 3 / Circuit CEIP 46, the overload for Scenario 1 is forecasted to occur in 2025, while in Scenario 2 - High Load, the overload is forecasted to occur earlier in 2023. The earlier required date in Scenario 2 makes this an unfavorable NWA opportunity based on the Timing criteria in the NWA methodology.
At 136 Related to Preferred Plan, what was driving the inclusion of the 153 MW CC unit that RESOLVE selected, if the RA analysis determined it was not necessary? Did the increased BESS duration alter any other grid needs?
See response above at 119
At 136, 137 It would be useful to summarize the changes made to the RESOLVE Base and Land-Constrained plans in developing the Preferred Plans in a table. Seeing the original and modified plans side-by-side would greatly increase clarity.
Were the Preferred Plans subject to a resource adequacy backcheck, given the changes from both RESOLVE and probabilistic resource adequacy analyses? Same comments apply to the Preferred Plan sections for all the other islands (Sections 8.3.6, 8.4.6, 8.5.6 and 8.6.6)
The preferred plans were not subject to a resource adequacy back check specifically but were the result of the resource adequacy back check conducted on the Base resource plans.
At 136 “Increased duration of paired and standalone BESS to 4 hours to match current market conditions.” How does this change affect costs and/or reliability? Why not start by constraining RESOLVE to use only 4-hour storage? *Same question for Maui at 163, Moloka’i at 171, and Lana’i at 179.
RESOLVE was run without constraining the duration of the storage to 4-hours to allow RESOLVE the opportunity to optimize the duration, which was based on TAP feedback early on in the process. Based on the RESOLVE results where 2-3 hr durations were selected for paired and standalone BESS, the TAP suggested assuming 4-hour duration to match market conditions and improve the BESS contribution to meeting reliability in the resource adequacy analyses. Longer duration batteries will increase cost but should also improve reliability as more energy can be stored and shifted to meet demand. We don’t believe constraining RESOLVE to 4-hr storage would have a significant impact on the optimization.
At 137, Table 8-14, 8-15 Please explain the comparison of production costs with and without transmission constraints. How are the transmission capital costs >$4B in the base case, but the difference with and without transmission constraints is <$1M? It would be more helpful to see the MW capacity of each resource type compared with and without transmission
The production costs shown in Table 8-14 and 8-15 include the cost for fuel, O&M, and IPP payments, but does NOT include the transmission capital cost shown in Table 8-15. The purpose of Table 8-14 and 8-15 was to determine whether the transmission constraints, which included
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constraints to see if the transmission constraints impact what resources are selected. modifications to the size of the REZ buildout and the additional reserve for dynamic stability, materially affected the costs for fuel, O&M, and IPP payments. The transmission constraints did not impact what resources are selected but did reduce the size of certain REZ to avoid additional new transmission or reconductoring cost to accommodate the REZ at its original size.
At 140, Figure 8-17 and at 141, Table 8-18
“In 2030, assuming a Base scenario load forecast with Hamakua Energy Partners combined cycle already retired…A loss of load less than 0.1 day per year is expected even if Hamakua Energy Partners combined cycle and some additional firm is brought offline unexpectedly.”
This seems to be a contradiction. If Hamakua Energy Partners combined cycle is assumed to be already retired in this scenario, what does it mean for HEP to be brought offline unexpectedly? Please clarify: is HEP modeled in the 2030 base scenario, or not?
HEP is modeled in the 2030 Base scenario. The results shown in Table 8-17 include HEP. The bullet points towards the end of section 8.3.2 summarize analysis detailed in Appendix C. As shown in Table 8-17, the 2030 Base scenario (which includes HEP) has an LOLE of 0. When evaluating how adding/removing resources affects LOLE, it’s helpful to compare systems with non-zero LOLE. This is why the analysis in section 12 and Appendix C (summarized in section 8) doesn’t include HEP. The comment about HEP being brought offline unexpectedly is meant to show that the 2030 Base system could withstand HEP being removed from the system.
At 141 Please discuss why the Future Wind and Future Standalone BESS resources are lower in the High Load case than in the Base case.
The Future Wind and Future Standalone BESS resources in the 2030 results are not planned resources but are resources added by RESOLVE. The intent was to include the RESOLVE-added resources in the 2030 analysis but only include planned resources for the 2035 analysis. Only including planned resources in 2035 gives a clearer reference point when discussing the additional resource capacity needed to meet reliability targets in Appendix C. Several rows have been added to Table 8-18 to show how the system reliability for Base and High Load scenarios changes with and without the RESOLVE-added resources.
At 141 “Though 140 MW of hybrid solar is not needed to meet the reliability target in 2030, acquiring even half of the 140 MW will greatly benefit the system.”
Please elaborate and provide specifics on what is meant by “greatly benefit the system.”
Figure C-5 in Appendix C shows the 2030 Base scenario without HEP and the 140 MW hybrid solar from Stage 3 achieves an LOLE of 0.1. Adding only 60 MW of hybrid solar to the system, while not reducing LOLE as much as an additional 140 MW of hybrid solar, will still reduce LOLE by an order of magnitude.
At 146 It would be helpful to see a formula for east side minimum generation (MW) with conditions. Overloading caused by too much east side generation is also related with location of where to interconnection future west side generation. So, that equation has not yet determined.
At 153 “In 2035, assuming a High electricity demand scenario and all of Stage 3 RFP resources and 37 MW of hybrid solar from RESOLVE model, approximately 540 MW of additional hybrid solar is needed and approximately 33 MW of additional firm is needed” Have there been any scenarios run to see if Maui can accommodate 540 MW of hybrid solar? Noting that there is no land-constrained modeling for Maui.
The 540 MW of additional solar is less than the REZ zone capacity for Maui; but roughly the amount needed by 2050. The 2050 REZ requirements would be a close approximation of the upgrades needed.
At 153 and Figure 8-26 “In 2035, assuming a High electricity demand scenario and all of Stage 3 RFP…and 37 MW of hybrid solar from the RESOLVE model:
Approximately 540 MW of additional hybrid solar is needed to bring the system loss of load expectation down below 0.1 day per year.
Wind is primarily being selected by RESOLVE for its low cost of energy and high capacity factor. In 2035, energy reserve margin is not a binding constraint. However, similar to the reliability curves developed in Section 12, wind will have a contribution toward meeting the reliability standard; albeit diminishing returns similar to the hybrid solar curves.
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Approximately 33 MW of additional firm generation is needed to bring the system loss of load expectation down below 0.1 day per year.”
The RESOLVE High Load scenario also includes substantial additions of onshore wind compared to the Base case. Please clarify whether wind is considered here to help the system meet the reliability standard?
At 163 “Modified Stage 3 firm renewable proxy to two 8.14 MW units based on 2030 resource adequacy results.” Please provide justification for this.
We explain in Maui’s Preferred Plan in Section 8 that we reduced the Stage 3 firm renewable proxy from five 8.14 MW units to two 8.14 MW units based on 2030 resource adequacy results. The justification can be seen in Section 12.3.3.2 and Figure 12-30 and Figure C-10 in Appendix C, where the addition of two 9 MW and 8.14 MW units meet the LOLE target respectfully.
Chapter 9 – Customer Impacts
At 181-188 How does potential continually rising fuel costs affect these analyses of customer bills? What is the assumed fuel cost? Does Hawaiian Electric assume that fuel costs will rise as fuel is purchased in smaller quantities? Does the Status Quo attempt to address this scenario?
The base fuel price forecast that was modeled assumes a continually rising trajectory through the planning horizon, using the EIA AEO. No adjustment was made to the forecast to account for high fuel prices as fuel is purchased in smaller quantities. The EIA forecasts were part of the approved Inputs and Assumptions in response to stakeholder feedback.
At 182 Please explain the “status quo” scenario in more detail, given that this was not listed as one of the modeling scenarios in Table 6-16. Is the jump in revenue requirements and bill impacts in 2045 observed across several of the islands largely due to the transition from fossil fuels to expensive biofuels?
The Status Quo scenario assumed the Base forecast; commercial operations of Stage 1, Stage 2, and CBRE Phase 2 Tranche 1 projects; successful renegotiation of existing independent power producers; and continued operation of most existing thermal units. The Status Quo plan excluded CBRE Phase 2 Tranche 2, Stage 3 RFP resources, and future resources selected by RESOLVE.
The jump in bill impact in 2045 is largely due to the transition from fossil fuel to biofuel.
At 194 Please consider providing a comparison chart that incorporates biogenic CO2 emissions. We did not provide the “with biogenic” GHG reduction analysis and calculations; however, we expect emissions to be higher than the without biogenic case because of biodiesel combustion and burning of municipal waste. To abate these emissions, we would need a zero emissions firm source (i.e. geothermal) on Oahu and other islands or additional investment for carbon capture or negative emissions technology.
Chapter 10 – Energy Equity
At 205 What opportunities does partnership in DOE’s ETIPP afford to Hawaiian Electric and its customers? Is there research assistance, funding assistance, or other support available?
The partnership with DOE’s ETIPP project has provided Hawaiian Electric with technical support to develop a hybrid microgrid opportunity map. In the development of this map, the technical team (made of national labs) have used data from the Company as well as other publicly available sources to find areas that can be categorized by criticality, vulnerability, and societal impact. These visualization tools (in-progress) can help customers and the Company to identify locations that may require additional focus and attention based on the characteristics of the particular area.
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Chapter 11 – Growing the Energy Marketplace
At 211 Table 11-1 presents avoided costs for the freeze scenarios without much context. While it’s clear from the DPS Phase 3 Modeling Results (in a separate docket) that these represent RESOLVE results for the year 2030, it’s difficult to contextualize what these avoided costs represent. Consider incorporating the total cost of the base case for each island as well to show the scale of impacts for each of these freeze scenarios.
The avoided costs are the difference between the Base and Freeze scenarios NPVs. The NPVs represent costs over the RESOLVE planning horizon (2029-2050), not just 2030 like what was shown in the DPS Ph 3 Modeling Results since these programs may not specifically target 2030. This difference in cost would inform the program costs that could be incurred to encourage adoption of DER, EV or EE resources and be cost effective to other supply side alternatives. The percent difference in NPV is described in the narrative.
Base case NPVs were added to the table in the report. At 212 Please elaborate on the differences observed due to the unmanaged EV scenario. The Unmanaged EV scenario produced similar results to the Base scenario which assumed managed EV charging. In 2030, the Unmanaged EV scenario and the Base scenario selected the same resources, and the sizes of the resources selected were within a couple percent.
In 2050, the Unmanaged EV scenario selected 6 MW of new firm renewable generation and an additional 45 MW of Biomass (45% more) over the Base scenario. The other resources selected in the Unmanaged EV scenario have sizes within 5% of the Base scenario. The difference in NPV was within 1% of each other between the Managed EV and Unmanaged EV scenarios.
At 212, Section 11.1.2.1 “The EE as a Resource scenario selects the EE supply bundle, standalone solar, and renewable firm in addition to the renewable resources selected in the Base scenario. As shown in Section 11.1.3, the load impact of the EE supply curves is smaller than the EE load forecast. This results in more selected resources and higher generation need for the EE as a Resource scenario than for the Base scenario.” Please clarify whether this implies that the load forecast develops some energy efficiency measures that are not cost-effective and/or double-counts some energy efficiency potential.
In cases where the EE as a Resource scenario built less EE bundles than the Base forecast, the load forecast may have assumed more energy efficiency than was cost effective. However, energy efficiency may be needed in greater amounts than what was modeled if onshore renewables cannot be developed as shown in the Base cases. There are also other EE benefits that cannot be precisely quantified such as reduction in land needed if more EE can be built, especially in land-constrained scenarios.
At 220 Will there be any strategy to smooth out the size and timing of the procurements coming out of IGP? Concerns have been raised about the size of the RFPs recently and the impacts of that on HECO’s resources on the interconnection/resource acquisition teams.
Yes, ideally. We clarify this in Section 11.2,
At 221 How will the details of the REZ studies be translated into future RFPs where more upfront information could be helpful to provide proposers with estimated costs of interconnecting their projects?
The REZ studies help to identify high-level transmission requirements to add generation capacity to certain zones. It is not yet certain how this information will be used to inform future procurements; however, there is consideration for planning procurements that target certain areas to combine the transmission requirements to support high amounts of renewable capacity to enable a more efficient interconnection and development process. The technical information developed in the REZ studies are one part of a complex process, which includes commercial, community, and other input to develop these zones.
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At 221 “Pre-selecting locations or areas for renewable projects as part of the RFP has potential benefits…” Is there potential to pre-study locations in order to reduce the time required for interconnection studies after the bidding selection process?
Yes, see response above. If there are targeted procurements, high-level transmission requirements can be identified to support the addition of targeted generation resource capacities in a region or area.
At 221 “In some instances, it may be prudent to specify technologies consistent with the IGP to send market signals that certain types of attributes are needed to fulfill certain grid needs.” Would it be more competitive and fairer to tailor procurements to the desired types of attributes and let the market respond with technologies that will meet those attributes at least cost?
In general, that has been our practice in Stages 1-3 RFPs, where we do not specify technologies. However, when it comes to urgent reliability needs, we have identified the need first through analysis, and made a determination that for critical needs such as reliability, strong market signals should be sent as to what we are seeking based on our assessment of the need and the current state of technologies. Otherwise, we may not attract the bids necessary to meet these critical needs. For example, we also specify grid-forming requirements which is a specific type of inverter; rather than describing the general problem or need that was identified in the analysis to ensure the market is clear what we need to meet critical reliability needs.
At 222 “Other examples of modifications that will likely be necessary include the requirements for certain actions at the time of bid submission, such as site control, and model submission. In addition, the overall RFP schedule will likely require modification, and contract terms will also need to be developed to contemplate the longer period between contract execution and commercial operations” There may be additional benefits to such changes to the RFP process, such as planning for a smoother allocation of resources to study interconnections over a longer time horizon, rather than several projects simultaneously.
Yes, please see response above on this topic.
At 223 “Based on the EE supply curve analysis we believe that including energy efficiency as part of the grid services would help to complement existing EE programs, accelerate adoption of energy efficiency, allow for competitive market pricing, and target location-specific benefits” How would introducing EE into GSPAs and introducing more competition into the EE offerings interplay with Hawaii Energy, the EE administrator role, and the PBF framework?
EE contracted through a GSPA would target the same load reduce grid service that is already being procured on this contract. An EE program and EE procurement can coexist. This is similar to aggregators contracted on the GSPA contract in parallel with ongoing DER programs. If there is a gap in the program reach, the procurement may be an avenue to fill that gap.
At 224 “A procurement would also allow the market to determine the value and compensation for resilience services, provide flexibility to determine the performance and capabilities needed for each unique microgrid opportunity, the best way to integrate and use DER for resilience, determine the supply and demand for microgrids in Hawai‘i, and identify prospective developers of microgrids” What other efforts are ongoing to put a value and determine compensation for resilience services?
Please see discussion in Section 7.3.2.
Chapter 12 – Securing Generation Reliability and Assessing Risks At 226 Please define the terms “removal from service,” “retirement,” “deactivation,” and “standby,” as they all represent steps toward replacing existing resources on
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the system, but have different requirements. It could be helpful to reference the Fossil Fuel Retirement Report. For planning purposes, what does HE plan to do with the property when a unit is fully retired? Will all structures and buildings on the property be demolished/cleared? Does HE have plans for the cleared properties? – Could they be used for future renewable generation sites?
Definitions for removal from service, retirement, deactivation, and standby were added to the Glossary.
In Section 11.2.3, the Company notes, “Pursuant to the Public Utilities Commission’s guidance, we are also exploring if other company-owned sites could be made available for interconnection of a variety of technologies in our RFPs, and further seeking ways to streamline the interconnection process.”
Section 12.3 This section references various demand scenarios and generation resource mixes. Are the graphs in this section based on any of the Tables provided in Appendix C? If so, please add references to the applicable tables in App. C.
The graphs in Section 12.3 are not based on a specific resource plan, but rather, they are based on sensitivities done to the resource plan to determine how the LOLE changes with varying firm/variable additions.
At 232 Section 12.3 would greatly benefit from a detailed summary section. This might include a summary of key findings, a comparison or results between islands (for example in a single table), an explanation of how results from this analysis were incorporated in selection of the Preferred portfolios, and additional explanation of where and how results were used to inform other parts of the GNA.
A table was added to each island’s subsection to summarize the resource adequacy scenarios that were performed. This table describes the resource combinations that were evaluated, as well as, the LOLE results.
At 232-264 For each island evaluated in Section 12.3, it would be helpful to include a table that summarizes of the probabilistic modeling results included in the GNA (Chapter 8), and includes the probabilistic adequacy results for the Preferred scenarios in 2030 under Base and in 2035 under Base and High load growth assumptions.
A table was added to each island’s subsection to summarize the resource adequacy scenarios that were performed. This table describes the resource combinations that were evaluated, as well as, the LOLE results.
At 225 “Generation reliability is an area of concern in Performance-Based Regulation and is intertwined with State policy to retire fossil fuel-based generation as soon as practicable…”
It would be helpful here (and elsewhere) to provide citations as footnotes, endnotes, or in-text citations to specific documents, webpages, etc. when referring to other dockets, policies, studies, etc.
Provided clarification and cite.
At 232 and Figure 12-6 “Importantly, this chart demonstrates the sensitivity of reliability that O'ahu has to small changes in capacity. For example, 200 MW of hybrid solar results in a significant swing (approximately 8.7 days per year) in reliability. We consider this point a significant consideration in how we plan and procure resources to meet our customers' reliability expectations.” Can you please elaborate on how this finding will be incorporated as a “significant consideration” in procurements for reliability? How will this affect how you are planning for near-term and long-term resource procurements?
We believe this means that given the age of our units, the challenges in developing a project through commercial operations among other factors, we must ensure that we are not caught short of capacity resources. That means our procurements should take into account awarding projects (i.e., hybrid solar and firm generation) such that we procure sufficient resources to retire units as outlined in the Plan as well as acquiring additional resources to ensure we can assure reliability while withstanding projects dropping out of the process. This may mean the we acquire projects in excess of the state targets.
At 236 and Figure 12-13 It appears there is unserved energy in more hours of the year in the case with the additional 150 MW of firm capacity. Can you please explain this behavior?
Figure 12-12 and Figure 12-13 was updated with corrected EUE charts.
At 236 Based on the caption for Figure 12-13 it appears the difference between the left and right is 150 MW and not the additional 650 MW identified in the paragraph about Figure 12-13.
Paragraph was corrected. Difference between left and right is 150MW of firm generation.
At 238-239 and Figure 12-14 It’s not clear what scenario are being modeled here. Why is 1,600 MW of future hybrid solar being evaluated if only 1,145 is intended to be procured in the Base case? What
The 1,600 MW of future hybrid solar is a combination of the 450 MW from Stage 3 RFP and the 1,145 MW selected by RESOLVE. Made a clarification in the narrative.
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amount of other new and existing resources are being modeled?
At 240-241 and Figure 12-16, Figure 12-17
It’s confusing to keep track of which resource combinations are being evaluated given the provided descriptions. A clear table showing the amount of each resource evaluated in each scenario, relative to the base case, would be helpful, for Hawai’i and all other islands where relevant.
A table was added to each island’s subsection to summarize the resource adequacy scenarios that were performed. This table describes the resource combinations that were evaluated, as well as, the LOLE results.
At 243 “We also observe that even small amounts of added resources can dramatically reduce the system's reliability.” Is this a typo? Wouldn’t additional resources increase the system’s reliability?
This was a typo. Paragraph was corrected to say small amounts of added resources can dramatically change the system’s reliability.
At 250-251 and Figure 12-31 “Figure 12-31 shows when we expect unserved energy to occur and at what quantities when no future firm renewable from Stage 3 is assumed, from the scenario shown in Figure 12-30 with a loss of load expectation around 0.75 day per year.”
Please explain why an LOLE of 0.75 is used here, when all of the other heatmaps show EUE when LOLE is around 0.1?
The LOLE of 0.75 was a result of the RA analysis for the no new firm scenario which does not meet the 0.1 LOLE target. The result of the analysis supports the finding that there is a firm need on Maui.
Appendix B – Forecasts, Assumptions and Modeling Methods At 7 Re NEM Customers add to Residential Addressable Market. How are NEM Plus participants who increase their PV size to attain the minimum bill but are prevented from increasing their export accounted for?
NEM+ customers were included in all case scenarios for all islands, but only from 2024-forward for Oahu and Maui Base case because Schedule-R NEM customers were re-introduced in the customer pool for uptake modeling in 2021-2023 due to scheduled dispatch/battery bonus on those islands.
At 15 “It is important to note that many of the measures in group A could have absolute costs ($/MWh) that are higher than measures in group B or C. In those cases, the greater benefit of peak-focused resources offsets the costs in the MPS methodology. Depending on how the shape of bundles meets the RESOLVE model’s needs, it might choose lower absolute costs first, which could produce differences between the RESOLVE model selections and the MPS.” This statement demonstrates the value of treating EE as a selectable resource in capacity expansion modeling.
Yes, however, the underlying conclusion whether a forecast layer or supply side resource is that EE is beneficial and can be cost-effective. The challenges are in implementation and the ability to acquire customers to implement these measures at the scale identified in the MPS report. We have proposed potential other mechanisms to help fill those gaps (i.e.,EE through procurements).
At 15 Bundles were assigned based on the range of Benefit-Cost Ratios. Can a table be provided that shows what exactly is in each bundle along with its BCR? (Based on Table B-14, it looks like each bundle just has a different amount of the same EE measures)
Figure B-5 provides the energy savings in each supply curve bundle using the same A, B, C, D grouping for its benefit-cost ratio on a consolidated basis. The mapping of BCR to bundle is noted in Section 11.1.3 and in Appendix B, table B-13. Similar charts as Figure B-5 are provided for each island in the Bundle Summary and Costs files in the Key Stakeholder Documents under the Energy Efficiency category, see https://www.hawaiianelectric.com/clean-energy-hawaii/integrated-grid-planning/stakeholder-and-community-engagement/key-stakeholder-documents
At 16, 1.4.1.1 In order to compete against other supply side resources, the model was provided a levelized cost of conserved energy (LCOE). Can the LCOE for each model be summarized along with a few generation resources’
The Bundle Summary and Costs files in the Key Stakeholder Documents under the Energy Efficiency category provide additional data on levelized cost, see https://www.hawaiianelectric.com/clean-energy-
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levelized cost to give a reader a sense of the similarities/differences between the costs? hawaii/integrated-grid-planning/stakeholder-and-community-engagement/key-stakeholder-documents.
Using Oʻahu as an example, the nominal savings weighted LCOE in $/MWh for 2023 ranged from Other_A at $21/MWh to Other_D at $1,723/MWh. Peak focused supply bundles were more expensive than the flatter Other bundle with Other_A and Other_B at $21/MWh and $49/MWh and Peak_A and Peak_B at $70/MWh and $72/MWh, respectively.
At 17, Table B-14 Adding a table showing the weighted average levelized cost of each bundle as well as the weighted average cost/kilowatt would greatly enhance the ability of readers to interpret the differences in EE development between those assumed in Base Case Forecast and the RESOLVE modeling results.
A reference was added in Appendix B to the Bundle Summary and Costs files that provide this information.
19, Figs. B-6 & 7 Please provide axes and units for these figures. Figures have been updated.
Appendix C – Data Tables
General Some of the generation resources and their dates available, may need to be updated prior to finalization of the IGP report, based on the latest status of the projects.
The dates in Appendix C match the modeled assumption that was made for Stage 1 and Stage 2 RFP resources.
Appendix D – System Security Study General Note that this study identifies system transmission level grid needs to accommodate various future plans in accordance with transmission system planning criteria. Also, “these study findings are sensitive to the future grid-scale resource interconnection locations and size, as well as system load growth and system DER growth. Therefore, it is necessary to update study when grid scale resource procurement plans are identified and finalized.” It is therefore understood that the future transmission system plans may change often in the coming years. Has HECO determined what frequency (at minimum) this plan should be updated (eg annually, every 2 years, etc.)?
A specific determination on frequency has not been made, but it may be appropriate to update the study every two years and/or when the system undergoes a significant resources or assumptions change.
General Which of the portfolios in Appendix C is this study based on? For example, does the study include the transmission system needs to support the Planned and New Resource Additions in the Preferred Plans for each of the islands? If not, which plans do the forecasted transmission system needs and projects identified in this study support?
The system security analyses was based on the Base and Land Constrained RESOLVE resource plans, prior to implementing any additional constraints or adjustments. The Base and Land Constrained resource plans were then iterated to account for the outcomes of the system security study and develop the Preferred plans. Resource Tables for the Preferred Plans (post-adjustments from RESOLVE plans) are included in Appendix C. Appendix E – Location-Based Distribution Grid Needs
At 9, 2.a The draft report states that initially, substation transformers and circuits are screened to determine if there are violations based on the forecasted annual peak demand. Are there additional analyses that need to be conducted related to the backflow of energy from
As circuits are forecasted to see reverse power flow, the transformer load tap changer is reviewed and upgraded as needed to accommodate the reverse power flow.
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Reference PUC Staff Question/Comment Hawaiian Electric Response
residential PV such as the adequacy of the transformer load-tap-changer?
At 12 HECO used a 75% of equipment rating to test for planning violations as a contingency condition based on engineering judgement. What types of scenarios would cause a derate of the equipment of this type? Do other jurisdictions use similar “derate” scenarios for distribution planning? If so, what percentage derate do they assume?
75% of normal rating was used to quickly screen for equipment that may not have capacity to provide backup capability under an N-1 contingency scenario. The contingency scenario is when load is transferred to an equipment because an adjacent circuit is out-of-service. If the equipment is already at or near normal rating capacity (75%), and additional load is transferred to it, there is a greater possibility that the equipment will become overloaded under contingency rating capacity. The 75% screen is to identify the circuits that will move on to more detailed hourly analysis to identify any grid needs under contingency scenarios. The Company is not “derating” any equipment for this screening analysis.
At 31 Was there any minimization of wires solutions between the Location-Based Grid needs and DER/Distribution Hosting Capacity grid needs?
The grid needs identified by the load-driven analysis for the Base scenario were on different tsfs/ckts compared to the grid needs identified by the hosting-capacity-driven grid needs. Therefore there were no overlap in wires solutions that would solve both a Location-Based grid need and a Distribution Hosting Capacity grid need.
Appendix F – NWA Opportunity Evaluation Methodology At 10 How does the North Kohala BESS project track with the timeline outlined in the NWA methodology? The North Kohala BESS project was initiated outside of the NWA methodology. At 36 “In the years 2022 and 2023, EOIs were issued for three T&D NWA opportunities which were identified as Track 1 opportunities based on the NWA methodology.” Where were these EOIs published?
The EOIs were posted on the website: https://www.hawaiianelectric.com/clean-energy-hawaii/selling-power-to-the-utility/competitive-bidding-for-system-resources The EOIs were also sent via email to the Company’s potential developer list made up of approximately 500 recipients.
At 38 For Kewalo/Kakaako load growth, where is the 50x jump in energy/8x jump in capacity coming from in one year? The load growth is primarily due to planned development by Kamehameha Schools and Howard Hughes in the Kakaako area. Appendix G – Revised Framework for Competitive Bidding
GENERAL Has HECO identified any changes to the CBF necessary to carry out a long-term RFP? In the January 27, 2021 filing, we said, “The topic of a long-term RFP was discussed in detail in the context of the CBF with the CPWG. Presently, the group believes that the CBF is broad and flexible enough to incorporate long-term RFPs and therefore has not proposed specific updates at this time, and will work together to address specific issues in these future procurements.” Also see Section 11.2.3. At 14, Section III.A.2.f Why did HECO drop the following clause section from the Approved Revised CBF from June 30, 2022:
“f. Where the utility is using a utility-owned (in fee simple) site in a self-build option, the utility shall offer that utility-owned site to bidders, unless it is demonstrated to the Independent Observer and the Commission that doing so would be unreasonable.”
This was an oversight; the incorrect version of the CBF was provided with the draft report. The final approved CBF reflecting edits made after comments were received is attached with this draft.
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Reference PUC Staff Question/Comment Hawaiian Electric Response
At 20 Please explain the addition of the clause: “Subject to Commission approval, the utility may also recover such costs through the major project interim recovery (“MPIR”) adjustment mechanism, Exceptional Project Recovery Mechanism (“EPRM”), renewable energy infrastructure program (“REIP”) surcharge or other recovery mechanism until such costs are recovered through effective rates approved in a rate case or other Commission approved regulatory process or mechanism.”
This language is not in the final approved version of the CBF and will not be included in the appendix filed with the next draft.
At 15, Section VI.B Has HECO considered adding a deadline for the request to not propose a self-build project? In practice, it would be best for such request to be submitted and approved before the final RFP is approved such that streamlining modifications can be made to the RFP to account for the absence of a self-build proposal.
GENERAL Has HECO considered moving the Framework to the Administrative Rules instead of including it in the IGP Report?
No. The Framework is a standalone document that was approved by the PUC in 2008. A revised version of the Framework was approved by the PUC in 2022 involving stakeholders. The Framework was revised to generalize the planning methodology used by the utility in the event that IGP were to change. In which case, the Framework could go on without being tied to the specific process as the 2008 one was with specific references to IRP.
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1.2 Technical Advisory Panel (TAP) Comments
This feedback and summary were delivered by the IGP Technical Advisory Panel (TAP) to Hawaiian Electric (HECO) based on HECO’s draft Integrated Grid Planning (IGP) report. As always, TAP’s comments are suggestions.
TAP members:
■ Jordan Bakke (MISO)
■ Dana Cabbell (SCE)
■ Matthias Fripp (UH/EDF)
■ Elaine Hale (NREL)
■ Andy Hoke (NREL, Chair)
■ Debbie Lew (ESIG)
■ Durgesh Manjure (MISO)
■ Vishal Patel (SCE)
■ Deepak Ramasubramanian (EPRI)
■ JoAnn Rañola (EPRI)
■ Matt Richwine (Telos/HNEI)
■ Rick Rocheleau (HNEI)
■ Kevin Schneider (PNNL)
■ Derek Stenclik (Telos/HNEI)
■ Gord Stephens (NREL)
■ Terry Surles (HNEI)
■ Aiden Tuohy (EPRI, Co-chair)
TAP feedback and comments are divided into four categories:
1. Informational, no action needed
2. Near-term action strongly suggested
3. Concern or suggestion, for future discussion or consideration
4. Clarification needed in draft report
Hawaiian Electric responses are provided in purple italicized font.
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1.2.1 General comments
Overall, the IGP report presents an enormous effort by HECO and its stakeholders to plan out how to reach very
ambitious and timely renewable energy goals. Many aspects of the report reflect past TAP feedback that has
been used to improve the analysis; some of those improvements are noted in this feedback document. The
report describes a long-term plan to achieve 100% renewable energy as well as concrete near-term actions to
meet interim renewable goals. The long-term plan and near-term actions appear reasonable. In the places
where the TAP would suggest improvements or clarifications, those are noted here in colored text.
As is to be expected from an integrated grid plan, the analysis described in the report makes various
assumptions; those assumptions in general appear reasonable. Similarly, the analysis uses modeling methods
designed to find an optimal solution; those methods are generally reasonable, well vetted, and are aligned with
best practices. Where the TAP has concerns, sees risks, or would suggest improvements or clarifications, that is
noted in this document in colored text with the most urgent items shown in red.
We agree on the need for urgent action and generally encourage HECO to continue the various efforts underway
and to begin implementing the plan described in this report, notwithstanding any specific TAP comments to the
contrary. At the same time, it will certainly be possible to improve the plan going forward as new information is
gained, modeling methods improve, and technology evolves. Therefore, the plan should remain flexible to allow
for future adjustments, as the report notes. For example, a near-term opportunity to evaluate assumptions will
come with the Stage 3 RFP bids, which will provide valuable information on resource availability, pricing, and
other details.
Some TAP comments may be best addressed by simply including a reference to the relevant section of the
report. In other words, we may have missed some details (and other readers could also use help finding those
details).
Inflation Reduction Act – we suggest more discussion on how large of a change this is and what it means for the
different resource portfolios.
● We understand that the legislation was passed recently and after all of the capital cost assumptions
were finalized, but this dramatically changes costs of clean technologies. Further discussion on the
potential implications for resources selected by RESOLVE and timing of new additions is warranted. In
the next IGP, we suggest HECO provide a detailed representation of the IRA in the capital cost of
resources.
● Oahu is an energy community (10% IRA bonus) and neighbor islands likely have low income community
or indigenous community multipliers. HECO should flag what HECO, SEO, and other government entities
can do to maximize the IRA opportunities for the state.
● Hawaiian Electric Response – Clarification made to Section 5.2.1. The Company does not expect that tax
credits from the inflation reduction act would materially affect the outcome of the modeling provided in
the IGP Draft Report. The cost projections for hybrid solar and wind already assumed these were the
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least cost resources. While there are “adders” in the inflation reduction act that may increase the eligible
tax credits for projects in Hawaii, the Company also notes that projects costs have risen since the cost
projections for IGP were approved by the Commission. There is likely to be some cancelling effect
between the additional tax credits and increase in underlying equipment costs. The Company will gain
further insight into the IRA impacts as it evaluates developer proposals through the Stage 3 RFP.
Standalone storage could be appreciably lower cost than we have seen in the past; which could lower
cost for the ancillary services that a standalone storage system provides; however, this likely would not
impact the optimization because it is not in of itself a generator of renewable energy which is needed in
large amounts to meet 2030 decarbonization goals. Notwithstanding, the Company does recognize the
importance of the IRA towards affordability. The Company is pursuing tax credits for any of its own
projects. We also expect that developers of prospective projects will look to maximize the tax credits
available to them when developing their project proposals for an RFP.
Firm capacity needs: There is a lot of discussion throughout the IGP on firm resource needs. It is clear that with
HECO’s aging fleet and limitations of (4-8 hour) battery storage that the need for new firm resources is
reasonable. However, the needs may not be to the level that the report indicates. For example, the Stage 3 RFP
firm RE target was not analyzed through the IGP process. While it makes sense to move forward with the Stage 3
RFP process given the need to identify what projects the market can provide (and at what costs), before building
the Stage 3 firm RE projects we recommend further analysis to clearly define the firm resource needs, including
those already part of Stage 3, at increasing levels of VRE and storage integration and with different retirement
assumptions. We are not suggesting this analysis needs to be done before this report is finalized.
Hawaiian Electric Response – First, the Company clarifies that the Stage 3 firm RFP targets were informed by a
grid needs assessment using IGP assumptions in July 2022, where firm resource additions were first optimized by
RESOLVE then verified through a combination of ERM and probabilistic resource adequacy analyses. In IGP, the
Stage 3 targets are then assumed to be planned resources. Notwithstanding, as part of the Stage 3 RFP
evaluation, based on direction by the Commission, the Company intends to consider firm generation needs in the
context of the entire portfolio (i.e., variable renewable resources) that may be advanced from the Stage 3
process.
● Firm resources are not selected by the RESOLVE model. It is unclear if this is because existing unit
retirements are not being selected by the model or not being included as an option?
Hawaiian Electric Response – Firm resources are a resource option in RESOLVE. It is not chosen because
there are other lower cost options in RESOLVE. When these other options are removed, as in the case of
the Land-Constrained scenario on Oʻahu, then a firm resource was chosen.
● Table 8-4 and 8-5 show resource adequacy results of the RESOLVE portfolios of 0.00 days/year LOLE. We
suggest analysis that shows for each of those future years/portfolios, how much existing firm resources
can be retired or new firm can be deferred to show how much firm the future years need. I.e., back-
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solve for the total firm capacity needed at each future year (2030, 2035, 2040). We recommend this be
done before reaching the building Stage 3 firm RE projects. We are not suggesting this analysis needs to
be done before this report is finalized.
Hawaiian Electric Response – The Stage 3 RFP will include a reliability analysis to assess system reliability
given the actual proposals/resources bid into the RFP.
● The firm resources actually don’t appear to need to be flexible. And the existing firm will not need to
cycle as much as it has had to in the past due to the amount of storage coming on. This is illustrated on
the Base Case of page 123 and is an important finding for the firm needs. 1) New firm resources may not
need to be flexible, but will need to operate for extended periods and be offline for potentially large
parts of the year. 2) HECO may be able to keep older units online longer if they don’t cycle as much.
It would be helpful to give context to the stage 3 RFP. It could be helpful to have a table showing the system as it
is today, then stage 1 and 2 projects, and then stage 3. The Status Quo scenario could be included in this table.
Hawaiian Electric Response – The Stage 3 firm RFP resources were modeled as 6 x 50MW CT and 1 x 200 MW
combined cycle on Oʻahu and 5 x 8 MW internal combustion engines on Maui. While they may not need to
constantly start/stop as flexible units, they will be relied upon to provide reserves on both an intra-hour basis to
shore up the intermittency of PV and wind and potentially multi-hour reserves for extended periods of poor
weather when the paired BESS is more likely to be exhausted.
Offshore wind
● No portfolios were evaluated without offshore wind being selected. Offshore wind on a small scale of a
couple hundred MWs (relative to North American plants that are between 1-2 GW) in the deep ocean is
highly uncertain.
● Given the high degree of technological, cost, and regulatory/siting uncertainty for future offshore wind
development, HECO should conduct a sensitivity for Oahu - similar to the land constrained case - where
offshore wind resources are not available to show the resulting portfolio.
Hawaiian Electric Response– Given the uncertainty of developing a new offshore wind project and
numerous public comments received in regards to offshore wind, the Company ran RESOLVE without
offshore wind as an option to determine if the resource plans meaningfully change. The results are
discussed in Section 8.2.1.3. In summary, when offshore wind is not an option, more hybrid solar is
developed in the Base scenario and more DER Aggregate is developed in the Land Constrained scenario.
This underscores that our lowest cost renewable options: onshore wind, hybrid solar and offshore wind
are critical to meeting our decarbonization goals. We must continue to diligently work with communities
to keep as many of these resource options on the table as possible.
● If the LCOE of OSW is much higher than grid-scale PV and residential PV (per page 88), why is it getting
built in the future scenarios? Is RESOLVE hitting land or other constraints? Or is the model highlighting a
benefit for resource diversity?
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Hawaiian Electric Response– The LCOE presented in the Draft IGP was mistakenly the capital cost and
not the LCOE. The figure has been corrected. The LCOE for offshore wind with the tax credit is close to the
LCOE for hybrid solar. Based on the LCOE, onshore wind, low slope PV+BESS, offshore wind, high slope
PV+BESS are the least cost resources in ascending cost order. The resource selections in RESOLVE follow
this same order. By 2050, the resource potential is being reached for the hybrid solar and onshore wind.
In both the Base and Land Constrained scenarios, the offshore wind is primarily being used for energy.
● There is discussion of this risk of offshore wind development on page 105, but it should be made more
explicit. Oahu has a significant problem if OSW is not technically feasible or cost effective.
Hawaiian Electric Response– See discussion above on “no offshore wind” scenarios.
● The Big Island RESOLVE model selects no grid-scale solar until after 2035 – presumably because land-
based wind is cheaper than solar+storage. However, this does not align with recent RFPs, community
acceptance, and likelihood of being built.
● We suggest at least one case for Hawaii Island where onshore wind is not available as a candidate
resource to see if the model selects more grid-scale solar or another resource (like geothermal). This
type of info is needed in case community preference is to avoid building new wind resources. This
analysis should be completed when the Stage 3 RFP results are available to inform the analysis. We
suggest the IGP report just include a brief note stating acknowledging the concern.
Hawaiian Electric Response– On Hawaii Island, the situation is different than Oahu in the Land
Constrained scenario and the uncertainty surrounding offshore wind. While RESOLVE is selecting wind for
its low cost and high capacity factor relative to other technologies, the Company believes there is
potential for development of other low cost resource such as hybrid solar. The RFPs will help to
determine the technology choices on Hawaii Island. Additionally, we believe if we limited the amount of
wind on Hawaii Island then the model would select hybrid solar in its place and both resources have
sufficient technical potential to serve Hawaii Island loads. This is similar to Oahu where the wind
potential is limited and so the RESOLVE model favors hybrid solar in its place once the wind potential is
maxed out. Indeed, wind and solar have different characteristics, but we will continue to test reliability of
portfolios that may be selected through the RFP process. Should we see evidence that neither future solar
nor wind is viable on Hawaii Island, that may warrant an update to Hawaii Island’s pathways at that
time.
● In general, the selection of land-based wind on Big Island (along with the OSW finding on Oahu) shows
the importance of showing multiple portfolio options. The RESOLVE portfolios show only the least cost
portfolio, but the costs of alternative portfolios are likely close (and the cost assumptions are highly
uncertain anyway). Other constraints like land, community acceptance, and regulatory/siting (DOD
restrictions) are likely the more important factors. Reporting out on other portfolios that aren’t
necessarily least cost but may have more realistic pathways to deployment, may be helpful.
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Hawaiian Electric Response – Stakeholders identified land-constraints on the island of Oahu; therefore, we
modeled a specific scenario to evaluate how we could reach 100% renewable energy in that scenario. We
currently do not have any reason to believe that Maui and Hawaii Island cannot achieve the Preferred Plans. If
procurements dictate that other factors like land or community acceptance may hinder the “optimal” plan
adjustments to pathways/scenarios could be made in future iterations.
Given that several projects have dropped out of recent RFPs, what is HECO’s backup plan if a similar result
happens with Stage 3? Will existing firm plant lives be extended, or is another plan needed to fill resource gaps?
Can you run resource planning scenarios in which one or more Stage 3 plants drop out? Would it make sense to
give preference to smaller firm projects from multiple developers rather than one big firm renewable resource?
Hawaiian Electric Response – These are important questions that we will need to evaluate as the portfolio from
the Stage 3 process becomes clearer. We are also developing contingency plans where necessary to ensure we
are able to maintain reliability if projects selected through the Stage 3 process are unsuccessful in timely
reaching commercial operations.
The grid needs assessment implemented the suggested “Bookend” analysis in the forecasts, as suggested by the
TAP, but didn’t really show that in the resulting portfolios. The point was to show how even with a very wide
range of assumptions, it doesn’t change the least cost portfolio much. Can you add some discussion with a figure
or table showing that?
Hawaiian Electric Response – Each island has a Capacity Expansion Scenario that shows the results from the Low
Load, Base, Faster Tech, and High Load scenario. The first bullet in Section 8.1 of the draft report (now Section
8.1.1) also highlighted that across different load scenarios, the models consistently selected high levels of solar,
wind, and energy storage.
Colors of resource types are not aligned throughout the report, making it hard to flip between figures/sections.
This is not a must-fix, but it's a “nice-to-have”.
Where does IGP go from here (in addition to the various items in the Action Plan)? Does another iteration of IGP
start once the plan from this iteration is approved? Or is there a pause?
Hawaiian Electric Response – The plan is to execute the action plan, including competitive procurement(s) over
the next several years. Updates to the plan can be made following each procurement/acquisition of resources.
The next major update may occur in the next 3-5 years depending how the market, environment, or other
material events may affect the pathways.
It might be useful to quantify more clearly to consumers the costs and benefits of different options, particularly
around aspects such as electrification of transport, smart thermostats/water heaters, etc.
TAP has not reviewed some of the aspects in quite a while, or in some cases, not at all yet; for example the
resilience section does not seem to have been shared. It might be worth discussing whether these aspects are
worth review, or if they are still too early to receive technical review from TAP.
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1.2.2 Executive summary
In general the executive summary provides a good summary of the report.
One TAP member felt the executive summary itself could benefit from a shorter summary.
Guiding Principles box:
● The guiding principles appear reasonable. It’s great to see that renewable energy is the first option.
● We were surprised to see a mention of “dynamic pricing”. What are the details? Or do you really mean
“advanced pricing”, rather than truly dynamic pricing (which implies that prices paid by customers
change frequently based on communicated signals)? (Dynamic pricing does not appear to be mentioned
anywhere else.)
Molokai: You note the majority landowner will form a microgrid. Will this be a utility-connected microgrid or will
they operate disconnected from HECO’s system most/all of the time?
Will the community benefits packages from IPP plant developers become an RFP requirement? Is this for Stage
3, or afterwards?
Hawaiian Electric Response – The community benefits packages for IPPs have been implemented for Stage 3 RFP.
We will continue to improve on iterate on these requirements as we gain more experience on how this is
implemented between developers and communities.
It will be very interesting to see what firm renewables are actually proposed in the Stage 3 RFP and future
procurements. This appears to be one of the biggest unknowns and challenges in the energy transition (not just
in Hawaii, but worldwide). Should the executive summary acknowledge this uncertainty? Also, we notice bio-
energy is not mentioned here, whereas geothermal, waste-to-energy, and green hydrogen are - is that
intentional? (In the report body, bioenergy/biofuels seem to be considered the most likely option, so it’s
surprising that they are not mentioned at all in the executive summary.)
Figure 1-3: What are the remaining CO2 emissions in 2050 from? Is this electric sector emissions or total Hawaii
emissions across all sectors?
Hawaiian Electric Response: The emissions shown in Figure 1-3 is for Hawaiian Electric. In 2050, some emissions
are still produced by H-Power as a byproduct of its waste-to-energy process.
Figure 1-4:
● The change in generation profile from 2022 to 2030 is enormous (from 32% renewable to 81%). How
likely is it to be successful? How far do just Stage 1 and Stage 2 resources get you?
● Stacked area plots or stacked bar charts are easier to read than side-by-side pie/donut charts to show
the preferred portfolio resource mix over time. (Figure 2-3, etc.) Here is an example of stacked area
plots from NREL’s Standard Scenarios report:
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Hawaiian Electric Response – Stacked area versions of the pie charts have been inserted into the
Preferred Plan subsections in Section 8.
● ● Please clarify that Figure 1-4 (and similar) are on an energy basis (not installed capacity)
Hawaiian Electric Response – This is on an energy basis and not a capacity basis.
● It would be good to provide an installed capacity version of the same information early on (e.g. Section
2) – especially if the plots later in Section 8 don’t reflect the final preferred plans
Hawaiian Electric Response – Installed Capacity Stacked area charts have been inserted into the
Preferred Plan subsections in Section 8.
● It might be helpful to show a difference plot (whether early on or in Chapter 8) that focuses specifically
on net capacity additions and removals relative to today, capturing both prescribed and optimized
(where applicable) retirements. This might help people internalize when and how much fossil is going
away, and what’s replacing it – effectively a graphical equivalent to Figure 1-3/2-1 (which is very
helpful). Here is an example of a capacity difference chart:
●
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Hawaiian Electric Response –Capacity Difference Stacked area charts have been inserted into the Preferred Plan
subsections in Section 8.
“Why is rooftop solar not enough?” - It does seem clear that getting to 100% renewables with only rooftop PV
would be extremely technically difficult. It would also likely be much more expensive than a plan that includes
large-scale solar and other resources; should this aspect be mentioned in this box?
Hawaiian Electric Response – In response to comments above on the offshore wind resource, the land-
constrained case was run without offshore wind. In this case, reliability and renewable goals are met through
additional biofuel generation and expansion of the DER aggregator. Because this case removed additional low-
cost large-scale resource options, it is expected to be much higher cost.
1.2.3 Section 2 - Action plan
The TAP agrees it is a good idea to implement IEEE 2800 for large-scale IBRs. You may also want to mention that
in many areas you go beyond IEEE 2800’s requirements due to the unique needs of your very high-IBR island
system.
2.1.4: You state “It is not possible to ensure a consistent, reliable flow of electricity if the entire grid is powered
by weather-dependent, energy-limited resources.” We'd suggest changing “not possible” to "not economically
desirable…". It is certainly possible to run a grid with only weather-dependent generation if enough storage is
present - but it would likely be extremely costly (i.e. very large amounts of energy storage).
Hawaiian Electric Response – We do not believe, especially on Oahu, that there would be sufficient land to
develop enough solar and wind to be able to charge the energy storage to supply the load on all days. On some
days, we would require some other generation source like firm generation to sufficiently charge the energy
storage or serve the load directly. While economics plays a part, other competing uses for limited land on Oʻahu
(housing and food/farmland) will limit what land can be used for energy.
2.1.4 Box titled “Near-term actions to adopt emerging technologies:”
● Adoption of grid-forming technology for large-scale plants should probably also be on this list. (It is
mentioned in the text above, but not here.)
● You mention a need for a standard for V2G. This probably should apply to all EVs, not just V2G, because
losing a very large block of load could be just as problematic as losing a very large block of V2G energy.
Hawaiian Electric Response – Changes have been made in the report main body section 2.1.4 to address both
bullets points, above.
2.2 :
● The resource mixes presented in this section are the result of optimization in a capacity planning tool
and a resource adequacy tool followed by a system security study, and potentially iteration of the
capacity planning/RA, right? If so, perhaps state this (in terms understandable to typical stakeholders) -
otherwise readers might think these are numbers HECO has picked based on some other criteria. In
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other words, if you have run detailed techno-economic models to find the least cost plan to meet
renewable and reliability goals, state that here. Maybe show the flow chart, or at least point to the
relevant section.
● There’s an obvious typo in the first paragraph.
Hawaiian Electric Response – Text updated
2.2.1: What is a "LMI project"? (LMI means low and middle income, but what kind of projects are these? Rooftop
PV? Community solar? Something else?) And what is "Phase 2"?
Hawaiian Electric Response – These are community based renewable energy projects. Section 2.2 has been
updated to clarify that these are community based renewable energy projects.
2.3: External Actions and Policies for Successful Implementation
● Why is “Investments in grid modernization and advanced technologies” listed as an "external
condition/action"? Seems like it's largely under HECO control. Or did you mean R&D investments by
vendors to improve technology?
● Under Resource and Technological Conditions, we’d suggest adding “ "Rapid maturation of technologies
for firm renewables and/or multi-day energy storage."
Hawaiian Electric Response – Removed “investments in grid modernization…” from external actions.
2.4 : Potential Risks and Challenges
● Good to see this section included. We'd suggest also referring readers to section 12 for a more detailed
risk analysis and mitigation strategies.
Hawaiian Electric Response – Added a reference to this section.
● You state “The primary threat to progress is the status quo and policy inaction to the above-listed
recommendations.” Agreed this is a major risk. However, this puts the focus on policymakers only. It
would be good to acknowledge the (obvious) fact that success will also depend on HECO's
implementation of these extensive and ambitious plants.
● Hawaiian Electric Response – Yes, we agree, added some clarity.
Figure 2-8: This is a helpful high-level timeline. What about transmission needs? If transmission is needed for
Stage 3 (e.g. on Maui), shouldn't transmission expansion also start asap?
Hawaiian Electric Response – Agree, added text to section 2.2.
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1.2.4 Section 8 - Grid needs assessment
General comments:
● After reading section 8, some TAP members still wanted to know what are you actually building and
what does it cost, and what adjustments are made. We’d suggest summarizing all the pieces at the end
of section 8. A bar chart or similar would be helpful showing additions and retirements from the current
system. Stage 3 and new DER assumed should be included as well, but could be categorized differently.
Changes in load should also be referenced there.
Hawaiian Electric Response – Each island now has a summary of the generation and change in capacity
for their preferred plan in Section 8.
● Most readers are going to be primarily interested in what the preferred plan actually is and what the
corresponding resource adequacy metrics look like, so having an independent discussion of the final
preferred portfolio/timeline for each island, separate from the methods details of how it was
determined, would be much easier to digest. Or some of those differences and motivations could be
mentioned up front, but the details saved for later.
○ E.g. “The preferred portfolio includes X MW of resource A – RESOLVE had chosen Y MW, but
based on RA assessment we determined less/more was needed – for more information see
Section 12.x.y.z”.
Hawaiian Electric Response – Appendix C has the preferred resource plans. A cross reference to Appendix
C was added to the Preferred Plan sections. New figures were also added to show the components of the
Preferred Plan. The description in each section discuss adjustments made from RESOLVE due to resource
adequacy or transmission system security analyses.
● The detailed RA is saved for Chapter 12, but might be better for that information to be conveyed prior to
Chapter 9, which summarizes costs and emissions reduction. Maybe these RA subsections in Chapter 8
could be expanded to include the results for the preferred adjustments that are explained in more detail
in Chapter 12, and the end of the Chapter 8 subsections on each island could clarify exactly what the
preferred plan is and how that was arrived at.
● It would be helpful to have a section describing how the grid needs were determined. A non-technical
summary will be useful to show that this was a very detailed analysis. A flow chart would be helpful. A
reference to any relevant appendices would also be helpful.
○ Concepts like ERM and HDC played a large role here, but they are not mentioned in this section.
A reference to further information in Appendix B would be helpful.
○ The TAP understands that a study is underway to compare the ERM/HDC approach used here to
other leading approaches. Is that study mentioned somewhere in the main report? It is
important to point out that HECO is looking at ways to improve capacity expansion modeling
before final procurement decisions are made. It is fair to say this is a novel and new approach,
but that it still needs more work to fine tune. In particular, the TAP has noted in the past that
the HDC/ERM approach may be biased in favor of adding thermal generation to meet reliability
needs, since even with the new 80% availability threshold, it likely understates the availability of
renewables during critical grid conditions. The other methods are designed to avoid this bias, so
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the comparison should be completed and the costs of the resulting plans should be compared to
the plan developed using ERM/HDC before reaching the “point of no return” on Stage 3 firm RE
procurement. The other methods include ERM/HEC, PRM/ELCC-light and a simple approach of
trying several quantities of solar and backfilling each one with enough firm capacity to reach
satisfactory reliability.
Hawaiian Electric Response – Yes, the company is taking a more detailed look at this in our
resource adequacy study as directed by the Commission. Notwithstanding, whether HDC/ERM is
biased toward firm generation in RESOLVE, the plans were evaluated using a probabilistic
resource adequacy analysis (that also evaluated lesser amounts of firm generation on the
system), we also note that in general, there was far more hybrid solar selected, and very little
firm generation selected in the RESOLVE modeling.
Add back in the flowchart showing the linkages between different modeling tools - it may be in
appendix but would be good to see and then refer to in the text when talking about changes
that needed to be made to portfolios
Hawaiian Electric Response – This was added to Section 8 to provide context of the modeling
framework.
● Is there a summary table of the Stage 3 RFP resources by island somewhere in the report?
● HECO states that load-driven grid needs and DER hosting-capacity-driven grid needs do not have much
overlap. Historically this is probably true: load-driven needs occur at peak load hours while hosting
capacity needs occur at midday hours. But distributed storage crosses these hours – how much
distributed storage is contemplated and how could this resource help address both challenges
simultaneously?
Hawaiian Electric Response – The grid needs identified by the load-driven analysis for the Base scenario
were on different tsfs/ckts compared to the grid needs identified by the hosting-capacity-driven grid
needs. This is because the load-driven grid needs are driven primarily by new service requests. Whereas
the hosting capacity grid needs are driven by DER growth forecast which may not be on the same
tsfs/ckts. The mutual-exclusiveness is not so much because the load-driven grid needs occur at peak load
hours while hosting capacity needs occur at midday hours. Clarification added to section 8.1.4.4
Distribution Grid Needs Summary.
The reference in the report to load-driven needs occurring during non-solar hours and hosting capacity
needs occurring during solar hours was removed after the above clarification was added to the report.
Distributed storage is included as a layer in the scenario forecasts used to determine load-driven grid
needs. Distributed storage is also an option for NWA solutions.
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● Generally all islands are showing sufficient margin on distribution equipment in the coming 5 years.
● It is not clear how PLEXOS results fit with the other parts of the study - are they used mainly for the
economic assessment, or do PLEXOS results also inform the capacity expansion or RA/transmission
modeling? Are violations of load/reserves assessed in PLEXOS and fed back to higher level models? If
not, it might be good to do this for future IGP iterations.
Hawaiian Electric Response – PLEXOS was used to capture the system cost over the planning horizon and
provide a view of how existing and new generators are expected to operate to meet electricity demand.
Results from PLEXOS were incorporated into the transmission analysis which resulted in adjustments to
the resource plans as described in each island’s Transmission and System Security Needs section. PLEXOS
was also used to perform the resource adequacy analysis, which may result in changes to the resource
plan. At the start of Section 8, we have added back the diagram that shows how all the models interact
with each other.
● Have PLEXOS results been used to benchmark the RESOLVE modeling in any way, other than LOLE
studies? For example, RESOLVE will have assumptions about production costs - it would be good to
verify those assumptions with the more detailed model.
8.1 - Thank you for addressing TAP feedback by describing the backup plan if large-scale renewables are not able
to be developed.
8.1.1 - You mention a North American standard of 0.1 LOLE - this is not actually a standard but rather a
commonly used criteria. Changing the metrics and criteria uses is also something being revisited in both
research (EPRI, ESIG, NREL efforts) and starting to be proposed in practice (recent PJM proposal, SPP and ERCOT
discussions). This is likely worth calling out to prepare for future changes and not to lock in 0.1 LOLE for future
work when it may not be appropriate in an energy-constrained system.
Hawaiian Electric Response – This is added into the latest version of report main body, Section 8.1.2 (of the Final
Report), “It is important to note that the TAP has indicated that changes to this criterion is being researched and
studied, and as a result, it may change in the future.”
8.1.3 - When mentioning transmission expansion, it would be good to also mention that you plan to explore
non-wire alternatives to transmission, or refer to other portions of the report where you already mention that.
Hawaiian Electric Response – This is added into the latest version of report main body Section 8.1.4 Overview of
Grid Needs, subsection Transmission and System Security Needs.
8.1.3.1: You state: “It is worth noting that to identify transmission system capacity needs to accommodate
future large-scale generation projects, distributed generation is not considered in the steady-state analyses.”
Can you add a sentence or two justifying this assumption? Otherwise stakeholders may strongly question it.
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Hawaiian Electric Response – This is added into the latest version of report main body Section titled Important
Study Assumptions and Scope Limitations.
8.1.4: In future iterations, have you considered combining the two distribution grid needs analyses into one
unified analysis? (It's not clear why the two analyses should be done separately - it would seem better to
combine them, but perhaps we’re missing something.)
Hawaiian Electric Response – This was due to the timing where the Company wanted to submit the hosting
capacity grid needs in the 11/2021 submittal directed by the Commission. In future iterations, it could be
performed together at the same time.
8.1.4.2 - Please explain up front the base, low and high DER forecasts – how many MW? Maybe have a table, or
refer to another section where they are explained.
Hawaiian Electric Response – The explanation for the DER forecasts can be found in Section 2:
https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/20211108_distri
bution_der_hosting_capacity_grid_needs_report.pdf
The links to the tables with the information can be found in Appendix A:
https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/20211108_locat
ion_based_distribution_forecasts.pdf
8.1.6 - A protection roadmap has been presented to the TAP. It was very useful to see how HECO is thinking
about and planning to address issues. It may be useful to separate transmission system protection from
distribution system protection because the protection schemes and complexity of each tend to differ. Our
understanding is that the protection challenges in the transmission system may be more difficult than those in
the distribution system.
Hawaiian Electric Response –– The protection challenges on transmission and distribution can be different, but
it’s uncertain which one would be more difficult. For instance, one significant impact of IBR generation is that it
generally decreases the critical clearing times for faults at all voltage levels. That is, faults must be cleared faster
everywhere. Speeding up protection system operation on transmission may, or may not, be more difficult than
speeding it up on distribution. However, we agree that separating the two can help illustrate the differences and
similarities between the two.
Figure 8-2 - Is “High Adoption” in Fig 6-9 is the same as Faster Tech in Fig 8-2. If so, please use a consistent name
for the scenario.
Hawaiian Electric Response –– Legends for Figures 6-8 and 6-9 updated to Faster Tech
Figure 8-3: We understand that DER+DBESS is from the forecast and not selected by RESOLVE, whereas. DER
aggregate is selected by RESOLVE. Please clarify this for readers.
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Hawaiian Electric Response –– This is added into the latest version of report main body, Section 8.2.1.
8.1.4.3 - Was this done before the state announced its new decarbonization/electrification goals? If so, will it be
repeated? With the state's new electrification goals, it is possible Hawaii will see very fast uptake of EVs on
some circuits, which might outpace the ability to upgrade circuits. (We understand that California has recently
become concerned about the high levels of time, resources, and materials like transformers that may be needed
to prepare distribution circuits for EV-related load growth from now to 2030.)
Hawaiian Electric Response – The High Electricity Demand (“High Load”) and Faster Technology Adoption
scenarios used the High EV forecast which is based on 100% EVs by 2045.
8.1.6 - How will you learn how customer-scale inverters perform on timescales relevant to protection? Are you
planning to collect point-on-wave current data on distribution circuits?
Hawaiian Electric Response - We will rely on industry experience with customer technologies to validate their
specific system impacts, including on protection performance. This industry experience can possibly include
research projects done in the field on actual customer equipment connected to utility systems.
8.2.1 (and other capacity expansion subsections) - Please explain for readers why different forms of firm RE are
presented and modeled separately (e.g. biomass, “new firm RE”, geothermal, etc). Similarly, clarify what is
meant by the “new firm RE” category that apparently does not include biomass or other resources that one
would assume are firm RE. If the definition of “firm RE” is different from in the RFP, please clarify; if not, please
refer readers to the RFP.
Hawaiian Electric Response –Biomass, CT, CC, and Geothermal were modeled separately because they had
different capital and operational costs based on the NREL ATB Data, as shown in Section 6.9 of the Draft IGP
report. CT and CC are firm resources on biodiesel.
8.2.1.1 - Thank you for including this additional scenario at the TAP’s request.
Figure 8-4: Should the LC_70pctRPS case be showing new firm RE in 2030?
Hawaiian Electric Response –– Clarification was made to report. Cumulative New Capacity charts only show the
new capacity that was selected by RESOLVE and does not include Stage 3 Firm resources.
Figure 8-5: In the LC_70pctRPS case, why is there "existing firm RE" in 2030 but it disappears in later years?
Hawaiian Electric Response– There is some biofuel generation to meet the 70% RPS target in 2030. In later years,
with the addition of other renewable resources such as the offshore wind and DER Aggregate PV+BESS, this
biofuel generation from existing resources is not needed.
8.2.1.2 - First word on page 117 should be “practical”.
Hawaiian Electric Response – This is corrected in the latest version of report main body.
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Figure 8-7: Why is 2030 HighFuel RetOpt only at 81% in 2030? Does it have to do with how Biomass is counted?
Hawaiian Electric Response– This is corrected in the latest version of report in Figure 8-7.
Table 8-4:
● Showing lots of zeros seems to indicate overbuilding. Maybe also the units and number of decimal
points should be adjusted?
● EUE (%) is usually shown in PPM instead.
8.2.2 - Regarding the statement “Approximately 200 MW of new firm generation is needed, in addition to the
500 MW of firm generation from Stage 3, to bring the system loss of load expectation below 0.1 day per year.”
It’s not clear that the numbers show this need since the LOLE goes all the way to 0.00.
In general, the system appears very reliable in most cases, with LOLE <<0.1; this should be noted somewhere.
We realize this may be due to the lumpiness of the units (e.g. it’s either well above 0.1 or well below when you
add realistic resource increments), but might be worth clarifying why the system may seem overbuilt from a
reliability perspective.
Hawaiian Electric Response – Results in Section 12.3.1.2 Firm Generation Reliability Impacts shows the
relationship between LOLE and new firm generation added after Stage 3. As shown, small changes in firm
capacity can result in large changes in LOLE. In the Probabilistic Resource Adequacy Summary, it is noted that in
2030 and 2035, both the Base and Land-Constrained plans developed by RESOLVE should meet our reliability
targets.
Figure 8-10 - The color for Standalone BESS Generation in this plot is better than the color used in previous and
subsequent plots, which are hard to read.
Hawaiian Electric Response– Standalone BESS data in graphs has been changed to a dark green.
Figure 8-13: In section 8.2.1.1, there was no "New firm fossil" plant built. But here we see a "new firm fossil"
plant operating during most hours. Where did it come from? If a new fossil fuel plant is to be built, that merits
more explanation. (Is this a mistake?)
Hawaiian Electric Response– Figure 8-13 has been corrected. It should have been New Firm RE, now labeled as
New Biofuels.
Figure 8-14: This shows total starts per year, but it would be more intuitive to show the average number of
starts per unit for groupings with more than one unit
Hawaiian Electric Response- Figures were updated to show average starts by unit grouping.
● We don't see a “high electricity demand” scenario in the capacity planning section. Where are the
details on this scenario, and where did the dispatches come from?
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Hawaiian Electric Response– The high load forecasts were modeled in RESOLVE to determine if the bookends of
the load forecast built the same resources or if a dramatically different resource mix was required. Based on the
results of the load bookend modeling, the same resources were largely being built that scaled with the load i.e.
more of the same resources were built in the high load bookend compared to the base and low load bookend.
● We don't actually see a system security study for the high load scenario described anywhere in this
section. How was the high load scenario from Appendix D used?
Hawaiian Electric Response– The high load scenario was used as a sensitivity and added to Appendix D. The main
body of the report focused on the base scenario.
● HECO noted that transmission expansion is not anticipated on Oahu until 2040 with the REZ. The
description of planned transmission build-out appears to utilize several double-circuit lines. Are the
double circuit lines considered a single N-1 event for planning (shared structure) or are these being
contemplated as a separate outages? This comment also applies to Maui in the 2035 scenario and later
scenarios.
According to current Oʻahu transmission planning criteria, transmission element thermal loading continuous
rating is used as loading limit for an outage of double circuit lines on the same steel pole; according to current
Maui and Hawaiʻi Island transmission planning criteria, transmission element thermal loading emergency rating
is used as loading limit for an outage of double circuit lines on the same steel pole.
8.2.4.1 - Hard to understand what “REZ Enablement cost estimate” is exactly in these tables. We assume “cost
per MW” is the transmission project cost per MW of renewable generation. Is the REZ enablement ($MM) the
millions of dollars of renewable generators or the cost of the transmission?
Hawaiian Electric Response - The REZ enablement cost is explained in section 6.9.4.
Table 8-8: Clarify why the grid needs are so high in the “Low Load” scenario (higher than in the base scenario),
especially since previous discussion said that the timing of the increased demand driven needs didn’t overlap
with the timing of the DER/PV driven needs.
Hawaiian Electric Response – The Low Load scenario has high DER forecasts which results in more hosting
capacity grid needs compared to the Base or High Load scenarios. Also the load-driven grid needs are primarily
driven by customer service requests which are the same for all forecast scenarios.
Table 8-10 is titled “High Load Customer Technology Adoption Bookend Scenario” which we think is the same as
table 6-16’s “High Electricity Demand” and Table 8-8’s “Scenario 2 (High Load)”. Can you make it all one
consistent name?
Hawaiian Electric Response – Confirming High Load Customer Technology Adoption Bookend Scenario (High
Load) is the same scenario as the High Electricity Demand scenario (Table 6-16). Similarly, Low Load Customer
Technology Adoption Bookend Scenario (Low Load) is the same scenario as the Low Electricity Demand scenario
(Table 6-16).
Figure 8-27:
● Y-axis label is wrong.
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● How can there be GWh produced by New Firm RE in all scenarios when New Firm RE is only built in the
High Load scenario (per figure directly above)?
Hawaiian Electric Response – Y-axis was corrected. Clarification was made to report. New Firm RE in the annual
generation charts include firm resources from the Stage 3 RFP.
Figure 8-29:
● Y-axis label is wrong.
● How can there be GWh produced by New Firm RE in the Base scenario when New Firm RE is not built in
the Base scenario (per figure directly above)?
Hawaiian Electric Response – Y-axis was corrected. Clarification was made to report. New Firm RE in the annual
generation charts include firm resources from the Stage 3 RFP.
8.2.6 - Storage was increased to 4 hours to reflect market conditions. While this is reasonable, indicating how
that impacts results would be helpful. Presumably has an impact on both LOLE studies and the cost of storage
for the overall portfolio? Would that change the resources selected in RESOLVE?
Hawaiian Electric Response – Longer duration batteries will increase cost but should also improve reliability as
more energy can be stored and shifted to meet demand. We don’t believe constraining RESOLVE to 4-hr storage
would have a significant impact on the optimization.
Page 153: In this screenshot, are both bullets needed, or does one suffice?
Hawaiian Electric Response – Both bullets are needed because they outline two paths to bring the system below
the reliability threshold. One path using only variable resources and one path using only firm resources.
Figure 8-33: Looks like the New Firm RE is turning on every morning for one hour and producing very little
energy. Just a few more MWh of BESS could avoid this (at least for these three typical days).
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Hawaiian Electric Response – As we move through the planning horizon, the morning peak becomes more
pronounced and difficult to serve (see RA heatmaps in Section 12) as additional DER is added to the system.
Assuming sufficient energy generation is available, longer duration storage may be able to solve for these
morning peak periods. We must also continue to monitor the performance of these new resources (i.e., hybrid
solar plants) to ensure that reliability will not be compromised in the long-term.
8.4.3.3 - “Newer internal combustion units” are mentioned here. What is the expected fuel for these units? (It
appears there may be an expectation that biofuel may be the primary near-term source of new firm RE, but that
is never really stated clearly. Can you clarify the expectation? And is the expected biofuel biodiesel? What were
the costs of the new firm RE based on in RESOLVE?)Figure 8-35: The high capacity factor of the new units is
surprising, especially compared to the PLEXOS results.
Hawaiian Electric Response – New internal combustion units are expected to burn biodiesel. Their capacity
factors in the mid 20%, higher than what might be expected for standby capacity, are due to the deactivation of
a significant amount of thermal capacity at Maalaea (~90 MW).
8.4.6 -
● You state that you “modified Stage 3 firm renewable proxy”. Was this an increase or decrease? If it’s an
increase, please include more details on the justification for the increase (which may be somewhere in
the report, in which case you could refer to that section and perhaps summarize here).
● Please add a reference or explanation for the grid-forming headroom constraint.
● Shouldn’t the “60% grid-forming headroom capacity for dynamic stability” be listed in the tables in 8.3.4,
as was done for Oahu and Hawaii?
Hawaiian Electric Response – The Stage 3 firm renewable proxy was reduced from five 8.14 MW units to two
8.14 MW units. This clarification was added to the report. The grid-forming headroom requirements are
listed for 2032 scenario but not 2050 scenario, since dynamic stability study is not performed for the 2050
scenario due to high uncertainty in the later years of the planning horizon.
1.2.5 Section 9 - Customer impacts
General comments
● It would be helpful to add the ECRC and PPA information to the capital expenditure tables to provide
total revenue requirements. This information is shown in the segmented bar charts but not provided in
tabular format.
● NPV and revenue requirements do not show enough uncertainty or sensitivity analysis. Showing the
revenue requirements across a range of oil prices and different resource costs would be helpful (but
would not require rerunning of models).
● There is no discussion on the assumed oil price and its effect on NPV. A section that shows sensitivity
analysis of low/high oil prices would be helpful to show the benefit of reduced oil price volatility on
rates relative to the Status Quo.
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● When reporting nominal dollars it is tough to understand whether revenue requirements and customer
bills are increasing, decreasing, or staying flat over time. Can you share these figures in real $ to make
those changes clear? Is the increase over time due to normal inflation assumptions, oil price increases,
or costs of new resources and transmission?
Hawaiian Electric Response – As shown in Section 9, the ECRC component of rates, which ties to fuel cost, is
expected to decline as new renewables are brought onto the system. This decreases the Company's exposure to
fuel price volatility and helps to stabilize bills as the new renewable resources are contracted at fixed annual
costs. This is shown in the figures showing divergence in electric rates between the Preferred Plan and Status
Quo.
9.1.3 - The RBA category is hard to understand, and is a significant component, especially in the Base case. Can
you explain more?
Hawaiian Electric Response – RBA is the revenue balancing account that continues the decoupling mechanism
under the Performance Based Regulation Framework. This mechanism allows the Company to recover target test
year revenues from customers, independent of the level of sales.
Figure 9-1: Does Status Quo assume simple swap-out of fuel--biomass instead of fuel oil? Are those cost
assumptions clearly laid out somewhere?
Hawaiian Electric Response – The Status Quo assumes conversion to biodiesel in 2045, which is shown in the
Status Quo resource plan in Appendix C.
9.2.3 - Could use more explanation/clarification. Won’t bills go up because of increased kWh demand with
electrification? You may want to prepare the public and therefore say clearly that people will be paying more to
HECO but paying less to the gas station so it will even out (or maybe be less in the long run).
Hawaiian Electric Response – While utility revenue requirements are estimated to increase steadily over time, its
effect on rates and bills is mitigated by a combination of higher sales with peaks reduced by managed charging
and TOU rates as well as the availability of low-cost variable renewables and storage that provide most of the
capacity and energy (comparing figures 9-1 to 9-2). EV adoption is also expected to avoid significant amounts of
fuel (figure 9-28) which may help customer’s save on their total energy bill (i.e., higher electric bill due to EV
charging is expected to be greater than a customer’s electric + gas bill on a combustion engine vehicle).
9.5.2 - Emissions reductions from transportation (Section 9.5.2) should be added to the emissions reductions
from the power sector to show the total emissions reductions for the state. This is important information.
Somehow add this to Figure 9-27 or alternative.
Hawaiian Electric Response – We have supplemented Section 9.5.2 in response to this comment to show
emissions reductions from the IGP Preferred Plans relative to total emissions for the State.
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1.2.6 Section 11 - Growing the energy marketplace
How will energy efficiency be incentivized (both by the utility and at the state and local level)?
Hawaiian Electric Response – A third party administrator, Hawaii Energy, administers the energy efficiency
programs. We do provide our system cost information based on the modeling outputs to assist in their program
design. As noted in our action plan we also intend to seek additional energy efficiency through our grid service
procurements.
Figure 11-3 appears to be missing new capacity for the DER freeze scenario. That case should have more hybrid
solar resources.
Hawaiian Electric Response – Figure 11-3 has been corrected.
Figure 11-4 should show the delta NPV relative to the base case so readers can compute how much DER saves
the system, or how much electric vehicles add. Also, the DER freeze scenario does not consider the avoided
distribution system upgrades, correct?
Hawaiian Electric Response – The difference in NPV is provided in Table 11-1. The difference in NPV is based on
the results from RESOLVE and do not include distribution system costs.
11.1.3: EE Various terms are used without a definition/explanation (or maybe we missed it). For example “the A
grouping”, “Other” measures. Can you clarify?
Hawaiian Electric Response – Appendix B provides additional background on the EE bundles. Two key
characteristics were used to categorize the energy efficiency measures into separate bundles: load shape and
cost effectiveness. For load shape, measures were grouped between evening “peak” focused measures vs. flatter,
“other” measures. For cost effectiveness, measures were grouped by their B/C ratio determined in the Market
Potential Study where A is >1.2, B is 1.0-1.2, C is 0.8-1.0, and D is < 0.8.
Some past DER programs have not achieved goals. For example, the Smart Export tariff made export
uneconomical compared to serving local loads and resulted in very little export. How will near-future tariffs be
designed to achieve their goals more effectively?
Hawaiian Electric Response – We are currently working with the DER industry and the Commission in the DER
docket to develop new DER programs based on the modeling completed in the IGP report.
1.2.7 Section 12 - Securing Generation Reliability and Assessing Risk
General comments:
● Overall the probabilistic analysis provided in Section 12 is a big improvement to the IGP and a place
where TAP feedback was directly integrated into the IGP process.
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● The section on retirement planning, schedules, and risks is a helpful discussion. Given the aging
generator fleet on HECO’s system, the retirement plan is equally important – if not more important –
than the analysis on new resources.
○ The discussion on unit age is important. It may be useful to HECO to show the average age of
the North American natural gas fleet for comparison to show that HECO’s resources are
significantly older than typical utilities across the country.
● Many of the results provided in this section appear for the first time and are based on previous TAP
feedback. This is the first opportunity the TAP has had to review those results. Similar results were
presented to the TAP in the past, so the overall methods make sense and are consistent with previous
discussions. However, some of the specific results would likely have benefited from discussion if time
had allowed, as discussed in more detail below.
● The first two sections of this chapter present really good information/context. Maybe those subsections
and the preferred plan adjustments for each island (based on the RA analysis) could be incorporated
into Chapter 8, and the details could be retained in an appendix?
Comments on Methodology / Assumptions:
● 250 samples is likely not enough for resource adequacy (RA) results to converge. In future RA analyses,
we recommend at least 500, potentially more if evaluating relatively small changes in the resource mix
or load.
Hawaiian Electric Response: On April 28, 2022, we presented some results from our resource adequacy
analysis that was done for the Oahu Stage 3 RFP. In that presentation, we showed that 250 samples
showed a good balance between computation time and convergence of the resource adequacy results.
That presentation is available on our website located here at
https://www.hawaiianelectric.com/documents/clean_energy_hawaii/integrated_grid_planning/stakeho
lder_engagement/technical_advisory_panel/20220428_tap_presentation_materials.pdf
● The probabilistic resource adequacy analysis requires more weather data. In the HNEI analysis, we
developed a 22-year solar dataset (while using fewer wind years). This was done at the expense of
breaking correlation with solar, but given that the portfolios are so solar-centric, it is important to have
many years of solar data.
● Can HECO provide more information on how storage is optimized? What model look-ahead was used?
Was grid charging allowed for paired resources? How were end effects modeled for battery resources?
Hawaiian Electric Response: In PLEXOS, the optimization is done over a day with a day look-ahead. The
Stage 2 paired storage was allowed to charge from the grid after 5-years. Stage 1 was not allowed to
charge from the grid due to the RFP terms. Future paired storage was not allowed to charge from the
grid.
● Sensitivities on outage rates would be useful to show how important that assumption is and why
thermal generator replacements may be useful/necessary.
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Response: In the Oahu Near-Term Grid Needs Assessment - July 2022 (hawaiianelectric.com), a resource
adequacy analysis was performed looking at the sensitivity of outage rates on LOLE. In that analysis, we
showed how our outage rates have trended higher over the past ten years, and that the recent outage
rates have led to higher LOLE.
Comments on Results:
● The LOLE vs. Capacity charts provide useful information and a good way to summarize results, but there
are a few recommendations to improve:
○ Try using a log-axis. The important region of the curve is between 0 and 0.5 days/year, so
making sure that range is readable is necessary.
Hawaiian Electric Response – A version of these graphs with a log-axis is located in Appendix C.
We felt it was important to emphasize how adding resources can have different reliability
impacts depending on the resource capacity currently in the system.
○ You can add curves from firm capacity and paired solar additions on the same chart, so readers
can directly compare the LOLE vs. capacity relationship between the two resource types.
○ Using this information, you can calculate Marginal Reliability Improvement (MRI) as the change
in LOLE relative to the change in capacity, which can be used as a proxy for capacity value.
○ Overall these curves and the report discussion overemphasize the diminishing returns of
resource additions to reduce LOLE. As the system gets more reliable, there are fewer loss of load
events, so new resources are inherently less effective at reducing risk. It is true that there is
saturation of the resources though.
Hawaiian Electric Response – While there may be fewer loss of load events as resources are
added, it’s not inherent that new resources should be less effective at reducing risk. Resource
availability during a loss of load event also plays a part as does resource saturation of a
particular resource type. If a resource could be perfectly available during loss of load events, its
effectiveness shouldn’t be diminished even though there may be fewer events as the portfolio
changes.
● The starting point of the probabilistic resource adequacy analysis is important. In each section, it would
be useful to have a footnote annotating which resources are included and which ones are assumed
retired for each curve.
○ At one point in the report it said that without any new firm resource, 1600 MW of paired solar
would be required to meet the LOLE target, but it was unclear what that assumed for generator
retirements (without retirements, there would be no need for new resources after Stage 1 and 2
are complete)
Hawaiian Electric Response: A table has been added to the beginning of each island’s section in
Chapter 12 to summarize the various resource adequacy scenarios that were run, along with the
capacity of existing and future firm and variable resources in each scenario and the resulting
LOLE.
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○ Overall the analysis that shows what retirements can be accommodated with a given renewable
and storage build is very useful. We recommend doing this analysis with and without new firm
resource replacements before additional firm resources are built (though not necessarily before
this report is finalized). This analysis can be shared with the TAP and stakeholders when
available (e.g., after Stage 3 RFP results are available), and can be included in applications for
approval for firm resources.
Hawaiian Electric Response: Agree that the procurement process for Stage 3 must be completed
and some of the current uncertainties can be resolved as plans are updated from the results of
the Stage 3 RFP. We look forward to further discussions with the TAP on this topic.
● One section of the report stated that uncertainty in demand is the largest risk. While the load level is
important, the forced outage rate assumptions for generators is also one of the largest, if not the
largest, drivers of system risk.
● In the Hawaii Island probabilistic RA analysis, it is unclear how Puna Geothermal is being modeled. Is it
assumed to be a baseload resource? Historical operations show that it is not always available and the
results show that during periods where the unit is unavailable (due to maintenance) the LOLE is much
higher. Modeling Puna’s availability is therefore critical.
Hawaiian Electric Response – In the probabilistic resource adequacy analysis, PGV is modeled similar to
other thermal generators with a forced outage rate. However, this outage rate does not take into
account its extended outage and derate due to the lava flow event in 2018. The Company is looking to
revise its assumptions for PGV to account for this in the probabilistic resource adequacy analysis going
forward.
● Molokai results seem problematic. On the days with LOLE there are no existing firm resources. In reality
the plant has several diesel units, so how/why were all units on outage simultaneously?
Hawaiian Electric Response – For the resource adequacy analysis, if we assumed the current generating
fleet, then the LOLE would be zero and we wouldn’t be able to develop a relationship between LOLE and
hybrid solar. As a result, the assumption was that there are only two 2.2 MW existing firm generators on
the system. This is shown in the summary table presented at the beginning of the Molokaʻi resource
adequacy section. For the days shown, the two units are on outage resulting in the unserved energy.
1.2.8 Appendix B
Figure B-1: What year is this showing?
Hawaiian Electric Response – 2030. Updated figure notation with footnote
Table B-2: Generally, do recent policy changes (e.g. IRA) impact which load and DER forecasts you see as most
realistic?
Hawaiian Electric Response – Incentives established by the Inflation Reduction Act could result in changes to the
assumptions used in the IGP Base case and less so in the Bookend scenarios. As industry, government, and
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consumers begin to familiarize with the Inflation Reduction Act, the magnitude of impacts on clean technology
adoption are early to speculate. In the event of revisiting the Base case, additional factors, such as continued
high inflation costs and ongoing supply chain issues, would need to be re-evaluated. For example, the
combination of high costs and the extension of tax incentives may incentivize customers to delay near term
adoption of certain clean energy technologies for more favorable economic conditions. Uncertainties remain to
what extent industry and government agencies can qualify and maximize the incentives put forth in the Inflation
Reduction Act. Additionally, the current IGP Bookend scenarios encapsulate a wide range of possible outcomes,
including those that may come to fruition after the enactment of the Inflation Reduction Act. For example, the
current Low Bookend scenario included a ten-year extension of federal tax credits, lower assumed costs of
distributed PV and battery systems, and inclusion of upfront battery storage incentives, while the High Bookend
scenario included 100% EV adoption.
1.2 - Why were buildings over 6 stories excluded from DER forecasts?
Hawaiian Electric Response – With stakeholder input, buildings over 6 stories were excluded due to consideration
of likely available roof space compared to the building’s load. From a practical perspective, customers with low
energy offset compared to overall consumption are less likely to make an investment in rooftop PV.
1.5 - This section is missing a summary of the projected number of EVs and projected annual EV load (by
projection year).
Hawaiian Electric Response – Added summary table in Section 1.5
Figure B-8 - What year and island are these EV charging profiles for?
Hawaiian Electric Response – Updated figure notation with footnote
1.2.9 Appendix D - System Security
2-1
● The main report body seemed to say that in the land-constrained scenario, grid-scale PV/wind is
replaced by firm renewables. Here you seem to have made a different assumption that it’s replaced by
DERs. Why?
● No information on the high load scenario portion of the security study seems to appear in the main
report. Did we miss it? (Same question applies to all islands.)
Hawaiian Electric Response – Language in the report has been revised. In the land-constrained scenario,
the grid-scale PV/wind resources are replaced by the combinations of firm renewables and DERs from
distribution side.
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As mentioned previously, the TAP is pleased to see quantitative planning metrics for grid forming headroom
developed. This is a leading practice. EIRGRID DS3 also has a similar service. However, it is likely that general
readers who are knowledgeable about GFM but not aware of Hawaii’s specific issues will not understand why
the metric is a function of DER power, so some explanation would be helpful. See next comment.
Some discussion on what aspects of grid-forming capability HECO needs would be helpful. This could be placed
in Appendix D, with a brief mention/reference in section 8. This could refer to other documents (RFPs for
example) if useful. The TAP understands after some discussion that the most critical aspect that is driving the
GFM headroom planning metric is the need to fast active power injection after a fault, but that is not clear to
those outside the TAP. In addition, probably other aspects of grid-forming will also be needed - for example
stabilization of the grid by providing a voltage source for grid-following IBRs to synchronize to (i.e. system
strength), as well as fault current. A TAP member provided the following slide that might be useful:
Hawaiian Electric Response – more discussion regarding our GFM needs are added into the latest version of
report main body section 8.1.3.
Page 25: First bullet deserves more explanation because it’s so important – what triggers the momentary
cessation? Do both the legacy DERs and the new DERs suffer from this? Give stakeholders a rough idea what the
issue is here.
Hawaiian Electric Response – Added the following text to Appendix D, Section 3.1.3: DER momentary cessation
poses high risk to system stability. Daytime peak load high DER generation with low wind generation dispatch
currently poses the highest risk on system stability. During the daytime, generation from customer-scale inverter-
based DER may makeup the highest proportion of generation, and in the future, this could be also true during the
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evening. When there is a three-phase to ground fault that happens at the transmission system, before the fault
get cleared, the voltage across the entire system can be very low (e.g., everywhere less than 0.2 pu) during the
fault. This magnitude of voltage sag can cause DER to enter into momentary cessation mode (or trip offline).
After the fault being cleared, which normally takes no more than 5 cycles after fault inception, system voltage
would recover within continous operation range, which means most of system demand would also recover.
However, depending on the inverter model, DER generation may not recover to pre-event level as fast as the
system demand once it enters into momentary cessation mode. This slow DER generation recovery would take
dozens of cycles, which would cause huge system wide generation load imbalance. Since system physical inertia
is already low, the huge generation load imbalance can potentially cause very fast frequency decline, generation
and load tripping, and even system blackout if frequency is not regulated back to acceptable range within a time
limit. From a recent system event, DER momentary cessation is observed from distribution substation power
quality meter fast recording data. The voltage sag caused by a fault is one of common causes for DER entering
into momentary cessation mode. The momentary cessation exists in both legacy DER inverters and the latest
inverters. More importantly, according to the IEEE 1547-2018 and Hawaii Rule14h Source Requirement
Document, DER momentary cessation is allowed when system voltage below a certain threshold. Currently,
according to the Rule 14h, this low voltage threshold for all the new inverters is no higher than 0.5 pu. For grid-
scale inverters, we have been not allowing DER momentary cessation from RFP Stage 1 procurement. Currently,
we are working with NREL, doing more inverter testings to better understanding inverter momentary cessation,
and preliminary results indicate certain inverters do indeed enter momentary cessation or trip at low voltage
levels (e.g., under 0.5 p.u.).
General comment: Can you identify what services existing IBRs provide to the network and how they are
modeled in this study? This is important to understand the context within which GFM conclusions are obtained.
For example: do existing IBRs provide voltage control as per FERC Order 828 (or similar)? Does existing IBR
provide frequency control as per FERC Order 842 (or similar)? If these are provided, are they at plant level or
inverter level? What is the closed loop response time for these services?
Hawaiian Electric Response - Existing IBRs provide reactive power and voltage control grid services per our PPAs.
Existing paired IBR provides primary frequency response as well. For exisitng standalone PVs, they only provide
primary frequency response when overfrequency occurs. They are plant level control. All those existing grid-scale
GFL IBRs have simliar issue as DER Momentary cessation, or not being able to provide stable response during
system event – we have seen actual events with some of our existing plants to this effect, which we are working
to remedy. That is one reason why we are requiring GFM for all paired resources.
The TAP agrees that grid-forming inverter capability is a key piece of maintaining system stability. The most
severe contingencies in the near/medium term involve a loss of GFM inverter / separation from the grid. Is
HECO exploring the ability to acquire GFM-like capability from some new DERs in order to diversify the resources
providing the stabilizing response?
Hawaiian Electric Response – This has come up as a research topic. This is something that may be required in the
future; however, there currently are no industry-wide accepted capability or function requirements of DER GFM,
or commercially available products that can provide this capability.
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The report notes that GFM inverters have not been deployed in HECO territory yet (though they have been
deployed in Kauai) and that validation will be a part of the tasks to ensure the performance predicted in the
models is exhibited in the field. The TAP agrees validation of models is important. Can HECO speak to the
validation plan to ensure close alignment between the inverter models and the hardware?
Hawaiian Electric Response – We will closly monitoring generation plants operational performance, especially
during system events. By replicating system event in planning simulation software, and comparing simulation
results, both in PSSE and PSCAD, with plant digital fault recorder recordings, Hawaiian Electric will validate IBR
models, and ensure alignment between the models and the plant. This is listed as one of the tasks in our action
plan.
Can HECO describe the procedure for updating IBR firmware (i.e., what modeling, stability scenario reruns, and
validation steps may need to be re-performed)?
Hawaiian Electric Response – depending on the contents of update, Company may require IRS restudy regarding
updating IBR inverter firmware.
Section 3:
● Can you add a note on how you verified the accuracy/sufficiency of simulation models across both
simulation domains (PSSE and PSCAD)?
Hawaiian Electric Response - So far, Company only requires overlapped simulation plots from PSSE
simulations and PSCAD simulations during generation facility technical model review. When using
historical system events to validate models, both PSSE and PSCAD simulations are performed. The PSSE
simulation results are compared with DFR slow speed data, and the PSCAD simulation results are
compared with fault recorder high speed data.
● Can you comment on whether the PSCAD studies faced any challenges?
Hawaiian Electric Response - Main PSCAD study challenges are: 1) EMT study, including usage of EMT
software (such as PSCAD/EMTDC), preparing EMT models, and processing simulation results, for an
entire system at this scale is novel for the industry and the Companyʻs planners. It takes lots of training
and preparation to setup an EMT planning study process and be familiar with EMT study; 2)simulation is
very time consuming. To run one contingency for 30 seconds takes 6-20 hours depends on system
complexity, simulation and plot time steps, and workstation computation capability; 3) Interpretation of
EMT study results is also much more time consuming than traditional postive sequence simulations.
Need familiar with OEM EMT models which are normally black-box style, with limited information and
support.
● Can you describe what challenges were identified in PSS/E to model GFM?
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Hawaiian Electric Response – Hawaiian Electric relies on plant developer or OEM to provide models, but
not create models for IBR in-house. So far, Hawaiian Electric received very few PSSE GFM models that
pass model review process.
● Please add a note regarding how dynamics of load have been represented and what are the limitations
associated with that representation, if any?
Hawaiian Electric Response – a short discussion regarding load modeling is added into the end of section
3.3 of Appendix D.
● Can you add a note regarding how model accuracy/sufficiency of existing IBR and DER resources was
verified?
Hawaiian Electric Response – currently, this is performed by replicating a historical system event in
planning model-based simulations and comparing results from the simulations with fault recorder data
from the simulated events. We have observed a gap between existing IBR models performance and
performance of IBR in field during system disturbance recorded by fault recorders.
Page 66: Regarding the statement “According to the past studies, maintaining available contingency reserve in
the form of MW headroom (i.e. contract MW capacity minus dispatched MW generation) on GFM resources is
critical for maintaining system stability and avoiding excessive UFLS.” - A TAP member asks: What would happen
if this MW headroom is offered by existing GFL resources?
Hawaiian Electric Response - Existing GFL resouces have struggled to maintain their generation during system
disturbances, according to fault recording from historical system events. So, it is not reliable to expect GFL IBR to
provide system surport during system event such as a three-phase to ground fault. This is the most important
reason to ensure sufficient GFM IBR is part of the system. In certain renegotiation of PPAs we have asked for GFL
inverters be retrofitted to GFM control.
Figure 27: Plot of frequency (yellow curve in first figure) seems to continue to have a decreasing trend even at t
= 25.0s. However, all other plots seem to have achieved steady state. This may need more explanation. Why do
none of the resources appear to be responding to the falling frequency?
Hawaiian Electric Response - The GFM resouces “virtual inertia response” faded. And they reached their MW
limits. Though system is stable, addtional MW generation dispatch would be required or more load shedding will
happen. This discussion is added these to section 4.1 dynamic stability study part in the Appendix D.
Figure 28: A TAP member questioned whether additional reactive support could help with the voltage problem.
Hawaiian Electric Response - It is possible. But with better voltage recovery, more MW injection to cover DER
generation momentary cessation will still be required to maintain certain stability margin.
Figure 30: A TAP member asks
● What device causes the delayed voltage recovery?
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● What role do load dynamics play in the voltage recovery?
Hawaiian Electric Response - In this study, the primary reason of delayed voltage recovery come from the
insufficient GFM resource and retirement of synchrnous generation. Since only ZIP load is used, the load
dynamics in this study is limited.
Figure 63: There is a lot of disturbance in voltage and frequency during the fault. Is there any concern regarding
this?
Hawaiian Electric Response – The disturbance during the fault is not a concern, since frequency measurement
could be very inaccurate when voltage is very low during the fault. Voltage and frequency oscillations post-fault
clearing is more significant.
This appendix has various typos. You may want to run it through spelling and grammar checks.
1.2.10 Appendix F
Section 1.3.2.4 contingency plan: This seems to be the biggest risk with NWAs, but we were surprised it wasn’t
mentioned. How do you manage non-performance? What if the customer response is not as great as the NWA
provider estimated?
Hawaiian Electric Response – The Company is equally concerned about the risk of NWA solutions not performing
as the NWA provider estimated. Section 1.3.2.4 includes some contingency plans at different stages of the NWA
procurement process. For example, continuing the wires solution design in parallel with the NWA procurement
steps in case the NWA contract is not approved. However, the absolute latest a decision can be made for a
distribution project intended for deferral is directly after final design is complete and before the scheduling,
permitting, and construction of the project begins.
Also if it is determined that the NWA does not meet its performance requirements, the Company suggests
contingency plans such as developing short lead time mitigation alternatives, smaller wires options, or operating
solutions (such as temporary switching). However, if these alternatives are not available, then the Company may
be left without sufficient distribution capacity to serve the load growth.
The Company currently does not have a solution to deal with non-performing NWAs for all scenarios. Additional
emphasis can be added to the report on the need to specify strict NWA performance requirements as well as
financial penalties for non-compliance in the NWA contract.
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