Hawaiian Electric Company, Inc. INTEGRATED RESOURCE PLAN 2009–2028

Docket No. 2007-0084

September 30, 2008

Hawaiian Electric Company, Inc.

HECO IRP-4 Table of Contents

TABLE OF CONTENTS

Page

EXECUTIVE SUMMARY…………………………………………………………. ES-1

1 INTRODUCTION...... 1-1

1.1 Purpose of IRP...... 1-1

1.2 Commission Ruling on HECO IRP-3 ...... 1-1

1.3 May 2007 Evaluation Report...... 1-1

1.4 Major Changes since HECO IRP-3 ...... 1-4 1.4.1 Global Warming Solutions - Act 234 ...... 1-4 1.4.2 Hawaii Renewable Portfolio Standard ...... 1-4 1.4.3 Hawaii Clean Energy Initiative...... 1-5 1.4.4 Legislation ...... 1-5 1.4.5 Infrastructure Program Docket...... 1-6 1.4.6 Intragovernmental Wheeling Docket ...... 1-6 1.4.7 Public Benefit Fund Docket...... 1-6 1.4.8 Net Energy Metering...... 1-7 1.4.9 Competitive Bidding for New Generation Docket...... 1-8 1.4.10 Solicitation for 100 MW of As-available Renewable Energy ...... 1-10 1.4.11 Campbell Industrial Park Generating Station ...... 1-13 1.4.12 Relating to Renewable Energy Act 207...... 1-13

2 IRP-4 PROCESS OVERVIEW ...... 2-1

2.1 Description of Overall Process ...... 2-1

2.2 Advisory Group Meetings...... 2-2

2.3 Public Information Meetings...... 2-4

2.4 IRP-3 Stipulated Agreement ...... 2-5

3 INITIAL IRP OBJECTIVES AND GOALS...... 3-1

3.1 Renewable Portfolio Standard Percentage...... 3-2

3.2 Gas Emission Reduction...... 3-3

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3.3 Potable Water Consumption Reduction...... 3-3

3.4 Demand-Side Management...... 3-4

3.5 Distributed Generation ...... 3-5

3.6 Generation System Reliability...... 3-6

3.7 Electricity Rates and Bills Impact...... 3-7

4 GLOBAL WARMING ...... 4-1

4.1 Introduction ...... 4-1

4.2 Background on Greenhouse Gas (GHG) and Global Warming...... 4-1 4.2.1 What are GHGs?...... 4-1 4.2.2 How GHG Causes Global Warming ...... 4-2 4.2.3 Sources of GHG in Hawaii ...... 4-2 4.2.4 General Policy Options ...... 4-4

4.3 HECO Policy on Global Warming...... 4-5

4.4 Summary of Potential Federal Legislation...... 4-6 4.4.1 Lieberman-McCain: Climate Stewardship and Innovation Act of 2007 (S.280) ...... 4-6 4.4.2 Needs and Usefulness of a Federal Policy Model...... 4-7 4.4.3 Lieberman-McCain Results Used in IRP-4...... 4-7

4.5 Federal Activities Related to Global Warming/Climate Change ...... 4-8 4.5.1 Climate Change Science Program...... 4-8 4.5.2 Department of Energy...... 4-8 4.5.3 Environmental Protection Agency ...... 4-8

4.6 Global Warming Actions in other Jurisdictions...... 4-9 4.6.1 Carbon Trading Markets ...... 4-9 4.6.2 State and Regional Initiatives...... 4-9

4.7 Hawaii Global Warming Solutions Act (Act 234)...... 4-10

4.8 Global Warming Issues for Hawaii...... 4-11 4.8.1 Establishing a 1990 Carbon Emission Standard...... 4-11

4.8.2 Establishing CO2 Emissions standards - Conceptual Issues...... 4-11 4.8.3 Accounting for Air and Marine Transport ...... 4-12 4.8.4 Waste-to-Energy Projects ...... 4-12 4.8.5 Prior & External Sequestration Programs ...... 4-13

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4.8.6 Emissions from Independent Power Producers...... 4-13 4.8.7 Accounting for Energy Conservation / Efficiency Programs in IRP...... 4-14 4.8.8 Economic Justice and Freedom of Choice ...... 4-14 4.8.9 Transportation Technology and Electrical GHG Emissions ...... 4-15

4.9 Summary of GHG Assumptions Used in HECO IRP-4 Modeling...... 4-16

4.10 How HECO’s Action Plan Proposals Reflect Future GHG Uncertainties ...... 4-18

5 OTHER PLANNING CONSIDERATIONS...... 5-1

5.1 Capacity Planning Criteria...... 5-1

5.2 Operational Requirements of Generation System for Today and Tomorrow ...... 5-1 5.2.1 System Operation Issues ...... 5-2 5.2.1.1 Need to Match Generation and Demand...... 5-2 5.2.1.2 Offsetting Wind Farm Variations ...... 5-4 5.2.1.3 Fault Ride-Through ...... 5-7 5.2.1.4 Resource Planning Implications ...... 5-8

5.3 Minimum Load Constraints and As-available Load Curtailment Issues...... 5-8

5.4 Spinning and Regulating Reserve ...... 5-9

5.5 Renewable Portfolio Standards...... 5-10

5.6 Competitive Bidding for New Generation...... 5-11 5.6.1.1 Ownership of Future Supply-Side Resources...... 5-11

5.7 Transmission System Considerations ...... 5-13 5.7.1.1 Overview of Transmission Considerations...... 5-13 5.7.1.2 HECO System Overview...... 5-13 5.7.1.3 Adequacy of Transmission Capacity ...... 5-15 5.7.1.4 T&D Considerations in Demand-Side Options ...... 5-17 5.7.1.5 Reliability Considerations of the Transmission System ...... 5-17 5.7.1.6 Transmission System Losses ...... 5-18 5.7.1.7 Voltage Support...... 5-18 5.7.1.8 System Stability Considerations...... 5-19

5.8 Distribution System Considerations ...... 5-19 5.8.1.1 Distribution Planning Process...... 5-20 5.8.1.2 Distribution Planning in IRP ...... 5-20 5.8.1.3 Customer-Owned DG/CHP in Distribution Planning in IRP...... 5-21

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6 LONG-TERM PLANNING ASSUMPTIONS AND FORECASTS...... 6-1

6.1 Sales and Peak Forecast...... 6-1 6.1.1 Background and Overview...... 6-1 6.1.2 IRP Advisory Group Load Forecasting Meetings...... 6-1 6.1.3 Forecast Assumptions and Models...... 6-2 6.1.4 Sales and Peak Forecasts...... 6-7 6.1.5 Alternative High- and Low- Load Scenarios ...... 6-11 6.1.6 Forecast Sensitivities...... 6-13 6.1.7 IRP-4 Forecasts Compared to the Forecasts in IRP-3...... 6-14 6.1.8 Summary...... 6-16

6.2 Fuel Price Forecast...... 6-16 6.2.1 Biodiesel ...... 6-17 6.2.2 Low Sulfur Fuel Oil (LSFO)...... 6-24 6.2.3 No. 2 Diesel Oil ...... 6-25 6.2.4 Liquefied Natural Gas (LNG) ...... 6-26 6.2.5 Ethanol...... 6-27

6.3 Financial Assumptions...... 6-27

7 RESOURCE OPTIONS...... 7-1

7.1 Demand-Side Resources...... 7-1 7.1.1 Background and Overview...... 7-1 7.1.2 Program Development Process ...... 7-3 7.1.3 Overview of Results...... 7-8 7.1.4 Summary...... 7-28

7.2 Distributed Generation Resources...... 7-30 7.2.1 Overview...... 7-30 7.2.2 Hawaii Public Utilities Commission DG Proceeding ...... 7-31 7.2.3 Customer-Owned DG/Combined Heat and Power Resources ...... 7-32 7.2.4 Utility Dispatchable DG...... 7-34 7.2.5 Utility-Sited ...... 7-36 7.2.6 Customer-Sited Photovoltaics...... 7-36

7.3 Supply-Side Resources...... 7-38

7.4 Generating Unit Retirement Evaluation ...... 7-42

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8 INTEGRATION ANALYSIS...... 8-1

8.1 Overview and Background ...... 8-1

8.2 Phase One: Development of the High and Low Scenarios ...... 8-2

8.3 Phase Two: Development of the Draft Benchmark Plan ...... 8-4

8.4 Phase Three: Sensitivity Analysis on the Draft Benchmark Plan ...... 8-8

8.5 Phase Four: Development of the Benchmark Plan...... 8-9

8.6 Objectives and Measures ...... 8-13 8.6.1 Renewable Portfolio Standard...... 8-14 8.6.2 Global Warming...... 8-15 8.6.3 Potable Water Consumption ...... 8-16 8.6.4 Demand Side Management ...... 8-16 8.6.5 Utility Dispatchable Distributed Generation / Customer Combined Heat and Power ...... 8-17 8.6.6 Reliability...... 8-18 8.6.7 Customer Impact...... 8-18

8.7 Higher Level of Reliability...... 8-19

8.8 Transmission Analysis ...... 8-22 8.8.1 Transmission Considerations in the IRP-4...... 8-22 8.8.2 East Transmission Project ...... 8-23 8.8.3 AES-CEIP #2 138 kV Transmission Line...... 8-24 8.8.4 -School-Iwilei 46kV Transmission Circuits...... 8-25 8.8.5 Waiau 46kV Bus...... 8-26 8.8.6 Halawa-School, Halawa-Iwilei, Makalapa-Airport Reconductoring ...... 8-27 8.8.7 AES-CEIP #3 Addition...... 8-28

8.9 Fuel Diversity and Generation Efficiency ...... 8-28

8.10 HECO LSFO Fuel Storage ...... 8-31

9 PREFERRED PLAN ...... 9-1

9.1 Preferred Plan ...... 9-1 9.1.1 Preferred Plan Development from the Benchmark Plan ...... 9-2

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9.2 Competitive Bidding Strategy ...... 9-5

9.3 Forthcoming Waiver Request for Renewable Firm Capacity in 2011...... 9-8 9.3.1 Overview...... 9-8 9.3.2 Need for Additional Renewable Firm Capacity Following CIP CT-1 in 2009 ...... 9-10 9.3.3 CIP CT-2 will Support Additional Intermittent and Variable Renewable Energy Generation on HECO’s System...... 9-10 9.3.4 CIP CT-2 will Reduce Fossil Fuel Consumption by Allowing Waiau 3 to be Taken Off-line...... 9-11 9.3.5 CIP CT-2 will Provide Needed Reserve Capacity ...... 9-12 9.3.6 CIP CT-2 is Consistent with HECO’s Portfolio Approach to Resource Planning...... 9-17 9.3.7 A Waiver of Competitive Bidding is Needed to Expeditiously Achieve These Goals ...... 9-17

9.4 Other Potential Waiver Requests...... 9-19 9.4.1 Waiver for Lockheed OTEC...... 9-19 9.4.2 Waiver for Military DG ...... 9-20

9.5 Calculation of Future Avoided Cost ...... 9-20

10 ACTION PLAN ...... 10-1

10.1 Demand-Side...... 10-1 10.1.1 Transition Energy Efficiency DSM Programs to Public Benefit Fund Administrator...... 10-1 10.1.2 Continue RCEA/Energy Awareness...... 10-4 10.1.3 Continue SolarSavers Pilot Program ...... 10-4

10.2 Customer-choice Action Items ...... 10-5 10.2.1 Implement Advanced Meter Infrastructure (AMI) Initiative...... 10-5 10.2.2 Implement Residential Time-of-Use (TOU) (Enabled or Enhanced by AMI) ...... 10-9 10.2.3 Implement Demand Response (Enabled or Enhanced by AMI)...... 10-9 10.2.4 Evaluate Green Pricing Tariff Options ...... 10-11

10.3 Customer-sited Distributed Generation ...... 10-12 10.3.1 Facilitate Photovoltaics...... 10-12 10.3.2 Dispatachable Standby Generation...... 10-12 10.3.3 Monitor CHP ...... 10-12

10.4 Supply-Side ...... 10-13 10.4.1 Install 113 MW CT in 2009...... 10-13 10.4.2 Pursue Projects “Grandfathered” from Competitive Bidding...... 10-15 10.4.3 Continue 100 MW Renewable Energy RFP ...... 10-16 10.4.4 Install 100 MW Firm Renewable Generation in 2011-2012...... 10-17 10.4.5 Determine Whether to Place Waiau 3 in Emergency Reserve or Retire the Unit...... 10-19

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10.4.6 50-125 MW non-firm Emerging Technology (Such as OTEC)...... 10-19 10.4.7 50 MW Firm Capacity Generation in 2014 ...... 10-19 10.4.8 Potential Utility Bid for Military Distributed Generation Projects RFP...... 10-20 10.4.9 50 MW Firm Capacity Generation in 2017 ...... 10-20 10.4.10 Determine Whether to Place Waiau 4 in Emergency Reserve or Retire the Unit...... 10-20 10.4.11 Conduct Biofuel Assessment in 2009 on Kahe 3 Using LSFO/Biofuel Blend...... 10-21 10.4.12 Conduct Biofuel Assessment For Substation DG...... 10-23 10.4.13 Conversion of Existing Generating Units to Biofuel...... 10-24 10.4.14 Explore Additional Utility-sited PV Projects ...... 10-24

10.5 Energy Delivery ...... 10-25 10.5.1 Complete The East Oahu Transmission Project ...... 10-25 10.5.2 Install Interconnection Facility for all Central Station Generating Facilities in the Plan .. 10-26 10.5.3 Investigate Integration of Additional As-Available Resources on Oahu...... 10-26 10.5.4 Honolulu – School, Halawa – Iwilei 46 kV Study...... 10-29 10.5.5 Waiau 46 kV Bus...... 10-29 10.5.6 Halawa – School, Halawa-Iwilei, Makalapa – Airport-Iwilei 138 kV Study ...... 10-30

10.6 Research, Development, and Demonstration ...... 10-30 10.6.1 Investigate Hawaii-based Bioenergy Crop Production...... 10-30 10.6.2 Investigate Plug-in Hybrid Vehicles...... 10-31 10.6.3 Investigate Potential Energy Storage Projects ...... 10-32 10.6.4 Other Miscellaneous R&D Projects...... 10-34

10.7 Other Action Items...... 10-37 10.7.1 Implement Renewable Energy Infrastructure Program ...... 10-37 10.7.2 Participate in Hawaii Clean Energy Initiative ...... 10-37 10.7.3 Delink Schedule Q (Avoided Cost) from Fossil Fuel Price...... 10-37 10.7.4 Explore Decoupling Utility Revenues from Electricity Sales...... 10-38

11 IRP ADVISORY GROUP STATEMENT OF POSITION ...... 11-1

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Docket No. 2007-0084 viii September 2008 HECO IRP-4 Table of Tables

TABLE OF TABLES

Page

Table 1.4-1 HECO Renewable Energy RFP Schedule ...... 1-11

Table 2.2-1 HECO IRP Advisory Group Membership ...... 2-3

Table 3.1-1 Initial RPS IRP Goals ...... 3-2

Table 3.2-1 Initial Greenhouse Gas Emission Reduction Goals ...... 3-3

Table 3.3-1 Initial Potable Water Consumption Reduction IRP Goals...... 3-4

Table 3.4-1 Initial IRP Goals for DSM ...... 3-5

Table 3.5-1 Initial Distributed Generation IRP Goals ...... 3-6

Table 3.6-1 Initial Generation System Reliability Goals ...... 3-7

Table 3.7-1 Initial Electricity Rates and Bills IRP Goals...... 3-8

Table 4.2-1 Preliminary Estimate of GHG Emissions in 1990 and 2005...... 4-3

Table 6.1-1 Long-Term Total Sales Forecast (GWh)...... 6-8

Table 6.1-2 Long-Term Total Peak Forecast (Gross MW)...... 6-10

Table 6.1-3 Average Economic Growth Rates for the Low, Base, and High Scenarios Over 30-Year (2000 – 2030) Forecast ...... 6-13

Table 6.2-1 Outlook Scenario & World Bank Scenario Palm Oil Forecast...... 6-21

Table 6.2-2 Large Scale Biodiesel Production Costs in Asia ...... 6-22

Table 6.3-1 IRP Assumptions...... 6-28

Table 6.3-2 HECO Unit Performance Data ...... 6-29

Table 6.3-3 IPP Firm Capacity Agreement...... 6-29

Table 7.1-1 Energy Efficiency Measures Included in the CIEE Program...... 7-9

Table 7.1-2 Projected Savings Impacts and Expenditures - CIEE Program...... 7-9

Table 7.1-3 Cost Effectiveness Test Results - CIEE Program...... 7-10

Table 7.1-4 Energy Efficiency Measures Included in the CINC Program ...... 7-11

Table 7.1-5 Projected Savings Impacts and Expenditures - CINC Program ...... 7-11

Table 7.1-6 Cost Effectiveness Test Results - CINC Program ...... 7-12

Table 7.1-7 Energy Efficiency Measures Included in the CICR Program ...... 7-12

Table 7.1-8 Projected Savings Impacts and Expenditures - CICR Program ...... 7-13

Table 7.1-9 Cost Effectiveness Test Results - CINC Program ...... 7-13

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Table 7.1-10 Energy Efficiency Measures Included in the ESH Program...... 7-14

Table 7.1-11 Projected Savings Impacts and Expenditures - ESH Program...... 7-15

Table 7.1-12 Cost Effectiveness Test Results - ESH Program...... 7-16

Table 7.1-13 Energy Efficiency Measures Included in the REWH Program ...... 7-16

Table 7.1-14 Projected Savings Impact and Expenditures - REWH Program ...... 7-17

Table 7.1-15 Cost Effectiveness Test Results - REWH Program ...... 7-18

Table 7.1-16 Energy Efficiency Measures Included in the RNC Program ...... 7-18

Table 7.1-17 Bronze Package...... 7-19

Table 7.1-18 Silver Package ...... 7-19

Table 7.1-19 Gold Package...... 7-20

Table 7.1-20 Gold Plus Package...... 7-20

Table 7.1-21 Projected Savings Impacts and Expenditures - RNC Program ...... 7-21

Table 7.1-22 Cost Effectiveness Test Results - RNC Program ...... 7-21

Table 7.1-23 Energy Efficiency Measures Included in the RLI Program...... 7-22

Table 7.1-24 Projected Savings Impacts and Expenditures - RLI Program...... 7-22

Table 7.1-25 Cost Effectiveness Test Results - RLI Program...... 7-22

Table 7.1-26 Projected Savings Impacts and Expenditures - RDLC Program ...... 7-23

Table 7.1-27 Cost Effectiveness Test Results - RDLC Program ...... 7-23

Table 7.1-28 Projected Savings Impacts and Expenditures - CIDLC Program ...... 7-24

Table 7.1-29 Cost Effectiveness Test Results: CIDLC Progam...... 7-25

Table 7.1-30 Aggregate Gross Level Savings and Expenditures ...... 7-28

Table 7.1-31 Cost Effectiveness TRC Test Results...... 7-29

Table 7.1-32 Other Benefit Cost Test Results for All Programs...... 7-30

Table 7.3-1 Conversion HECO's Existing Generation Units to Utilize Biofuels...... 7-39

Table 8.2-1 Scenarios ...... 8-3

Table 8.6-1 Objectives and Measures (2010-2028)...... 8-13

Table 8.6-2 Renewable Portfolio Standard Renewable Electrical Energy Percentage...... 8-14

Table 8.6-3 Renewable Portfolio Standard Total RPS Percentage ...... 8-15

Table 8.6-4 Demand Side Management Cumulative MWh...... 8-17

Table 8.6-5 Demand Side Management Cumulative MW...... 8-17

Docket No. 2007-0084 x September 2008 HECO IRP-4 Table of Tables

Table 8.7-1 Comparison of Proxy CT Timing and Plan Revenue Requirements for Current and Higher Generating System Reliability...... 8-21

Table 8.9-1 Fossil Fuel Generation Efficiency, in Btu/kWh-net, for Benchmark Plan ...... 8-30

Table 10.1-1 Summary of Cumulative Peak Impacts (MW) of All DSM Programs (Not Reduced by Free Riders at the Gross System Level) ...... 10-2

Table 10.1-2 Summary of Cumulative Energy Savings (MWh) of All DSM Programs (Not Reduced by Free Riders at the Gross System Level) ...... 10-2

Table 10.1-3 Summary of Expenditure Schedule for All DSM Programs ($000) ...... 10-3

Table 10.2-1 AMI Program (Current Estimates of Expenditures) ($000) ...... 10-8

Table 10.2-2 AMI Program (Timetable)...... 10-9

Table 10.2-3 Timeline for Implementation...... 10-10

Table 10.2-4 Dynamic Pricing Pilot Program Incremental Budget ($)...... 10-11

Table 10.4-1 Summary of Major Milestones for CIP CT-1 Unit Addition...... 10-14

Table 10.4-2 Estimated Capital Expenditure Schedule for CIP CT-1 Unit Addition and Transmission Line ($000) ...... 10-15

Table 10.4-3 HECO Renewable Energy RFP Schedule ...... 10-17

Table 10.4-4 Summary of Major Milestones for CIP CT-2 Unit...... 10-18

Table 10.4-5 Estimated Capital Expenditure Schedule for CIP2 Unit Addition ($000) ...... 10-18

Table 10.4-6 Summary of Expenditure Schedule ($000) of K3 Biofuel Co-Firing Project ...... 10-23

Table 10.4-7 Summary of Major Milestones K3 Biofuel Co-Firing Project...... 10-23

Table 10.4-8 Summary of Expenditure Schedule ($000) Substation DG Biofuel Co-Firing Project...... 10-24

Table 10.5-1 EOTP Costs as for July 2008 Actuals ($000) ...... 10-25

Table 10.5-2 EOTP Milestones ...... 10-25

Table 10.5-3 Summary of Expenditure Schedule ($000) for Integration of As-Available Resources ...... 10-28

Table 10.5-4 Summary of Major Milestones of Integration of As-Available Resources...... 10-29

Table 10.5-5 Waiau 46kV Milestones...... 10-29

Table 10.6-1 Summary of Expenditure Schedule ($000) Biofuel Crop Research . 10-31

Table 10.6-2 Summary of Major Milestones Biofuel Agriculture Crop Research...... 10-31

Table 10.6-3 Summary of Expenditure Schedule ($000) for PHEV...... 10-32

Table 10.6-4 Summary of Major Milestones for PHEV...... 10-32

Table 10.6-5 Summary of HECO Expenditure Schedule ($000) for Key Energy Storage...... 10-34

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Table 10.6-6 Summary of Major Milestones of Key Energy Storage Projects ...... 10-34

Table 10.6-7 Summary of Expenditure Schedule ($000) of General Renewable Energy Research & Development ...... 10-37

Docket No. 2007-0084 xii September 2008 HECO IRP-4 Table of Figures

TABLE OF FIGURES

Page

Figure ES-1 IRP Preferred Plan for the period 2009-2028 ...... ES-8

Figure 1.3-1 Updated IRP-3 Plan ...... 1-2

Figure 2.1-1 IRP-4 Process Flow Chart ...... 2-2

Figure 6.1-1 Oahu Visitor Arrivals ...... 6-4

Figure 6.1-2 Oahu Non-Agriculture Jobs...... 6-4

Figure 6.1-3 Oahu Real Personal Income (1992 dollars)...... 6-5

Figure 6.1-4 Alternative Sales Scenarios ...... 6-11

Figure 6.1-5 Alternative Peak Demand Scenarios ...... 6-12

Figure 6.1-6 Forecast Sensitivity (For Sample Year 2020) ...... 6-14

Figure 6.1-7 August 2007 Sales Forecast is Lower than the February 2004 Sales Forecast ... 6-15

Figure 6.1-8 August 2007 Peak Demand Forecast is Lower than the February 2004 Peak Demand Forecast ...... 6-16

Figure 6.2-1 Imputed Biodiesel Prices (2007 Prices)...... 6-23

Figure 6.2-2 HECO Low Sulfur Fuel Oil Price Forecast...... 6-24

Figure 6.2-3 HECO Diesel Oil Price Forecast ...... 6-25

Figure 7.1-1 Detailed Approach for IRP-4 Energy Efficiency Study...... 7-4

Figure 8.3-1 Draft Benchmark Plan...... 8-5

Figure 8.5-1 Benchmark Plan (2009-2018) ...... 8-10

Figure 8.6-1 System Carbon Dioxide Emissions...... 8-16

Figure 8.6-2 Methodology Flow Chart ...... 8-18

Figure 8.8-1 Honolulu-School-Iwilei 46kV Transmission Circuits...... 8-26

Figure 9.1-1 Preferred Plan (2009-2028) ...... 9-2

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Docket No. 2007-0084 xiv September 2008 HECO IRP-4 Appendices

APPENDICES APPENDIX A: Glossary APPENDIX B: Acronyms APPENDIX C: A Framework for Integrated Resource Planning (IRP Framework) (D&O No. 11630, Docket No. 6617) APPENDIX D: HECO Compliance with the IRP Framework APPENDIX E: Advisory Group Membership APPENDIX F: Advisory Group Meeting Material APPENDIX G: Statement of Issues From Public Comments Received APPENDIX H: Public Information Meeting Material APPENDIX I: June 3, 2007 Global Warming Advisory Group Meeting Material APPENDIX J: Hawaii Global Warming Solutions Act, Act 234, 2007 Session Laws of Hawaii APPENDIX K: Natural Resources Defense Council Biodiesel Policy APPENDIX L: August 2007 and March 2008 Sales & Peak Forecast APPENDIX M: Fuel Price Forecast APPENDIX N: Energy Efficiency Potential Study, Global Energy Partners APPENDIX O: HECO 2008 Adequacy of Supply Letter APPENDIX P: HECO Capacity Planning Criteria APPENDIX Q: Fuel Diversity and Fossil Fuel Generation Efficiency APPENDIX R: HECO Transmission Planning Criteria APPENDIX S: Integration Analysis APPENDIX T: Description of Strategist

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Docket No. 2007-0084 xvi September 2008 HECO IRP-4 Executive Summary

EXECUTIVE SUMMARY

Hawaiian Electric Company’s Integrated Resource Planning (IRP) process is designed to develop a comprehensive 20-year plan for meeting Oahu’s energy needs, evaluating and integrating both resources that supply electricity and resources that reduce or better manage the demand for electricity. As part of its IRP process, Hawaiian Electric Company, Inc. (Hawaiian Electric) works with a community-based Advisory Group and the public to ensure the delivery of reliable and reasonably-priced electric power for residential and business customers. From March 2007 through September 2008, Hawaiian Electric conducted its fourth IRP process (IRP-4).

The resulting IRP-4 preferred plan represents an aggressive move towards the use of renewable resources and the reduction of fossil fuel use, including major changes to Hawaiian Electric’s infrastructure and policies that will be technically challenging and require significant investment. The successful implementation of the IRP-4 preferred plan will also be dependent on government and public support. This executive summary explains the preferred plan and the complex framework of technology, recent legislation and increasing environmental and consumer impacts in which the IRP-4 preferred plan was developed.

Two Primary Objectives for Hawaiian Electric

As a public utility, Hawaiian Electric is required to serve the public interest. The world is rapidly changing with respect to how it looks to meet its future energy demand, and Hawaii is at the forefront of that effort. Traditional fossil fuel electrical generation must give way to renewable energy and other pathways to control energy use. This is driven by our need to decrease our vulnerability to imported sources of energy, our desire to use clean energy sources, rapidly rising fuel oil prices, and international, national and state-by-state initiatives to reduce greenhouse gas (“GHG”) emissions through the increase use of renewable energy and energy efficiency resources. This is evidenced by the Kyoto Protocol, the National Energy Policy Act of 2005, state and possible federal renewable portfolio standards (“RPS”), state GHG regulations, and other policies and regulations. At the same time, Hawaiian Electric has an obligation to serve its customers. The public expects electrical service consistently and with quality. This is Hawaiian Electric’s traditional core activity and remains as important as ever.

Hawaiian Electric has two main objectives: • transition the system to one that focuses on renewable energy, energy efficiency, and energy conservation, • keep the current system providing reliable power.

Both are critical, both require support, and Hawaiian Electric fully intends to deliver on both.

Docket No. 2007-0084 ES-1 September 2008 HECO IRP-4 Executive Summary

Transitioning Hawaiian Electric’s System for the Future

Hawaiian Electric needs to transition its generation and transmission system to focus on renewable energy, energy efficiency, and energy conservation. The Renewable Portfolio Standard (RPS) law, Global Warming Solutions Act, bioenergy legislation, and Hawaii Clean Energy Initiative all provide policy guidance to Hawaiian Electric in transitioning its system for the future.

Renewable Portfolio Standard

The RPS law (sections 269-91 to 269-95 of the HRS), as amended by Act 162 (2006), provides that each electric utility company that sells electricity for consumption in Hawaii shall establish a renewable portfolio standard of:

(1) 10% of its net electricity sales by December 31, 2010;

(2) 15% of its net electricity sales by December 31, 2015; and

(3) 20% of its net electricity sales by December 31, 2020.

The RPS law defines “renewable portfolio standard” to mean “the percentage of electrical energy sales that is represented by renewable electrical energy.” Renewable electrical energy includes both electrical energy generated using renewable energy (including biofuels) and energy savings brought about by energy efficiency and off-set technologies.

Hawaiian Electric, Hawaii Electric Light Company and Electric Company achieved a consolidated Renewable Portfolio Standard (RPS) of 16.1% in 2007, up from the 13.8% achieved in 2006. Hawaiian Electric’s percentage was 11.0%, compared to 39.8% for Hawaii Electric Light Company and 24.7% for Maui Electric in 2007. The higher percentage in 2007 was primarily the result of the new neighbor island wind farms and additional demand-side management (“DSM”) implemented in 2007 on all islands.

Global Warming

In July 2007, Act 234 of the 2007 Hawaii State Legislature became law requiring a statewide reduction of greenhouse gas (GHG) emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990. It also establishes a task force, comprised of representatives of state government, business (including the electric utilities), the University of Hawaii and environmental groups, charged with preparing a work plan and regulatory approach for “implementing the maximum practically and technically feasible and cost-effective reductions in greenhouse gas emissions from sources or categories of sources of greenhouse gases” to achieve 1990 statewide GHG emission levels. The Director of the Hawaii Department of Health is also required to adopt rules, before December 31, 2011, which establish emission limits for specific sources or categories of sources of emissions and provide for reporting and verification

Docket No. 2007-0084 ES-2 September 2008 HECO IRP-4 Executive Summary

of statewide emissions and monitoring and compliance. The legislation became law in July 2007. (Act 234, signed June 30, 2007, effective July 1, 2007.)

State Bioenergy Policy

In addition to Act 196, 162, and 240 of the 2006 Hawaii State Legislature, the 2007 Hawaii State Legislature added two more bioenergy measures. Act 159 has the stated purpose to encourage further production and use of biofuels in Hawaii, establishes that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts, and establishes a program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels) in Hawaii. (Act 159, signed June 8, 2007; effective July 1, 2007.)

Act 253 requires the Hawaii Department of Business, Economic Development, and Tourism to develop and prepare a bioenergy master plan that sets the course for the coordination and implementation of policies and procedures to develop a bioenergy industry in Hawaii. The primary objective of the bioenergy master plan is to develop a Hawaii renewable biofuels program to manage the State's transition to energy self- sufficiency based in part on biofuels for power generation and transportation. (Act 253, signed June 5, 2007; effective July 1, 2007.)

Hawaiian Electric is aware of the environmental issues arising out of the use of biofuel feedstock, such as palm oil. In conjunction with its commitment to use 100% biodiesel in its combustion turbine that is currently under construction and scheduled to be in service in 2009, Hawaiian Electric and the Natural Resources Defense Council (NRDC) have developed an environmental policy for sourcing biofuel feedstock. Community meetings were held on Oahu, Big Island and Maui in late June and early July of 2007 to discuss the project’s preliminary findings, and receive community feedback on the draft policy. Hawaiian Electric released the final policy on August 21, 2007, which is intended to ensure that Hawaiian Electric, Maui Electric and Hawaii Electric Light Company purchase only biodiesel fuel produced from locally grown sustainable feedstocks and palm oil that complies with international standards established by the Roundtable on Sustainable Palm Oil. The eight components of the policy are: (1) local feedstock support mechanisms, (2) sourcing requirements for palm oil, (3), baseline criteria for all biodiesel feedstocks, (4) chain of custody tracking for feedstocks and oils, (5) global warming pollution accounting and reporting, (6) establishment of a Biofuels Public Trust Fund, (7) public review and notification, and (8) public progress reporting and contingencies. (See Appendix K for the Environmental Policy for Hawaiian Electric Company’s Procurement of Biodiesel from Palm Oil and Locally-Grown Feedstocks.)

The biofuel contract for the 2009 combustion turbine complies with this procurement policy and includes an incentive for locally produced biofuel feedstock.

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Hawaii Clean Energy Initiative

In January 2008, the State of Hawaii and Department of Energy (USDOE) signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). The stated purpose of the HCEI is to establish a long-term partnership designed to transform Hawaii’s energy system to one that uses renewable energy and energy efficient technologies for a significant portion of its energy needs. The partnership aims to put Hawaii on the path to supply 70% of its energy needs using clean energy by 2030. The implementation plan for the HCEI involves the creation of working groups to address, among other things: (1) the use of renewable energy at remote locations not close to existing transmission and distribution infrastructure; (2) transmission and distribution improvements, grid management improvements, and energy storage, to ensure that existing and future infrastructure facilitates optimal use of renewable energy resources and readily incorporates new developments in system planning and transmission technologies while maintaining system reliability; (3) the development of innovative public and private financing vehicles for alternative energy sources and clean technologies at the state and county levels; and (4) design and enactment of comprehensive regulatory mechanisms that provide appropriate incentives for all stakeholders in the chain to proactively transition to a renewable energy- based future.

In April 2008, the USDOE sponsored Hawaii workshops supporting the initiative for the Commission, Consumer Advocate, DBEDT, Hawaii energy utilities and other invited stakeholders. The workshops addressed topics such as the objectives of the HCEI (which include meeting 70% of Hawaii’s “business as usual” energy needs in the ground transportation and energy utility sectors through clean energy resources by 2030), utility incentives and disincentives, and renewable energy and other “clean” resources (such as energy efficiency). At the last workshop, the Commission announced plans to open an “Incentive Alignment” proceeding, and to formulate an alternative regulation “strawman” proposal to be considered in later workshops and proceedings. An additional workshop was held in August 2008 on regulatory issues.

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Customers Focused on Energy Efficiency and Conservation

World oil costs have soared recently from $40/barrel in 2004 to $80/barrel in May 2007 to over $130/barrel in May 2008. These increases have driven electricity prices rapidly upwards. Although they have since dropped somewhat as of the date of filing this report, oil costs remain very high relative to just a year ago. As the cost of generating and delivering energy continues to rise and in recognition of the important role energy efficiency and conservation play in all future energy plans, Hawaiian Electric needs to increase options for its customers to help them manage their energy usage and bills. To help customers, Hawaiian Electric has aggressively implemented energy efficiency demand-side management (DSM) programs since 1996. These programs have helped our customers save over 568 GWh of energy annually from measures installed between 1996 through 20071. The Company has also engaged in extensive conservation informational advertising. However, more still needs to be done to help customers manage their electricity use and bills.

Challenges to Adding Renewable Energy Resources

In July 2006, a report entitled Siting Renewable Energy Facilities2 was issued in Washington, D.C., stating that one of the greatest challenges to the development of renewable energy nationwide is the lack of infrastructure to support it. The fact is that while most fossil fuel facilities are not site dependent and can be located with other fossil fuel facilities or at other desired locations, renewable energy exists at specific locations based on the resource involved and is geographically constrained, often in remote locations away from load centers and existing electric transmission infrastructure. In addition, the intermittent nature of many of these resources requires an infrastructure that can take into account and handle such intermittency. These are challenges that Hawaiian Electric must and will solve.

The challenges faced by developers of renewable energy projects in Hawaii, and by the Hawaiian Electric Companies in facilitating these projects in their respective service areas, can be even greater because of the state’s small, isolated, island electrical systems. The current electric infrastructure was not designed or built to interconnect with a variety of renewable electrical energy generation resources developed at remote locations away from the current transmission grid. It was designed to consolidate generation facilities in a few places (as permitted by government regulations) and transmit the power to the major load centers in a reliable and efficient manner. In order for the Hawaiian Electric Companies to be able to take advantage of remote renewable resources, new transmission lines and supporting infrastructure will have to be designed

1 Assuming that all measures remain in service. 2 Shalini P. Vajjhala, Siting Renewable Energy Facilities, (Washington, D.C,: Resources for the Future, July 2006)

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and built to these remote locations. In addition, building transmission lines and supporting infrastructure to the renewable projects will not completely solve the issues related to placing additional renewable generating resources on electrical transmission grids. Because of the intermittent nature of many of these renewable resources, additional infrastructure may be required to account for and handle the variability of electrical output from such intermittent resources.

Hawaii’s current electric infrastructure was designed for “firm power” resources – resources that provide steady flows of energy and, by design, vary their output relatively slowly to provide stable power in concert with the steady and predictable change in customer demand. Renewable resources, on the other hand, are often times not “firm power” and may exhibit wide fluctuations in the amount of electric power generated at any given moment. A good example is . The electrical power generated by wind will fluctuate depending on the changing speed, force and direction of the wind, and appropriate infrastructure must be developed to accommodate increasing amounts of it. Infrastructure such as energy control systems will help to regulate the variability of electrical output from intermittent resources such as wind power.

Small island systems currently have limitations on their ability to integrate intermittent renewable energy resources like wind power. There is a strong need to find solutions for integrating greater amounts. One alternative is energy storage infrastructure to allow the systems to absorb greater levels of intermittent energy and increase the level of dispatchable capacity. Potential examples involve the use of battery energy storage systems or pumped storage hydroelectric systems.

Providing Reliable Power

As the sole provider of electricity for Oahu, Hawaiian Electric has an ongoing commitment and responsibility to invest in and maintain our electric system. Hawaiian Electric’s infrastructure is critical to providing the service customers expect and deserve as well as to accommodate future electric load, such as the rail system.

The reliability of Hawaiian Electric’s electric system is key to public safety and the ability to respond to emergencies; critical to Oahu’s economy; and an integral part of this nation’s defense efforts, especially given Hawaii's strategic location. Reliability and stability of Hawaiian Electric’s grid are also key to integrating substantial amounts of renewable energy resources such as wind into Hawaiian Electric’s system.

As do the State and City & County of Honolulu, Hawaiian Electric faces the continuing challenge of operating, maintaining, and enhancing an aging infrastructure – including aging generating units that generate the bulk of the electricity used by Hawaiian Electric’s customers and aging transmission and distribution systems that deliver electricity to Hawaiian Electric’s customers. Hawaii’s economy and population have grown over the last economic cycle. And as does the government, Hawaiian Electric

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plans not only to ensure the working order of its system, but also plans to add new facilities to serve this growth.

IRP-4 Preferred Plan: All Future Renewable Generation

Based on the IRP-4 process conducted from March 2007 to September 2008, Hawaiian Electric has put forth a proposed 20-year IRP plan (i.e. IRP preferred plan) with bold initiatives to transition and transform its system for the future, while maintaining reliable electric power. The IRP preferred plan calls for all future generation to be renewable. In addition, it calls for conversion of the existing Hawaiian Electric-owned generating units to co-fire biofuel, continued aggressive demand-side management programs, and anticipates significant amounts of customer-sited renewable generation (see Figures ES- 1). The IRP preferred plan is briefly explained below and is explained in detail in Section 9.1 of the IRP-4 report.

Due to the requirement to use competitive bidding to procure future generation unless granted a waiver by the PUC, the IRP preferred plan indicates future resource blocks, rather than specific resources.

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Figure ES- 1 IRP Preferred Plan for the period 2009-2028

Preferred Plan (2009-2028) ( 109 MW) ( 156 MW) Demand-Side Management (including SWAC)

( 30 MW) ( 140 MW) Customer-sited Photovoltaics ( 1 MW) ( 1 MW) Customer-owned Distributed Generation/Combined Heat & Power

( 8 MW) ( 8 MW) Utility Dispatchable Distributed Generation

CT 113 MW Biofuel

RE 100 MW Firm

ER Waiau 3 Emergency Reserve

RE 50 MW Firm

ER Waiau 4 Emergency Reserve

797 MW HECO BT BC Biofuel Conversion Kahe 3 Biofuel RE 35 MW Non-Firm RE 100 MW Firm Testing Explore Placing an Additional RE 100 MW Non-Firm ER HECO Unit on Emergency Reserve

RE 50 MW Firm 100 MW Firm RE

Explore Placing an Additional ER HECO Unit on Emergency Reserve

RE 16 MW C&C Waste-to-Energy

RE 50-125 MW Non-Firm Emerging Technology (such as OTEC)

09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 Action Plan

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The main features of this ambitious IRP preferred plan are:

• Reducing the peak load through demand-side management programs by 156 MWs over the 20-year planning period.

• 149 MWs of distributed resources, the majority of which would be customer-sited photovoltaic systems.

• All future generation (711 MWs) to be renewable with 510 MWs of firm generation and 201 MWs of non-firm generation.

• 93 to 200 MWs of existing fossil fuel generation to be retired or placed in emergency reserve status.

• Conversion of 797 MWs of existing fossil fuel generation to renewable biofuel.

The specific resources in the IRP preferred plan are:

Demand-side Management – utility and third party programs resulting in 156 MW of reduction to the system peak load over the 20-year planning period using energy efficiency and load control measures including seawater air conditioning.

Customer-sited Photovoltaic – 140 MW of customer-sited photovoltaic systems is anticipated to be installed over the 20-year planning period. These photovoltaic systems could be net-metered or non-net-metered systems. The utility will also pursue a program to provide customers with a utility-facilitated third party-owned option.

Customer-owned Distributed Generation/Combined Heat and Power – 1 MW of Customer-owned DG/CHP generation is anticipated to be installed over the 20- year planning period. Activity in this area has slowed in recent years and is not expected to be significant in large part because of its reliance on high cost diesel fuel.

Utility Dispatchable Distributed Generation – 8 MW of utility dispatchable customer-owned DG over the 20-year period.

113 MW Biofuel Combustion Turbine in 2009 – This utility project is currently under construction in Campbell Industrial Park and is expected to be completed in 2009.

100 MW Firm Renewable Energy Generation in 2011 and Waiau 3 Retirement or Emergency Reserve – Given HECO’s desire to accelerate the transition to using more renewable energy generation and the system’s current need for additional dispatchable firm capacity, HECO intends to submit a request for a waiver from competitive bidding in the fourth quarter of 2008 for this resource and plans to

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submit an application for approval to expend funds to install a second biofueled combustion turbine at CIP. Once the additional capacity is operational, HECO intends to take Waiau 3 generating unit off the HECO system and either retire Waiau 3 or place Waiau 3 into emergency reserve status.

50 MW Firm Renewable Energy Generation in 2014 and Waiau 4 Retirement or Emergency Reserve – This resource block is firm capacity needed to maintain the generation planning criteria and will also allow, once operational, the placement of Waiau 4 generating unit into a status similar to Waiau 3. Hawaiian Electric plans to acquire this block through a competitive bidding process. The proposal to meet this capacity might also be met by a Hawaiian Electric response to a military RFP for distributed generation, depending on the requirements of the military RFP and whether Hawaiian Electric’s response is the winning bid. In the case of the military RFP, it is anticipated that Hawaiian Electric would need to seek a waiver from competitive bidding in order to submit a bid to the military. In addition, Hawaiian Electric’s other options may be a combine-cycle conversion of a biofuel CT as the utility proposal in a competitive bidding process.

100 MW Non-firm Renewable Energy Generation in 2012-2014 – This resource block would be filled by the result of the renewable energy RFP currently being conducted by Hawaiian Electric, which includes a process for evaluating non- conforming proposals, if any.

35 MW Non-firm Renewable Energy Generation in 2012 - 2014 – This resource block is anticipated to be filled by a waste-to-energy project by Honua and a wind project in Kahuku by First Wind. Both projects are “grandfathered” from the PUC’s competitive bidding requirement.

50 MW Firm Renewable Energy Generation in 2017 – This resource block is firm capacity needed to serve future load growth and the capacity will be acquired through a competitive bidding process.

Boiler Biofuel Assessment and Conversion of Existing Steam Generating Units – This represents the testing of boiler biofuel in Kahe 3 generating unit, and if successful, the co-firing or conversion of all baseload generating units (Kahe units 1 through 6, Waiau 7 and 8) to boiler biofuel. Currently, Hawaiian Electric’s other units that use low sulfur fuel oil are not candidates for co-firing or conversion due to their lower system energy contribution compared to the anticipated conversion cost. The conversion of 797 MW of Hawaiian Electric- owned generation represents a conversion of 66% of the Hawaiian Electric- owned generating capacity to boiler biofuel.

16 MW Waste-To-Energy Generation – This is a placeholder for future action by the City and County of Honolulu on increasing its municipal solid waste handling

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capability. The timing and implementation of such a resource is inherently dependent on the City and County’s actions to meet its waste disposal needs, therefore a waiver from the competitive bidding process may be appropriate and such a waiver may be requested when plans for the waste-to-energy facility are more definite.

50 - 125 MW Non-firm Emerging Renewable Energy Technology – This resource block is anticipated to be met by emerging technologies such as the ocean thermal energy conversion (OTEC) project proposed by SeaSolar Power International which is “grandfathered” from competitive bidding, the OTEC project proposed by Lockheed, or by any emerging technology that may come forward.

100 MW Firm Renewable Energy Generation in 2021 and 2027 – These resource blocks are needed to serve future load growth and is planned to be procured through competitive bidding.

Explore Additional Units in Emergency Reserve Status in 2021 and 2027 – The addition of firm capacity in 2021 and 2027 would allow, once they are operational, the consideration of placing additional existing fossil-fuel generating units into emergency reserve status similar to Waiau 3 and 4.

Some aspects of the preferred plan such as the need for supporting transmission infrastructure, potential bid for military DG, rate design, and advanced metering infrastructure (AMI) are not depicted in Figure ES-1 and ES-2, but are explained in the action plan in Chapter 10 of the IRP report.

The IRP preferred plan charts a course to reliable electricity that is sustainable and secure. In doing so, the plan lays the foundation for complying with Act 234 whereby the estimated carbon dioxide (CO2) emissions for the total system (including IPPs) would be reduced to below 1990 levels by 2020. The plan would also greatly exceed the amount of renewable energy required by the RPS law of 20% in 2020.

To achieve the significant amount of renewable energy and reduction in GHG emissions, the IRP preferred plan calls for all future generation and a majority of the existing generation to be from renewable energy. Efforts will be made for all new resources to tap into a myriad of potential sources of renewable energy (sea water air-conditioning, OTEC, solar, wind, biofuel, municipal solid waste).

For existing generation, biofuel is a critical component of the IRP preferred plan because it can be used in conventional generators allowing transition to renewable energy while avoiding costly replacement of existing generating units. It also creates a local market for biofuels to facilitate local production of bioenergy crops leading to increased energy security and sustainability. Conventional generators using biofuels can provide essential characteristics that the system fundamentally needs for reliable operation and

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play a key role in facilitating the integration of as-available renewable generation such as wind and photovoltaics. These characteristics include adequate firm generating capacity, frequency regulation, load following, operating and spinning reserves, voltage control, and sufficient rotational inertia to maintain system stability.

The use of biofuels also extracts additional value to ratepayers from existing generation infrastructure. Although higher levels of operating and maintenance cost are anticipated for these units, they reduce costly investment in new generating units and these generating units continue to operate with a high degree of reliability. Maintaining a portion of Hawaiian Electric’s existing units remains the least-cost option even though they have significant operating and maintenance expense. The IRP preferred plan does include removing the oldest generating units (Waiau 3 and 4) from day-to-day operation and to explore similar actions for other units later in the plan as new firm renewable energy generation is brought onto the system.

To help customer manage their bills, the IRP preferred plan continues aggressive DSM programs and calls for the implementation of AMI. AMI refers to systems that measure, collect and analyze energy usage, from advanced electricity meters through various communication media on request or on a pre-defined schedule. This infrastructure includes hardware, software, communications, customer associated systems and a meter data management system. AMI provides customers with information about their electricity usage and also provides communication and control technologies that facilitates the implementation of time-of-use pricing, demand response, and dynamic pricing programs

IRP-4 Action Plan

The action plan identifies the steps to be undertaken in the next five years to implement the IRP preferred plan. The details of each item in the action plan are provided in Chapter 10 of the IRP report. The following is a list of the action plan items.

Demand-side Action Items: 1. Transition energy efficiency DSM programs to Public Benefit Fund Administrator 2. Continue Residential Customer Energy Awareness (RCEA)/energy awareness 3. Continue SolarSavers pilot program

Customer-choice Action Items: 1. Implement Advanced Meter Infrastructure (AMI) initiative 2. Implement residential TOU pricing (enabled or enhanced by AMI) 3. Implement demand response (enabled or enhanced by AMI) 4. Evaluate green pricing tariff options

Customer-sited Distributed Generation Action Items: 1. Facilitate photovoltaic 2. Dispatchable standby generation 3. Monitor CHP

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Supply-side Action Items: 1. Install 113 MW biofuel CT in 2009 2. Pursue projects “grandfathered” from competitive bidding 3. Continue 100 MW Renewable Energy RFP 4. Install 100 MW Firm Renewable Energy Generation in 2011-2012 5. Determine whether to place W3 in emergency reserve or retire the unit 6. 50 - 125 MW non-firm emerging technology (such as OTEC) 7. 50 MW firm capacity generation in 2014 8. Potential utility bid for military distributed generation projects RFP 9. 50 MW firm generation in 2017 10. Determine whether to place W4 in emergency reserve or retire the unit 11. Conduct biofuel assessment in 2009 on Kahe 3 using LSFO/biofuel blend 12. Conduct biofuel assessment for substation DG 13. Conversion of existing generating units to biofuel 14. Explore additional utility-sited PV projects

Transmission and Distribution Action Items: 1. Complete the East Oahu Transmission Project 2. Install interconnection facility for all central station generating facilities in the plan 3. Investigate integration of additional as-available resources on Oahu grid including need for transmission infrastructure, energy storage, variability mitigation, operational impacts, and wind farm control features 4. Honolulu—School-Iwilei 46 kV study 5. Waiau 46 kV study 6. Halawa-School, Halawa-Iwilei, Makalapa-Airport-Iwilei 138 kV study

Research and Development (R&D) Action Items: 1. Investigate Hawaii-based bioenergy crop production 2. Investigate plug-in hybrid/electric vehicles 3. Investigate potential energy storage projects 4. Other miscellaneous R&D projects

Other Action Items: 1. Implement Renewable Energy Infrastructure Program 2. Participate in the Hawaii Clean Energy Initiative 3. Delink Schedule Q (avoided energy cost) from fossil fuel price 4. Explore decoupling utility revenues from electricity sales

Overview of IRP-4 Process

Hawaiian Electric initiated the process of developing its IRP preferred plan in March 2007 with a kick-off meeting of its Advisory Group. The Advisory Group is comprised of a broad cross-section of the community including members from business, government, industry, and community groups. Between March 2007 and August 2008, a total of 16 meetings were held with the Advisory Group. Hawaiian Electric also maintained an internet web site (www.hecoirp.com) to make meeting material available to the Advisory Group and the general public. In addition to input from its Advisory Group, Hawaiian Electric also sought input from the general public through two public information

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meetings. The first meeting was held in July 2007 at the beginning of the IRP-4 process. The second meeting was held in June 2008 to seek input in the development of the draft IRP preferred plan.

The plan development phase of the IRP-4 process culminates with the submission to the PUC in September 2008 of this IRP-4 report explaining the IRP preferred plan and action plan. The IRP process then enters the regulatory review phase in which the PUC conducts its process to determine whether the IRP preferred plan and action plan should be approved.

Conclusion

The IRP preferred plan and action plan charts a very bold course to transition Hawaiian Electric’s system to renewable energy and pathways of controlling energy use while maintaining the delivery of reliable electricity from the current system. The key components of the plan are energy efficiency programs, new generation from renewable energy sources, distributed generation, converting existing generating units to biofuels, and customer-choice options. The plan will use clean energy sources, decrease our vulnerability to imported sources of energy, guard against rapidly rising fuel oil prices, and comply with initiatives to reduce greenhouse gas emissions.

The management and staff of Hawaiian Electric greatly appreciates and would like to sincerely thank the members of its Advisory Group for their advice and input into the development of the IRP preferred plan. Their commitment of time and effort, along with their passion for improving the future of Hawaii were invaluable. Such a far reaching and aggressive long-range plan would not be possible without the support of Hawaiian Electric’s Advisory Group.

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1 INTRODUCTION

1.1 Purpose of IRP

Integrated Resource Planning (IRP) is a process in which each electric utility in the State of Hawaii is required to develop a long-range plan to meet future energy needs. The IRP process provides an opportunity for Hawaiian Electric Company, Inc. (HECO), with input from its Advisory Group and the public, to develop long-range and short-range plans that incorporate both demand-side and supply-side resources to ensure the delivery of reliable and affordable electric power for residential and business customers.

From March 2007 through September 2008, HECO conducted an integrated resources planning process that engaged the Advisory Group in providing input and recommendations to develop this fourth major review report (IRP-4).

1.2 Commission Ruling on HECO IRP-3

On March 21, 2007, the Public Utilities Commission (PUC) in Order No. 23328 approved the stipulation by the parties in HECO’s previous IRP (IRP-3) Docket No. 03-0253, by which the parties agreed to dispose of the docket without an evidentiary hearing, and instead, proceed with the development of HECO’s IRP-4. The stipulation also set-forth that HECO shall file an Evaluation Report for its IRP-3 by May 31, 2007.

1.3 May 2007 Evaluation Report

Based on changes since the IRP-3 plan was filed in October 2005, HECO updated its IRP-3 plan in its Evaluation Report filed on May 31, 2007. The updated IRP-3 plan is shown in Figure 1.3-1 Updated IRP-3 Plan and serves as the base plan for future planning activities. This includes serving as the starting point for HECO’s IRP-4. This IRP plan identifies renewable energy for all future supply-side resource needs. Each resource is described below in the order in which it appears in Figure 1.3-1 Updated IRP-3 Plan, and a more complete description of each resource can be found in the IRP-3 Evaluation Report.

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Figure 1.3-1 Updated IRP-3 Plan Updated IRP-3 Plan ( TBD MW) ( TBD MW) Demand-Side Management ( TBD MW) ( TBD MW) Customer-owned Photovoltaics ( 3 MW) ( 3 MW) Customer-owned Distributed Generation/Combined Heat & Power ( TBD MW) ( TBD MW) Utility Dispatchable Distributed Generation 150 kW 150 kW 300 kW 300 kW 300 kW PV PV PV PV PV 100 MW Biofuel CT 100 MW Non- RE Firm TBD MW Firm C&C WTE 180 MW Firm RE RE TBD MW RE RE 0-20 MW Non-Firm New Technology (such as wave energy) 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Action Plan

Demand-Side Management: The Demand-Side Management program is comprised of the following resource portfolio:

Existing DSM energy efficiency programs: • Commercial and Industrial Energy Efficiency Program (CIEE) • Commercial and Industrial New Construction Program (CINC) • Commercial and Industrial Customized Rebate Program (CICR) • Residential Efficient Water Heating Program (REWH) • Residential New Construction Program (RNC)

Load Management Programs: • Residential Direct Load Control Program (RDLC) • Commercial and Industrial Direct Load Control Program (CIDLC)

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New DSM energy efficiency programs: • Energy Solutions for the Home Program (ESH) • Residential Low Income Program (RLI) • SolarSaver Pilot (SSP) • Residential Customer Energy Awareness Program (RCEA)

Customer-Owned Photovoltaics: This will be an estimate of customer-sited photovoltaic systems over the planning period. Included in this resource type are larger PV systems installed by commercial customers or via power purchase agreements as well as smaller PV systems installed on smaller commercial facilities or residences that qualify under the net energy metering (NEM) program.

Customer-Owned Distributed Generation / Combined Heat & Power: Projects not dispatchable by the utility.

Utility Dispatchable Distributed Generation: Utility-owned and customer-owned distributed generation, dispatchable by the utility.

Utility Photovoltaics (PV): Larger 150 - 300 kW utility-sited photovoltaic systems through utility ownership or power purchase agreement.

Biofuel Combustion Turbine (100 MW Nominal): 110 MW simple-cycle combustion turbine-generator in Campbell Industrial Park utilizing biofuel.

Non-Firm Renewable (100 MW): 100 MW of non-firm renewable resources.

Firm Renewable (100 MW): Additional 100 MW of firm capacity renewable energy.

C&C Waste-to-Energy (TBD MW): The City & County of Honolulu issued a Request For Competitive Sealed Proposals (“CSP No. 037”) in January 2007 for the addition of waste-to-energy processing capacity and/or the refurbishment of the existing H-Power waste-to-energy facility at Campbell Industrial Park.

Firm Renewable (180 MW): 180 MW of firm capacity renewable energy in 2022

Non-Firm New Technology (0-20 MW): Up to 20 MW of non-firm energy from emerging technologies for installation later in the Action Plan period.

The key forecasts and planning assumptions used in IRP-3 were reviewed in the May 2007 Evaluation Report and it was determined that events since the IRP-3 filing on October 25, 2005 had overcome the plan. Accordingly, the Evaluation Report provided updated planning assumptions and the resulting updated IRP-3 plan and Action Plan.

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The updated IRP-3 plan identified the steps to address the near-term reserve capacity shortfall and meet customer energy needs. It also expressed a strong commitment to renewable energy and reflected a major transition to renewable energy for future supply- side resources.

1.4 Major Changes since HECO IRP-3

Since the filing of HECO’s IRP-3 report in October 2005, there have been significant changes in the legislative and regulatory environment affecting the long-range planning for HECO. This section summarizes the major changes and initiatives.

1.4.1 Hawaii Global Warming Solutions - Act 234

In July 2007, Act 234 became law, which requires a statewide reduction of greenhouse gas (GHG) emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990. It also establishes a Task Force, comprised of representatives of state government, business (including the electric utilities), the University of Hawaii and environmental groups, which is charged with preparing a work plan and regulatory approach for “implementing the maximum practically and technically feasible and cost- effective reductions in greenhouse gas emissions from sources or categories of sources of greenhouse gases” to achieve 1990 statewide GHG emission levels. The electric utilities are participating in the Task Force, as well as in initiatives aimed at reducing their GHG emissions. The full scope of the Task Force report remains to be determined and regulations implementing Act 234 have not yet been promulgated.

1.4.2 Hawaii Renewable Portfolio Standard

Hawaii has a RPS law requiring electric utilities to meet an RPS of 8% of kWh sales by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015, and 20% by December 31, 2020. These standards may be met by the electric utilities on an aggregated basis and were met in 2005 when the electric utilities attained a RPS of 11.7%. It may be difficult, however, for the electric utilities to attain the required RPS percentages in the future.

The RPS law provides that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources, such as wind or solar, versus from the electrical energy savings from renewable energy displacement technologies (such as ) or from energy efficiency and conservation programs. The RPS law also provides for penalties to be established by the PUC if the RPS requirements are not met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the electric utility’s control.

The law directed that the PUC, by December 31, 2007, develop and implement a utility ratemaking structure to provide incentives that encourage Hawaii’s electric utility

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companies to use cost-effective renewable energy resources found in Hawaii to meet the RPS, while allowing for deviation from the standards in the event that the standards cannot be met in a cost-effective manner, or as a result of circumstances beyond the control of the utility which could not have been reasonably anticipated or ameliorated.

In January 2007, the PUC opened Docket No. 2007-0008 (RPS Docket) to examine Hawaii’s RPS law, to establish the appropriate penalties for failure to meet RPS targets and to determine the circumstances under which penalties should be levied. On December 20, 2007, the PUC issued Decision and Order No. 23912 approving a stipulated RPS framework to govern electric utilities’ compliance with the RPS law.

1.4.3 Hawaii Clean Energy Initiative

In January 2008, the U.S. Department of Energy (USDOE) and the State of Hawaii entered into a Memorandum of Understanding (MOU) establishing the Hawaii Clean Energy Initiative (HCEI), a long-term partnership designed to transform Hawaii’s energy system to one that utilizes renewable energy and energy efficient technologies for a significant portion of its energy needs. The goal of the HCEI is to develop plans for supplying 70% of Hawaii’s energy needs using clean energy by 2030.

Four HCEI working groups were established: 1) Electric Generation, 2) Transmission & Distribution, 3) Transportation & Biofuels, and 4) Integration. Initial meetings of the HCEI Working Groups, consisting of USDOE, State, industry, and other energy stakeholders were held in March 2008. Subsequent meetings were held in June.

Public PUC workshops on HCEI related issues were held in April and in August, in which USDOE and DBEDT representatives briefed the audience and answered questions on various energy technology and energy policy issues.

At the time in which this report was finalized, work of the HCEI continues, and the plans, strategies and initiatives that may be developed as a result of the Hawaii Clean Energy Initiative are still unknown.

1.4.4 Biofuels Legislation

In 2007, a law was enacted with the stated purpose of encouraging further production and use of biofuels in Hawaii. It established that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts and established a program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels).

In 2008, a law was enacted that encourages the development of biofuels by authorizing the Hawaii Board of Land and Natural Resources to lease public lands to growers or producers of plant and animal material used for the production of biofuels.

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1.4.5 Renewable Energy Infrastructure Program Docket

In its December 20, 2007 Decision and Order No. 23912, the PUC deferred the RPS incentive framework to a new generic docket (Renewable Energy Infrastructure Program or REIP Docket No. 2007-0416). The Renewable Energy Infrastructure Program proposed by HECO consists of two components: (1) renewable energy infrastructure projects that facilitate third-party development of renewable energy resources, maintain existing renewable energy resources and/or enhance energy choices for customers, and (2) the creation and implementation of a temporary renewable energy infrastructure surcharge to recover the capital costs, deferred costs for software development and licenses, and/or other relevant costs approved by the PUC. These costs would be removed from the surcharge and included in base rates in the utility’s next rate case. The parties to the REIP Docket include the electric utilities, the Consumer Advocate, an environmental organization and Hawaii Renewable Energy Alliance (HREA). Public hearings were held in May 2008. Statement of positions were filed by the other parties in the docket in July 2008 and the Consumer Advocate and HREA support the REIP and the REIP surcharge mechanism. The environmental organization does not oppose this mechanism. HECO filed its reply position statement in September 2008.

1.4.6 Intragovernmental Wheeling Docket

On June 29, 2007, the PUC issued Order No. 23530 and initiated an investigation to examine the feasibility of implementing intra-governmental wheeling of electricity in the State of Hawaii, Docket No. 2007-0176. The issues in the proceeding adopted by the PUC include (1) identifying what impact, if any, wheeling will have on Hawaii’s electric industry, (2) addressing interconnection matters, (3) identifying the costs to utilities, (4) identifying any rate design and cost allocation issues, (5) considering the financial cost and impact on non-wheeling customers, (6) identifying any power back-up issues, (7) addressing how rates would be set, (8) identifying the environmental impacts, (9) identifying and evaluating the various forms of intra-governmental wheeling and (10) identifying and evaluating the resulting impact to any and all governmental entities, including but not limited to economic, feasibility and liability impacts. Parties to this proceeding include HECO, HELCO, MECO, Island Utility Cooperative, the Consumer Advocate, governmental agencies (the DOD, the DBEDT, the City and County of Honolulu, the Counties of Hawaii, Maui and Kauai), two environmental groups, and two renewable energy developers. Two renewable energy contractors and a renewable energy developer also have been granted limited participant status. The procedural schedule includes technical workshops and meetings through November 2008, with a formal PUC proceeding to commence thereafter.

1.4.7 Public Benefit Fund Docket

The PUC opened Docket No. 2007-0323 to select a third-party DSM administrator and to refine details of the new DSM market structure in Order No. 23681 issued on

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September 26, 2007. This docket was a result of the Energy Efficiency (EE) DSM Docket No. 05-0069 in which the PUC issued Decision and Order No. 23258 on February 13, 2007, requiring that the administration of all EE DSM programs be turned over to a non-utility, third-party administrator, with the transition to the administrator, funded through a public benefits fund (PBF) surcharge, to become effective around January 2009. (The utility was subsequently ordered to continue administering the programs until June 30, 2009).

The EE Docket D&O 23258 also provides for HECO’s recovery of DSM program costs and utility incentives. With respect to cost recovery, the PUC continues to permit recovery of reasonably-incurred DSM implementation costs, under the IRP framework.

Unlike the EE DSM programs, load management DSM programs will continue to be administered by the utilities. HECO’s residential load management program includes a monthly electric bill credit for eligible customers who participate in the program, which allows HECO to disconnect the customer’s residential electric water heaters or central air conditioning systems from HECO’s system to reduce system load when deemed necessary by HECO. The commercial and industrial load management program provides an incentive on the portion of the demand load that eligible customers allow HECO to control or interrupt. This program includes small business direct load control and voluntary program elements.

In the order opening the Public Benefit Fund (PBF) Docket, the PUC stated that “[u]pon selection of the PBF Administrator, the PUC intends, in this docket, to determine whether the electric utilities will be allowed to compete for the implementation of the Energy Efficiency DSM programs.” The PUC has issued a draft RFP for the PBF Administrator. On July 2, 2008, the PUC issued an Order to Initiate the Collection of Funds for the PBF Administrator of Energy Efficiency Programs, in Docket No. 2007- 0323, which authorized the electric utilities to expense $50,000 per quarter beginning July 1, 2008 for the initial start-up costs associated with the PBF Administrator and recover the cost in the DSM surcharge; confirmed that the load management, SolarSaver and RCEA programs shall remain with the electric utilities; directed the electric utilities to continue to operate the energy efficiency DSM programs through June 30, 2009, and after the transition period, the electric utilities can compete for implementation of DSM programs as a subcontractor.

1.4.8 Net Energy Metering

Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier of energy and will make payment to or receive credit from the electric utility accordingly).

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In 2005, the Legislature amended the net energy metering law by, among other revisions, authorizing the PUC, by rule or order, to increase the maximum size of the eligible net metered systems and to increase the total rated generating capacity available for net energy metering. In April 2006, the PUC initiated an investigative proceeding on whether the PUC should increase (1) the maximum capacity of eligible customer-generators to more than 50 kilowatts (kW) and (2) the total rated generating capacity produced by eligible customer-generators to an amount above 0.5% of an electric utility’s system peak demand. The parties to the proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative (KIUC), the Consumer Advocate, a renewable energy organization and a solar vendor organization. In March 2008, the PUC approved a stipulated agreement filed by the parties (except for KIUC, which has its own stipulated agreement) to increase the maximum size of the eligible customer-generators from 50 kW to 100 kW and the system cap from 0.5% to 1.0% of system peak demand, to reserve a certain percentage of the 1.0% system peak demand for generators 10 kW or less and to consider in the IRP process any further increases in the maximum capacity of customer-generators and the system cap. The PUC further required the utilities to: (1) consider specific items relating to net energy metering in their respective IRP processes, (2) evaluate the economic effects of net energy metering in future rate case proceedings and (3) design and propose a net energy metering pilot program for the PUC’s review and approval that will allow, on a trial basis, the use of a limited number of larger generating units (i.e., at least 100 kW to 500 kW, and may allow for larger units) for net energy metering purposes.

In April 2008, the electric utilities filed a proposed four-year net energy metering pilot program to evaluate the effects on the grid of units larger than the currently approved maximum size. The program will consist of analytical investigations and field testing and is designed for a limited number of participants that own (or lease from a third party) and operate a solar, wind, biomass, or hydroelectric generator, or a hybrid system. The electric utilities propose to recover program costs through the IRP cost recovery provision.

In 2008, the net energy metering law was again amended to authorize the PUC in its discretion, by rule or order, to modify the maximum size of the eligible net metered systems and evaluate on an island-by-island basis whether to exempt an island or utility grid system from the total rated generating capacity limits available for net energy metering.

1.4.9 Competitive Bidding for New Generation Docket

The stated purpose of this proceeding was to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii. On December 8, 2006, the PUC issued Decision & Order No. 23121 in Docket No. 03-0372 that included a final competitive bidding framework, which became effective immediately.

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The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable, (2) the determination of whether to use competitive bidding for a future generation resource or a block of generation resources will be made by the PUC during its review of the utility’s integrated resource plan (IRP), (3) an exemption from the framework is granted for cooperatively- owned utilities, (4) the framework does not apply to two pending projects (HECO’s CIP-1 and HELCO’s ST-7), MECO’s M-18 project (which went into commercial operation in October 2006), specifically identified offers to sell energy on an as-available basis or to sell firm energy and/or capacity by non-fossil fuel producers that were under review by an electric utility at the time the framework was adopted (provided that negotiations with the nonfossil fuel producers for firm capacity were completed no later than December 31, 2007), and certain other situations identified in the framework, (5) waivers from competitive bidding for certain circumstances will be considered by the PUC and granted when considered appropriate, (6) for each project that is subject to competitive bidding, the utility is required to submit a report on the cost of parallel planning upon the PUC’s request, (7) the utility is required to consider the effects on competitive bidding of not allowing bidders access to utility-owned or controlled sites, and to present reasons to the PUC for not allowing site access to bidders when the utility has not chosen to offer a site to a third party, (8) the utility is required to select an independent observer from a list approved by the PUC 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 PUC otherwise determines, (9) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP, (10) the evaluation of the utility’s bid should account for the possibility that the capital or running costs actually incurred, and recovered from ratepayers, over the plant’s lifetime, will vary from the levels assumed in the utility’s bid and (11) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC.

Projects that offered energy on an as-available basis by non fossil fuel producers that were submitted to an electric utility before that Competitive Framework was adopted were exempt from competitive bidding under section ii.a.3.e. of the framework. In Footnote 10 of Decision and Order No. 23121 the Commission limited this exemption to those projects identified in a list submitted by HECO to the Commission and the Consumer Advocate under confidential protective order on June 27, 2006, as updated by the HECO Companies on September 11, 2006 (“Grandfathered Projects”).

The Commission set a deadline of September 2, 2008, to reach material agreement on any or all of the three remaining grandfathered projects as evidenced in writing by fully executed term sheets for any or all of the three HECO projects and to file fully executed

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copies of the same with the Commission. The grandfathered exemption shall no longer apply to any remaining grandfathered HECO project on Oahu for which a fully executed term sheet is not filed by HECO with the commission by September 2, 2008.

1.4.10 Solicitation for 100 MW of As-available Renewable Energy

In June 2008, HECO issued its Final Request for Proposals (“RFP”) for the supply of up to approximately 100 megawatts (“MW”) of long term (i.e. 20 years) renewable energy for the island of Oahu under a Power Purchase Agreement (“PPA”), the terms of which would be negotiated between HECO and the seller. The RFP is the first prepared in accordance with the PUC’s Competitive Bidding Framework issued in December 2006.

The resources sought under this RFP would commence commercial operation in the 2010-2014 timeframe, with a preference for resources that achieve commercial operation before 2013. The resources proposed will be evaluated with respect to impacts to the HECO system, adherence to HECO’s performance standards, and their ability to be installed within this preferred timeframe which encourages projects that require no more than modest infrastructure improvements.

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The schedule for the RFP is as follows in Table 1.4-1:

Table 1.4-1 HECO Renewable Energy RFP Schedule

HECO Renewable Energy RFP Schedule

Event Anticipated Dates

Issue Draft RFP and Contract Forms February 8, 2008

Prospective Bidders may submit initial questions Thru Technical Conference

Technical Conference on RFP with Interested Parties. March 14, 2008

Prospective Bidders File Comments on the Draft RFP April 14, 2008

HECO Files Proposed Final RFP and Contract Forms May 19, 2008 with the Commission

Independent Observer Submits Comments and May 19, 2008 Recommendations on the Proposed Final RFP

Opportunity for Participants to Comment on Proposed June 2, 2008 Final RFP and Independent Observer Recommendations

Commission Review and Approval of the Final RFP and June 18, 2008 Contract Forms

Final RFP Posted to the Company’s Website June 19, 2008

Bidders Conference Held July 14, 2008

Submit Notice of Intent to Bid July 19, 2008

Due Date for Proposals September 25, 2008

Selection of Short-Listed Bidders December 2008

HECO Completes Interconnection Studies for June 2009 Short-Listed Bidders

Selection of Award Group August 2009

Execution of Contracts December 2009

Submit Contracts for Commission Approval December 2009

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Several developers proposing large-scale wind farm projects located on the is lands of and , ranging in size up to 400 MW each, have notified HECO that they plan to submit a proposal in response to the HECO Renewable Energy RFP, assuming development of an undersea transmission line to transmit power to Oahu. If bids of this large scale nature are actually submitted in response to this RFP, they will be designated as “non-conforming”.

The process for considering non-conforming proposals of this nature has been identified in the RFP. Non-conforming proposal must include sufficient justification and substantive information to allow a reasonable evaluation of (1) the anticipated impacts arising from the integration of the proposed project on the operation, reliability and power quality of the system, (2) the compliance of the proposed project with performance standards set forth in the RFP, and (3) the ability to implement the project, including all related interconnection facilities and infrastructure upgrades, within a reasonably defined and practical project development schedule.

Integrating large scale wind projects into the Oahu system is expected to be a complex and challenging process. Studies must be done to examine the necessary engineering, technical, and financial impacts, performance requirements, undersea cable systems requirements, and HECO’s system modifications, infrastructure additions, and operational issues. These studies are identified in HECO’s Action Plan Section 10.5.3 Investigate Integration of Additional As-Available Resources on Oahu. The results of these studies could also have an impact on the attributes identified for future supply side generation resources identified in HECO’s Preferred and Action Plans.

HECO recognizes the important role that a large scale neighbor island wind farm may have on the system. At the same time, HECO also recognizes that the Renewable Energy RFP is the best near term opportunity to provide approximately 100 MW of renewable energy resources on Oahu.

To facilitate both the Oahu projects and the neighbor island wind farm, HECO will be working with the parties involved to consider a process whereby the large scale neighbor island wind non-conforming proposals may be bifurcated from the conforming proposals in the Renewable Energy RFP. The bifurcated RFP process to select the winning neighbor island wind project is envisioned to be led by HECO, with support from the State of Hawaii, and is contemplated to be conducted in conformance with the Public Utilities Commission’s Competitive Bidding Framework.

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1.4.11 Campbell Industrial Park Generating Station

HECO is building a new 110 MW simple cycle combustion turbine (CT) generating unit at CIP and plans to add an additional 138 kilovolt transmission line to transmit power from generating units at CIP (including the new unit) to the rest of the Oahu electric grid (collectively, the Project). Plans are for the CT to be run primarily as a “peaking” unit beginning in mid-2009, fueled by biodiesel. In December 2006, HECO filed with the PUC an agreement with the Consumer Advocate in which HECO committed to use 100% biofuels in its new plant and to take the steps necessary for HECO to reach that goal. On May 23, 2007, the PUC issued Decision & Order No. 23457 in Docket No. 05-0145 approving the Project and the DOH issued the final air permit, which became effective at the end of June 2007. The D&O further stated that no part of the Project costs may be included in HECO’s rate base unless and until the Project is in fact installed, and is used and useful for public utility purposes. HECO’s 2009 test year rate case application, filed on July 3, 2008 as Docket No. 2008-0083, requests inclusion of the Project investment in rate base when the new unit is placed in service (expected to be at the end of July 2009).

In August 2007, HECO entered into a contract with Imperium Services, LLC, to supply biodiesel for the planned generating unit, subject to PUC approval. Imperium Services, LLC, agreed to comply with HECO’s procurement policy requiring sustainable sources of biofuel and biofuel feedstocks. On October 18, 2007, HECO filed an application with the PUC for approval of this biodiesel supply contract, Docket No. 2007-0346.

1.4.12 Relating to Renewable Energy Act 207

On July 1, 2008, Act 207 became law, that establishes new responsibilities for director of the Department of Business, Economic Development and Tourism (DBEDT) as the State's energy resources coordinator. This position will create a streamlined permitting process that includes state and county permits required for the siting, development, construction, and operation of a new renewable energy facility of at least 200 megawatts of electricity.

In HECO IRP-4, this Act will affect only the 300-400 MW Neighbor Island Wind Project that is being planned by Castle and Cooke for Lanai. Other renewable energy projects that are currently being proposed are smaller than the 200 megawatt minimum size requirement to qualify for the streamlined permitting process.

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Docket No. 2007-0084 1-14 September 2008 HECO IRP-4 Chapter 2: IRP-4 Process Overview

2 IRP-4 PROCESS OVERVIEW

2.1 Description of Overall Process

The previous IRP plan (i.e. HECO IRP-3 plan) took approximately 28 months to develop. Having such an extended timeframe creates challenges for the IRP process as many of the assumptions used can become outdated or overtaken by events. From the onset of the IRP-4 process, it was evident that time was of the essence in preparing the HECO IRP-4 plan. Therefore, the PUC specified at the time it opened the IRP-4 docket that the IRP-4 plan would be due by June 30, 2008 as agreed to by the parties in the HECO IRP- 3 docket. The PUC subsequently granted HECO an extension of time until September 30, 2008 to file its IRP-4 plan.

In order to insure a timely IRP process, HECO built upon the results of its IRP-3 process. In May 2007, HECO shared with its Advisory Group an evaluation report of its IRP-3 plan including an update of the plan. The updated IRP-3 reflected the major regulatory changes that had occurred since the filing of IRP-3 and also indicated the beginning of a major shift in energy policy towards even greater use of renewable energy and the reduction of greenhouse gas emissions in Hawaii. See Section 1.3 for more information on the May 2007 IRP-3 Evaluation report.

HECO worked with its Advisory Group through the summer and fall 2007 to obtain updated information and develop updated assumptions to be used in IRP-4. During winter 2007 and spring 2008, HECO developed its approach to integration which was discussed with the Advisory Group in April 2008. Based on the input of the Advisory Group and general public, Hawaiian Electric developed a draft IRP-4 preferred plan which was reviewed with its Advisory Group in August 2008. Public comments on the draft IRP-4 preferred plan were received. The plan was then finalized and filed with the PUC in September 2008. See Figure 2.1-1 for a flow chart of the process used for IRP-4.

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Figure 2.1-1 IRP-4 Process Flow Chart

IRP-4 Process

Mar 2007 Kick-off Meeting

Define System Needs, Initial Apr - May 2007 Objectives, Measures and Goals

Panel Discussion on Jun 2007 Climate Change Public Input Meeting Update Forecast and Resource Jun 2007 - Apr 2008 Data, Develop Approach to Integration Analysis

Mar - Jul 2008 Integration Analysis Public Input Meeting Develop Preferred Plan and Jun - Sep 2008 Action Plan

Prepare Report and File Sep 2008 with PUC

The input of the public is an important part of the IRP-4 development process. In order to receive this input, HECO held numerous meetings with its Advisory Group and also held public information meetings at key points in the IRP process. HECO also used an internet web site (www.hecoirp.com) to post presentation materials and meeting schedules to keep the Advisory Group and public aware of the latest information and to provide a venue for the public to submit comments and questions.

2.2 Advisory Group Meetings

An Advisory Group was formed to allow discussion of the issues and to provide HECO with public input from a broad a cross section of the community including business, government, industry, and community groups. The members of the Advisory Group are shown in Table 2.2-1.

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Table 2.2-1 HECO IRP Advisory Group Membership

Name Title Organization

Robert Alm Senior Vice President -Public Affairs Hawaiian Electric Company Land Use Research Foundation of Hawaii David Arakawa Executive Director (LURF) Catherine Awakuni Executive Director Division of Consumer Advocacy Warren Bolmeier President Hawaii Renewable Energy Alliance Carlito Caliboso * Chairman Public Utilities Commission Henry Curtis Executive Director Life of the Land Kathy Cutshaw Vice Chancellor for Administration University of Hawaii Michael Fitzgerald President & CEO Enterprise Honolulu Mark Fox Director of External Affairs The Nature Conservancy of Hawaii Research Corporation of the University of Dr. Michael Hamnett Executive Director Hawaii Neil Hannahs Director - Land Assets Division Kamehameha Schools Economic Development Alliance of Hawaii Paula Helfrich Executive Director (EDAH) Leonard Hoshijo Education Director Hawaii Carpenters Union D Wayne Judd (Retired) Shad Kane (Retired) Todd Kanja Director-Engineering Services Queen's Medical Center Department of Business, Economic Maurice Kaya Chief Technology Officer Development, and Tourism Chairman & CEO Energy Industries Holdings, Inc. Clifford Lum Manager & Chief Engineer Honolulu Board of Water Supply Pacific International Center for High Harold Masumoto Program Director Technology Research (PICHTR) Richard Meiers President & CEO Healthcare Association of Hawaii Ron Menor (Senator) Senator 17th District Hawaii State Legislature Jeff Mikulina Director, Hawaii Chapter Sierra Club, Hawaii Chapter

Hermina Morita (Rep.) Representative 14th District Hawaii State Legislature Rick Reed President Hawaii Association Director of Hawaii Natural Energy Dr. Richard Rocheleau Institute University of Hawaii at Manoa Pauline Sato Malama Hawaii Captain Taylor Skardon Commanding Officer Naval Station Pearl Harbor Professor of Financial Economics & Dr. Jack Suyderhoud Institutions University of Hawaii at Manoa Dept. of Planning & Permitting David Tanoue Deputy Director City & County of Honolulu Murray Towill President Hawaii Hotel & Lodging Association Joan White Executive Director Honolulu Community Action Program

* Observer 3/30/2007 A total of 16 Advisory Group meetings were held between March 2007 and August 2008. Opportunities were also provided to Advisory Group members to visit actual projects such as the Honolulu Generating Station, H-Power, utility distributed generation, solar photovoltaic, load control, and energy efficiency projects, to view first hand the potential benefits and trade-offs associated with the various technologies. All meetings were open to the public and all meeting materials including meeting minutes are contained in Appendix F and I. HECO sincerely appreciates the major commitment of time and effort made by the Advisory Group members to understand the complex issues affecting the

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electric utility industry and to provide their input so that the IRP-4 plan can effectively address public concerns. An Advisory Group meeting of special note was a day-long forum on the topic of Global Warming held on June 8, 2008 at the State Capitol. The meeting consisted of four panel sessions developed through input by the Advisory Group members covering Background on Climate Change Issues, Policy Implications for Hawaii, Options and Strategies for Controlling GHG Emissions, and Including Climate Change into the IRP Process. Panel speakers included University of Hawaii researchers, industry experts, and representatives of government agencies, and community groups. The meeting was video taped and televised on Olelo public TV. Copies of the video tape were shared with IRP Advisory Group members for HECO, MECO, and HELCO, community leaders, elected officials and environmental organizations. A transcript of the meeting is available on HECO’s IRP web site (www.hecoirp.com) and Appendix I of this report.

2.3 Public Information Meetings

HECO held two public information meetings to obtain input from interested individuals and those sectors of the public not represented on the Advisory Group. One meeting was held in the beginning of the IRP process to inform the public that the IRP process was starting and to obtain initial input on the objectives and goals of the IRP process. The second meeting was held to share information developed in the IRP-4 process and to obtain input into the selection of the preferred plan.

The first meeting was held on July 5, 2007 at Stevenson Middle School. The meeting was well publicized with advertisements in major local publications. In addition to members of the public, the meeting was attended by staff from various HECO departments, and representatives of the PUC and Consumer Advocate. The majority of the input received that night focused on the public’s interest in increasing the use of renewable energy on the HECO system through such means as , solar water heating, and wind farms. There were also comments on increasing the use of energy efficiency measures to reduce the demand for electricity.

The second meeting was held on June 26, 2008 at Kapalama Elementary School and was also publicized with advertisements in the major local publications and attended by members of the public, staff from various HECO departments, and representatives from the PUC and Consumer Advocate. As with the first meeting, the majority of the input received that night again focused on the public’s interest in increasing the use of renewable energy and energy efficiency in Hawaii. All meeting materials for both public meetings are contained in Appendix H.

After considering all of the public comments and selecting a draft preferred plan, HECO continued to work with the Advisory Group to obtain more feedback and refine the plan. In August 2008, HECO presented the draft preferred plan to the Advisory Group for

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discussion and additional recommendations. The opportunity to submit written comments or a Statement of Position was provided to Advisory Group members to allow members to provide their feedback and perspectives about the IRP process conducted by HECO and the resulting draft preferred plan for the PUC to consider in its deliberations on the HECO IRP-4. The statements of position are included in Section 11 of this report. In addition, HECO has identified the key issues that were raised by the Advisory Group members and general public and provided summaries of the issues in Appendix G.

Hawaiian Electric is grateful to its Advisory Group members for their commitment and collaboration to develop this IRP-4 plan. The additional time and effort to maximize public involvement and to receive a broad range of input has resulted in a preferred plan and action plan that meets the energy needs of our community while helping HECO transition to a more renewable and changing energy future for our island.

2.4 IRP-3 Stipulated Agreement

In March 2007, the PUC issued an Order approving the agreed-upon terms to govern the disposition of the HECO IRP-3 docket and the development of HECO IRP-4 plan. The agreed-upon terms were set forth in a March 7, 2007 stipulated agreement between the parties to the HECO IRP-3 docket which discussed in part issues and activities contemplated for the IRP-4 development process. This included an outline of the types of information to be provided to HECO’s Advisory Group. As discussed above, HECO held a significant number of Advisory Group and public meetings for the purpose of receiving public comment on development of HECO’s IRP-4 plan. This included but is not limited to the following examples of the efforts undertaken to promote a robust discussion of the issues and informed Advisory Group participation in the IRP-4 development process:

1. Started the IRP-4 process in March 2007 with a kick-off meeting of the IRP Advisory Group held on March 30, 2007.

2. Submitted the IRP-3 Evaluation Report by May 31, 2007.

3. Used the IRP-3 plan as the base reference plan to start the IRP-4 cycle and considered the changes to the IRP plan set forth in the 2007 HECO IRP Evaluation Report and based upon developments in recent dockets.

4. Conducted a day-long technical session with panel discussion on climate change and global warming. The technical session materials including transcript were filed with the PUC as part of the record of the IRP-4 docket. Performed scenario analyses on utility cost to address global warming.

5. Held meetings for the Advisory Group and public to review and comment on sales, load, and fuel forecast, supply-side, demand-side, distributed generation,

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transmission and distribution constraints, global warming, and integration analysis.

6. Held Advisory Group meetings in March through May 2007 that presented HECO’s initial position on quantitative measures of each element constituting Section 1.6 of HECO IRP-3 to the extent information was available.

7. Held technical sessions which provided updated information for discussion and analysis. Opportunities were provided to Advisory Group members to visit actual projects to better understand the potential trade-offs associated with the projects.

8. Scheduled Advisory Group meetings to be held quarterly although HECO was not able to hold a meeting in the first quarter of 2008. Dates for meetings were provided to the Advisory Group at least two weeks in advance of the meeting.

9. Discussed the issue of competitive bidding and how that process is addressed through the preferred plan. The interrelationship of the IRP process to competitive bidding was discussed with the Advisory Group in June 2007.

10. A steady state impact analysis was performed on HECO’s transmission system for various supply-side resource options. The results were shared with the Advisory Group in the form of energy delivery Action Plan items.

11. Consideration of externalities was discussed with the Advisory Group in April 2007.

12. Conducted the IRP-4 process expeditiously (although a three month extension was requested and granted), HECO completed the IRP-4 cycle in significantly less time than previous IRP cycles.

Docket No. 2007-0084 2-6 September 2008 HECO IRP-4 Chapter 3: Initial IRP Objectives and Goals

3 INITIAL IRP OBJECTIVES AND GOALS

The PUC requires HECO to provide a description of the objectives to be attained by the plan and the measures by which achievement of the objectives is to be assessed. This chapter describes the objectives developed for the IRP-4 plan and the measures employed to determine the attainment of these objectives.

The IRP Framework defined the goal of IRP as “the identification of the resources or the mix of resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost.” This goal establishes three general objectives for IRP: efficiency, reliability, and cost. The document provides further guidance for the development of objectives by stating that integrated resource plans “shall give consideration to the plans’ impacts upon the utility’s consumers, the environment, culture, community lifestyles, the state economy, and society.” In addition, the PUC stated that integrated resource plans “shall take into consideration the utility’s financial integrity, size, and physical capability.”

Through previous IRP processes, Hawaiian Electric received recommendations that there should be a handful of key, specific goals established at the start of the IRP planning, which could be adjusted over time as information was refined during the analysis. HECO worked with the Advisory Group to define the specific goals or target values for IRP-4.

In order to develop specific goals, HECO identified overall objectives for IRP-4 that were based on the objectives from IRP-3. These overall objectives were: • Sustainable Future • Energy Security • Power Quality and Reliability • Economical Electricity • Increased Plan Flexibility

The Advisory Group and Hawaiian Electric then identified the more narrowly focused areas for development of specific objectives. These areas were: • Renewable Portfolio Standard • Greenhouse Gas Emissions • Potable Water Consumption • Demand-side Generation • Distributed Generation

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• Generation System Reliability • Electricity Rates and Bills Impact

The development of the overall objectives, as well as the initial specific objectives and goals were discussed with the Advisory Group in the April 18, 2007 and May 30, 2007 Advisory Group meetings. In the April 18, 2007 meeting, HECO presented possible areas for development of specific objectives. Based on the discussion at the April 18, 2007 meeting, HECO then developed initial goals or target values for specific objectives. The initial goals were presented and discussed at the May 30, 2007 Advisory Group meeting. The following sections explain the initial specific objectives and goals that were developed. Analysis of the expected achievement of the goals by the IRP-4 preferred plan is explained in Section 8.7

3.1 Renewable Portfolio Standard Percentage

The RPS law as explained in Section 1.4.2 requires the utility to use an increasing amount of renewable energy to serve the electrical needs of its customer. Accordingly, the IRP preferred plan developed in this cycle of IRP must comport with the RPS law and should be an initial objective of the IRP-4 process. Although the RPS law allows HECO, HELCO, and MECO to aggregate its renewable energy to meet the RPS law, initial IRP objective that was developed with input from the Advisory Group is for HECO to meet the RPS requirement on a stand alone basis. Therefore, the target value for the initial goals were determined using the RPS requirement of 10%, 15%, and 20% in 2010, 2015, and 2020, respectively. In addition, since the RPS law requires that at least 50% of the renewable electrical energy (which includes energy efficiency) come from electrical energy generation from renewable energy sources, HECO included an initial IRP goal for renewable electrical energy that is 50% of the RPS percentage requirement. Table 3.1-1 shows initial IRP goals for complying with the RPS law.

Table 3.1-1 Initial RPS IRP Goals

2005 2010 2015 2020 2028 (Actual)

Electrical Energy Generated from 4.3% 5% 7.5% 10% TBD Renewable Energy

Total RPS Percentage 8.8% 10% 15% 20% TBD

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3.2 Greenhouse Gas Emission Reduction

The Hawaii Global Warming Solutions Act (Act 234) as explained in Section 1.4.1 and in Section 4 requires the utility to reduce its greenhouse gas emissions to 1990 levels by 2020. Although HECO’s IRP-4 preferred plan would need to comply with Act 234, it was not possible to determine initial goals for the GHG reduction because Act 234 requires a GHG emission reduction task force to inventory GHG emissions within the state and determine the emission reductions that would required by the various GHG emitters. The GHG emission reduction task force had not been formed at the time the initial IRP goals were being formulated. It was not clear how to establish initial IRP goals with respect to the treatment of GHG emissions from IPPs, life cycle treatment of biofuel and MSW, and prior sequestration activities by an IPP.

HECO did determine that in formulating initial IRP goals for GHG emissions, that it should focus on carbon dioxide as it represents more than 99% of HECO’s GHG emissions and it would be difficult to estimate the emissions for other GHG gases. Also, the IRP goals for carbon dioxide emissions should be separated into that for just the HECO-owned generating units and for the total system including IPPs. It is also useful to understand the carbon intensity (the rate of carbon dioxide emission per kWh of electricity generated), therefore that was included as an IRP goal. Table 3.2-1 shows the initial IRP goals for GHG emission reduction.

Table 3.2-1 Initial Greenhouse Gas Emission Reduction Goals

1990 2005 2020 (Actuals) (Actuals)

CO2 Emissions – HECO Units (Million Tons) 5.3 4.2 TBD

CO2 Emissions – Total System (Million Tons) TBD TBD TBD

CO2 Intensity (Tons per MWh) TBD TBD TBD

Note: The global warming goals are subject to change as measurement and certification criteria may be established as a result of Act 234.

3.3 Potable Water Consumption Reduction

Electricity generation by HECO’s generating units is currently a major use of potable water on Oahu. Potable water is primarily used for boiler make-up water to create the steam for the generating units. Potable water supply on Oahu is constrained by the size of the island and its topology. In recent years, there has been increasing concerns of drought and potential for mandatory water use reductions. Accordingly, reducing HECO’s potable water consumption is a desired objective for this IRP process. There was some discussion at the Advisory Group meeting to expand this specific objective to

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encompass impacts to all water use, not just potable water, including the use of water by any bioenergy crops. After considering the Advisory Group input, HECO elected to focus this specific objective on potable water use by HECO’s generating units as that is the pressing issue for the HECO grid at this time. And while it was envisioned at the start of the IRP-4 process that biofuels would be considered, it would have been premature to include water impacts for bioenergy crops as water requirements vary greatly with the type of crop and location of cultivation which would not be known in this cycle of IRP. HECO developed the initial target values for the specific IRP goal of reducing potable water consumption by looking at its actual potable water consumption over the recent three years and determine a reasonable amount of reduction that could be achieved over the 20-year IRP planning period with the majority of the reduction coming from a potential RO water line to the Kahe power plant. Table 3.3-1 shows the initial IRP goals for potable water consumption.

Table 3.3-1 Initial Potable Water Consumption Reduction IRP Goals

3-year 2010 2015 2020 2028 Average

(2004-06)

HECO Power Plants 295 195 200 205 210 (thousand gallons/day)

Note: The potable water consumption reduction goals are preliminary estimate and are dependent on the installation of the reclaimed R0 water line to Kahe Power Plant.

3.4 Demand-Side Management

The efficient use and conservation of electricity is one of the state energy objectives and therefore maximizing cost-effective DSM is desirable for the IRP plan. The target values for this specific IRP objective were based on the DSM goals established in the recent Energy Efficiency DSM Docket conducted by the PUC. In the Advisory Group meetings, HECO had initially proposed to include a goal to cap the total expenditure for DSM programs as a means to limit the rate impact of the DSM programs. However based on input from the Advisory Group, HECO elected to delete that item as an initial IRP goal for DSM. Table 3.4-1 shows the initial IRP Goals for DSM.

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Table 3.4-1 Initial IRP Goals for DSM

2006 2010 2015 2020 2025 2028 (Actual)

Cumulative Energy 40,964 221,787 390,030 525,549 535,623 536,131 Reduction (MWh)

Cumulative Peak 19 85 125 151 153 153 Reduction (MW)

Low Income Program N/A $1.0M $1.2M $1.4M $1.6M $1.7M Expenditure

Portfolio Cost-Benefit TRC > 1 TRC > 1 TRC > 1 TRC > 1 TRC > 1 TRC > 1

Note: Cumulative energy and peak reduction are based on a 2005 reference year (i.e., 2005 = 0), net of freeriders, and gross generation level.

3.5 Distributed Generation

Distributed generation, if implemented in a manner that does not negatively impact the transmission and distribution system (see Sections 5.2, 5.7, and 5.8), could increase energy security of the HECO grid. It could also add operational flexibility to the grid (especially if dispatchable by the utility) or provide customers with additional energy options. Therefore, DG was deemed to be a desirable objective for IRP-4.

At the same time however, it was difficult to establish initial target values for the specific IRP objective for DG as the near-term uncertainty in energy markets makes it difficult to estimate the cost-effective level of DG that would allow customers to consider customer- sited DG. Also, the changing environmental requirements for DG greatly affect the viability of DG. See Section 7.2 for discussion on DG. Table 3.5-1 shows the initial IRP Objective for DG.

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Table 3.5-1 Initial Distributed Generation IRP Goals

2006 2008 2009 2010 2011 (Actual)

Utility 24.6 TBD TBD TBD TBD Dispatchable DG (MW)

Customer 0.240 TBD TBD TBD TBD CHP (MW)

Note: Utility dispatchable DG in 2006 were installed as temporary mitigation units. As described in the Action Plan, HECO will evaluate continued use of these units and the feasibility of operating them on biodiesel.

3.6 Generation System Reliability

Having a sufficient amount of resources to serve the forecasted load is crucial to maintaining reliability for the electric system. Previous IRP have been criticized for not explaining the amount of new resources required on the system to maintain generation system reliability. HECO has established criteria for determining the sufficient level of generation on its system (see Section 5.1). These criteria take into account that not all resources contribute equally to the reliability of the system, for example the size of the generation and the duration of maintenance outages for different types of generating units would affect how much reliability the resource contributes to the system. Nevertheless, HECO developed for purposes of the initial target value for the specific IRP objective of generation system reliability an estimate of the amount of resources required to avoid reserve margin shortfalls. This estimate was based on the work done for the Adequacy of Supply report for February 2007. Table 3.6-1 shows the initial IRP goals for generation system reliability.

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Table 3.6-1 Initial Generation System Reliability Goals

Year Goal Reserve Capacity Shortfall With No Future Resource Additions

2007 No Shortfall 100 MW – 170 MW

2009 No Shortfall 160 MW – 220 MW

2010 No Shortfall 180 MW – 240 MW

2015 No Shortfall 220 MW – 290 MW

2020 No Shortfall 280 MW – 350 MW

2025 No Shortfall 330 MW – 370 MW

2028 No Shortfall 380 MW – 390 MW

3.7 Electricity Rates and Bills Impact

Electricity is an essential need for today’s society. The cost and affordability of electricity therefore is important for the safety, health and welfare of HECO’s customers. Accordingly, minimizing the impact to electricity rates and monthly electric bills is a major concern in the HECO IRP-4 process. At the same time, the other specific IRP objectives set forth above, especially the GHG emission reduction objective, would clearly require significant resource changes in the HECO’s IRP-4 preferred plan compared to the previous IRP plan. Therefore, HECO elected to not focus the effort early in the IRP-4 process on setting initial target values for electricity rates and bills, but rather to revisit this issue as information becomes available on the resources it would take to meet the previously stated initial IRP goals. See Section 8.7 for discussion on the estimated electricity rates and bills impact of the HECO IRP-4 preferred plan.

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Table 3.7-1 Initial Electricity Rates and Bills IRP Goals

2010 2015 2020 2025 2028

Rate Increase TBD TBD TBD TBD TBD

Bill Impact TBD TBD TBD TBD TBD

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4 GLOBAL WARMING

4.1 Introduction

It is becoming reasonably clear that climate change induced global warming will be the dominant environmental issue for the next several decades. As governments come to terms with the regulation of greenhouse gases (GHG’s), the pattern of fossil fuels use will be fundamentally reshaped. Even if carbon sequestration technologies prove technically and economically feasible the cost of energy resources will rise as society begins to pay for an environmental service that it had previously received for “free.” With increasing costs will come demand adjustments and potentially, in many parts of the world, adjustments in lifestyles and living standards.

With the enactment of Act 234 the Hawaii legislature committed the State to reduction of GHG emissions. Like similar statutes in other states, Act 234 was a statement of future intent rather than a detailed legislative solution to a problem. Act 234 established an emission target and a compliance timeframe that was modeled on climate change regulation being considered in . At the time of its enactment, Hawaii’s statute was one of only two state laws on this topic in the United States.

Rather than attempting to directly tackle an enormously complex issue, Act 234 established a commission (“Task Force”) of major stakeholders to provide recommendations on how the State should proceed. From the outset, the Legislature took the view that Hawaii needed a regulatory framework which reflected both the character of the State economy and unique characteristics of the local energy sector. Implicitly, this approach recognizes that the ‘best’ GHG reduction approach for Hawaii might be different from regulatory solutions suggested in other states or by the federal government.

4.2 Background on Greenhouse Gas (GHG) and Global Warming

4.2.1 What are GHGs?

While the role of greenhouse gases in climate change has historically been a topic of some controversy there is a scientific consensus of the link between carbon emissions and global warming. Even though GHG issues are commonly discussed in terms of carbon dioxide emissions there are, in fact, 6 major greenhouse gases: Carbon dioxide, methane, nitrous oxide and three groups of fluorinated gases (sulfur hexafluoride, HFCs, and PFCs). The gases are linked by a common scale; referred to as the global warming

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3 potential (GWP) index. The emphasis on carbon dioxide (CO2) is the result of this being the most common gas and the gas that is most amenable to public policy intervention.

4.2.2 How GHG Causes Global Warming

The exact link between release of the GHG and changes in world climatology and global warming is still being investigated by scientists. However, the general causal relationships have been understood for some time. Basically, most of the sunlight that falls on the earth is either absorbed by the earth’s surface or reflected back into space as infrared radiation. The greenhouse gases create an insulating layer in the atmosphere which traps a portion of the reflected sunlight and causes the atmosphere to slowly warm. In turn, the warming atmosphere causes climatic change and global warming.

GHGs are emitted from a number of sources related to the combustion of fossil fuels and to various natural or industrial processes. Typical (national) GHG emitters include: electricity and heat (24.6%), land use changes (18.2%), agriculture (13.5%), transportation (13.5%), industrial emissions (10.4%), other fuel combustion (9%), equipment leaks (3.9%), landfills (3.6%), and industrial processes (3.4%). Because of this wide variety of sources, GHG regulation must include a fairly detailed framework for carbon accounting.

4.2.3 Sources of GHG in Hawaii

For the HECO companies (and its independent power producers) the major source of GHG emissions is the combustion of oil products (residual oil, diesel fuel, and ) to power electrical generators. The reduction of these emissions is a major focus of the Company’s response to meet its Act 234 responsibilities. To the degree that HECO can replace generation from its existing generators with low emitting renewable energy sources, achievement of the GHG target will become more feasible. However, it should be noted that the “life cycle” of many renewable resources, including biofuels, wind and photovoltaic cells, involve the release of some GHG during growing, manufacturing, or processing. The only energy strategy which is entirely free of carbon is savings from energy conservation / energy efficiency programs.

The other major GHG emitter in Hawaii is the transportation sector. While emissions from surface transport (automobiles and trucks) are substantial, jet fuel and marine transport emissions are substantially larger. In fact, emissions from jet fuel account for almost 30% of Hawaii’s GHG emissions. The importance of marine and air emissions is

3 The GWP depends on both the efficiency of the molecule as a greenhouse gas and its atmospheric lifetime. Other gases are considerably more potent than CO2. Methane, for example has a GWP that is 22 time that of CO2.

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a major factor which differentiates Hawaii from the rest of the country. Table 4.2-1 presents DBEDT preliminary estimates of Hawaii emission by source.

Table 4.2-1 Preliminary Estimate of GHG Emissions in 1990 and 2005

Expressed as Global Warming Potential (Tons Carbon dioxide equivalent CO2E) % Change Energy Sector 1990 2005 1990-2005

Residential, Commercial, Industrial 1,038,657 2,271,802 118.7%

Electric Utilities (and IPP's) 7,556,515 9,039,571 14.7%

Stationary Subtotal 8,923,172 11,311,672 26.6%

Ground Transport 3,395,696 4,992,307 26.3%

Domestic Aviation and Marine 3,880,601 3,717,036 -4.2%

International Aviation and Marine 6,432,255 4,722,044 -26.6%

Transportation Subtotal 14,208,644 13,431,887 -6.5%

Energy Total 23,131,816 24,743,560 7.0%

Non-Energy Sector Industrial Processes (Gas, Refining, Storage Transportation) 4,977 5,157 3.6% Industrial Processes; Cement Manufacturing 109,274 ENDED 1995 ----

Industrial Processes Subtotal 114,251 5,157 -95.5%

MSW Management 1,161,291 1,701,100 46.5%

Wastewater Treatment 21,513 22,923 10.9%

Domesticated animals 273,879 192,119 -29.9%

Manure Management 129,768 56,774 -56.2%

Sugarcane Burning 31,598 19,727 -66.2%

Fertilizer Use 60,850 67,310 2.4%

Non-energy use 1,793,559 2,052,180 14.4%

Total 24,925,375 26,795,740 7.5%

Source: DBEDT

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4.2.4 General Policy Options

There are two basic approaches to regulating GHG emissions: (traditional) command and control regulation and (newer) “market-based measures.” Current regulatory thinking favors market-based measures. These market measures involve two alternative approaches: a carbon tax or a ‘cap-and-trade’ scheme. One of the major issues facing the Act 234 Task Force will be to evaluate the impact of these alternatives on the State economy and on various stakeholder groups.

Command and Control Regulation

Historically, air pollution emissions have been approached through a system of government decreed standards and benchmarks. Typical examples of command and control measures in the energy sector include; • Federally imposed fuel efficiency standards on vehicles • State imposed renewable portfolio standards (RPS) for regulated utilities aimed at minimizing greenhouse gas emissions though development of renewable generation technologies like wind or geothermal. • State imposed building efficiency standards.

Under most command and control systems a failure to meet prescribed standards results in substantial fines or penalties and, in extreme cases, can involve a loss of operating licenses.

Market-Based Approaches

Carbon Tax: under this approach a tax is imposed on fuels based on their carbon content. The tax is levied on oil refineries and importers of fossil fuels (refined products, natural gas, and coal, but not crude oil unless this could be burned directly). This tax would directly increase the cost of transportation fuels, gas, and coal and indirectly increase the cost of all goods and services that use fossil fuels, including electricity. In turn, as consumers respond to the higher prices they would reduce their consumption of fossil fuels. For energy intensive goods where energy represents a major cost, the prices of goods and services could rise significantly.

A carbon tax would be less burdensome to impose and administrative costs are likely to be modest. In addition, imposing a cap-and-trade program (see next section) in a small market like Hawaii, with few buyers and sellers, could be problematic. For these reasons a carbon tax levied across the board on carbon might theoretically imply lower per capita increases. The other major advantage of a carbon tax is its flexibility. If a given tax rate is not achieving the desired carbon reduction the tax rate might be readily changed.

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Cap and Trade System: The other major market-based mechanism is a cap and trade system. Caps on greenhouse gas emissions would be determined by the State and either a statewide target or industry specific targets would be established. If a statewide target were set for carbon emissions, then the regulatory mechanism would be similar to that of the carbon tax described above.4 Under the cap and trade system, distributors of fuel would be required to obtain a permit for each ton of GHG that they produce.

Emission allowances under the caps would either be distributed free or auctioned. Emitters that produce fewer greenhouse gases than their allowance ceiling would be allowed to sell their excess allowance as ‘emission credits.’ Emission credits could also be purchased from carbon sequestration projects such as the planting of trees that absorb CO2. These credits are referred to as carbon offsets. Emitters who cannot meet their allowance ceiling could purchase emission credits from other emitters or, under specified ‘safety valve’ conditions, from government.

For the market-based regulatory mechanisms (cap and trade, and carbon tax), large sums of money would be generated. These funds might be used to ease the financial burden on disadvantaged groups; directly reduce emissions through demand management and energy efficiency programs; or encourage specific types of related development, like forest sequestration. It would also be possible to simply return some of the money to consumers through the tax system.

4.3 HECO Policy on Global Warming

In January 2007 the HECO Board of Directors issued a policy Statement on Global Warming. The statement recognized the potential for climate change associated with the burning of fossil fuels and committed the Company to planning strategies which would minimize its contributions to global warming. The text of the Company policy statement is as follows: “Hawaiian Electric Company shares the very serious concerns of many regarding the potential effects of global warming and human contributions to this phenomenon, including the burning of fossil fuels for electricity production, transportation, manufacturing, agricultural activities and deforestation. To effectively address global warming, actions addressing all contributing sources must be taken with priority given to those which provide the greatest benefit for the costs involved. To be successful, the response to global warming requires commitment by private sector businesses, all levels of government, and every member of the public. At Hawaiian Electric, we remain committed to taking direct action to mitigate the contributions to global warming from electricity production. Such action has and

4 The tax and cap-and-trade system would yield the same emission reductions if the tax were equal to the permit price.

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will continue to include promoting aggressive energy conservation and transitioning to clean, efficient and eco-effective energy production in all markets that we serve.”

January 29, 2007

4.4 Summary of Potential Federal Legislation

The Clinton administration was a major supporter and participant in discussions which eventually led to establishment of the Kyoto Protocol. While the Protocol was signed by the United States, the US Senate voted against ratification and the US has remained outside the Protocols’ regulatory system. Once in power, the Bush Administration rejected the need for international regulation and took the view that curbing GHG emissions should be based on voluntary compliance programs and technology advances.

Since 2002, a number of climate change bills have been introduced in Congress. There are currently six draft bills before Congress.5 The most recent legislative proposal is the Lieberman-Warner Act (S.2191) proposed in October 2007. The best known, and most studied, federal proposal is the Lieberman-McCain Act (S.280). Lieberman-McCain has been used in IRP-4 as a loose prototype model of future Federal legislation. However, it is recognized that none of the existing proposals (including Lieberman-McCain) is likely to be enacted without substantial modification.

4.4.1 Lieberman-McCain: Climate Stewardship and Innovation Act of 2007 (S.280)

Many of the basic principles underlying S.280 were established in earlier versions of the bill (S.139: 2003). S.280 was chosen as proto-legislation for IRP-4 because of the extensive analysis of its provisions undertaken by the Federal Energy Information Administration (EIA) and other policy research organizations. The legislation envisages a cap-and trade system, with domestic carbon offset credits for the period 2012-2050. The economic impacts of the proposed legislation are evaluated through 2030. This period corresponds with the IRP-4 forecast period.

5 Bingaman-Specter: Low Carbon Economy Act of 2007 (S.1766) Sanders-Boxer: Global Warming Pollution Reduction Act of 2007 (S.309) Feinstein-Collins-Snowe: Electric Utility Cap and Trade Act of 2007 (S.317) Kerry: Global Warming Reduction Act of 2007 (S.485) Lieberman-McCain Climate Stewardship Act of 2007 (S.280) Lieberman-Warner (S.2191) Americas Climate Security Act of 2007 (S.2191)

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4.4.2 Needs and Usefulness of a Federal Policy Model

Since Hawaii’s Act 234 (and the legislation in other states like California) is still largely undefined it is necessary to make some assumptions about the provisions and impact of eventual GHG legislation. Several questions are of importance to the IRP-4 analysis. First, it is important to have a benchmark estimate of how energy demand might respond as a result in reducing GHG emissions to 1990 levels (as specified in Act 234). Second, since an important feature of cap and trade regulation is the creation of tradable emission credits, it is necessary to have a proxy estimate of the potential prices of such carbon credits.

4.4.3 Lieberman-McCain Results Used in IRP-4

As noted, the EIA did a lengthy analysis of the impacts of S.280.6 Two findings were used in the IRP-4 analysis: the price-demand response (elasticity) needed to reduce 2030 emissions to 1990 levels (as specified in Act 234) and the projected price of carbon credits. Although the EIA presented year by year forecasts for these two variables it was felt that such detailed information was beyond the precision of the IRP and would unnecessarily complicate interpreting the modeling results. As a result a single value was adopted for the price-demand response and two values were adopted for the price of carbon credits. For purposes of the demand response a reduction of base case demand of 6% was adopted for the period from 2012 (when both Act 234 and S.280 were scheduled to take effect) to the end of the plan period.7

Estimation of carbon credit prices was more complicated since two different policy scenarios are widely discussed. The first carbon credit price assumed in the IRP-4 analysis was $10/ton of CO2. This price assumption reflects a widely held policy option designed to prevent runaway carbon prices from damaging the economy. This option is commonly called a “safety valve” and assumes that a ceiling price or price cap will be needed on carbon prices.8 The second carbon price assumption used in IRP-4 assumed carbon prices at $25/ton of CO2. The EIA analysis of S280 assumed that this price corresponded to a free, unrestricted world-wide market for GHG credits.

Reservations exist about applying Lieberman-McCain results to Hawaii. In adopting the S.280 analysis as a model, there is no suggestion that this approach will ultimately be selected for implementation in Hawaii under Act 234. Similarly we recognized that numbers generated from national studies may be of limited applicability to Hawaii.

6 This analysis can be found in its entirety at http://www.eia.doe.gov/oiaf/servicerpt/csia/index.html 7 The EIA analysis assumed that the price response to rising energy prices for the sort of residential/commercial customers that make up the HECO demand base would be 5-6% in 2020 and 10-11% in 2030. 8 Under a safety valve scheme, at carbon prices above $10/ton of CO2, the government would simply sell any necessary permits at the safety valve price.

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Nevertheless, a benchmark was needed from which to start our analysis based on a well researched and widely recognized piece of proposed federal legislation.

Further, there is a strong possibility that before Act 234 can be implemented, it will be superseded by federal climate change legislation. S.280 has many of the same policy mechanisms put forth in other current proposals and therefore is a useful proxy for what future federal legislation may look like.

4.5 Federal Activities Related to Global Warming/Climate Change

4.5.1 Climate Change Science Program

In 2002 the federal government established an interagency coordinating group to oversee climate change activities. This agency, called the “Committee on Climate Change Science and Technology Integration” is headed by the Secretary of Energy and reports to the Office of the President. The committee is charged with overseeing federal research on global warming and climate change.

4.5.2 Department of Energy

In addition to the legislative analysis undertaken by the EIA, the Department of Energy (DOE) has a number of climate-related programs. These programs involve both departmental level initiatives such as DOE’s Climate VISION (Voluntary Innovative Sector Initiatives: Opportunities Now) program and a variety of climate-linked studies being undertaken by the various national laboratories. One prominent DOE agency involved in GHG related studies is the Office of Fossil Energy. The Office of Fossil Energy has active programs designed to: (1) Make fossil energy systems more efficient, and (2) capture and sequester greenhouse gases.

4.5.3 Environmental Protection Agency

In keeping with its air pollution regulation mandate, the EPA has several active climate change programs. EPA is part of the federal government’s interagency ‘Climate Change Science Program’ and has primary responsibilities in: 1) coastal elevation and sensitivity to sea level rise; 2) reviews of adaptation options for climate-sensitive ecosystems and resources; and 3) analyses of the effects of global change on human health and welfare. In addition, EPA is likely to assume a primary role in implementing any climate change regulations that may eventually be adopted by Congress.

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4.6 Global Warming Actions in other Jurisdictions

4.6.1 Carbon Trading Markets

As GHG regulation has emerged as a major environmental policy issue a number of institutions, markets, and trading facilities have been created to facilitate the trading of carbon credits. Since the US has no GHG regulation scheme, these institutional markets are still in their infancy and, in this country, mainly serve the special needs of a limited clientele.9 Due to the small market being serviced and the gradual introduction of the European emission reduction standards, current prices on these exchanges are probably not representative of potential longer term carbon credit price levels under a formal world-wide regulatory system. Early carbon trading has suggested the need for much tighter validation, regulation and monitoring of the carbon credits that are being offered for sale. The current experience of the climate exchange markets in the U.S. and Europe is providing valuable knowledge and insights into how a future market-based cap-and-trade mechanism might function.

Chicago Climate Exchange (CCX) is a voluntary, legally binding greenhouse gas (GHG) reduction and trading system for emission sources and offset projects in North America and Brazil. CCX employs independent verification of credits offered for sale; includes all six greenhouse gases; and has been trading greenhouse gas emission allowances since 2003. The 350 companies in the exchange committed to reducing their aggregate 2010 emissions by 6%. CCX has an aggregate baseline of 226 million metric tons of CO2 equivalent, which is approximately 4% of U.S. annual GHG emissions. CCX owns the European Climate Exchange.

The European Climate Exchange (ECX) manages the marketing and product development for ECX Carbon Financial Instruments (ECX CFIs). The ECX contracts are standardized and electronic traded. More than 80 businesses are members and trade ECX products. In addition, several hundred clients can access carbon markets via banks and brokers. ECX/ ICE Futures are the most active European platform for carbon emissions trading, attracting over 80 % of the exchange-traded volume in the European market.

4.6.2 State and Regional Initiatives

In the absence of federal GHG regulation, several state and regional climate change initiatives have been proposed or implemented. The most visible and comprehensive of these initiatives are the California Climate Change Law and the Regional Greenhouse Gas initiatives (RGGI) undertaken by New England and Mid-Atlantic States. These two schemes share many similarities as well as substantial differences. Taken together they

9 In Europe, the climate exchange serves the credit trading needs of firms within the European Community in meeting their obligations under the Kyoto Protocol.

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represent the cutting edge of climate change policy thinking. The general approach adopted by California was the model for the Hawaii climate change legislation (Act 234).

California’s law caps the state’s greenhouse gas emissions at 1990 levels by 2020. This emissions program to mandate an economy-wide emissions cap that includes enforceable penalties. The bill requires the California State Air Resources Board (CARB) to establish a program for statewide greenhouse gas emissions reporting and to monitor and enforce compliance with this program. It also authorizes the state board to adopt market-based compliance mechanisms including emissions cap-and-trade, and allows a one-year extension of the targets under extraordinary circumstances. California’s law covers all industries and economic sectors.

In late 2005 the governors of seven states signed a memorandum of understanding that established the Regional Greenhouse Gas Initiative (RGGI). The regional agreement sought to develop a multi-state cap-and-trade program covering greenhouse gas (GHG) emissions. The program was aimed at developing a program to reduce carbon dioxide emissions only from power plants in the participating states. The accord takes effect in 2009, and is designed to reduce carbon dioxide pollution to a level 10 percent below current emissions by 2019.

4.7 Hawaii Global Warming Solutions Act (Act 234)

Act 234 (Global Warming Solutions Act) was passed by the Hawaii State Legislature in its 2007 session and was signed by Governor Lingle in June 2007. It establishes statewide greenhouse gas emissions limits at or below the statewide greenhouse gas emissions levels that prevailed in 1990. This compliance target is to be achieved by January 1, 2020. It also establishes a greenhouse gas emissions reduction task force to prepare a work plan and regulatory scheme to achieve the statewide greenhouse gas emissions limits. Other provisions and target dates of the Act 234 include: • By December 31, 2008, DBED&T and DOH shall complete an updated inventory of emission sources and carbon sinks. • Before December 1, 2009, the GHG emission reduction task force shall prepare a work plan and regulatory scheme for implementing the maximum practically and technically feasible and cost-effective reductions in GHG emissions from sources to achieve the statewide GHG emissions limit. (In October 2007 the Task Force held its initial meeting) • The sum of $500,000 for each of two years was appropriated to support the policy work of the task force and the Inventory work of DBEDT/DOH.

In August 2007 several University of Hawaii research organizations came together to consider ways in which they might support the GHG emission reduction task force in the implementation of Act 234. Following the initial meetings a coordinated research agenda was prepared. The groups agreed to prepare a carbon inventory for the state

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and to proceed with modeling work using existing UH Economic Research Organization (UHERO) economic models. An initial report on the carbon inventory was published in early September 2008. The UH work was supported by a grant from HECO and private donors and will be presented to the task force and legislature late in 2008.

4.8 Global Warming Issues for Hawaii

Before effective climate change legislation can be implemented there are a number of critical questions that need to be resolved. Some of these issues were anticipated in Act 234 while other issues are a consequence of Hawaii’s economic situation or of special definitional questions. This section will consider some of these special issues. This discussion will consider GHG issues from the perspective of state policy. It is important to note that not all of these issues relate to the electricity sector, HECO or IRP-4.

4.8.1 Establishing a 1990 Carbon Emission Standard

An essential prerequisite for climate change policy is the development of a climate change registry which establishes ‘current’ and ‘target’ (e.g., 1990) emission levels for all major GHG emitters. Act 234 specifically mandated DBEDT/DOH to complete this task by December 31, 2008. Prior work by DBEDT to catalogue emissions and carbon sinks in this state10 was not considered to be sufficiently detailed for the purposes of Act 234, though this work had been annually updated.

4.8.2 Establishing CO2 Emissions standards - Conceptual Issues

Lifecycle versus Tailpipe Emissions - One of the major issues in establishing a carbon registry is setting up a flexible carbon accounting system. A significant issue here is whether to measure estimated carbon emissions on a “tailpipe” or “lifecycle” basis. A tailpipe measurement essentially focuses only on the final emissions released to the atmosphere, e.g., from an automobiles tailpipe or a power plant’s smokestack. In contrast, a ‘lifecycle’ measurement supplements tailpipe releases with estimates of any carbon releases that may have been necessary to bring the fuel to the end user. In the case of a fossil fuel generating plant, a life cycle measurement would add any carbon releases involved in extracting, transporting or refining crude oil or coal to actual smokestack releases. For new fuels like biodiesel these calculations can sometimes be complicated.

Jurisdictional Issues - For Hawaii this issue is especially complicated because our energy is imported from a number of sources and some fuels, like jet fuel, are both refined here and imported as finished products. In the context of global warming, the most difficult carbon accounting questions relate to jurisdictional problems. For example, if HECO’s biodiesel is produced from a feedstock crop like palm oil, which is

10 See Hawaii Climate Change Action Plan (Nov 1998) and Hawaii Energy Strategy 2000 Documents.

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grown in other countries, how are lifecycle emissions and credits to be accounted for? Since the growing crop takes up (sequesters) carbon from the atmosphere there should be a credit against eventual stack releases. But who gets the credit? If the crop is grown in Hawaii obviously someone in the state should get sequestration credits but what if the bio-diesel feedstock crop is grown in Malaysia or the ethanol feedstock crop is grown in El Salvador? This sort of conceptual issue will need to be resolved as part of the Act 234 implementation processes. The GHG assumptions used in IRP-4 are further discussed below and in the “Fuels” Chapter.

4.8.3 Accounting for Air and Marine Transport

Although air and marine emissions are specifically excluded under Act 234, they cannot in fact be excluded under general GHG legislation. As noted, emissions from jet fuel are the single largest source of CO2 in the state and, of course, air travel is vital to Hawaii’s tourist industry. Likewise, marine transport is the lifeblood of the importation of goods to the local economy. These are enormously important economic questions but they are not within the state’s regulatory control. Rather than avoiding these transportation issues it has been argued that the state’s GHG system should examine the impacts of including air and marine emissions and use the results of the analysis to influence national legislation.

4.8.4 Waste-to-Energy Projects

While Waste-to-Energy (WTE) projects like H-Power do not use fossil fuel they do generate significant amounts of GHG emissions from the burning of municipal solid waste (MSW). This GHG emission appears in the carbon inventory as a separate entry from the GHG (methane gas) that is generated by the states sanitary landfills (e.g., by burying rather than burning the MSW). Proponents of MSW projects argue that the combustion of municipal waste generates less GHG than if the waste were deposited in the land fills and resulted in increased methane releases. By extension, MSW proponents feel that they should receive an offset credit for the methane that is avoided through incineration.

Whether an offset should be granted and whether methane savings are equal to or exceed direct WTE emissions is a complicated question involving both direct measurements and the application of general policy principles that define which sorts of carbon sequestration would qualify for offset treatment under Act 234.

The treatment of GHG emissions from WTE projects is particularly important for our state since the capacity and acceptability of sanitary landfill sites is severely limited. Bringing MSW/WTE facilities (without a methane offset that is equal to or greater than smokestack emissions) under a GHG regulatory system would directly increase the cost of municipal waste disposal since the counties would have to purchase offsets on the open market.

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4.8.5 Prior & External Sequestration Programs

At the heart of any cap and trade regulatory system is the notion of tradable credits. Emission credits are generated in one of two ways: 1) through the initial allowance permitting system and 2) from special projects which remove (sequester) carbon from the atmosphere. After acquiring credits sufficient to cover estimated emissions a company may find it profitable to undertake relatively inexpensive internal reduction programs and sell their ‘allowance credits’ to other firms at a profit. Alternatively, a company needing to acquire emission credits may purchase ‘offset credits’ in the open market. Offset credits come about as a result of deliberate sequestration activities such as the planting or protecting of forests which absorb carbon from the atmosphere and capture the carbon in living plants or crops.

In Hawaii one independent power producer, AES, anticipated GHG regulation and purchased a rainforest in Paraguay as an offset against its emissions in Hawaii. Without question this was a farsighted act; however, whether such an external offset would be allowed under Act 234 or, for that matter, under many of the proposed federal climate change Acts, is still to be determined.

The reason for limiting ‘offset’ credits to domestic resources is both political and financial. If unrestricted foreign offset credits are permitted there could be very substantial outflows of money from states (or countries) needing credits to mainly low income developing nations. Clearly, the purchasing states would prefer to keep this money at home -as investments in local offset projects.

For the purpose of IRP-4, no carbon offsets were assumed for either H-Power (reduced methane for the landfills) or for the AES rainforest project. In both cases it was felt that this determination should be made in the course of implementing Act 234 so the conservative assumption was made that offsets would not be included in the analysis. This IRP-4 assumption does not imply any company policy or attitude toward the legitimacy or validity of the H-Power and AES claims.

4.8.6 Emissions from Independent Power Producers

A major jurisdictional issue that must be addressed in implementing Act 234 is who will be responsible for the emissions of the independent power producers (IPPs) that sell power to HECO. Most of the IPPs were established after the 1990 compliance target date. Therefore, IPP emissions would show up as additional emissions in the carbon registry.11 HECO has no contractual authority to restrict IPP emissions from these independent contractors nor does Act 234 provide any guidance on how this problem will eventually be addressed. This situation is likely to become further complicated in the

11 In fact, if only the reductions form HECO owned generation units are considered the Company actually produced fewer emissions in 2006 than it did in 1990.

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future under recent PUC rulings that require that new additions to the HECO system will be subject to competitive bidding.

4.8.7 Accounting for Energy Conservation / Efficiency Programs in IRP

Under PUC Decision and Order No. 23258, filed on February 13, 2007, in Docket No. 05-0069, a third-party administrator will assume overall responsibility for new Demand-Side Management (DSM) programs in 2009. The intention is that the third- party administrator will solicit outside contractors to manage the energy efficiency DSM programs. Conservation and DSM will play an enhanced role under a GHG regulatory scheme, but will not be under HECO’s control. This means that the allocation of emission permits to the Company will need to be based on the performance of programs and contractors who are not responsible to the Company. In the (likely) event of over or under performance of the third party DSM program, additional carbon offset credits will need to be bought or sold to meet the compliance targets. How these transactions will be handled and financed will need to be worked out as part of the implementation strategy for Act 234 and through discussions with state regulators.

4.8.8 Economic Justice and Freedom of Choice

The clearly acknowledged idea behind using either of the market mechanisms to regulate GHG is that price increases will cause reductions in energy demand and lead directly to a reduction in carbon emissions.

Increasing energy prices are likely to have a disproportionate impact on low income and disadvantaged groups. To achieve compliance targets these impacts will be substantial and especially pronounced in Hawaii due to the already high cost of living. These social justice consequences of climate change regulation will need to be addressed in the eventual implementation path identified for Act 234. It may be necessary to identify compensatory programs or mechanisms by which disadvantaged groups can counterbalance the price increases. Clearly, expanded DSM /energy conservation programs will have an important role to play in these compensatory programs.

A major distinction between a series of command and control regulations versus using market based mechanisms is the freedom for consumers to choose carbon solutions that best suit their needs. High carbon intensity choices by consumers should be reflected in high carbon prices. The fundamental assumption of a market approach to GHG regulation would maintain freedom of choice as a priority.

This principle is as applicable to the generation of electricity as to the purchase of a heavy vehicle or high horsepower automobile. For example, if society highly values MSW projects like H-Power then such technology options should be included in the

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HECO generation mix- with carbon reductions from elsewhere in the integrated resource planning process.

4.8.9 Transportation Technology and Electrical GHG Emissions

Emerging technologies may soon blur the distinction between GHG emissions that result from electrical generation and emissions that result from land transport technologies. Of particular importance in the next five to seven years will be the construction of the mass transit system from Kapolei to the city center and the potential emergence of plug-in hybrid electric vehicles (PHEV). Current indications are that the shift from gasoline powered transport technologies to electrically powered transport technologies will have a substantial impact on reducing overall GHG emissions. While the overall reductions will clearly benefit the state, obviously the additional electricity consumption to support this transportation demand will increase emissions from HECO. A mechanism will need to be designed to address the carbon costs and savings of this technology and inter- sectoral shift.

Recent studies suggest that PHEV’s can result in net GHG reductions of between 40-65% over conventional vehicles.12 While these vehicles are not yet available from manufacturers, it is anticipated that they will become commercially available by 2010 and may comprise as much as 25-30% of the vehicle fleet by the end of the IRP-4 planning period in 2030.

Although less dramatic than the PHEV net GHG reductions, there are clear GHG savings associated with the development of the mass transit system connecting the Ewa plains and city center areas. As currently conceived the mass transit system will require about 20 MW in 2013 and 60 MW in 2030 of power.

4.9 Summary of GHG Assumptions Used in HECO IRP-4 Modeling

As suggested in the background discussions presented in Sections 4.2 and 4.8, there are many unresolved issues in adapting the IRP models to the new GHG legislation. Since IRP-4 must proceed in parallel with studies to define Act 234 implementation issues, a number of assumptions must be made about the eventual form of Act 234 which may not parallel the final version that is recommended.

A number of sensitivity studies were conducted to highlight potential impacts of various factors on the resources and plan. Given the uncertainties surrounding the implementation of Act 234, the sensitivity studies were intended as proxies for potential options rather than trying to model one specific future.

12 EPRI-NRDC, Environmental Assessment of Plug-in Hybrid Electric Vehicles, July 2007.

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For the purposes of IRP-4, basic assumptions need to be made for the six previously explained GHG-linked variables: • A 1990 compliance emission target. • The demand response to increasing electricity prices by consumers. • The carbon content of low sulfur fuel oil (LSFO), diesel fuel and biodiesel. • Treatment of the carbon offsets for landfill methane avoided by H-Power and the Paraguay rainforest owned by AES. • The cost of carbon credits under various policy mechanisms. • The role and cost of various levels of DSM and energy conservation measures.

In addition, an assumption needs to be made about who will assume the responsibility for emissions from the IPPs and what might be the impact and timing of mass transit and PHEVs.

IRP-4 assumed that the 1990 emissions estimates contained in the Hawaii Climate Change Action Plan13 reflect the emissions target anticipated in Act 234. Likewise, it is assumed that 2006 emissions will reflect estimates presented by DBEDT at the IRP-4 Climate Change Workshop.14 These estimates have been presented above in Table 4.2-1. Both of these assumptions are likely to change as a result of the carbon registry project presently underway by UHERO and Dept of Health / DBEDT but, at this point, they are the best estimates available.

We have borrowed the demand response to rising energy prices from the EIA’s Lieberman-McCain analysis. As noted in Section 4.4.3, EIA estimated the national reduction in electrical demand brought on by GHG price increases to be approximately from 6% to 11% over the IRP period. Since Hawaii is starting from a point of having the nation’s highest electricity prices, we modeled that demand would decline by 6% beginning in 2012 (e.g., the commencement of Act 234 compliance). We chose a single (6% reduction) rather than a variable demand reduction to increase the transparency of the plan results.

As mentioned above the carbon accounting system for GHG emissions is still under study and a literature search suggested a range of potential carbon estimates as various authors assumed one or another factors should be included in the life cycle emissions of biodiesel. We adopted the results of the most commonly used reference study conducted by the federal governments National Renewable Energy Laboratory (NREL)

13 DBEDT, Hawaii Climate Change Action Plan, November 1998: Page 3-2. 14 Held in Honolulu on June 8, 2007.

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in Colorado.15 The NREL emission estimates have been collaborated by detailed studies undertaken by the Australian government which showed that biodiesel produced from palm oil grown on established plantations reduced life cycle emissions by 79% when compared to fossil diesel.16 For the purposes of the IRP analysis, we assumed that biodiesel would have 25% of the carbon content of fossil diesel.17

While we recognize the logic behind the avoided methane and rainforest offsets suggested by H-Power and AES, we felt that acceptance of these offsets was a decision that only the legislature could make. As noted above, there are clear and plausible arguments for both acceptance and exclusion. We chose to exclude these offset credits from the IRP analysis even though other generation elements in the IRP plan would need to compensate by carrying a greater emissions reduction burden.

As described above, our approach was to adopt the findings of Lieberman-McCain but to substitute a single price for the variable carbon price methodology adopted by EIA. The IRP-4 analysis analyzed two different sensitivities for carbon prices. In the first sensitivity we assumed an unconstrained worldwide, free-trade carbon price of $25/ton of CO2. In the second scenario we assumed the enactment of safety valve mechanism to protect against the economic consequences of runaway carbon prices. A literature search suggested that $10/ton was an appropriate ‘safety valve’ assumption.

Since DSM / energy conservation are the only carbon-free options on which everyone agrees and the only option for consumers to offset price increases associated with GHG regulation we assumed continuation of our existing DSM/energy conservation efforts even though these projects will no longer be under Company control after 2008. Due to the price increases associated with the climate change initiative it is highly likely that additional energy conservation efforts may become economical during the course of IRP-4.

Given all the uncertainties surrounding the implementation of Act 234 there is some likelihood that our base case assumptions will not mirror what is proposed. Against this possibility we have prepared a number of sensitivity cases to examine the impacts of variations in the key parameters. These sensitivity studies are summarized in the Integration Chapter.

15 In 2005 the National Renewable Energy Lab (NREL) conducted what has become a ‘benchmark’ carbon life-cycle study for biodiesel. This study concluded that biodiesel reduced emissions by ~78% when compared to fossil diesel. See Sheehan,J., Camobreco, J., Duffield, Graboski, M., Shapour, H.; Life Cycle Iinventory of Biodiesel and Petroleujm Diesel in a Urban Bus; NREL/SR-580-24089 and An Overview of Biodiesel and Petroleum Diesel Life Cycles. 16 Beer,,T., Grant, T., Campbell, P, The greenhouse and air quality emissions of biodiesel blends in Australia, CSIRO Report KS54C/1/F2.79, August 2007 17 There is a rich literature on the GHG emissions of biofuels. Readers interested in learning more about this topic might consider reading the recent Worldwatch Institute Study Biofuels for Transport; Chapter 11 (Effects on Greenhouse Gas Emissions and Climate Stability); EARTHSCAN, 2007.

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4.10 How HECO’s Action Plan Proposals Reflect Future GHG Uncertainties

For the purposes of IRP-4 we have made simplifying assumptions about several institutional and technological issues. In some cases we have been forced to make assumptions about the actions and decisions of people outside the Company. For example, after 2008 HECO will turn over responsibility for energy efficiency DSM programs to an independent third party administrator. This administrator may chose to take the DSM program in entirely new directions that have not been anticipated in IRP-4.

Likewise, IRP-4 makes a number of technological assumptions that may be quickly overtaken by events. Examples might include carbon sequestration technologies such as methane capture from landfills, or capture and burial of fossil fuel emissions, or sequestration and carbon recycling through aquaculture of algae (and recycle to biofuels). Breakthroughs in areas such as these could quickly transform the emissions strategy in the state. In short, IRP-4 presents a plan, which under certain circumstances, may be quickly outdated. Updates to the IRP4 plan will be reflected in subsequent evaluation reports submitted to the Public Utilities Commission.

As described in the next chapter the results of our analysis suggest that the basic planning strategy of IRP-4 will make it possible for us to comply with Act 234 and/or Lieberman-McCain. However, the Company is committed to search for carbon neutral technologies for new generating units and ways to reduce carbon emissions that go beyond the 1990 target set out in Act 234. As a small utility we cannot fund basic research on carbon neutral technologies but we can participate through trade organizations like EPRI and through direct collaborative ventures with other utilities to pursue technologies which we believe make sense in Hawaii’s unique energy environment. Even though the range of possible technologies is almost limitless we believe that the most promising technologies are likely to be those that make use of our indigenous natural resources. We believe that technologies which take advantage of our semi-tropical climate (biofuels), our marine environment (OTEC, wave and tidal power) and our geology (geothermal) should receive particular attention. Investigations into these alternatives form a major part of our Action Plan activities.

As noted there are a number of promising technological options for sequestering carbon dioxide and other greenhouse gases. Many of these options are based on the capturing, and storing by burying the carbon. The Department of Energy estimates that the capture and storage of GHG from power plants will represent about two-thirds of the costs of most of these sequestration technologies.

Currently most attention is focused on burial of captured carbon in geological formations in the western states. Although marine burial is theoretically feasible there are major environmental barriers and uncertainties to be addressed. We do not believe that marine disposal of GHG will be acceptable over the near term so the capture and

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sequestration of GHG emissions from Hawaii will require transfer to land burial sites on the U.S. mainland.

Three aspects of carbon sequestration are of particular importance to Hawaii. First, of considerable economic importance, is the direct relationship of sequestration costs to the price of carbon credits and the eventual economics of climate change regulation. Second, the prospect that captured GHG might be recycled as an algae nutrient (from which local biodiesel can be produced) is extremely exciting and could directly transform a GHG disposal problem into an opportunity. Third, if eventual sequestration strategies are based on U.S. mainland burial sites then Hawaii’s energy consumers may need to absorb the significant costs of transferring our GHG sequestration funds to the U.S. mainland. None of these factors have been incorporated into IRP-4 but we recognize that each of these factors may play a significant role in the eventual economics of implementing the climate change plan.

Since the IRP is a long term plan for developing electrical infrastructure on Oahu it needs to incorporate definable risks in its analysis. With the recognition that global warming / climate change will present major challenges over the 30 year period of the plan it is important to assess the environmental risks to the Oahu’s electrical infrastructure.

Although precise predictions of impact of climate change on Hawaii will not be available for several years, the general impacts of global warming are sufficiently well understood to permit development of a general adaptation framework. Commonly associated global warming impacts18 include: • Warming air and water • Changes in the location and amount of rain and drought • Increase storm intensity • Sea level rise and • Changes in ocean characteristics

While some of these changes, such as sea level rise, will eventually have reasonably predictable timeframes, other changes like the frequency and intensity of storms will involve largely unpredictable events.

HECO believes that each of these impacts can be systematically (if not definitively) accommodated in our long term planning through risk management strategies and through direct adaptive measures. As part of the IRP-4 Action Plan, preliminary studies will need to be undertaken to identify those parts of the HECO system which may be most impacted by global warming and to establish a timetable for addressing adaptive

18 EPA, National Water Strategy- Response to Climate Change, March 2008.

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measures. Of equal importance, work will begin on establishing long term planning principles that explicitly recognize the risks of global warming.

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5 OTHER PLANNING CONSIDERATIONS

5.1 Capacity Planning Criteria

Compliance with HECO’s capacity planning criteria is critical to maintaining an adequate amount of capacity and reliable operation of the HECO generating system. All future resource plans, regardless of perspective, were developed to satisfy the load service capability and quick load pickup criteria, the reliability guideline, and the spinning reserve requirements at a minimum.

Early in the HECO IRP-3 planning process, questions were raised on HECO’s current capacity planning criteria by Advisory Group and Technical Committee members. In response to these questions, HECO had an independent consultant, Shaw Power Technologies, Inc., perform a review of HECO’s capacity planning criteria and assess whether these criteria are appropriate for continued use in the integrated resource planning process. The consultant’s study, provided in Appendix P, concluded that the current reliability guideline of 4.5 years per day is reasonable for a regulated vertically integrated utility on Oahu. HECO’s current capacity planning criteria are also provided in Appendix P and are summarized below. These criteria were applied in computer simulations using the Strategist model developed by Ventyx to determine the appropriate timing of supply-side resource additions. Results of this analysis are reviewed in Chapter 8.

5.2 Operational Requirements of Generation System for Today and Tomorrow

Although HECO does not currently have any substantial amount of renewable, as-available resources on its system, HECO is well aware of the issues pertinent to integrating intermittent, as-available resources, such as wind or photovoltaics, onto the grid based on the experiences of its sister companies, HELCO and MECO. HELCO is a world leader for a stand-alone utility in the percentage of wind energy on its system and in the diversity of its renewable generating resources.

This section explains the challenges with integrating additional as-available renewable resources and the potential impact to HECO’s ability to operate its generation system in a reliable and cost-effective manner, if large amounts of intermittent, as-available resources are integrated onto its grid. Based on HELCO’s experience, new ground is being broken in the industry on some of these integration issues and thus solutions are not readily available. However, this section also explains the steps required to better understand and address these issues.

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5.2.1 System Operation Issues

System operations is concerned, among other things, with system stability, which is the ability of an electrical generating system to continue to operate and remain stable. This is especially important during and immediately after a disturbance on the grid such as the sudden loss of generation or the sudden loss of load from the initiation of system protection relays because of a system fault condition. System faults can be caused by trees contacting power lines, vehicular accidents with utility poles, transformer failures, or lightning. More recently, system stability concerns have also included the effects of highly variable output from intermittent generation, such as from wind generation. The impacts on system stability due to rapid variations in output of as-available renewable resources are a key planning concern for HECO’s relatively small and isolated utility system.

5.2.1.1 Need to Match Generation and Demand

Operation of the electric grid requires a constant matching of the amount of generation (i.e., MW being generated) with the total amount of demand for electricity by customers (i.e., MW of customer load). When generation matches the demand for electricity, the system frequency will be 60 cycles per second (Hertz or Hz). If generation exceeds the demand, system frequency will increase. If generation is lower than demand, then system frequency will decrease. Customer equipment depends on 60 Hz (i.e., the standard for system frequency in the United States) for proper operation. In addition, generating units are designed to operate at 60 Hz. Deviation from 60 Hz of greater than 0.5 Hz can cause cumulative damage to customer equipment and generating units. The greater the deviation is from 60 Hz, the greater the impact to customer equipment and to generating units. If the deviations are large enough, and not remedied by protective relaying, failure of customer equipment or generating units may occur.

Matching the generation with demand basically involves changing the level of generation to match, or follow, the total customer load. At the system level, generally the change in total customer load from minute to minute on the HECO system is relatively small and fairly predictable using the load profile of the system. However, matching the total generation with the total customer load involves many factors and can be complicated.

The ability for generation to match the demand depends upon the operating characteristics of the individual generating units that are on-line at the given point in time. Only generating units that are dispatchable (i.e., output levels that are controllable by the system operator) or generating units with local governor control (i.e., automatic response to change in rotational speed) can help towards following the total customer load and therefore maintain system frequency at 60 Hz. Fixed dispatch units (e.g., H-Power on the HECO system and PGV on the HELCO system) and as-available generation (e.g., hydro, wind, and PV) are not dispatchable and have limited ability to

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respond to frequency changes, therefore do not help in following customer load. In fact, highly variable non-dispatchable generation such as wind increases the mismatch between generation and load.

The operating point of each generating unit at any given point in time also constrains the ability of the generating units to follow customer load. If a generating unit is operating at its maximum output, it cannot increase (i.e., ramp-up) its output to match an increase in customer loads. Likewise, a generating unit operating at its minimum output levels cannot reduce its output (i.e., ramp-down) to match a decrease in customer loads. The output level of dispatchable generating units are usually set to optimize (i.e., reduce) overall cost, since different generating units have different operating economics (e.g., fuel consumption rate, operating and maintenance costs). However, determining the output level of dispatchable generating units must also consider the amount of ramp-up and ramp-down capability (i.e., regulating reserve) needed and therefore the output levels might need to be adjusted away from the optimal economic output level. Also, voltage levels must be managed throughout HECO’s system. This may further constrain generators at different locations on the system to operate at certain output levels needed to maintain the voltage in an area (see Section 5.7.1.7). HECO uses a program in its Energy Management System to best manage these issues and control the output of dispatchable units19.

Generating units also have different start-up time requirements (e.g., 20 minutes for combustion turbines to one to two hours for cycling steam units). A generating unit can also have a minimum duration of time it must remain shut down, once it is shutdown (i.e., minimum shutdown time). In addition, air permit requirements may limit the amounts of start-ups and/or the number of operating hours. Therefore, having enough generation on-line to match changes in load requires advance consideration of which units to start and at what point in time to start them.

As a last resort in avoiding extreme low system frequency situations, underfrequency relays are used on a number of HECO’s distribution circuits. As system frequency decreases to dangerously low levels, the relays open to drop circuits from the grid (i.e., load shed), thus reducing the demand for electricity and allowing other generating units to pick up a higher share of the load to restore system frequency to 60 Hz. The underfrequency relays start to interrupt customer water heating loads through HECO’s Residential Water Heating Program at 59.5 Hz. Additional underfrequency load shedding occurs at 58.5 Hz and 10 seconds or 58 Hz with no time delay. Traditionally, a drop in system frequency to approximately 59.3 Hz is typically caused by a sudden loss

19 It should be noted that the EMS is used to dispatch MW automatically. MVAR and transformer taps which help regulate voltage are either controlled automatically in the field through load tap changers (LTCs) or done manually by the control operator or (for generator VARS) and dispatcher (for manual load tap changers). There is no EMS program to automatically control voltages.

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of one or more large generators (e.g., 90 MW units). The bigger the loss in generation, the greater the drop in system frequency, and thus a larger number of customers would need to be interrupted to restore system frequency. Additional underfrequency relays are set to interrupt customers at lower system frequencies (i.e., lowest set at 57 Hz). The underfrequency relays operate over a range of system frequency and trip times so as to drop enough load to allow system frequency to be restored while not interrupting electricity to too many customers. Given the short response times (i.e., fractions of a second to a few seconds), the system of underfrequency relays must be set-up to operate properly in advance, even though the demand for electricity changes on individual circuits throughout the day. If the underfrequency relays and other generating units picking up a higher share of the load are not able to quickly restore system frequency, generating units that are operating outside their design range will begin to experience equipment failure and begin to trip off-line. This will further decrease system frequency possibly causing a cascading effect of generators tripping off-line leading to an island-wide outage.

5.2.1.2 Offsetting Wind Farm Variations

HECO currently does not have any wind farms on its system. However, HECO is now in the process of evaluating a proposal to install a 30 MW wind farm in Kahuku. In addition, HECO has issued a Request For Proposals for up to 100 MW of non-firm renewable generation. HECO anticipates that it will receive proposals for intermittent, as-available renewable generation. Therefore, there is a potential for a large amount of intermittent, as-available generation to be installed on the HECO system.

HECO has learned a substantial amount about the challenges of integrating substantial amounts of wind generation onto a small isolated island grid from the experiences of its sister companies, HELCO and MECO. The following section explains HELCO’s experience, which may be applied to HECO.

With the addition of the 10.56 MW Hawi Renewable Development (HRD) wind farm (i.e., variable non-dispatchable generation) to the HELCO system, system frequency changes have been occurring more often (i.e., second-to-second) and to a greater degree due to the uncoordinated nature of the changes in wind farm output. With the installation of the 20.5 MW Pakini Nui wind farm in March-April 2007, deviations in system frequency can conceivably drop close to 59 Hz where underfrequency load shedding begins. This greatly complicates the matching of generation with customer load to maintain a constant frequency of 60 Hz. Changes in output of wind farms must be countered with an offsetting change in output from dispatchable generation and/or tempered with units with high inertia (see Section 5.2.1.3 for explanation of inertia), or else excessive underfrequency relay operation will occur resulting in excessive customer outages.

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To be able to quickly offset the changes in wind farm output, it is necessary to have additional generation (i.e., regulating reserve) on-line such that total generation can be ramped either up or down to cover the potential variation in wind farm output. The larger the total amount of wind farms that are on-line, the larger the potential variation in wind farm output and the larger the required amount of regulating reserves. However, having additional regulating reserves (i.e., more generation on-line) means additional fuel consumption. In addition, for the dispatchable generating units to be able to ramp up, the generating units need to be operated at lower output levels which are inherently less efficient (i.e., more fuel consumed per kWh generated). Although less total fuel is consumed for a lower load, more fuel is consumed per kWh generated and increases the overall cost per kWh of the electricity produced.

HELCO has been evaluating the reasonable amount of regulating reserves it should have when wind farms are on-line. HELCO’s practice is evolving and the current practice, which is similar to other islands with high amounts of wind generation, is to not necessarily shut-down dispatchable generating units just because of the added generation from wind farms on the system. The behavior of the output levels of the wind farms on a particular day will affect the amount of regulating reserves that are maintained. Stable wind farm output may allow delaying start up of a cycling unit, but under conditions of highly variable output, a MW-for-MW regulating reserve may be required. With the Pakini Nui wind farm on-line, the total rating of wind farms on-line is just over 30 MW. At that time, it is anticipated that HELCO will need to keep regulating reserves of approximately 16 to 20 MW on average compared to approximately 3 to 5 MW that HELCO would otherwise normally have kept if the wind farms were not on-line. Actual operational experience will be required to refine these estimates.

As intermittent, as-available resources are added to the HECO system, HECO will need to develop its own practices specific to its system. While the general principles are the same, the actual amount of regulating reserve that would need to be carried on the HECO system will be different from that carried by HELCO because the system characteristics (e.g., frequency bias, system inertia) are different. In addition, HECO has an operating policy of carrying a sufficient amount of spinning reserve to cover the loss of the largest unit whereas HELCO does not have such an operating policy. Also, HELCO and MECO have more quick-starting generation that takes minutes to start up and HECO has large steam units which take hours to start up. HECO’s existing combustion turbines (Waiau Units 9 and 10) can start in at least 20 minutes and its 29.5 MW of distributed generation units can start up in a few minutes. Quick-starting capability is useful in helping keep supply and demand in balance when there are significant amounts of intermittent, as-available generation on the system.

Having a reasonable amount of dispatchable generation for regulating reserve can be a challenge on the HELCO system. To accept as-available generation (i.e., wind and hydro), dispatchable generation must be reduced and/or taken off-line since the fixed

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dispatch and as-available generation are not controllable by the system operator. This means less dispatchable generation is available to provide regulating reserve. This can be especially challenging during periods of minimum load in the early morning hours of the day. During these times, the sum of the minimum ratings of the must-run units20 plus the fixed dispatch and as-available generation is close to the total customer load. Even with must-run units at their lowest reasonable output levels, it is necessary at times to curtail (i.e., not accept) as-available generation so that reasonable regulating reserves can be kept. As the amount of intermittent, as-available generation that is integrated into the HECO grid increases, this may also become an issue for HECO.

At HELCO, there are times when even having a reasonable amount of regulating reserve is not sufficient to regulate the variableness of wind farm output. During periods of gusty winds, the output of wind farms can vary at rates much greater than 2 MW per minute. This can be more than the ramping capability of the dispatchable generating units that are on-line. Modern wind farms have sophisticated control systems to control wind turbine blade pitch and yaw (i.e., direction the turbine is facing) to maintain MW and frequency, however wind farm operators may be reluctant to make full use of this capability as it would result in lower electricity generation and therefore lower revenues. Also, wind farms cannot guarantee control in instances where the wind suddenly dies off. During gusty winds, the wind farm output can change from ramping up to ramping down on a second-to-second basis. At HELCO, the Automatic Generation Control (“AGC”) used to control the output of dispatchable generating units, operates on a four- second cycle based on data obtained by the supervisory control and data acquisition (“SCADA”) system every two seconds. (HECO’s AGC operates on a ten-second cycle and obtains data from the field by the SCADA system every two seconds.) Quick changes in wind farm output, the short timeframe required for generation response to match the change, and the inherent delay in the time for the AGC signals to change the output of dispatchable generating units can lead to situations where the AGC signals to the generating units actually exacerbate the mismatch between generation and load, causing swings in system frequency, even with a reasonable amount of regulating reserves. HELCO has worked with its AGC vendor to enhance its AGC programming to address this issue by essentially ignoring a certain level of wind fluctuations. Now that the 20.5 MW Pakini Nui wind farm has become operational, HELCO is closely monitoring this issue. If there are instances when the wind farm outputs fluctuate together in the same direction, it may not be possible to ignore the fluctuations.

20 Certain units must be kept on-line because: either the unit is not designed for cycling duty and would incur thermal stress damage; there are contractual obligations to accept power from the unit; the unit is needed to meet stability, voltage regulation, and/or transmission constraints; the unit would need to be back in service to meet load before completing its minimum time for shutdown; or air permits constrains the instances for taking the unit off-line.

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5.2.1.3 Fault Ride-Through

System stability is also concerned with the sudden loss of load, quickly clearing system faults, and the ability for the generating units to continue to operate during faults (i.e., fault ride-through). During a system fault, the sudden increase in electric current alters the electromagnetic field in the generator such that it acts to slow down the generator rotor causing the generating unit to possibly become unsynchronized with the rest of the system. The ability of a generating unit to ride-through a system fault is dependent on its ability to maintain constant rotating velocity during the fault (i.e., inertia) and is dependent on the mass and shape of the rotor in the generating unit. Generators with heavier and larger rotors have higher inertia. In addition to mass and shape of the rotor, high pressure steam contained in the boiler system of steam units provides an inherent short-term storage feature that also helps to keep the steam turbine rotor assembly rotating when acted upon by system faults. When many generators are on line, their combined inertia is cumulative. Therefore, system stability is not only affected by the type of units on line, but also the number of generating units.

An enormous amount of rotational power with very small tolerances is used to generate electricity. For example, the mass of the rotor assemblies for HELCO steam units range from 8 to 18 tons and rotate at 3600 revolutions per minute or 60 revolutions per second. HECO’s steam units are much larger, with ratings ranging from about 46 MW-net to about 135 MW-net and their masses are much larger than those of the HELCO steam units. The clearance between the spinning rotor assembly and the stationary portion of a generating unit is less than one inch and in some areas of a steam turbine the clearance can be 0.006 inches. The loss of synchronization, even for a fraction of a second, can cause extreme torsional stresses and, without proper automatic relays to take the unit off-line, can (1) physically damage generator windings, generator rotors, and turbine rotors, and (2) fracture foundation bolts damaging vibration conditions or severe overheating of the generator windings (to the point of melting) on generating unit components which, in extreme situations, can result in a catastrophic failure of the generating unit.

Unless the system fault is removed within fractions of a second using automatic system protection relays that detect the high electric current flow, generating units at that station may trip off-line to protect them from catastrophic damage. Then the balance between generation and load must be quickly restored by reducing load (load shedding), and/or by other generating units picking up a higher share of the load. Therefore, it is important for generating units to remain on-line as long as possible during system faults, while not sustaining damage.

Distributed generation (“DG”) represents a special case of how generation can contribute to system operation. Non-utility DG is typically non-dispatchable, especially if it is customer-sited serving customer-specific needs. It may provide some benefits in

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reducing loads on circuits or at substations and can be quick-starting, especially in the case of utility-dispatchable substation DG. For DG installed at the distribution level, it generally needs to trip off-line during a distribution fault so as to not reduce the electric current flowing in the automatic protection relay that removes the fault from the circuit. At the same time, the DG unit at the distribution level should stay on-line during transmission faults so as to not contribute to any imbalance between the customer load and generation. In addition, customer-sited DG units are typically fixed dispatch and reduce the amount of dispatchable generation on the system, further reducing the ability for the system to handle generation from wind farms.

5.2.1.4 Resource Planning Implications

System stability is especially important on an island system like HECO’s where there are limited sources of generation on-line at a given point in time, as well as a limited amount of transmission lines to transfer power to the load, and therefore a limited ability to respond to disturbances on the system.

System stability and operations issues are important in resource planning. Although some of the detailed characteristics (e.g., generator inertia) of generating units are determined in the design phase of the generating unit, some characteristics (i.e., firm versus as-available, highly variable output, quick start, steam storage) are inherent to the type of generation and should be considered in resource planning. Some of the cost factors such as higher regulating reserves and minimum load constraints can be roughly analyzed using a production simulation model and considered in resource planning, but other aspects, such as cost of frequent deviation from 60 Hz and frequent redispatch of regulating units, are difficult to estimate. System stability and system operation issues, especially with increasing amounts of wind power require further investigation. HECO, HELCO and MECO are breaking new ground in the industry on some of these issues and thus solutions are not readily available and may require new technology and research. See Chapter 10 for action items that have been identified. In the interim, caution must be exercised when considering the addition of more wind farms or other sources of as-available energy to ensure the grid can handle the additional variable non-dispatchable generation, as a certain amount of conventional generation must be kept on-line for reliable system operation.

5.3 Minimum Load Constraints and As-available Load Curtailment Issues

There may be instances where as-available resources may be in compliance with the specified performance standards, yet, due to situations and conditions on HECO’s system that could affect the reliability or power quality of its system, HECO may still have to curtail the delivery of energy from as-available providers. HECO’s system

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operator will review the situations/conditions and determine, according to his or her judgment and experience, whether as-available delivery of energy should be curtailed. The following sections provide examples of such situations and conditions on HECO’s system that could affect the reliability or power quality of HECO’s system (the following is not an exhaustive list).

Dispatch and System Operation Constraints

Examples include: • Baseload units at minimum load (including a necessary regulating ramp-down reserve), cycling units are at minimum but cannot be stopped due to permit restrictions on number of starts allowed per day. • Quick Load Pickup and spinning reserve requirements. As-available resources do not supply quick load pick up or spinning reserve. • Baseload units are at minimum load, and other units are at fixed output for good engineering and operating reasons. Such reasons could include emission testing, capacity testing and troubleshooting. • Storm conditions, especially lightning storms or windy conditions, cause fault conditions. Such abnormal conditions require additional frequency regulation to ensure system reliability. Under these conditions, regulating units are dispatched to maintain extra quick-load response and additional regulating units may be kept online. This may displace as-available power.

Transmission/Distribution System Constraints

Examples include: • Line outages on certain transmission or distribution lines can require curtailment of generating units, including as-available resources – for example, the portion of the transmission line to which the as-available resource is tied may need to be de-energized for maintenance or repair. • High voltages or low voltages in the vicinity of the as-available resource that cannot be controlled through means other than curtailment of the as-available resource. • Voltage flicker problems (noticeable, rapid changes in electric light levels) due to swings in power output of an as-available resource may require curtailment of as-available generation to reduce the magnitude of these rapid power fluctuations.

5.4 Spinning and Regulating Reserve

Spinning reserve is the amount of reserve capacity that is immediately available from units that are connected to the system and are operating below their maximum rated levels. In actual operation, the spinning reserve level carried on the system is a function of the load on the system, the generating units serving the system, and the load on the

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unit carrying the largest amount of the system load. Strategist is not designed to model this level of sophistication; it allows only a single input for this variable. As a result, 180 MW, which represents the largest generating unit (AES) on HECO’s system, less the amount of interruptible loads on the system, is used to model spinning reserve requirements.

In cases where the large 2-on-1 combined-cycle units (with capacities greater than 180 MW) were part of the resource plan, spinning reserve requirement was maintained at 180 MW. The reason for this is that both 2-on-1 combined-cycle units were considered as two halves for operational purposes. Combined-cycle units can be designed such that the forced outage of one turbine-generator will not result in the loss of more than one-half of the total generating output of the combined-cycle generator. Therefore, since one-half of the capacity of a 242 MW dual train combined-cycle unit (GE PG7221) would be 121 MW, no increase in spinning reserve above 180 MW was required.

The Company has been operating in accordance with this philosophy since the installation of the Kalaeloa combined-cycle unit in 1992. Prior to 2005, the Kalaeloa unit, which has a 2-on-1 configuration, had a total output of 180 MW, equal to that of AES and larger than that of the 134 MW Kahe Unit 6 (K6), the next largest unit on the system. If AES is on-line, its capacity is the determining factor in the level of spinning reserve, and about 180 MW is carried. If AES is offline, since Kalaeloa is treated as two 90 MW units, K6 is the largest unit operating. Therefore, if AES is offline, K6 becomes the determining factor, and about 134 MW of spinning reserve is carried. For the IRP-3 optimization runs, Kalaeloa was assumed to have a capacity of 209 MW (based on the anticipated facility capacity resulting from Amendment Nos. 5 and 6 to Kalaeloa’s purchase power agreement), which was represented in Strategist as two 104.5 MW units. Subsequent completed capacity evaluation results determined that the demonstrated facility capacity is 208 MW.

5.5 Renewable Portfolio Standards

The Hawaii State Legislature revised the State’s Renewable Portfolio Standard (RPS) law, as explained in Section 1.4.2. Since this law requires a certain percentage of electricity sales to be from renewable energy, and the IRP Framework requires each utility to conform to all laws and state energy objectives, the requirements of the RPS law affect the mix of future resources in the utility’s integrated resource plans. The RPS law allows HECO to aggregate the electricity sales and energy from renewable energy for its three utilities (HECO, HELCO, and MECO).

In order to develop an IRP plan that to meet the RPS law, the HECO IRP-4 looked at meeting the RPS requirement for Oahu only (i.e., meeting the RPS requirement for all of the electricity sales on Oahu with renewable resources only on Oahu). This is a

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conservative approach as MECO and HELCO exceed their RPS requirement and are expected to continue to do so into the foreseeable future. This assumption, along with the forecasted electricity sales for HECO, determined the amount of renewable energy required for the HECO system so that on a stand alone basis HECO would meet the RPS law in future years.

5.6 Competitive Bidding for New Generation

As explained in Section 1.4.9, the PUC issued a Competitive Bidding Framework for new generation in December 2006 that requires the utility to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC has found competitive bidding to be unsuitable. The determination of whether to use competitive bidding for a future generation resource or a block of generation resources is to be made by the PUC during its review of the utility’s IRP.

Since the actual resource to be built, in general, will be determined through a competitive bidding process and not through the IRP process as previously was the case, there is less importance in the accuracy of the cost and performance estimates for new resources used in the IRP analysis. It is important, however, that the IRP identify the attributes of the future generation resource or block of generation resources required by the system so that the attributes can be acquired via the competitive bidding process.

It is also important to note that, in general, the lead time for procuring new generation resources would be longer due to the requirement to conduct a competitive bidding process and this increased lead time should be factored in the utility’s IRP.

5.6.1.1 Ownership of Future Supply-Side Resources

For the purposes of integrated resource planning, the supply-side resources were evaluated without regard to ownership. HECO evaluated supply-side technologies that could be implemented by either the utility or independent power producers (IPPs). The resource plans, while characterized using the utility’s cost estimates and financing structures, identifies the size and timing of resources without distinction as to the ownership or the resources. IPPs are able to submit proposals to HECO for evaluation to implement, replace, or defer the resource options included in HECO’s IRP.

The Commission has previously stated “The IRP framework does not specifically address the role of IPPs in the development or acquisition of the resources deemed appropriate in the IRP. However, the framework, at Section IV.D.2 provides that the utility, in the development of its integrated resource plan, shall consider supply-side and demand-side resource options that ‘are or may be supplied by persons other than the utility.’ This provision was deliberately intended to leave to the implementation phase

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the determination of who should build and operate the resource included in the IRP. IPP-supplied resources should be in conformance with the utility’s IRP.” 21

The actual ownership of a resource would be determined later, during the project development phase, if the candidate resource is selected for implementation. The remainder of this section discusses some of the differences that should be considered in determining the ownership of supply-side resources.

While a generating resource may be installed under either a utility or an IPP ownership structure, the costs and risks incurred by the utility and its customers may not be the same unless all of the impacts of purchasing power are considered in the calculation of the price paid to the IPP. For example, if 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 power on its balance sheet, then this rebalancing cost must also be taken into account in evaluating the total cost of the new generating unit if it is owned by an IPP.

In addition, the presence of a power purchase agreement (PPA) between the utility and an IPP does not provide the utility with as much operating flexibility as the utility has with its own units. While the PPA can specify operating conditions favorable to the utility (such as coordination of maintenance, dispatchability, etc.), the utility generally has less control over plant maintenance practices, operational considerations, fuel conversion opportunities, and environmental enhancements. In contrast, the utility does have such operating flexibility with its own units.

Utilities also have the obligation to serve their customers, while IPPs who supply capacity and energy to the utilities under PPAs may be obligated to provide to the utility only those items and services, or to perform only those duties, that are covered by provisions in the PPA. Even with contract buy-out options, project in-service date deferral or acceleration provisions, and project acquisition options, a utility has more flexibility to adjust to changed circumstances if it owns and operates its own units, than if it purchases power under long-term PPAs, because PPAs cannot be drafted to provide for all future contingencies and changed circumstances.

Ownership also matters for DG/CHP resources, including combined heat and power DG. Third-party or customer-owned DG systems theoretically can provide some of the same generic benefits as DG systems owned by the utility, such as deferral of new central station generating capacity, if the systems meet reasonable design, operability and reliability standards and operation can be coordinated with the utility. Only DG systems dispatchable by the utility, however, can provide the direct operational benefits to the utility. In addition, if a third-party or a customer installs DG, the load to be served by the

21 Regarding Integrated Resource Planning, Hawaii Public Utilities Commission, Docket No. 7257, Decision and Order No. 13839, filed March 31, 1995, p. 15.

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utility is reduced and the utility loses that portion of the rate normally charged to the customer to cover fixed costs. When that happens, such costs must be borne by other ratepayers when rates are adjusted at the next rate case.

5.7 Transmission System Considerations

5.7.1.1 Overview of Transmission Considerations

The purpose of a transmission system is to deliver generated power to the sub- transmission and distribution systems and ultimately to the customer at the lowest reasonable cost. Implicit in this is the need to strike a reasonable balance among cost, reliability, and sensitivity to the environment. Among the transmission considerations which impact generation resource planning are: • Adequacy of transmission capacity • Reliability considerations of the transmission system • System transmission losses • Voltage support • System stability

5.7.1.2 HECO System Overview

Bulk power from Leeward Oahu power plants is transmitted to the East Oahu Service Area over two major transmission corridors. The northern transmission corridor extends from Kahe power plant to the Halawa substation, Koolau substation and the Pukele substation, where it currently ends. With the completion of the two Waiau-CIP 138 kV transmission lines in 1995, the southern transmission corridor was extended from the Kahe power plant to the Waiau power plant and substations at Iwilei, School Street, and Archer. The southern transmission corridor was extended to the Kamoku substation through the installation of two 138 kV transmission lines from Archer substation to Kewalo substation and the installation of a 138 kV transmission line from Kewalo substation to Kamoku substation

In West Oahu, the two corridors are linked together by transmission lines between power plants and substations connected to the northern and southern corridors. However, no similar connection exists to provide reliable power to the East Oahu service area. HECO’s plan has been to build upon existing facilities installed to serve the local load growth through the Archer-Kewalo-Kamoku projects and close the existing gap between the northern transmission corridor and the southern transmission corridor on the east side of Oahu, providing added reliability to the eastern and windward portions of Oahu, which represents 56% of HECO’s total load.

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The normal power flow of power is from Waiau to the Honolulu load center via four 138 kV lines. The Kahe power plant is located beyond the Waiau power plant in proximity to the Barbers Point area. Four 138 kV lines transport power from the Kahe / Barbers Point area toward the load center. All four lines are in one corridor for a substantial distance, making the lines vulnerable to a common outage and potential system isolation.

Non-Utility Generators (NUGs): Kalaeloa, AES, and HRRV, are located in the Barbers Point Industrial Park. Power from these plants is transported through two 138 kV lines linked to Kahe Power Plant and two 138 kV lines linked to Waiau.

The transmission system provides the links between the generating sources and the customers. It functions most efficiently and effectively when the entire transmission system is intact. A system separation occurs when all of the transmission lines connecting one portion of the system to another are out of service. This separation could result from conditions induced by unusual system disturbances or a cascading of line outages, thereby completely isolating (or islanding) specific areas of the system.

At best, each isolated area could remain stable with generation supporting load in that same area, with or without load shedding. At worst, the generation in an area could be insufficient to support the load in that area, causing the frequency to drop enough below 60 Hz for automatic load shedding to take place. Depending on the severity of the mismatch between load and generation and the number of lines out of service, the isolated area may not stabilize. As a result, the frequency could continue to drop, eventually causing the system to collapse.

Generating units with quick load pick-up capabilities, such as combustion turbines, are important additions to the system from a system separation point of view. Their ability to quickly pick up load (within 3 seconds) during a system contingency helps to prevent the frequency from dropping to the point of system collapse. In addition, combustion turbines can provide greater regulating capabilities than larger steam turbine generators to help support fluctuations in intermittent generation.

Transmission Planning

The transmission planning process is applied to the HECO 138 kV system, and the distribution planning process is applied to HECO’s 46 kV sub-transmission system, 25 kV distribution system and at the 12 kV voltage level and below. The distribution planning process is discussed later in this chapter.

Long-term analyses covering time periods ranging from six to 20 years and short-term analyses covering a period of five years or less are conducted when needed. The analyses utilize load flow programs, which model the characteristics of the actual 138 kV system. Computer models of the electric grid are utilized to represent a base case load

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flow. An electrical grid can be represented by a set of simultaneous linear algebraic equation expressing Kirchoff’s laws for the utility system and the voltage, current, and power characteristics of the loads. HECO uses a program called Power System Simulator for Engineering or PSS/E, which is developed by a company called Power Technologies, Inc (“PTI”). The PSS/E program is widely used by utilities and transmission planners in North America and around the world. The program conducts an iterative procedure to solve the algebraic equations for given loads and generator power outputs, which is referred to as the load flow or power flow calculation. The load flow simulation results can produce current flows and voltages on the utility electrical grid. The base case load flow uses historical load data. Transmission planning will typically benchmark a peak load flow against historical data to ensure the accuracy of the models.

The load distributions in the base case load flow are scaled by the load growth rate from the latest utility load forecast. The load flow simulations are forward looking simulations and are used to determine voltages at substation busses and the amount of current flowing through the 138 kV transmission lines based upon load forecasts at the substations and various configurations of the HECO system. Transmission planning criteria violations and transmission reliability concerns are identified. Solutions are formulated and load flow simulations are used to test the solutions against HECO’s transmission planning criteria. Transmission projects are recommended using the HECO Transmission Planning Criteria as a minimum guideline. Recommendations are also based upon other factors including: 1) engineering design criteria, 2) operational experience, 3) risks involved and 4) financial constraints.

5.7.1.3 Adequacy of Transmission Capacity

Transmission planning criteria provide minimum guidelines for planning the transmission system. For instance, voltages exceeding acceptable tolerance levels or current flows exceeding the current carrying capacity of transmission lines are criteria violations.

Historically, planning criteria on the U.S. mainland and at HECO have been developed based on successful utility practice and has evolved over time along with the growth in size, complexity and importance of electric power systems. As an example, the high voltage electrical network on the U.S. mainland grew from isolated systems into the interconnected bulk power system that exists today. With the growth and interconnections came the need to establish planning and operating practices that would result in the economical and reliable operation of the power system. The establishment of realistic planning criteria for the electrical system came about as the result of lessons learned in operating the system.

The North American Electric Reliability Council (NERC) was formed subsequent to the 1965 blackout that affected the northeastern United States and Ontario, Canada, to

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promote the reliability of the electrical supply in North America. NERC does this by reviewing the past for lessons learned and creating and/or reviewing operating and planning standards. For example, now that variable generation, such as wind power in particular, has grown significantly on the North American grid and in Hawaii, lessons are being learned on impact these larger penetrations of variable generation have on an electrical grid. As a result, NERC has organized the Integration of Variable Generation Task Force to prepare 1) a concepts document that includes the philosophical and technical considerations for integrating variable resources into the interconnection, and 2) specific recommendations for practices and requirements, including reliability standards, that cover the planning, operations planning, and realtime operating timeframes. A representative from HELCO has been invited to participate in this task force because of the lessons it has learned from the high level of wind power integration currently on the HELCO system as compared to other system in North America. The NERC planning standards and operating policies reflect the combined experience of the utilities in North America. These various criteria, developed through industry experience in operating the electrical system, reflect the more probable forced and maintenance outages that should be evaluated in planning studies, as well as extreme, but less probable scenarios that should also be addressed. As part of the electrical system planning process, an analysis is conducted to determine the response of the system to the various outage scenarios, i.e. one line out for maintenance when another line fails. NERC has nine member reliability councils, such as WECC (Western Electric Coordinating Council), and each of these reliability councils adapts and modifies the NERC guidelines to apply to its own unique system requirements, in some cases more stringent than the NERC guidelines.

The HECO electrical grid does not fall under the jurisdiction of NERC; however, HECO’s planning criteria were developed using NERC and other U.S. mainland reliability council experience as a guide. The criteria developed are consistent with NERC Planning Standards and provide general guidelines for all transmission system planning across HECO’s system.

Using the transmission planning process described earlier, load flow analysis is performed. If the load flow model fails to perform acceptably by meeting criteria then the transmission system is considered to be inadequate or does not have adequate capacity. In this situation alternatives, such as the addition of a new transmission line or a new substation, are developed that will correct the failure. If the load flow model does not produce any criteria violations, then the transmission system has an adequate amount of transmission capacity.

5.7.1.4 T&D Considerations in Demand-Side Options

Criteria violations can be triggered by load growth and the addition of new generation. In theory, a reduction in demand by the end-user could result in a deferral in the need date

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for transmission and distribution facilities. In practice, realization of the deferral is dependent on the location of the demand reduction and the actual impact of the reduced demand on the coincident peak. The impact of customer-owned DG on Hawaii’s distribution system is very complex and requires detailed studies on a case-by-case basis. In order for customer-owned DG to provide transmission or distribution deferral benefits the utility would have to rely on the DG unit as firm distribution capacity. There are concerns with relying on the customer-owned DG units as firm distribution capacity. For example, there are issues on diversity of DG installations over a distribution circuit area, the impact of a DG unit’s availability on the need for backup distribution capacity, and the utility’s ability to control the output of the DG which will determine if there is distribution deferral and the amount of distribution deferral. Given the factors concerning the issues with treating customer-owned DG as firm distribution capacity, deferral of distribution facilities using customer-owned DG are not common and situations in which customer-owned DG is used to address criteria violations and/or reliability concerns require a number of factors to be in place in order for the DG to be effective.

If a criteria violation is triggered due to the installation of generation, it is assumed that demand-side measures were considered with the decision to install the generation unit. Therefore the considered alternative to address the criteria violation is to upgrade and/or is install new transmission capacity.

5.7.1.5 Reliability Considerations of the Transmission System

From a planning perspective, there are basically two types of reliability concerns against which HECO continuously try to guard. The first type of reliability concern is a catastrophic power outage, where disturbances on the system could potentially throw the entire system into instability. The second type of reliability concern is a localized power outage, where the outage affects a limited area of the island. A catastrophic power outage has the potential of taking down the entire system for many hours. If the entire system becomes too unstable after system disturbances, generation facilities will eventually shut down, as designed, to protect vital equipment from long-term or permanent damage. The restart of generation facilities is a very involved, complex, and time consuming process. Therefore, a significant amount of customers could be without power for many hours until the system could be restored. A localized outage is limited to a certain area and is unlikely to cause the entire system to become unstable and cause loss of generation. Certain localized power outages also are of significant concern because of the number of customers affected, the duration of the outages, and the severity of the outages on the impacted customers and the state.

Performing the load flow simulations is a very complex and lengthy undertaking, even for a single assumption for the timing, size and location of future generating units. Single and double contingency outage scenarios for HECO must be considered in order to determine whether or not planning criteria violations and/or reliability concerns will occur

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in any particular scenario. Transmission reliability projects are not and cannot be identified and characterized in an IRP because of the complexity of the analyses required to address reliability projects and the numerous load flow analysis which is required to evaluate solutions for the reliability concerns. In addition, analyzing reliability concerns and solutions under numerous possible resource plans, which are generated through the IRP process, could not be completed in the time frame set forth for the IRP analysis. Instead, transmission reliability analyses are conducted outside of the IRP process and are done in a manner that is consistent with the IRP process and takes into account the resource additions in the latest resource plan.

5.7.1.6 Transmission System Losses

The efficiency of the transmission system with respect to losses is another concern associated with the transmission corridor. Since the generation from the Kahe/Barbers Point area is the most efficient and economic, it will be dispatched before other units at Waiau power plant. This results in high loadings and, consequently, high losses on the transmission lines connected to these generating sites. This is because electric system losses are a function of the square of the current carried by the lines and the resistance of the lines.

There are basically two negative impacts arising from system losses. The first is the unproductive use of the energy which requires additional fuel consumption. Second is the generation capacity which must be installed to cover the demand component of the losses. These two impacts, if left unchecked, could unnecessarily increase the cost of electric service.

Reducing the line loadings and the effective resistance of the transmission system lowers system losses. These reductions in loadings and resistance can be obtained by adding new lines and/or having generation closer to the load demand. The total loss factor for the HECO system, which includes both transmission and distribution losses is estimated to be approximately 4.7%, which is relatively small. Transmission losses account for only 1.3 % of the 4.7% or over a quarter of the losses; the majority of the losses are on the distribution system.

5.7.1.7 Voltage Support

In addition to supplying power, generators are also used to maintain system voltage within acceptable limits by regulating the supply of reactive power, or volts-amperes reactive (VARs). That is, the generating units must be capable of supplying the VARs required by both the customers and the transmission system in order to maintain the required voltage levels to the customers. The VARs required by the transmission system increase as a function of the square of the current on the lines.

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Generating units have a limited capability to supply VARs, and any VARs used to supply the transmission system requirements cannot be used to supply the VARs required by the customers. If a balance between the supply and demand for VARs cannot be met, the voltage level either decays (if there is insufficient supply) or increases (if there is an excess supply) until a balance is found at another voltage level. However, the voltage at this balance point may not be within acceptable limits for customer appliances and utility equipment to prevent possible damage.

While it is relatively easy to reduce an excess of VARs on the system, there is an upper limit to the supply. If the demand outstrips the supply, either a new VAR source (e.g., a generating unit, capacitor banks, or static VAR compensators) must be added or the transmission system VAR demand (which is determined by system analyses) must be reduced. Additional transmission lines would reduce the average load on each line and the result is less VAR losses and a better voltage profile.

5.7.1.8 System Stability Considerations

Stability is that feature of a generating system that allows it to operate or remain stable during a period of disturbance such as a sudden loss of load through a power interruption (a fault). System stability is affected by characteristics of the electric system including the strength of a transmission system (i.e., transmission systems with few or no criteria violations, or can operate with no voltage and/or current carrying capacity violations under multiple line contingencies), the proximity of generation to the load, and the physical characteristics of the generating units. Stability is of primary importance in an island system such as HECO’s that cannot receive assistance from other electrical systems. The parameters that make a system stable have an impact on the transmission system, generating unit siting, and type and size of generating units added. System stability analyses are typically performed when new generating units or transmission additions are added to the system. Stability analyses requires detailed, generator and transmission system specific information that is usually available only in the project implementation phase and may identify a need for additional transmission, protection, and generation reinforcements or modifications to maintain system stability when subjected to various system disturbances.

5.8 Distribution System Considerations

The purpose of a distribution system is to deliver transmission power to the sub-transmission and distribution systems and ultimately to the customer at the lowest reasonable cost. The transmission planning process that was discussed earlier in this chapter is applied to the HECO 138 kV system, and the distribution planning process is applied to HECO’s 46 kV sub-transmission system and distribution system at the 25 kV voltage level and below.

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5.8.1.1 Distribution Planning Process A long-term forecast is not created for the distribution planning process, because (1) distribution load forecasting is geographically dependent and therefore very dynamic, (2) growth rates between lines are highly variable, (3) distribution load forecasting is highly dependent upon customer plans (e.g., a new hotel can double the load on a distribution line) and (4) useful forecasting for the distribution system rarely exceeds five years. Short-term forecasts are used to determine power and current flows through the sub-transmission and distribution systems, voltages on the system, and transformer loading. Distribution planning criteria and reliability concerns are identified. Most of the analysis in distribution planning is conducted looking at historical loads by taking actual load demand readings from distribution substation transformers and readings from each individual distribution line In some cases, the PSS/E model is used to model select areas of the distribution system.

5.8.1.2 Distribution Planning in IRP

Because of the variability and the time frame for the distribution system load forecast, distribution system impacts were not incorporated into the long-range plan for the HECO IRP-4. However, the distribution planning process is consistent with the IRP planning process and takes into consideration load reduction, DG at substations and distribution capacity solutions on a project specific basis.

As stated earlier, part of the load forecast for distribution planning purposes incorporates actual load demand from distribution substation transformers and readings from individual distribution lines. A growth rate for the distribution substations is applied to the actual load demands at the substations. Load growth rates for the distribution system will be different from different areas and are not based on the IRP 20-year sales and peak forecast. Load growth at the distribution level is dependent on customer project developments (new customers or existing customers) and will vary depending on the progress of the project and therefore cannot be forecasted more than three to five years into the future because such load growth depends so much on customer decisions over which HECO has no control. It would be difficult to integrate distribution planning into the long-term IRP analysis.

As an example, in Docket No. 7526, filed on November 12, 1992, HECO proposed a project to install the Kewalo A&B 30/40/50 MVA transformers, two underground 138 kV transmission lines, two 25 kV underground distribution lines, fiber optic cable and associated work to increase the capacity required to relieve projected distribution overloads and to provide capacity for future load growth in the Kakaako area. At the time of the application, overloads were projected to occur in 1993 and the service date for the project December 1994. The project was approved by the Commission in Decision and Order No. 12616 on September 23, 1993. On January 25, 1996, HECO

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informed the Commission that the service date for the Kewalo transformers and the 138 kV transmission line was deferred due to lower load forecasts for the Kakaako area than when the application was prepared. In Docket No. 7602, filed February 10, 1993, HECO proposed a project to install the Kewalo-Kamoku 138 kV transmission line, which was the second phase of the Archer to Pukele 138 kV line and would also make provisions for the Kamoku substation to accommodate future load growth. The project was approved by the Commission in Decision and Order No. 12627 on September 24, 1993. On January 25, 1996, HECO informed the Commission that the service date for the Kewalo-Kamoku 138 kV transmission line was deferred from a service date between 1995-1997 to May 1999 because of lower load forecasts for the area than when the application was prepared.

5.8.1.3 Customer-Owned DG/CHP in Distribution Planning in IRP Just as there are difficulties in incorporating distribution planning into the IRP process, there are difficulties in incorporating the potential impacts of customer-owned DG/CHP on distribution planing in the IRP process. As in the transmission planning process, DG/CHP will be considered in the distribution planning process through a series of orderly steps, but with some significant differences. Like the transmission planning process, the distribution planning process starts with a forecast of demand. However, because distribution planning involves smaller geographical areas compared to transmission planning, the demand forecast for small geographic areas is based on historical demand, actual load data from distribution substation transformers, and current readings from each individual distribution line. Growth rates are applied to the historical demand. Load data from distribution substation transformers and distribution line readings to forecast load demand on the distribution system. Growth rates are based on a historical trend of load demand and will include near-term DG/CHP projects. Load growth is dependent on customer project developments and can be attributed to the addition of new customers or increases in demand from existing customers. Since customers make the decisions as to what and when they will build, demand forecasts for these small geographical areas will vary depending on the progress of the project and load forecasts for distribution planning are updated on a regular basis as a result of project developments. Therefore, load forecasts for the distribution system cannot be made further than three to five years into the future. Next, given the assumptions for future demand, load flows on the distribution system can be calculated for radial distribution system. In some instances, computer simulations are performed to determine the magnitude and direction of the flow of electricity over the various distribution lines (i.e., distribution network systems). The calculated load flows and/or simulated load flows are compared against HECO’s distribution planning criteria to determine where and when planning criteria violations, if any, are forecasted to occur. Finally, if any planning criteria violations are identified, then possible solutions are evaluated.

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Furthermore, when considering customer-owned DG/CHP units, particular sites may be identified, but because of the timing of installations is driven primarily by the customer, there is much uncertainly as when the units will be installed. Without knowing the timing of the installation of the DG/CHP units, the distribution planning scenarios would have a high degree of uncertainty.

Docket No. 2007-0084 5-22 September 2008 HECO IRP-4 Chapter 6: Long-Term Planning Assumptions & Forecasts

6 LONG-TERM PLANNING ASSUMPTIONS AND FORECASTS

6.1 Sales and Peak Forecast

6.1.1 Background and Overview

Chapter 6 describes the IRP-4 electric sales and peak forecasts for the period 2007– 2030. This chapter covers the assumptions and methodology used in the forecasts and describes the forecast development process in IRP-4. To validate the assumptions used in the forecasts, this chapter explains how HECO examined the key factors used in the development of the base forecast and associated high and low scenarios, and which factors have the greatest impact on electricity sales projections. The sales and peak forecasts are not adjusted to account for future DSM impacts, as this adjustment is performed in the integration analysis described in Chapter 8. Finally, the current long-term forecasts are compared to the forecasts presented in the IRP-3 Report, and the reasons for the decreased demand for electricity are discussed.

6.1.2 IRP Advisory Group Load Forecasting Meetings

The long-term sales and peak forecast were derived using an extensive forecasting process that is an integral part of HECO’s IRP. Participation is solicited from HECO, the IRP Advisory Group, and the community at large. The sales and peaks forecasting process started in early 2007 and continued through August 2007, when the final forecast draft was presented in August 2007 to HECO’s IRP Advisory Group.

The sales and peak long-term forecasts were discussed with HECO’s IRP Advisory Group at three meetings in 2007, including two technical sessions on the load forecast in July 2007 and August 2007.

At the July 2007 meeting, the load forecasting methodology and a panel discussion on the economic outlook and issues affecting the forecast were presented, after which the Advisory Group was invited to participate in a facilitated discussion. The panel included Carl Bonham of the University of Hawaii Economic Research Organization (UHERO), Murray Towill of the Hawaii Hotel & Lodging Association, Kyle Chock of The Pacific Resource Partnership (construction), Tom Quinn of the Hawaii Center for Advanced Transportation Technologies (plug-in hybrid electric vehicles), Simon Zweighaft of InfraConsult (mass transit), and Steve Young of the City and County of Honolulu’s Department of Planning and Permitting.

At the August 2007 meeting, the preliminary load forecast was presented and Advisory Group members and guests discussed forecast methodology, assumptions, and preliminary projections. While the IRP Advisory Group acts in an advisory capacity and

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does not have approval authority for the final forecasts, IRP Advisory Group discussions are carefully considered in the IRP process.

In addition to the IRP Advisory Group review, the draft forecasts were also discussed informally with a technical group of experts external to the Company. The draft short-term (2007 – 2012) forecasts were further subjected to two levels of internal Company review. The long-term (2013 – 2030) forecast was developed using the same methodologies and source of forecast assumptions as the short-term forecasts and subjected to additional review, including the final review by the IRP Advisory Group at the August 2007 meeting.

The informal technical group was comprised of several noted local economists and the purpose of their review was to examine the technical merits of the forecasting models and methodologies. The first level of internal review was the Forecast Working Group, made up of mid-level HECO employees, who evaluated the forecast from a technical standpoint and decided whether or not to recommend if the forecast should be forwarded to HECO's Executive Committee for the second level of internal review. The Executive Committee is comprised of HECO’s executive staff. The multiple levels of review ensure that the forecasts receive maximum evaluation and exposure, and those reviewing the forecasts have diverse expertise and knowledge that contribute significantly to the development and approval of the final forecast.

6.1.3 Forecast Assumptions and Models

6.1.3.1 Forecast Assumptions

HECO’s forecast process begins with an examination of current sales and peak actual performance measures, followed by detailed studies of both the short-term and long-term economic outlook. The short-term (2007 – 2012) economic outlook assumed continued local economic growth, although at a slower pace than experienced recently as the economy matures and moves past the peak in the current construction cycle.

Hawaii’s economy slowed significantly in 2006 after several years of strong growth. Recent economic growth was supported by the construction and visitor industries. The housing market peak has passed, resulting in diminished residential construction, but robust non-residential construction, including military projects, was expected to continue supporting moderate growth in the short-term.

Visitor arrivals were flat in 2006 and only minimal growth was anticipated in 2007 and in subsequent years. Uncertainty in the U.S. economy may handicap previously robust domestic visitor arrivals growth. Rising energy prices, creeping inflation, and a falling housing market in the U.S. appear to be creating downward pressure on the economy that may affect domestic visitor arrivals. Despite potential threats to the U.S. economy,

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domestic visitor arrivals were projected to continue growing at a slow but steady pace. The Japanese economy was projected to continue to see moderate growth, but international visitor arrivals have declined since 2005, offsetting some of the domestic market increases.

Activity in the construction industry has supported Hawaii’s economy for the last several years. Initially, the hot residential housing market carried the building industry, and that was followed by strength in non-residential construction. Non-agricultural jobs continued to grow through 2006. While the construction industry will likely peak by 2007 – 2008, new projects are likely to support moderate job growth through much of the forecast horizon.

The Honolulu inflation rate for 2006 was 5.9%, the highest rate in fifteen years. Inflation was expected to slow in the second half of 2006, but the predicted slowdown did not occur because of rising energy, housing, and food costs. It is now expected that higher inflation will continue for the next several years. Higher inflation is expected to dampen real personal income growth in 2007and could put a strain on consumers as wage increases are not keeping pace with inflation. Oahu real personal income will see only moderate growth as the Hawaii economy slows and inflationary pressures dampen wage increases.

A major component of HECO’s forecast efforts is a detailed economic forecast. The long-term sales and peak forecasts were based on economic data and forecasts prepared by UHERO in March 2007 for HECO’s exclusive use. In January 2007, HECO invited several local business executives to a roundtable discussion on the economy to gain a deeper understanding of the outlook from various business sectors’ perspectives. This discussion provided a background from which UHERO could build a detailed economic forecast. Some examples of the economic data utilized by HECO from UHERO’s database include visitor arrivals, job growth, and personal income. Figures 6.1-1, 6.1-2, and 6.1-3 show the general long-term trends of these variables.

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Figure 6.1-1 Oahu Visitor Arrivals

6,000 15%

5,000 10%

4,000 5% e

3,000 0%

2,000 -5% ChangYOY % Visitor Arrivals (000)

1,000 -10%

0 -15% 1990 1995 2000 2005 2010 2015 2020 2025 2030

YOY % Chg Actual

Figure 6.1-2 Oahu Non-Agriculture Jobs 600 8%

500 6%

400 4% e

300 2%

200 0% Chang % YOY Non-Ag Jobs (000) Jobs Non-Ag

100 -2%

0 -4% 1990 1995 2000 2005 2010 2015 2020 2025 2030

YOY % Chg Non-Ag Jobs

Docket No. 2007-0084 6-4 September 2008 HECO IRP-4 Chapter 6: Long-Term Planning Assumptions & Forecasts

Figure 6.1-3 Oahu Real Personal Income (1992 dollars)

45,000 14%

40,000 12%

35,000 10%

30,000 8% e

25,000 6%

20,000 4%

15,000 2% Chang % YOY

10,000 0% Real Personal Income ($000)

5,000 -2%

0 -4% 1990 1995 2000 2005 2010 2015 2020 2025 2030

YOY % Chg Real Pers Inc

The tourism industry was expected to experience lower growth over the 24 years of the forecast horizon. The U.S. and Japan markets have reached maturation, and competition and demographics in these markets were expected to erode Hawaii’s tourism market over the long-term. Oahu visitor arrivals were expected to continue to grow, but by an average annual growth rate of only about 0.7% over the forecast horizon. Tourism continues to be a key industry upon which the state depends for economic strength, however, the local economy has come to rely more on other industries such as construction and business services for job growth. These industries tend to have higher income jobs, and combined with productivity improvements and technological innovations, personal income was expected to increase over time. Continued economic growth was expected for the state based on projected long-term average growth of 0.8% and 1.6% in jobs and real personal income, respectively.

In late 2007, economic conditions changed drastically after the IRP sales and peak forecast process was completed, and uncertainty has continued into 2008. Pressure on consumer spending skyrocketed as West Texas Intermediate oil prices jumped up by 35% in the second half of 2007, and increased by another 40% by mid-2008. In addition, the torrid U.S. housing market crashed and U.S. financial markets were roiled by massive mortgage losses and bank failures. The current short-term economic outlook for both the U.S. and Hawaii are significantly more pessimistic than the outlook that was used in the IRP forecast. UHERO’s Quarterly Hawaii Forecast Update issued

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in June 2008, projects lower economic activity for 2008 and 2009, but the general long-term trend rebounds to moderate growth by 2010.

6.1.3.2 Sales Forecast Methods

HECO’s sales forecasts were derived using historical sales data that were not reduced by DSM program impacts and econometric methods. Forecasting efforts were focused on two main sectors: residential sales and commercial sales.

The residential sales forecast was developed by further partitioning the residential sector into number of residential customers and electricity use per residential customer. The number of customers forecast is based on historical trends in the number of customers and projected using a time series model. The projections for electricity use per residential customer were derived using two econometric models. For the 2007 forecast, an econometric model based on monthly use per customer was developed and electricity price, cooling degree days (a measure of temperature) and wet bulb temperatures (a measure of humidity) were found to be the major nearer-range drivers of residential use. To forecast longer-range residential use, the growth rates from an econometric model using annual data were developed, and electricity price, cooling degree days (CDD), real personal income per capita were used as independent variables. The growth rates from the annual model were applied to the base 2007 forecast to project 2008 – 2030 average residential use per customer. Total residential sales were then derived by multiplying the forecasted number of residential customers by the projected average use per residential customers.

The commercial sales forecast was also derived using two econometric models, one for the near-term and one for the long-term. The near-term (2007 – 2008) forecast was based on an econometric model using monthly data and the major drivers of commercial sales were found to be CDD, wet bulb temperature, and Honolulu County non-agricultural (non-ag) jobs. The long-term annual econometric models included CDD, non-ag jobs, and electricity price as drivers. The growth rates from the annual models were used to project sales from 2009 – 2030. Load projections from specific large new construction projects that were deemed outside of normal historical trends were added to the econometric commercial forecasts. This is based on the assumption that the additional loads are not fully captured in the historical sales relationships modeled.

The commercial sales forecast was further apportioned between HECO’s commercial rate schedules in order to develop peak forecasts that were based on load profiles by rate schedule from HECO class load studies. The allocation of the commercial sales forecast into rate schedules was performed using ratios based on sales projections by rate schedule using the same econometric model specifications for total commercial

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sales. New construction loads were allocated to specific rate schedules based on information for each project. The majority of the projects fall in Schedule P because of their large size. Finally, sales growth by rate schedule was also adjusted to conform to expectations about trends in rate schedule growth.

6.1.3.3 Peak Forecast Method

The sales forecast determines annual energy requirements. The peak forecast determines the total system capacity requirements for planning purposes. HECO’s peak forecast was developed using the Electric Power Research Institute’s Hourly Electric Load Model (HELM). This model uses weather-normalized rate schedule reference profiles from HECO’s 2003 class load study and the forecasted sales by rate schedule. The rate schedule profiles adjusted for forecasted sales were summed by HELM to produce a system profile and the highest demand on the system profile was used to calculate the annual system peak. Adjustments were made for installed DSM, self- and co-generator outages, and specific large projects (for example, mass transit).

6.1.4 Sales and Peak Forecasts

The short-term sales forecast (2007 – 2012) shows that total sales (not reduced by future DSM installations) are expected to increase at an annual average rate of 1.7% as shown in Table 6.1-1. This rate of growth is higher in the short-term than that experienced in the 1990’s and the first six years of this century. However, much of the growth is due to the large increase expected in 2012 as the planned City and County of Honolulu’s High Capacity Transit Corridor (mass transit) Project begins operations. Without the mass transit project, short-term sales growth would be slower and more similar to recent historical trends. The mass transit loads are expected to begin in 2012, escalating rapidly through 2017 as the planned route is completed, then see continuing but slower rates of growth through 2030 with ridership increases. The sales growth rate gradually slows over the remaining years of the forecast horizon as the local economy matures.

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Table 6.1-1 Long-Term Total Sales Forecast (GWh)

Hawaiian Electric Company, Inc.

AUGUST 2007 LONG TERM SALES FORECAST GWH SALES

Acquired Recorded Recorded DSM Sales Average Sales Program w/o Future Annual w/o DSM Impact DSM % Chg

Actual 2000 7,303.3 -91.5 7,211.8 2001 7,386.3 -109.6 7,276.7 0.9% 2002 7,511.5 -121.1 7,390.4 1.6% 2003 7,657.3 -135.1 7,522.2 1.8% 2004 7,882.1 -149.3 7,732.8 2.8% 2005 7,886.2 -164.9 7,721.3 -0.1% 2006 7,889.9 -189.3 7,700.6 -0.3%

Forecast 2007 7,943.9 -197.6 7,746.3 0.6% 2008 8,034.9 -197.4 7,837.5 1.2% 2009 8,129.3 -197.4 7,931.9 1.2% 2010 8,275.7 -197.1 8,078.6 1.8% 2011 8,388.7 -193.0 8,195.7 1.4% 2012 8,587.2 -173.5 8,413.7 2.7%

Five-Year Intervals 2010-2015 8,932.3 -110.6 8,821.7 1.8%

2015-2020 9,472.5 -37.2 9,435.3 1.4%

2020-2025 9,871.6 0.0 9,871.6 0.9%

2025-2030 10,320.8 0.0 10,320.8 0.9% Note: Recorded sales in rows for five-year periods represent end of period sales. For example, in the 2010-2015 row, the sales shown are for 2015.

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The commercial sector benefits from the mass transit load growth, but in the long-term, the maturing economy will limit job growth and thus constrain the strongly correlated electricity sales to commercial customers. The forecast of residential sector sales expects steady growth driven in part by population which possesses substantial inertia from natural rates of births and deaths. Innovations in home-based technologies and larger home sizes are expected to maintain residential household electrical consumption growth. In the long-term, residential sector increases are expected to be a constant driver of overall sales growth.

Peak demand, unadjusted by future DSM, is expected to grow 1.7% annually over the short-term (2007 – 2012) forecast period, leveling off to lower rates of growth in the outer years of the forecast horizon. The forecast for peak demand for the entire forecast horizon through 2030 without future DSM is shown in Table 6.1-2. Once again, much of the rapid load growth from 2012 through 2017 is due to the mass transit project. The maturing economy and slower sales growth in the outer years of the forecast horizon contributes to the slower long-term growth rate in peak demand.

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Table 6.1-2 Long-Term Total Peak Forecast (Gross MW)

Hawaiian Electric Company, Inc.

AUGUST 2007 LONG TERM PEAK FORECAST GROSS MW

Acquired Peak Peak DSM Demand Average Demand Program w/o Future Annual w/o DSM Impact DSM % Chg

Actual 2000 1,223 -20 1,203 2001 1,257 -24 1,233 2.5% 2002 1,278 -28 1,250 1.4% 2003 1,316 -32 1,284 2.7% 2004 1,363 -36 1,327 3.3% 2005 1,313 -40 1,273 -4.1% 2006 1,360 -45 1,315 3.3%

Forecast 2007 1,381 -44 1,337 1.7% 2008 1,392 -44 1,348 0.8% 2009 1,412 -44 1,368 1.5% 2010 1,438 -44 1,394 1.9% 2011 1,457 -43 1,414 1.4% 2012 1,496 -39 1,457 3.0%

Five-Year Intervals 2010-2015 1,565 -27 1,538 2.0%

2015-2020 1,660 -6 1,654 1.5%

2020-2025 1,745 0 1,745 1.1%

2025-2030 1,840 0 1,840 1.1% Note: Historical peaks do not include standby loads but forecast peaks do. Peaks in rows for five-year intervals represent end of period peaks. For example, in the 2010-2015 row, the peaks shown are peaks for 2015.

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6.1.5 Alternative High- and Low- Load Scenarios

The long-term forecasting process considered alternative high- and low-growth scenarios that provide plausible paths for sales and peak demand over the long-term planning horizon. The alternative scenarios were further examined in the integration process in relation to the global warming analysis, see Chapters 4 and 8.

The basic alternative sales and peak demand scenarios (prior to issues raised in the integration process and global warming analysis) are discussed in this section, and the scenarios are shown in Figures 6.1-4 and 6.1-5.

Figure 6.1-4 Alternative Sales Scenarios

14,000

12,000

10,000

8,000

6,000 GWh Sales

4,000

2,000

0 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027

Recorded Base High Low

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Figure 6.1-5 Alternative Peak Demand Scenarios

2500

2000

1500

1000

Gross MW System Peaks System Gross MW 500

0 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027

Actual Base High Low

The alternative forecast scenarios were based on a range of scenarios with respect to the variables driving the forecast, including economic outlook, fuel oil prices, residential customer growth, weather, mass transit loads, and efficiency trends in the commercial sector. The alternative scenarios considered plausible changes in the assumptions used to develop the long-term forecasts. The alternative economic assumptions considered for the high and low scenarios are shown in Table 6.1-3. In 2030, the last year of the forecast horizon, the high and low projections are about 24% above and 20% below the base scenario, respectively. These scenarios exclude extreme events such as major terrorist attacks, political upheavals, natural disasters, oil supply disruptions, and the introduction of replacement technologies.

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Table 6.1-3 Average Economic Growth Rates for the Low, Base, and High Scenarios Over 30-Year (2000 – 2030) Forecast Measure Low Base High

Visitor Arrivals -0.2% 0.5% 1.3%

Non-Ag Job Count 0.5% 1.0% 1.6%

Real Personal Income Per 0.6% 1.0% 1.5% Capita

Population 0.0% 0.6% 1.2%

6.1.6 Forecast Sensitivities

Sensitivity analysis was used to examine which variables had the greatest impact on the forecast demand in a sample year. The forecast of electricity consumption depends on a number of assumptions about future demand drivers, and to validate these assumptions, HECO examined how sensitive the August 2007 long-term forecast was to key factors. By individually varying a factor while keeping all other factors unchanged from the base forecast, HECO analyzed the impact of each assumption on the long-term total sales forecasts in isolation.

Based on the sensitivity evaluation, the forecast appears to be particularly sensitive to the assumptions and uncertainty associated with economic projections. Figure 6.1-6 shows that economic variables such as number of residential customers, number of non-ag jobs, and real personal income per capita have the greatest impact on sales in the sample year 2020. These changes to the economy produce the greatest variability in the forecast, followed by weather and price assumptions.

Docket No. 2007-0084 6-13 September 2008 HECO IRP-4 Chapter 6: Long-Term Planning Assumptions & Forecasts

Figure 6.1-6 Forecast Sensitivity (For Sample Year 2020)

Economy

Weather

High Sales Scenario Price Low Sales Scenario

-1,500 -1,000 -500 0 500 1,000 1,500 GWh Sales Impact in 2020

6.1.7 IRP-4 Forecasts Compared to the Forecasts in IRP-3

The August 2007 long-term sales forecast is initially lower than the February 2004 long-term sales forecast that was used for IRP-3 (PUC Docket No. 03-0253 filed in October 2005), as shown in Figure 6.1-7.

Docket No. 2007-0084 6-14 September 2008 HECO IRP-4 Chapter 6: Long-Term Planning Assumptions & Forecasts

Figure 6.1-7 August 2007 Sales Forecast is Lower than the February 2004 Sales Forecast

Note: Excludes 2007-on future DSM 12,000 1200

10,000 800

8,000 400

6,000 0 GWh Sales GWh DifferenceGWh

4,000 -400

2,000 -800 1971 1976 1981 1986 1991 1996 2001 2006 2011 2016 2021 2026

Differ Recd Aug 07 Fcst Feb 04 Fcst

The current long-term forecast is lower largely as a result of lower sales since 2004.

While the local economy continued to grow, both residential and commercial sales were below recent forecast expectations. Weather appeared to be a factor in 2005 – 2006 sales performance with cooler, less humid weather lowering sales after a very hot, humid 2004. In addition, double digit increases in electricity prices beginning in mid- 2005 appear to have dampened residential use. Sales have been lower every year since 2004, and 2007 sales were 0.7% below that recorded in 2004. Actual sales have consistently been below forecast since 2003, and these lower than previously anticipated sales trends are reflected in the August 2007 forecast. In addition, both the tourism and construction industries have most likely already passed their peak growth and going forward the local economy is not expected to match the rapid expansion experienced in the earlier part of this decade.

Similarly, as shown in Figure 6.1-8, peak demand is also initially lower in the August 2007 forecast than in the February 2004 forecast. The reason for this more pessimistic peak demand forecast is due to the lower forecast of sales.

Similar to sales, peak demand has been lower since 2004. The record system peak demand of 1,327 gross MW achieved in 2004 has not yet been surpassed.

Docket No. 2007-0084 6-15 September 2008 HECO IRP-4 Chapter 6: Long-Term Planning Assumptions & Forecasts

Figure 6.1-8 August 2007 Peak Demand Forecast is Lower than the February 2004 Peak Demand Forecast

Note: Excludes 2007-on future DSM 2000 350

1800 300

1600 250

1400 200

1200 150

1000 100

800 50

600 0 Gross MW DifferenceGross MW

Gross MW System Peaks System Gross MW 400 -50

200 -100

0 -150 1971 1976 1981 1986 1991 1996 2001 2006 2011 2016 2021 2026

Differ Actual Aug 07 Fcst Feb 04 Fcst

6.1.8 Summary

The August 2007 long-term forecast reflects a more pessimistic outlook for sales and peaks than in the previous IRP forecast (February 2004) in the short-run. However, in the long-term, sales and peaks are expected to continue to grow at a moderate pace. The completion of a mass transit system by 2017 is expected to boost sales and peaks back to the level of the IRP-3 forecast in the long-run. The August 2007 forecast was validated by sensitivity analysis that demonstrated that electricity demand continues to be affected the most by changes in economic conditions.

6.2 Fuel Price Forecast

The difficulty in forecasting the fuel oil prices for HECO IRP-4 continues the challenge that was faced in HECO IRP-3, and that is the rapidly increasing price in the cost of crude oil. HECO’s fuel oil price forecast methodology relies on the research and analytical capabilities of the U.S. Department of Energy’s Energy Information Administration (EIA), and on the futures contract prices for Light Sweet Crude Oil from the New York Merchantile Exchange (NYMEX).

IRP-4 relies on three sets of forecasted fossil fuel oil prices (i.e., Low Sulfur Fuel Oil and No. 2 Diesel Oil):

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The reference price scenario uses the January 8, 2008 NYMEX Most Recent Settle prices for Light Sweet Crude Oil as the basis for the first seven years of the forecast and uses the EIA’s Early Release of the 2008 Annual Energy Outlook (AEO) report’s “World Oil” prices as the basis to extend the forecast out to 2030.

The high price scenario uses the May 19, 2008 NYMEX Most Recent Settle prices for Light Sweet Crude Oil as the basis for the first seven years of the forecast and uses the EIA’s Early Release of the 2008 AEO report’s “World Oil” prices as the basis to extend the forecast out to 2030.

The low price scenario uses the EIA’s Early Release 2008 AEO’s “World Oil” price forecast as the basis to forecast HECO’s fuel oil prices.

In all three fossil fuel oil price forecasts the methodology of forecasting HECO’s Low Sulfur Fuel Oil and No. 2 Diesel Oil is based on the historical relationship between the company’s fuel oil prices and the World Oil prices. A description of this model can be found in Appendix L.

The precedence of using the NYMEX futures contract prices as the basis for forecasting HECO’s fuel oil prices was established in HELCO IRP-3 (see HELCO IRP-3, §4.3 Fuel Price Forecast, pp. 4-15 through 4-18) where the NYMEX prices presented a more “current” view of World Oil prices than the data that was the basis for EIA’s 2006 AEO. In HECO IRP-4, World oil prices have continued to rise rapidly since HECO IRP-3 was filed, and the need for a forecast that reflects “current” fuel oil prices has drawn HECO to utilize the NYMEX futures contract prices for Light Sweet Crude Oil.

Besides fossil fuels, IRP-4 is also analyzing the use of biofuels because of greenhouse gas legislation (see Chapter 4 on Global Warming) and due to Governor Lingle’s leadership in guiding the State of Hawaii’s move towards a more future that is less reliant on fossil fuels that are imported into the state.

6.2.1 Biodiesel

An important part of HECO’s “green” diesel strategy is to encourage local cultivation of feedstock crops which can eventually be grown and processed in the State. To promote the development of investment in Hawaii’s biofuels industry the company has entered into supply agreements with biofuel processors. On the basis of HECO’s biofuels commitments, investors have committed to make sizable new investments on Oahu and Maui. • On Oahu, Imperium Renewable Hawaii LLP developed plans to invest $90 million in a 100 million gallon/year biodiesel facility at Kalaeloa Harbor. The chemical plant would create 50-60 new jobs. At the time of IRP-4 preparation the Kalaeloa plan has been placed on hold.

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• In February 2007, BlueEarth Biofuels LLC (BlueEarth) announced plans for a biodiesel transesterification plant to be built on the island of Maui. The plant is anticipated to be operational by early 2011. MECO intends to lease to the project a portion of the land owned by MECO for its future Waena generating station as the site for the biodiesel plant, with lease proceeds to be credited to MECO ratepayers. In addition, MECO is negotiating a fuel purchase contract with BlueEarth Maui for biodiesel to be used in existing diesel-fired units at MECO’s Maalaea plant. Both the land lease agreement and the biodiesel fuel contract will require PUC approval. HECO, working closely with the Natural Resources Defense Council, developed an environmental policy, which focuses on sustainable palm oil and locally-grown feed stocks, to ensure that any HECO, HELCO or MECO project will procure biofuel and biofuel feed stocks only from sustainable sources. Also key to the project is the creation of a Biofuels Trust Fund to support the development of biofuel production in Hawaii.22

In parallel with its agreements with biodiesel processors, HECO is supporting agricultural specialists at the University of Hawaii who are undertaking field trials designed to establish the commercial viability of oil palm and jatropha agriculture on the Big Island. Also at the University of Hawaii, HECO is supporting preliminary investigations into the development of algae as a biodiesel feedstock.

Unfortunately, an entirely new bio-energy industry cannot be established overnight nor can new agricultural crops be field tested, planted and harvested in a short period of time. As a result, the initial stages of the green biofuel strategy will depend on vegetable oils (primarily palm oil) imported from outside the state. To insure that these crops are grown in ecologically responsible and sustainable ways, HECO worked with the Natural Resources Defense Council (NRDC), a prominent environmental advocacy group, to develop a sustainable procurement policy and to monitor feedstock supply sources (see Appendix K). HECO is now a member of the international Roundtable for Sustainable Palm Oil (RSPO) a consumer/producer association dedicated to sustainable cultivation of oil palms.

Methodological Problems - Since biodiesel is a relatively new industry, there is almost no publically accessible information on actual biodiesel prices in the United States. The fragmentary information available on the US biodiesel market is almost exclusively based on very small scale processing of surplus feedstock crops in niche markets. For example, in Hawaii, used cooking oil and grease are used to produce limited quantities

22 In order to accelerate the development of local feedstocks, HECO will create an independent Biofuels Public Trust Fund to fund biofuels research and development in Hawaii and build intermediate processing facilities for locally grown biofuel crops.

Docket No. 2007-0084 6-18 September 2008 HECO IRP-4 Chapter 6: Long-Term Planning Assumptions & Forecasts

of biodiesel at a pioneering facility on Maui. However, neither the scale of these niche operations nor the feedstock inputs can be extended to the economics of a commercial-scale biodiesel production facility. While biodiesel production in Europe is generally at a much larger scale, existing plants are only a fraction of the size of the state-of-the-art plants currently being planned. Moreover, plants in Europe and on the US Mainland use feedstock crops like soybean or rapeseed that are not suitable for cultivation in Hawaii.

Role of Biofuel Scenarios in IRP-4 - Since there is little “hard” pricing information of relevance to IRP-4 biofuel requirements a contingency approach has been adopted in the plan. Under this approach two alternative biofuel price scenarios have been identified that encompass a range, or envelope, of future likely prices. By comparing the planning results that occur as a consequence of each scenario we can gain insight into the impact of higher biofuel prices.

While clearly one of these scenarios is higher than the other scenario, there is a more subtle distinction between the two projections: time.

It is increasingly clear that the explosion in fossil fuel prices since early 2007 has influenced the prices of agricultural commodities used in making biofuels. As fossil fuel prices have escalated, they have increased upward pressures on biofuel feedstock prices.23 As a result of this linkage, a commodity price forecast made , for example, in the third quarter of 2007 is likely to be considerably lower than a commodity forecast made in mid-2008. In the case of palm oil there is an additional complication, since national and multinational biodiesel mandates in Europe and elsewhere have added substantial short-term speculative price pressures to an already volatile market (see below).

Crude Palm Oil Prices - Due to the initial importation of palm oil, the development of the IRP-4 biofuel price forecast is based primarily on international palm oil prices. Two things are important about this outlook. First, all IRP-4 price projections are based on the international price for crude palm oil (CPO) rather than reported prices for derivative products.24 Where the IRP-4 projections use prices from these intermediate products, they are calculated from the basic palm oil price. We have adopted this convention to reflect the Company’s intention to meet our needs primarily from local processors and

23 While this is most easily seen in the grain and sugar prices required for producing ethanol, it is also evident in those agricultural commodities used as biodiesel feedstocks…notably soybeans, rapeseed, and palm oil. 24 The major derivative products are RBD (used as an edible cooking oil throughout much of Asia) and PFAD (used in soap and chemical processes).

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agricultural feed stocks rather than by simply buying biofuels derivatives on the international market.25

The world price for CPO reflect supply shortages of edible cooking oil in China and India and a regulatory mandate in the European Community that 5.75% of total diesel consumption must come from biodiesel sources. Exactly how these short term factors will play out in the future is uncertain. However, over the medium and longer term, Palm Oil is a renewable agricultural commodity whose price behavior is expected to reflect typical agricultural commodity cycles where high prices are generally followed by price declines resulting either from expanded cultivation, improved yields from existing acreage, or changes in customer demand. Thus, the expectation is for price stabilization and eventual price declines to take place during the course of the IRP-4 planning period.

Most commodity analysts agree that there is substantial speculation in current palm oil prices. This speculation is, at least, partially related to the inability of European farmers to meet the EU biodiesel mandate. If there is a short fall in European soy or rapeseed production then large scale importation of palm oil is seen as a strong possibility, and price speculators will bidding up “futures” prices to profit from any shortfall.

Palm Oil Price Scenarios - After a literature review we have decided to adopt two alternative palm oil price scenarios in IRP-4. Our “outlook scenario” assumes reduced price speculation and eventual price declines to historical levels. It also anticipates that substantial local feedstock production will occur in Hawaii at “delivered costs” (net of transport) which are below international commodity price levels but that the price of finished biodiesel will still be determined by international markets. Future price declines will reflect an increase in palm oil supply resulting from new overseas oil palm plantations and the replanting of existing plantations with higher yielding varieties. Since new Oil Palm trees require four to six years to reach full commercial production, the impact of these new plantings will not immediately be reflected in increased supply. After an initial period, the outlook scenario prices will gradually return to levels reflected in long term projections made by the United Nations Food and Agricultural Organization (UNFAO).

In our “alternative price scenario,” we have adopted the World Bank projections for palm oil prices through 2020 and assumed that prices will remain at the 2020 level for the remainder of the forecast period. The alternative price projection is substantially higher than the projection generated in the “outlook scenario” and reflects the World Bank’s

25 The company is currently investigating the prospects for directly burning crude palm oil (CPO) in its generating plants without processing the feedstock into biodiesel. However, this research is not sufficiently advanced to warrant its inclusion as an assumption in IRP-4.

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view of greater (current) price speculation giving way to longer term price moderation as additional supplies enter the market from new sources. The World Bank does not believe that palm oil prices are likely to fall to the historic levels (as anticipated by UNFAO) but that substantial declines are very likely. Since the purpose of the two scenarios is to define the bounds of uncertainty in the IRP-4 planning assumptions, the large difference between the outlook scenario and the World Bank scenario contributes to the range of possibilities assessed in integration analysis.

The outlook scenario and World Bank Scenario palm oil prices used in the IRP-4 analysis are presented in Table 6.2-1 below.

Table 6.2-1 Outlook Scenario & World Bank Scenario Palm Oil Forecast

Palm Oil Forecast

Outlook WB 2008 105 182 2009 108 173 2010 108 163 2011 97 156 2012 88 148 2013 81 141 2014 74 134 2015 68 127 2016 61 120 2017 62 113 2018 63 106 2019 64 99 2020 64 93 2021 65 93 2022 66 93 2023 66 93 2024 67 93 2025 67 93 2026 68 93 2027 69 93 2028 69 93 2029 70 93 2030 71 93

Processing Costs - is processed into biodiesel using a process called transesterfication. Like many chemical processes, transesterfication is less costly in large scale facility (e.g., enjoys significant economies of scale). Most American biodiesel is produced from very small facilities in niche markets in the Midwest. As mentioned the costs of these small operations are not indicative of the costs that would accompany a large scale facility. The largest transesterfication facilities currently being considered are in the major palm oil producing countries of Malaysia and Indonesia. The Japanese Petroleum Center developed a production cost estimate for a state-of-art facilities planned for Malaysia. This estimate is presented in Table 6.2-2.

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Table 6.2-2 Large Scale Biodiesel Production Costs in Asia

Cost element US$/liter %

Raw material

Palm oil .39 72%

Methanol .02 4%

Conversion Cost

Capital .07 13%

Variable .05 9%

Total Cost .54

Source: Japan Petroleum Energy Center (as reported In Ogha, K. and Koizumi, T. Biofuels Policies in Asia…)

Clearly, the overwhelming cost in producing biodiesel is the basic cost of the crude palm oil.

Other Costs - • Transportation Costs - Estimating transportation costs is particularly difficult at this stage in the biodiesel strategy. Since we do not yet know the likely sources of palm oil, or the rate at which locally grown agricultural feed stocks might be substituted for imported palm oil, the shipping volumes and supply sources will be constantly changing. For these reasons, it is not possible to develop a clear methodology for ocean shipment of palm oil to Hawaii. • Refiner Profit - Although well developed in Europe, the American biodiesel industry is still in its infancy. In practice, this means that American biodiesel processors are likely to be undercapitalized, undiversified, and face above-average business and technology risks. In combination this suggests that the profit expectation of pioneering firms is likely to be somewhat higher than might be expected in mature industries. How much higher these profit expectations might be is not easily determined outside the industry. • Taxes and Sustainability validation costs - As mentioned, HECO’s policy is to only use palm oil from sustainable sources. A process for auditing palm oil sources has been agreed with the Natural Resource Defense Council (NRDC). It is expected that securing palm oil under the NRDC agreement together with the cost of auditing the supply chain to insure compliance will involve significant additional costs.

Since these other costs are not transparent at this stage, the biodiesel price projections have made a simplifying assumption about these cost elements. Under current federal

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law, biodiesel processors are entitled to claim a $1 per gallon blending credit. For the purpose of these preliminary estimates it is assumed that this blending credit is adequate to offset a significant fraction of these “other” costs.

Behind any forecast of international price levels there are numerous uncertainties. These uncertainties include movement in relative exchange rates, price speculation, changes in national resource and export policies and the entry of new overseas suppliers. In the case of biodiesel, there are also numerous potential feedstock crops that might be substituted for palm oil.

Crude Palm Oil Prices for Biodiesel Prices - By combining the “Outlook” and “World Bank” estimates for palm oil prices with the Japanese Petroleum Institutes estimate of long-term processing costs, IRP-4 developed an Imputed biodiesel price for both price scenarios. A comparison of these forecasts is presented in Figure 6.2-1.

Figure 6.2-1 Imputed Biodiesel Prices (2007 Prices)

Imputed BioDiesel Prices (2007 Prices)

300 250 200 Imputed World Bank 150 Imputed 'Outlook'

US$/bbl 100 50 0

4 6 08 1 17 2 0 0 0 2 2011 20 2 2020 2023 2 2029 ye ar

Other Biofuels - While biofuels are a central strategic theme in IRP-4 there is a considerable amount of testing and technical evaluation which must be undertaken to find the most suitable and cost effective way to use these fuels. This work is a major task of the IRP-4 Action Plan.

In the HECO system there are two major types of generation units: combustion turbines (CT) used for mid-range and peaking purposes and steam boilers used for base load generation. These generators use different fossil fuels and would potentially require different biofuels. While it is likely that the CT’s will require finished biodiesel it is less clear whether this is the preferred (or most economical) fuel for the steam boilers. Against the possibility that the steam plants might burn lower-cost crude (or

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semi-processed) palm oil, forecasts were made for these fuels and incorporated into selected IRP-4 integration runs. As noted the basis for these ‘other biofuels’ was the CPO prices presented above. The prices of derived products are set out in Attachment 1.

6.2.2 Low Sulfur Fuel Oil (LSFO)

Low Sulfur Fuel Oil (LSFO) is a residual fuel oil that has a 0.5% maximum sulfur content (by weight) and is currently used in the HECO steam generating units at the Honolulu, Waiau, and Kahe power plants. LSFO is currently HECO’s primary fuel source.

The forecasted LSFO prices that are used in IRP-4 are significantly higher than the forecasted prices that were used in IRP-3 as shown on the graph below.

Figure 6.2-2 HECO Low Sulfur Fuel Oil Price Forecast

HECO Low Sulfur Fuel Oil Price Forecast

$160

$140

$120 Actual 2008 Actual is Year-To-Date June 2008 $100 2008-High 2008-Base $80 2008-Low 2002-High $60 2002-Base 2002-Low

Dollarsper Barrel (Nominal) $40

$20

$- 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

Year

The LSFO price forecast that is used in IRP-4 reflect the current high price that is being experienced, as opposed to the forecast that was used in IRP-3 that was lower than the price that was experienced back then. This LSFO price forecast in IRP-4 allows the

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Company to reflect the relative cost between fossil fuel oil resources and renewable resources in a better way than what was available in IRP-3.

HECO IRP-3 used HECO’s 2002 Fuel Oil Price Forecast in its analysis and the availability of a more recent forecast did not become available until late in the Integration process. There was an immaterial difference between the forecasted prices between the 2002 and the 2005 Fuel Oil Price Forecasts.

6.2.3 No. 2 Diesel Oil

No. 2 Diesel Oil is a distillate fuel oil that has a 0.4% maximum sulfur content (by weight) and is currently used in HECO’s Waiau 9 and Waiau 10 combustion turbine generating units.

The forecasted LSFO prices that are used in IRP-4 are significantly higher than the forecasted prices that were used in IRP-3 as shown on the graph below.

Figure 6.2-3 HECO Diesel Oil Price Forecast

HECO Diesel Oil Price Forecast

$200

$180

$160

$140 Actual 2008 Actual is Year-To-Date June 2008 2008-High $120 2008-Base $100 2008-Low 2002-High $80 2002-Base $60 2002-Low Dollars perBarrel (Nominal) $40

$20

$- 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

Year

Docket No. 2007-0084 6-25 September 2008 HECO IRP-4 Chapter 6: Long-Term Planning Assumptions & Forecasts

In HECO IRP-3, the No. 2 Diesel Oil price was based on the 2002 Fuel Oil Price Forecast, for the same reasons as discussed for LSFO (§6.2.2).

6.2.4 Liquefied Natural Gas (LNG)

Liquefied natural gas (LNG) is natural gas that has been cooled to cryogenic temperatures (approximately 256°F below zero) to liquefy it such that it occupies 1/600th the volume of natural gas and is easier to transport. The use of LNG would help to diversify Hawaii’s fuel supply mix and reduce the dependence on imported oil. It is typical to have long-term (i.e., 20-year) LNG supply contracts to help suppliers ensure their cashflow for the large infrastructure investment. Therefore, it might be possible that the use of LNG could help reduce the volatility in fuel prices in Hawaii. LNG, being almost pure methane, would also reduce CO2 emissions levels when combusted by about 30% compared to fuel oil.

LNG is currently not used in Hawaii; however, with the increase use of natural gas in recent decades, the LNG industry has grown significantly. LNG liquefaction terminals have been built within the Pacific Basin and potential sources for LNG for Hawaii are Australia, Brunei, Indonesia, and Malaysia. Alaska has also been pursuing the construction of a liquefaction terminal and could be a potential source in the future.

A study by FACTS Inc., prepared in 2007 evaluated the potential of the using LNG in Hawaii26. In this evaluation, the expected volume of LNG for such a system to be viable on Oahu would require the conversion of the Kahe and Waiau generating stations to natural gas. Kalaeloa Power Partner’s 208 MW combined cycle unit would convert to natural gas after their current contract expires in 2016 and any new generation built on Oahu would be fuel with natural gas.

The use of LNG on Oahu would have significant infrastructure requirements. It would require the building of a regassification terminal and storage facility, presumably at Kalaeloa Harbor, with a cost in the order of $400 million. The regassification and storage facility would be a large infrastructure project with possible impacts and safety concerns by the local communities. In addition, there would possibly be harbor improvements required to accommodate the large size of LNG tankers including dredging of the harbor and entrance. Gas pipelines would be required to connect the storage facility to the Kahe, Waiau and Kalaeloa generating stations, and any other future generating units. Safety and national security requirements would likely require harbor restrictions during ingress and egress of the LNG tanker.

26 FACTS, Inc., Evaluating Natural Gas Import Options for the State of Hawaii, April 2007.

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Although LNG offers potential for fuel diversity and some reduction in GHG emission, it would require tremendous fuel infrastructure improvements that would likely preclude the transition to renewable energy. More importantly, LNG is still a fossil fuel and its use would merely transfer dependence from one imported fossil fuel to another. For these reasons, LNG was not considered further in HECO’s IRP-4. It is clear that creating an LNG system on Oahu would have far reaching impacts to the state energy situation that go beyond that of the electric utility including impacts to the local communities. Until such time as state and local government adopt LNG as part of its energy objectives, HECO will continue to monitor the LNG industry.

6.2.5 Ethanol

Ethanol, also called ethyl alcohol, is traditionally made by fermenting starch or sugars. In Hawaii, it is blended with gasoline to meet a state requirement that 85% of the gasoline sold in Hawaii contain 10% ethanol. In recent years there have been several ethanol plants proposed, but due to delays in these projects, none are operational yet.

HECO initially pursued the use of ethanol in its Campbell Industrial Park CT-1 project scheduled to be operational in 2009, but has since determined the preferred biofuel for the project to be biodiesel. For the CT-1 project, it was determined that ethanol, because of its high vapor pressure, could not be used to start-up the unit due to potential vapor lock in the fuel forwarding pumps, whereas this is not expected to be the case with biodiesel. Also, ethanol has a 65% lower heat content such that the maximum generating capacity of CT-1 would be reduced at blends about 50%. If 100% ethanol fuel is used in CT-1, its capacity is expected to be derated by 14 MWs.

For the above reasons, HECO did not consider the use of ethanol further for the CT-1 project and the HECO IRP-4 process. However, the potential to produce ethanol using fiber through a cellulosic process has promise for the future, therefore HECO will continue to monitor the ethanol industry for possible consideration of ethanol in future IRP efforts.

6.3 Financial Assumptions

Table 6.3.1 highlights the significant financial assumptions used in the IRP-4 integration analysis.

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Table 6.3-1 IRP Assumptions

Item Assumption Analysis Period 2009 - 2028 Transmission & Distribution 4.84% of net generation (2002-2006 historical Losses and Company Use average) August 2007 Forecast and March 2008 Sales & Peak Load Forecast Forecast (Appendix K) Fossil Fuel Price Forecast HECO May 2008 Forecast (Appendix L) Biofuels Price Outlook Data shown in Section 6.2.1 DSM Cost & Performance Data Data shown in Appendix M Future Supply-Side Resource Data shown in Section 7.3 Cost & Performance Data Existing HECO-owned generating unit performance and Data shown in Table 6.3.2 maintenance data Emergency Reserve Status of Waiau 3 and Existing Unit Retirements Waiau 4 in 2011 and 2014, respectively. Purchase Power Agreements Data shown in Table 6.3.3 Weight Rate Short-term debt 3% 6% Long-term debt 36% 7% Cost of Capital Preferred Stock 7% 8% Common Equity 54% 12% Composite Weighted Average 9.56% After-tax Weighted Average 8.58% Inflation Rate 2009-2012 1.80% (used to escalate O&M) 2013-2016 1.71% 2017-2021 1.85% 2022-2028 1.97% Composite Income Tax Rate 38.91% Revenue Taxes 8.89%

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Table 6.3-2 HECO Unit Performance Data

Unit Minimum Unit Normal Top Initial Current FuelRatings, MW Load Rating, MW Operation Age, Unit Type Gross Net Gross Net Date Years

Honolulu 8 LSFO 24 22.3 56 52.9 1954 54 Honolulu 9 LSFO 24 22.3 57 54.4 1957 51

Waiau 3 LSFO 24 22.3 49 46.2 1947 61 Waiau 4 LSFO 24 22.3 49 46.4 1950 58 Waiau 5 LSFO 24 22.5 57 54.6 1959 49 Waiau 6 LSFO 24 22.5 58 55.6 1961 47 Waiau 7 LSFO 35 32.6 92 88.1 1966 42 Waiau 8 LSFO 35 32.8 92 88.1 1968 40 Waiau 9 Diesel 6 5.9 52 51.9 1973 35 Waiau 10 Diesel 6 5.9 50 49.9 1972 36

Kahe 1 LSFO 35 32.5 92 88.2 1963 45 Kahe 2 LSFO 35 32.7 90 86.3 1964 44 Kahe 3 LSFO 35 32.3 92 88.2 1970 38 Kahe 4 LSFO 35 32.3 93 89.2 1972 36 Kahe 5 LSFO 55 50.7 142 134.7 1974 34 Kahe 6 LSFO 55 50 142 133.9 1981 27

Total 476 441.9 1263 1208.6

Table 6.3-3 IPP Firm Capacity Agreement

Contract Firm Capacity IndependentCapacity 2007 Energy Expiration Power ProducerMW (net) Sales, kWh Year

HPOWER 46 302,090,955 2015 Kalaeloa Partners, L.P. 208 1,425,425,008 2016 AES Hawaii 180 1,507,083,734 2022

Total 434 3,234,599,697

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Docket No. 2007-0084 6-30 September 2008 HECO IRP-4 Chapter 7: Resource Options

7 RESOURCE OPTIONS

7.1 Demand-Side Resources

7.1.1 Background and Overview

The demand-side management (“DSM”) resource portfolio presented in IRP-4 is the result of a comprehensive and wide-ranging assessment of energy efficiency and demand response potential and program development. Energy efficiency programs are designed to permanently reduce energy use during all times of the day and are typically enabled through the installation of high efficiency measures and equipment. Demand response programs being pursued under DSM temporarily reduce energy use during periods when the utility anticipates having or is having difficulty meeting the load. Both types of programs are designed to aggressively acquire efficiency and conservation resources in a cost-effective manner. DSM measures may include new or replacement equipment, information, policies, and/or innovative rate design.

This chapter provides an overview of the DSM program development process, a discussion of the programs that were selected through this process, and an overview of the potential impact that these programs would have for HECO and its ratepayers in terms of energy savings, expenditures, and cost-effectiveness.

As discussed earlier in Chapter 1, on February 13, 2007, Decision and Order No. 23258 was issued by the Commission in the Energy Efficiency Docket, Docket No. 05-0069. Decision and Order No. 23258 addressed two major categories of issues, namely statewide energy policy Issues and HECO’s proposed DSM programs issues, and set forth broad policies and principles for the implementation of energy efficiency demand- side management (“DSM”) programs. With respect to statewide energy policy Issues, Decision and Order No. 23258 established the transition for the administration of all energy efficiency DSM programs be turned over to a non-utility, third-party administrator, with the transition to a third-party administrator, funded through a public benefits fund surcharge, to become effective around January 2009. Unlike the Energy Efficiency DSM programs, load management DSM programs will continue to be administered by the utilities. On May 12, 2008 the Commission convened a status conference of the parties to Docket No. 2007-0323 to discuss, among other things, a transition process that included the continuation of the current energy efficiency programs by HECO for up to six months after January 1, 2009, the projected initiation date of the third party

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administrator. The resolution of issues discussed at the May 12, 2008 status conference was confirmed by a PUC Order issued on July 2, 2008.27

In updating its DSM resource portfolio, HECO used a comprehensive analytical and collaborative process involving extensive advice and input from the HECO Advisory Group (“AG”) and trade allies, review of best practices from other utilities and lessons learned from its own experience gained over the past 12 years of implementing a variety of DSM programs. The resulting portfolio of DSM programs was designed to aggressively acquire energy conservation resources in a cost-effective manner as HECO anticipates future resource needs. That is, there are net benefits of the DSM programs to the ratepayers when compared to the revenue requirements necessary if the DSM programs were not pursued, regardless of the structure of administrative structure of DSM programs.

To assist in the development of this assessment, HECO retained Global Energy Partners (“GEP”) to conduct a study which forms the basis for HECO’s proposed DSM programs outlined in this report (Appendix M). The study was conducted in two phases. The Phase I portion of the study is an updated assessment of the Maximum Achievable Potential (“MAP”) for energy efficiency and demand response that was originally conducted by GEP in the 2003-2004 timeframe for the purposes of developing the DSM resource portfolio under HECO’s IRP-3 efforts. Since that time, changes to HECO’s baseline forecast and electric prices necessitated an updated analysis and review of the original assumptions in preparation for the development of the energy efficiency and demand response programs that would be assessed during the IRP-4 process. In addition, various measures that were screened out during the 2004 study are now more commercially viable and were re-examined for possible inclusion in the MAP. The updated MAP serves as the basis for the development of the energy efficiency programs in Phase II.

MAP represents a hypothetical upper-boundary for energy savings that a utility can possibly achieve through its DSM programs. While it is the intent for DSM programs to be designed to achieve the MAP, expected DSM program impacts can never capture 100 percent of the MAP. This is due to market factors and customer acceptance issues that are always present in spite of optimal DSM program designs.

In Phase II, HECO’s ongoing programs were reviewed and modified based on the MAP assessment in Phase I, updated program data from HECO’s implementation experience, and benchmarking targets from other utility program best practices.

27 Order to Initiate the Collection of Funds for the Third Party Administrator of Energy Efficiency Programs, July 2, 2008.

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The AG provided input and feedback to the study. During the two phases of the project, GEP participated in three meetings with the AG to solicit input on the study process, including feedback on overall methodology, qualified measures, program portfolio, and the reasonableness of the results. Copies of the three presentations are provided in Appendix F. The AG’s input was incorporated into the study at each stage of development. The following proposed DSM programs, described in more detail later in this chapter, were moved onto the integration analysis phase for further testing for cost- effectiveness against supply-side resources: • Commercial and Industrial Energy Efficiency Program (“CIEE”) • Commercial and Industrial New Construction Program (“CINC”) • Commercial and Industrial Customized Rebate Program (“CICR”) • Energy Solutions for the Home (“ESH”) • Residential Efficient Water Heating Program (“REWH”) • Residential New Construction (“RNC”) • Residential Low Income (“RLI”) • Commercial and Industrial Direct Load Control Program (“CIDLC”) • Residential Direct Load Control Program (“RDLC”) 28

The impact of transitioning the administration of all energy efficiency DSM programs to a non-utility, third-party administrator is unknown at this time. However, the maximum achievable potential and resulting cost-effective DSM resource portfolio is independent of the administrative structure. HECO’s administrative costs were used as a proxy for the third-party administrator’s costs. HECO will work with the third-party administrator to provide a smooth transition in which customers are continuously encouraged to pursue cost effective energy efficiency improvements. HECO will update its resource plans to reflect the outcome of the transition in its next scheduled HECO IRP-related filing.

7.1.2 Program Development Process

Development of the DSM resource portfolio began with updating the Phase I Study that identified the maximum achievable potential for energy efficiency and demand response. The last MAP study was completed in early 2004, but changes to HECO’s baseline forecast and electricity prices and costs relative to the earlier study necessitated conducting a new assessment. Also various measures that were not considered

28 The GEP Study, Phase II also proposed a pilot residential home energy audit program. Further, in addition to the programs identified in the study, HECO also intends to continue implementing the SolarSaver Pilot (SSP)and Residential Customer Energy Awareness (RCEA) pilot programs pending the result of program evaluations due to be completed by the end of September 2008.

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commercially viable at the time were considered during this stage of the analysis. Phase II is an assessment of HECO’s energy efficiency and demand response programs relative to the updated MAP estimates and other changes since the last review, including the transition of the administration of future energy efficiency programs to a third-party entity. Figure 7.1-1 illustrates the process that was employed for both the Phase I and Phase II efforts that culminate in this Plan. The items illustrated in the upper portion of the figure represent the Phase I Study. The items illustrated in the lower portion of the figure represent the Phase II study. Throughout the analysis process, both HECO- specific data sources as well as secondary data sources were used as at the basis for conducting various aspects of the Phases I and II efforts.

Figure 7.1-1 Detailed Approach for IRP-4 Energy Efficiency Study

Base Case Development

Characterizing Energy Efficiency Measures Phase I: Database of Energy Market Review MAP Study Efficiency Measures -Utility accomplishments -Benchmark review IRP-4 AG Group

Economic Screen of Assessment of Energy Efficiency Measures Maximum Achievable Potential

Development of HECO-Specific Energy Efficiency Data Sources Program Portfolio Phase II: Cost Effectiveness Analysis of Energy Program Efficiency Programs Secondary Outside Development Data Sources Selection of Programs for IRP Analysis

The approach taken to update the estimates of the long-range energy efficiency and demand response potential included the following steps:

Step 1: Development of Base Case – Development of a base case of energy consumption and peak demand that excludes any impacts associated with future energy efficiency and demand response programs and initiatives. The base case serves as a benchmark from which assessments could be made regarding the potential savings associated with the energy efficiency and demand response measures evaluated in this study. The base case includes a breakdown of energy consumption and peak demand by 1) sector (residential, commercial and industrial), 2) market segment within each sector (e.g. nine building types for the commercial sector including offices, retail, etc.), and 3) end-use for each market segment (e.g. cooling, lighting, etc.).

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Step 2: Assessment of Energy Efficiency and Demand Response Measures – Development of a comprehensive list of energy efficiency and demand response measures as possible candidates for eventual implementation in Hawaii. Two levels of measure screening were then applied. The first screening was a qualitative screening to select those measures that were most applicable and suitable given conditions in Hawaii. The qualitative screen included new measures that had been identified following IRP-3. In addition, input from the AG pertaining to the measures and screening criteria was incorporated into the process. The measures that passed the qualitative screening were forwarded to the second screening, which was a more rigorous economic screening that calculated the unit-level energy and demand savings and costs associated with the measure. This stage required the development of the savings and cost parameters for the new measures, including update of the data parameters for measures that passed the economic screen the first time around. Using HECO’s latest electric rate forecast, a benefit-cost test was applied to each measure to determine if the measure met the cost-effectiveness threshold.

Step 3: Assessment of Maximum Achievable Potential - The subset of the original measures that passed the economic screen in the previous step was then bundled together and used in establishing the “economic potential.” Economic potential represents the maximum savings of the measures that pass the economic screen and ignores program administration costs and customer preferences. Maximum Achievable Potential or MAP is the subset of economic potential. Maximum achievable potential factors in expected program participation, customer preferences, and budgetary constraints. Maximum achievable potential is established using market acceptance rates derived from programs with incentives that represent 100% of the incremental costs combined with high administrative and marketing costs. Maximum achievable potential must be balanced against other constraints such as low participation rates, economic boundaries, and customer equity in the development of final program designs and savings targets. Recognizing that it is difficult to economically justify programs with these types of incentives and marketing efforts, MAP represents a theoretical upper- boundary for the energy efficiency and demand response savings.

Step 4: Development of Programs - HECO’s existing programs were reviewed and modified taking into account the revised MAP estimates determined during Phase I. The MAP study identifies the amount of achievable energy efficiency and demand response potential which might be obtained from each market segment and end-use as well as the segments and end-uses that appear to provide the greatest level of cost-effective savings. HECO’s existing nine programs were then reviewed from the perspective of how well they could potentially tap into the majority of the MAP. For example, high efficiency cooling and associated ventilation measures make up nearly 50% of the total MAP energy savings and a third of the peak demand savings for existing buildings where retrofit measures are most applicable to this program. High efficiency lighting

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measures make up about 35% of the total MAP energy savings and about half of the peak demand savings for existing buildings. The energy efficiency measures incented in the CIEE Program (i.e., cooling/ventilation and lighting) correspond directly with the retrofit end-uses that were identified in the MAP as having large potential that could be cost-effectively addressed.

HECO also provided the results of the MAP study as well as the past results and experiences of implementing its existing programs to the AG in order to gather input from the AG. HECO also took into consideration input from trade allies, benchmarking targets from other utility program best practices, HECO’s past program experience, and the impact of transitioning the administration of future energy efficiency programs to a third-party administrator.

Step 5: Development of Program Parameters - During this step, program-level parameters were developed that correspond to the programs established in step 4. These parameters serve as the basis for determining the cost-effectiveness of each program. The parameters include the number of new participants, unit-level energy and demand savings, measure lifetimes, equipment costs, incentives, and program budget. Projected budgets for the programs were developed through an approach that was based largely on using HECO’s past DSM program experience as a proxy for what expenditures would be required for the future. Expenditure categories included the following: • Incentives • Implementation labor • Program tracking • Marketing and advertising • Other (includes materials, travel and miscellaneous) • Capital equipment costs associated with load control programs • Monitoring and evaluation activities.

Step 6: Estimate Preliminary Cost-Effectiveness - A preliminary cost effectiveness analysis was conducted for each program, drawing upon the parameters developed in Step 5 in order to broadly assess whether the proposed program portfolio would be cost- effective. The results are represented by the benefit/cost ratios and the present value benefits and costs for the four California Standard Practice Tests - Total Resource Cost (TRC), Utility Cost (UC), Rate Impact Measure (RIM), and the Participant tests. In general, HECO believes that its DSM programs should all have positive net benefits according to the Total Resource Cost perspectives to be considered “cost-effective.” However, the overall determination of cost effectiveness in the IRP process should take into account all of the goals and objectives of IRP including the availability of non- quantifiable benefits such as supporting Hawaii’s state energy policies and objectives,

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and the rate impact of the programs. Inputs for the cost effectiveness analysis include the avoided capacity and energy costs29, retail rates, and other economic parameters including the various discount and cost escalation rates used by HECO for its system planning needs. These inputs allowed the preliminary economic analysis to provide an initial screening for program cost effectiveness and economic viability, in advance of integration with supply-side options.

7.1.2.1 Input from the Advisory Group

An important consideration in developing DSM programs was the input received from the Advisory Group. The following is a summary of the comments received through the various meetings and was, to the extent practicable, incorporated into the development of new or enhancement of existing programs.

Residential Sector: • Remove barriers that exist in reaching renters, the low income market and apartment buildings • Reach out to developers and architects to get them to include solar water heating in their projects. • Have a third-party provide a “bulk loan” financing structure for the SolarSaver Pilot Program • Conduct residential energy audits to improve residential energy efficiency awareness • Address phantom loads by educating and incentivizing changes to behavior • Continue and/or develop additional educational programs such as the Residential Customer Energy Awareness Program. Target elementary school children and provide consumer tips • Consider battery storage, PV systems and plug-in hybrids to help reduce residential load peaks • Continue to provide quality controls on solar water heater installations in conjunction with the state mandated solar water heating on new construction

29 Avoided costs were developed using the CT proxy method for this study in order to gain an understanding of the economics of the various energy efficiency programs as part of the pre-integration analysis (see Attachment M, Section 9.2). The cost-effectiveness analysis of the resulting DSM programs is done in the IRP-4 integration analysis.

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Commercial Sector: • Provide rebates for new DSM technologies to reduce first cost barriers • Simplify the rebate process for customized applications. e.g., The process and time it takes to monitor the performance of an energy management system is cumbersome.

All sectors: • Look into programs that encourage load shifting • Financing of DSM measures is important • Provide tiered incentives to provide for greater incentives for “ultra efficient” technologies • Goal should be to lower entire load curve to save energy and not just peak demand

7.1.3 Overview of Results

The following section provides an overview of the nine existing programs for inclusion in IRP-4. Included for each individual program is a brief description of the program, potential savings impacts, expenditures, and benefit/cost (“B/C”) ratios resulting from the integration analysis.

7.1.3.1 Commercial and Industrial Energy Efficiency (CIEE) Program

Program Description

The Commercial and Industrial Energy Efficiency (CIEE) Program is designed to provide a full range of technology options including energy efficient air conditioning, lighting, and motors. This program offers cash rebates to commercial and industrial customers who purchase high-efficiency electric equipment and provides incentives to dealers who sell high-efficiency electric equipment. The program also offers low-interest loans focusing specifically on the small business sector.

The target market for this program includes the commercial and industrial equipment change-out market, that is, customers who are replacing units in existing buildings, and customers who are purchasing the equipment for the first time. The target market also includes dealers of high efficiency equipment. The following table summarizes the energy efficiency equipment and measures included in this program.

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Table 7.1-1 Energy Efficiency Measures Included in the CIEE Program

Program Element End-Use Qualifying Measures

Package, split systems, and chillers (qualifying efficiency varies depending on A: High-Efficiency Cooling Cooling cooling capacity); Room AC, Energy Star or better

Package of T8, T5, CFL, delamping and reflectors, LED exit signs, induction, metal B: High-Efficiency Lighting Lighting halide, high pressure sodium, and occupancy sensors.

C: Premium-Efficiency Motors Motors Motors, NEMA Premium™ efficiency or better

Window film with shading coefficient of 0.40 D: Window Tinting Cooling or less

Projected Savings and Impacts and Expenditures The projected savings impacts and expenditures resulting from the CIEE Program are summarized in Table 7.1-2. Cumulative savings and annual expenditures in nominal dollars are indicated at the gross system level (i.e., includes free riders at the gross system level) projected for the 2009-2029 timeframe.

Table 7.1-2 Projected Savings Impacts and Expenditures - CIEE Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 3.4 6.9 10.3 13.8 17.2 32.2 39.7 41.3 Energy Savings (MWh) 23,379 46,757 70,136 93,514 116,893 221,406 273,891 286,141 Annual Expenditures ($000) Implementation $1,198 $1,235 $1,282 $1,330 $1,381 $1,664 $2,005 $2,416 Incentives $2,228 $2,277 $2,327 $2,378 $2,431 $2,710 $3,022 $3,369 Total $3,426 $3,512 $3,609 $3,709 $3,811 $4,374 $5,026 $5,785 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-3. As shown in the table, the CIEE Program was determined to be cost-effective from the Total Resource Cost (TRC), Utility Cost (UC), and Participant Cost (Participant) perspectives. This

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means that, from the perspective of the utility and participants together, in addition to the utility and participants separately, this program under the proposed structure would yield a net positive benefit to these stakeholders. However, the program did not pass the Rate Impact Measure (RIM) test. This means that, from the perspective of all ratepayers (including non-participants), this program will result in an increase in rates above current levels. These results are consistent with HECO’s past experience with the CIEE program.

Table 7.1-3 Cost Effectiveness Test Results - CIEE Program

Benefits Costs Net Benefits B/C Ratio Participant Test $336,881,458 $53,974,199 $282,907,260 6.24 Ratepayer Impact Measure Test $153,880,521 $381,074,916 ($227,194,394) 0.40 Utility Cost Test $153,880,521 $44,193,457 $109,687,064 3.48 Total Resource Cost Test $153,880,521 $88,607,142 $65,273,379 1.74

7.1.3.2 Commercial and Industrial New Construction (CINC) Program

The Commercial and Industrial New Construction (CINC) Program provides commercial and industrial customers with customized incentives and design assistance for the construction of energy-efficient buildings and facilities. This program will include new buildings and facilities as well as buildings and facilities undergoing major renovations.

This program provides for the unique differences between customers in existing buildings and customers who are building new facilities. The CINC program excludes offering incentives for equipment that is typically installed in new construction and overpaying for a resource. The different incentive levels are also necessary to encourage the builder to implement all possible energy measures at the time of construction. Since the capital investment required to implement all possible energy conservation measures at the time of construction may be quite large, higher incentive levels are necessary to encourage that investment. In addition to prescriptive rebates, the program will provide design and technical assistance for the design and engineering community. The program will provide a customer with the services of a consulting engineer to evaluate the cost-effectiveness of energy-saving measures under consideration by the customer, and to recommend measures that may have been overlooked. The program also provides technical workshops and other technical developmental activities for the design and engineering community to familiarize and educate them on energy efficient design methods and new technologies. The measures targeted by this program are similar to that of the CIEE program, and the qualification levels are summarized in the following table.

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Table 7.1-4 Energy Efficiency Measures Included in the CINC Program

Program Element End-Use Qualifying Measures

Package, split systems, and chillers (qualifying A: High-Efficiency Cooling Cooling efficiency varies depending on cooling capacity); Room AC, Energy Star or better

Package of T8, T5, CFL, induction, metal halide, B: High-Efficiency Lighting Lighting high pressure sodium, and occupancy sensors.

C: Premium-Efficiency Motors Motors, NEMA Premium™ efficiency or better Motors

D: Window Tinting Cooling Window film with shading coefficient of 0.40 or less

E. Customized Measures Various Refer to Table 7.1-7

Projected Savings and Impacts and Expenditures The projected savings impacts and expenditures resulting from the CINC Program are summarized in Table 7.1-5. Cumulative savings and annual expenditures in nominal dollars are indicated at the net system level (i.e., excluding free riders at the gross generation level) projected for the 2009-2029 timeframe.

Table 7.1-5 Projected Savings Impacts and Expenditures - CINC Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 1.4 2.9 4.3 5.7 7.2 13.6 17.8 18.4 Energy Savings (MWh) 9,798 19,596 29,394 39,191 48,989 93,126 121,064 124,553 Annual Expenditures ($000) Implementation$ 768 $ 785 $ 814 $ 845 $ 878 $ 1,057 $ 1,274 $ 1,535 Incentives$ 939 $ 960 $ 981 $ 1,003 $ 1,025 $ 1,142 $ 1,274 $ 1,420 Total$ 1,707 $ 1,745 $ 1,795 $ 1,848 $ 1,903 $ 2,199 $ 2,548 $ 2,955 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-6. The CINC program was determined to be cost-effective from the TRC, UC, and Participant Cost perspectives. However, the program did not pass the RIM test. These results are consistent with HECO’s past experience with the CINC Program.

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Table 7.1-6 Cost Effectiveness Test Results - CINC Program

Benefits Costs Net Benefits B/C Ratio Participant Test $132,295,751 $23,264,175 $109,031,576 5.69 Ratepayer Impact Measure Test $60,219,199 $154,493,653 ($94,274,455) 0.39 Utility Cost Test $60,219,199 $22,197,903 $38,021,296 2.71 Total Resource Cost Test $60,219,199 $40,769,708 $19,449,491 1.48

7.1.3.3 Commercial and Industrial Customized Rebate (CICR) Program

The purpose of the Commercial and Industrial Customized Rebates (CICR) Program is to provide customized energy-efficiency services to HECO’s commercial and industrial customers to increase their competitiveness and ensure their sustainability. HECO assists these customers in identifying energy efficiency opportunities in conventional end uses and their specific processes. The flexibility and design of this program provide customers with incentives for energy efficient measures that are not covered by prescriptive rebates. Instead, incentives are based on the energy and demand savings derived from the installed measures.

HECO works with the large and small customers in estimating the energy savings for the proposed installation of the energy saving equipment. The program provides the targeted customers with a full range of services and products throughout their facilities that are aimed at achieving total efficiency improvements rather than individual measure efficiency. The program also addresses building commissioning and equipment maintenance. The qualifying measures for this program are summarized in Table 7.1-7.

Table 7.1-7 Energy Efficiency Measures Included in the CICR Program

Program Element End-Use Qualifying Measures

Air-Cooled:

Reciprocating chiller = 1.23 kW/ton or better

Screw chiller = 1.30 kW/ton or better A: High-Efficiency Cooling Cooling Water-Cooled: (chillers) Reciprocating chiller = 0.90 kW/ton or better

Screw chiller = 0.75 kW/ton or better

Centrifugal chiller = 0.60 kW/ton or better

B: High-Efficiency Refrigeration High-efficiency compressors

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Typical system controls HVAC system w/ C: Energy Management Various 10% energy reduction and 20% demand Control Systems reduction

D: Industrial Applications Various To be determined

E: Cooling equipment Cooling Equipment that has not been serviced

Building systems that has not been F: Building Commissioning Various commissioned

Projected Savings and Impacts and Expenditures The projected savings impacts and expenditures resulting from the CICR program are summarized in Table 7.1-8. Cumulative savings and annual expenditures in nominal dollars are indicated at the gross system level (i.e., includes free riders at the gross system level) projected for the 2009-2029 timeframe.

Table 7.1-8 Projected Savings Impacts and Expenditures - CICR Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 1.6 3.3 4.9 6.6 8.2 16.5 24.7 24.7 Energy Savings (MWh) 12,626 25,252 37,878 50,504 63,130 126,259 189,389 189,389 Annual Expenditures ($000) Implementation$ 1,048 $ 1,072 $ 1,113 $ 1,155 $ 1,199 $ 1,445 $ 1,741 $ 2,098 Incentives$ 777 $ 794 $ 812 $ 829 $ 848 $ 945 $ 1,054 $ 1,175 Total$ 1,825 $ 1,866 $ 1,925 $ 1,984 $ 2,047 $ 2,390 $ 2,795 $ 3,273 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-9. The CICR program was determined to be cost-effective from the TRC, UC, and Participant Cost perspectives. However, the program did not pass the RIM tests. These results are consistent with HECO’s past experience with the CICR Program.

Table 7.1-9 Cost Effectiveness Test Results - CINC Program

Benefits Costs Net Benefits B/C Ratio Participant Test $241,870,413 $64,121,103 $177,749,311 3.77 Ratepayer Impact Measure Test $106,066,793 $265,938,647 ($159,871,854) 0.40 Utility Cost Test $106,066,793 $24,068,234 $81,998,559 4.41 Total Resource Cost Test $106,066,793 $85,873,654 $20,193,139 1.24

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7.1.3.4 Energy Solutions for the Home (ESH) Program

The Energy Solutions for the Home (ESH) program provides a comprehensive range of energy efficiency options that address several major end-uses. This program offers cash rebates to residential customers who purchase high efficiency electric equipment and/or incentives to dealers who sell high-efficiency electric equipment, and also provides customers with educational materials that discuss ways that they can reduce their energy consumption. The program works in parallel with the Energy Star program to leverage the benefits of this national initiative. In addition, through a co-branding arrangement involving the national Energy Star rating system, further information can be provided about the energy savings associated with various appliances in the household.

A program element that has been implemented on the U.S. mainland includes a front- end home energy audit that identifies a variety of energy efficiency measures for possible implementation and helps the customers find ways to install some or all of the identified measures. Many times audits help to enhance the participation process for programs such as Energy Solutions for the Home. Given there is limited experience with this approach in Hawaii, this program would include a pilot effort where a variety of home energy audit methods would be tested (ranging from internet-based self audits to onsite audits performed by energy audit experts). The audit component would be offered to a subset of participants of the program as an option prior to their implementation of the various measures that are available through this program.

This program is comprised of a number of energy efficiency measures that are grouped into the following categories: space cooling, cooling equipment servicing, lighting, and appliances. The qualified equipment for this program by category is shown in Table 7.1-10.

Table 7.1-10 Energy Efficiency Measures Included in the ESH Program

Program Element End-Use Qualifying Measures

A: High-Efficiency Room Air Cooling Room AC, Energy Star or better Conditioners

B: High-Efficiency Central Air Cooling Central AC, SEER 14 or greater Conditioners

C: Ceiling Fans Cooling Ceiling fans, Energy Star or better

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D: Compact fluorescent lamps30 Lighting CFLs, Energy Star or better

Refrigerators, clothes washers, and E: Energy Star Appliances Appliances dishwashers, Energy Star or better

HVAC equipment that has not been F: Cooling Equipment Servicing Cooling serviced

Projected Savings and Impacts and Expenditures The projected savings impacts and expenditures resulting from the Energy Solutions for the Home Program are summarized in Table 7.1-11. Cumulative savings and annual expenditures in nominal dollars are indicated at the gross system level (i.e., includes free riders at the gross system level) projected for the 2009-2029 timeframe.

Table 7.1-11 Projected Savings Impacts and Expenditures - ESH Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 2.5 4.5 6.0 7.5 9.0 16.0 19.0 19.0 Energy Savings (MWh) 8,058 13,908 18,886 23,864 28,842 51,524 59,259 59,259 Annual Expenditures ($000) Implementation$ 778 $ 804 $ 844 $ 876 $ 909 $ 1,096 $ 1,320 $ 1,591 Incentives$ 894 $ 834 $ 852 $ 871 $ 890 $ 993 $ 1,107 $ 1,234 Total$ 1,672 $ 1,638 $ 1,696 $ 1,747 $ 1,799 $ 2,089 $ 2,427 $ 2,825 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-12. The ESH program was determined to be cost-effective from the TRC, UC, and Participant Cost perspectives. However, the program did not pass the RIM test.

30 On July 7, 2008, the Commission approved 2008 Budgets for HECO’s DSM programs. In its approval, the PUC indicated that it would approve no further incentive for CFL’s; therefore HECO intends to limit its CFL rebate program in 2009 to specialty or ornamental CFLs only.

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Table 7.1-12 Cost Effectiveness Test Results - ESH Program

Benefits Costs Net Benefits B/C Ratio Participant Test $105,455,717 $26,024,354 $79,431,363 4.05 Ratepayer Impact Measure Test $54,475,769 $126,564,704 ($72,088,936) 0.43 Utility Cost Test $54,475,769 $21,108,987 $33,366,781 2.58 Total Resource Cost Test $54,475,769 $45,608,002 $8,867,767 1.19

7.1.3.5 Residential Efficient Water Heating (REWH) Program

The Residential Efficient Water Heating (REWH) Program promotes solar water heating and high-efficiency electric water heaters to customers in existing residential dwellings. Cash rebates are offered to residential customers who purchase qualified equipment and/or incentives to dealers who sell qualified equipment. The program also provides customers with educational materials that discuss ways that they can reduce their water heating energy consumption. Target audiences are the existing single-family, multi-family and rental markets.

The qualified equipment for this program by category is shown in Table 7.1-13.

Table 7.1-13 Energy Efficiency Measures Included in the REWH Program

Program Element End-Use Measure Qualifications

Solar water heater, per Water A: Solar Water Heating HECO’s existing program Heating specifications

B: High-Efficiency Electric Water Water Water heater, EF=0.93 or Heaters Heating better

Projected Savings and Impacts and Expenditures The projected savings impacts and expenditures resulting from the REWH program are summarized in Table 7.1-14. Cumulative savings and annual expenditures in nominal dollars are indicated at the gross system level (i.e., includes free riders at the gross system level) projected for the 2009-2029 timeframe.

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Table 7.1-14 Projected Savings Impacts and Expenditures - REWH Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 0.9 1.7 2.6 3.5 4.3 8.6 12.6 12.6 Energy Savings (MWh) 3,767 7,533 11,300 15,067 18,834 37,415 54,988 54,988 Annual Expenditures ($000) Implementation$ 1,368 $ 1,421 $ 1,475 $ 1,531 $ 1,589 $ 1,915 $ 2,308 $ 2,781 Incentives$ 1,535 $ 1,569 $ 1,604 $ 1,639 $ 1,675 $ 1,868 $ 2,082 $ 2,322 Total$ 2,903 $ 2,990 $ 3,079 $ 3,170 $ 3,264 $ 3,783 $ 4,390 $ 5,103 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-15. The REWH program was determined to be cost-effective only from the participant perspective. The program does not pass the TRC, UC, and RIM tests, which is consistent with MECO’s past experience with the REWH Program. In general, HECO believes that its DSM programs should all have positive net benefits, according to the TRC test perspective, to be considered “cost-effective.” However, while the TRC test can work well in testing a proposed program, it can be problematic when testing an on-going program using recorded costs. In testing a proposed program, data can be obtained from suppliers and vendors regarding the installed costs of the measure. Assumptions can also be made regarding whether the measure is installed as a retrofit, that is replacing a working system, or as a replacement measure, which is installed when the existing equipment has failed. In the case of a retrofit installation, the full cost of the measure is considered the total cost. In a replacement installation, the incremental cost (i.e., the added cost of purchasing a more efficient motor) is considered the cost of the measure.

Another limitation to the TRC test occurs with the residential programs. While most business decisions are based on expected financial returns, residential customers often make purchases for other reasons. A residential customer may purchase energy efficient equipment, such as a solar water heating system, based on his/her personal environmental concerns and/or commitments. Other customers may purchase the same product because it is different or new and they want to be in the forefront of new technologies. Residential customers with only two people in the family may also purchase a solar water heating system in anticipation of a growing family in the future, however, the increased future savings cannot be factored into the current cost effectiveness of the residential programs.

The overall determination of cost effectiveness in the IRP process should take into account all of the goals and objectives of IRP — including the availability of non-quantifiable benefits, the impact of the programs on the utility’s financial integrity, supporting Hawaii’s state energy policies and objectives and the rate impact of the programs. The determination of cost effectiveness in IRP should also consider both quantitative benefits and costs which are reflected in the benefit-cost ratios and qualitative benefits and costs, which are not reflected in the benefit-cost ratios. From

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this perspective, solar water heaters utilize an environmentally clean, renewable energy resource. In addition, the solar water heating component of the residential DSM programs is a major contributor to meeting the state’s renewable energy objective.

Table 7.1-15 Cost Effectiveness Test Results - REWH Program

Benefits Costs Net Benefits B/C Ratio Participant Test $72,853,430 $37,074,458 $35,778,972 1.97 Ratepayer Impact Measure Test $33,465,825 $110,983,975 ($77,518,149) 0.30 Utility Cost Test $33,465,825 $38,130,545 ($4,664,720) 0.88 Total Resource Cost Test $33,465,825 $70,059,671 ($36,593,846) 0.48

7.1.3.6 Residential New Construction (RNC) Program

The Residential New Construction (RNC) program promotes solar water heating, high efficiency electric water heaters, and packages of other energy efficiency measures to customers in new residential dwellings. The packages of energy-efficiency measures are developed in partnership with the Building Industries Association’s (BIA) Hawaii BuiltGreen™ initiative. The packages of energy efficiency measures include wall and ceiling insulation, high performance windows, high efficiency cooling equipment and EnergyStar® appliances. Cash rebates and financing options are offered to residential customers who purchase qualified equipment and/or incentives to dealers who sell qualified equipment. The program also provides customers with educational materials that discuss ways that they can reduce their water heating energy consumption. The target audience is the new construction, single-family home market. The components of the program are shown in Table 7.1-16.

Table 7.1-16 Energy Efficiency Measures Included in the RNC Program

Program Element End-Use Qualifying Measures

Water Solar water heater, per HECO’s A: Solar Water Heating Heating existing program specifications

B: High-Efficiency Electric Water Water Water heater, EF=0.93 or better Heaters Heating

C: Bronze Package Various See Table 7.1-17 below

D: Silver Package Various See Table 7.1-18 below

E: Gold Package Various See Table 7.1-19 below

F: Gold-Plus Package Various See Table 7.1-20 below

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The four tables below present details of the energy performance criteria for each of the energy efficiency measure packages. A new construction single-family home must meet the qualification criteria for each of the package components in order to qualify under that particular package. Each step-up in level (e.g., Bronze to Silver and Silver to Gold) require meeting the qualifications of the preceding level however, the Gold-Plus package replaces central air-conditioning from the Gold package with natural ventilation.

Table 7.1-17 Bronze Package

Qualifying Measure End-Use

High-Efficiency Central Air Conditioners, SEER 14 or better Cooling

Ceiling Fans, Energy Star or better Cooling

Compact Fluorescent Lamps. Energy Star or better Lighting

Table 7.1-18 Silver Package

Qualifying Measure End-Use

High-Efficiency Central Air Conditioners, SEER 14 or Cooling greater

Ceiling Fans, Energy Star or better Cooling

Compact Fluorescent Lamps, Energy Star or better Lighting

Clothes Washers, Energy Star or better Appliances

Refrigerator, Energy Star or better Appliances

Wall Insulation, R-15 or better Cooling

Ceiling Insulation, R-25or better Cooling

Skylights, Solar heat gain coefficient <0.5 Lighting

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Table 7.1-19 Gold Package

Qualifying Measure End-Use

High-Efficiency Central Air Conditioners, SEER 14 or greater Cooling

Ceiling Fans, Energy Star or better Cooling

Compact Fluorescent Lamps, Energy Star or better Lighting

Energy Star Clothes Washers, Energy Star or better Appliances

Energy Star Refrigerator, Energy Star or better Appliances

Wall Insulation, R-15 or better Cooling

Ceiling Insulation, R-25 or better Cooling

Skylights, Solar Heat Gain Coefficient <0.5 Lighting

Energy Star Windows, Low-e, double-pane, Energy Star or better Cooling

Table 7.1-20 Gold Plus Package

Qualifying Measure End-Use

Natural Ventilation, No mechanical cooling system Cooling

Ceiling Fans, Energy Star or better Cooling

Compact Fluorescent Lamps, Energy Star or better Lighting

Energy Star Clothes Washers, Energy Star or better Appliances

Energy Star Refrigerator, Energy Star or better Appliances

Wall Insulation, R-15 or better Cooling

Ceiling Insulation, R-25 or better Cooling

Skylights, Solar Heat Gain Coefficient <0.5 Lighting

Energy Star Windows, Low-e, double-pane, Energy Star or better Cooling

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Projected Savings and Impacts and Expenditures The projected savings impacts and expenditures resulting from the RNC are summarized in Table 7.1-21. Cumulative savings and annual expenditures in nominal dollars are indicated at the gross system level (i.e., includes free riders at the gross system level) projected for the 2009-2029 timeframe.

Table 7.1-21 Projected Savings Impacts and Expenditures - RNC Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 1.1 2.2 3.4 4.5 5.6 11.0 16.3 16.3 Energy Savings (MWh) 2,823 5,645 8,468 11,291 14,113 27,051 39,701 39,701 Annual Expenditures ($000) Implementation$ 769 $ 797 $ 827 $ 858 $ 891 $ 1,074 $ 1,294 $ 1,559 Incentives$ 1,019 $ 1,074 $ 1,130 $ 1,188 $ 1,249 $ 1,583 $ 1,977 $ 2,205 Total$ 1,788 $ 1,871 $ 1,957 $ 2,046 $ 2,140 $ 2,657 $ 3,271 $ 3,764 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-22. The RNC program was determined to be cost-effective from the UC, and Participant Cost perspectives. However, the program did not pass the TRC and RIM tests.

Table 7.1-22 Cost Effectiveness Test Results - RNC Program

Benefits Costs Net Benefits B/C Ratio Participant Test $61,039,355 $18,291,896 $42,747,460 3.34 Ratepayer Impact Measure Test $33,866,138 $87,177,858 ($53,311,720) 0.39 Utility Cost Test $33,866,138 $26,138,503 $7,727,635 1.30 Total Resource Cost Test $33,866,138 $41,981,293 ($8,115,155) 0.81

7.1.3.7 Residential Low Income Program

The Residential Low Income (RLI) program enables qualified low-income customers to receive compact fluorescent lamps and low cost water heating measures such as faucet aerators, low-flow showerheads, and temperature set-back at no cost. The program also provides low income customers with educational materials that discuss ways that they can reduce their energy consumption.

This program augments the energy efficiency improvements made through the state’s existing programs by making financial resources available to local community action program (CAP) agencies. The objective of the educational component of this program is to increase energy awareness among low-income customers, thus improving efficiency and potentially reducing the number of federal-funded Low Income Home Energy Assistance Program (LIHEAP) participants.

The measures offered through the LIHEAP are listed in Table 7.1-23.

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Table 7.1-23 Energy Efficiency Measures Included in the RLI Program

Program End-Use Qualifying Measures

Water Faucet aerators, low-flow showerheads, A: Water Heating Measures Heating thermostat setback

B: CFL Bulbs (2 free per household) Lighting CFLs, Energy Star or better

Projected Savings and Impacts and Expenditures

The projected savings impacts and expenditures resulting from the RLI are summarized in Table 7.1-24. Cumulative savings and annual expenditures in nominal dollars are indicated at the gross system level (i.e., includes free riders at the gross system level) projected for the 2009-2029 timeframe.

Table 7.1-24 Projected Savings Impacts and Expenditures - RLI Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 0.6 1.2 1.8 2.4 3.0 5.1 7.2 7.2 Energy Savings (MWh) 2,633 5,267 7,900 10,533 13,166 21,918 30,670 30,670 Annual Expenditures ($000) Implementation$ 378 $ 392 $ 407 $ 423 $ 439 $ 529 $ 637 $ 768 Incentives$ 578 $ 590 $ 603 $ 617 $ 630 $ 703 $ 783 $ 873 Total$ 956 $ 982 $ 1,010 $ 1,040 $ 1,069 $ 1,232 $ 1,420 $ 1,641 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-25. The RLI program was determined to be cost-effective from the TRC, UC, and Participant Cost perspectives. However, the program did not pass the RIM test.

Table 7.1-25 Cost Effectiveness Test Results - RLI Program

Benefits Costs Net Benefits B/C Ratio Participant Test $58,613,294 $7,142,526 $51,470,768 8.21 Ratepayer Impact Measure Test $27,299,564 $71,040,707 ($43,741,143) 0.38 Utility Cost Test $27,299,564 $12,427,413 $14,872,151 2.20 Total Resource Cost Test $27,299,564 $12,427,413 $14,872,151 2.20

7.1.3.8 Residential Direct Load Control Program

Participants in the Residential Direct Load Control (RDLC) Program receive ongoing incentives in return for allowing HECO to control their air conditioning (central air conditioners) and/or their electric water heater equipment through the use of load control devices attached to the customers’ equipment.

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The program offers the following measures:

Air conditioner cycling (every 15 minutes);

Water heater cycling (shut off during the entire control period).

Projected Savings and Impacts and Expenditures The projected savings impacts and expenditures resulting from the RDLC are summarized in Table 7.1-26. Cumulative savings and annual expenditures in nominal dollars are indicated at the gross system level (i.e., includes free riders at the gross system level) projected for the 2009-2029 timeframe.

Table 7.1-26 Projected Savings Impacts and Expenditures - RDLC Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 18.7 18.7 18.7 18.7 18.7 18.7 18.7 18.7 Energy Savings (MWh)00000000 Annual Expenditures ($000) Implementation$ 795 $ 784 $ 814 $ 845 $ 877 $ 1,057 $ 1,274 $ 1,535 Incentives$ 1,018 $ 1,038 $ 1,055 $ 1,070 $ 1,085 $ 1,160 $ 1,236 $ 1,312 Total$ 1,813 $ 1,822 $ 1,869 $ 1,915 $ 1,962 $ 2,217 $ 2,510 $ 2,847 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-27. The RDLC program was determined to be cost-effective from the TRC perspective only however, the program was close to passing the UC and RIM tests.

Table 7.1-27 Cost Effectiveness Test Results - RDLC Program

Benefits Costs Net Benefits B/C Ratio Participant Test $0 $0 $0 NA Ratepayer Impact Measure Test $21,435,912 $22,513,504 ($1,077,592) 0.95 Utility Cost Test $21,435,912 $22,513,504 ($1,077,592) 0.95 Total Resource Cost Test $21,435,912 $10,606,643 $10,829,269 2.02

7.1.3.9 Commercial and Industrial Direct Load Control Program

Under the interruptible tariff component of the Commercial and Industrial Direct Load Control Program (CIDLC) program, HECO provides commercial and industrial customers a contract-based interruptible tariff that allows customers to receive a year-round rate discount for making their loads available for interruption during the year. The amount of hours available for interruption is predetermined. Non-performance by a customer during a curtailment alert will bring about significant penalties for the customer.

When the electricity grid reaches peak system conditions, HECO initiates the load control events, which notifies participants within one hour that they must initiate their

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equipment shutdown procedures, according to the terms of their agreement. The customer’s load is curtailed either in response to a request through a radio frequency signal sent to auxiliary load switches or automatically via an under-frequency relay (UFR). Customers may initiate backup generators, in accordance with local regulations governing the use of the equipment.

The existing program was modified in order to increase customer participation levels. The changes to the program included reducing the minimum load requirements, increasing incentives (via the tariff design), providing an equipment installation allowance, and offering options on automatic interruption and other program requirements.

To further increase enrollment, the program was expanded to include two new options: 1) Voluntary Load Control (VLC), which offers customers the option of reducing load during a curtailment alert in lieu of mandatory participation; and 2) Small Business Direct Load Control, which offers small businesses the opportunity to participate in the program for the control of equipment specific loads such as central air conditioning and electric hot water heater.

Projected Savings and Impacts and Expenditures The projected savings impacts and expenditures resulting from CIDLC are summarized in Table 7.1-28. Cumulative savings and annual expenditures in nominal dollars are indicated at the gross system level (i.e., includes free riders at the gross system level) projected for the 2009-2029 timeframe.

Table 7.1-28 Projected Savings Impacts and Expenditures - CIDLC Program

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 24.8 31.8 34.1 36.1 37.9 41.3 41.8 41.8 Energy Savings (MWh)00000000 Annual Expenditures ($000) Implementation$ 1,267 $ 224 $ 233 $ 241 $ 251 $ 302 $ 364 $ 439 Incentives$ 2,869 $ 3,567 $ 3,909 $ 4,147 $ 4,345 $ 4,823 $ 4,877 $ 4,882 Total$ 4,136 $ 3,791 $ 4,142 $ 4,388 $ 4,596 $ 5,125 $ 5,241 $ 5,321 Cost Effectiveness Results

The cost effectiveness analysis results are summarized in Table 7.1-29. The CIDLC Program was determined to be cost-effective from the TRC perspective. The program did not pass the UC and RIM tests.

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Table 7.1-29 Cost Effectiveness Test Results - CIDLC Program

Benefits Costs Net Benefits B/C Ratio Participant Test $23,074,820 $0 $23,074,820 NA Ratepayer Impact Measure Test $44,439,030 $73,021,572 ($28,582,541) 0.61 Utility Cost Test $44,439,030 $49,946,751 ($5,507,721) 0.89 Total Resource Cost Test $44,439,030 $4,070,609 $40,368,421 10.92

7.1.3.10 Pilot Programs

SolarSaver Pilot Program

In 2006, Act 240 (SB 2957) mandated that the utilities shall establish a “pay-as-you- save” type program similar to the nationally recognized Pay As You Save® trademarked financing program to allow residential customers to install solar water heaters on their existing homes with no money down. To comply with the requirements of Act 240, HECO filed a proposed tariff to create the SolarSaver Pilot (“SSP”) program designed to satisfy the requirements of Docket No. 2006-0425. The SSP program was approved by the Commission as a three-year program in Decision and Order No. 23531, issued on June 29, 2007.

Through the SSP program, customers may install a solar water heating system on an existing home or rental unit with no up-front cost. The customer will pay for the system in small monthly installments called a SolarSaver fee to be collected by the utilities along with the customer’s monthly electric bill. As required by the pay-as-you-save model, the SolarSaver fee is designed to not exceed the estimated utility savings of the solar water heating system, and should not be collected for longer than 80% the system’s life, which is estimated at 15 years.

The SSP program complements the REWH customer incentive program for the installation of a solar water heating system. Therefore, the solar water heaters enrolled in the SolarSaver pilot program are also eligible for the REWH program’s $1,000 incentive.

Residential Customer Energy Awareness Pilot Program

On November 12, 2004, HECO filed its 2005 test year rate case, Docket No. 04-0113, which included the addition of three new programs - the RLI program, the ESH program and the Residential Customer Energy Awareness (“RCEA”) pilot program, which is a customer awareness program designed to bring about changes in residential customers’ energy usage patterns. An application requesting approval of the RCEA program was previously filed on May 15, 2003, in Docket No. 03-0142.

On February 13, 2007, the Commission approved the RCEA program in Decision and Order No. 23258 issued in Docket No. 05-0069. The primary objective of the RCEA program is to determine if an aggressive customer communications program can change

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levels of residential customer awareness of energy options, encourage customers to adopt efficient appliances and behavior and result in significant energy savings and peak load reduction. The objective will be accomplished by three tasks: • The first task is a survey to determine the pre-program level of energy awareness by residential customers; • The second task is to implement a communications program that provide residential customers with information on how they can reduce their energy bills and at the same time help make Hawaii energy efficient; • The third task is a final survey of residential customers to test their level of awareness after being exposed to the communications program (second task).

The RCEA program was initially approved as a two year pilot program beginning in 2007 and ending in 2008. However, on May 12, 2008, the Commission convened a status conference on Docket No. 2007-0323 to discuss among other things the continuation of the DSM programs during the transition period to the third party administrator and the disposition of the DSM pilot programs. During this status conference, HECO pointed out that the RCEA program had been very useful and helpful in advancing the DSM programs as evidenced by the unprecedented success of the DSM program in 2007 and early 2008. Following the May 12, 2008 status conference, the Commission issued an Order to Initiate the Collection of Funds for the Third Party Administrator of Energy Efficiency Programs on July 2, 2008. In this order the Commission stated that they will review and analyze the RCEA program and decide whether to extend it. HECO will be submitting an evaluation report of the RCEA pilot program by September 30, 2008, to allow the Commission time to review and approve the continuation of the program beyond 2008, if so desired, in order to avoid any loss of progress in the RCEA Program.

Dynamic Peak Pricing.

On April 24, 2008, HECO filed its application for a Dynamic Pricing Pilot (“DPP”) program in Docket No. 2008-0074. HECO is proposing to run the DPP program for approximately one year. A demand response program attempts to change customer demand of electricity through price signals. The objective of this pilot is to test the effect of a demand response program on a sample of residential customers for system reliability purposes. Approval of the DPP program would allow HECO to achieve the following objectives: • Determine whether dynamic pricing is a viable approach to demand reduction for reliability enhancement; • Identify the cost and implementation issues in advance of a possible island-wide rollout of a residential demand response program; • Determine customer program adoption rates and satisfaction with the program;

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• Collect customer load profiles with and without central air-conditioners; and • Validate the ability of Advanced Metering Infrastructure (“AMI”) meters to collect and transmit accurate time-based energy consumption information to the HECO’s billing system.

Dynamic pricing is a subset of demand response and similar to HECO’s direct load control programs (RDLC and CIDLC). Incentives are paid to program participants for the curtailment of load when there is insufficient generation to meet a projected peak demand period. Unlike the direct load control programs, dynamic pricing allows prices to change from normal tariff rates as system conditions change.

The development and implementation of a pilot DPP program was discussed with HECO’s AG in two technical sessions31. The AG responded favorably to the DPP program concept. Thus, a dynamic pricing pilot is being included in the DSM program portfolio to be integrated into HECO’s IRP-4 planning process.

Home Energy Audit

A program element that has been implemented by U.S. mainland utilities offering programs much like the Energy Solutions for the Home includes a front-end home energy audit. An experienced energy auditor typically will go to the home and identify a variety of energy efficiency measures for possible implementation. The auditor would also help the customers find ways to install some or all of the identified measures, and make recommendations for next steps including participation in one or more of HECO’s energy efficiency programs. Many times audits help to enhance the participation process for programs such as Energy Solutions for the Home.

Given there is limited experience with this approach in Hawaii, and costs to implement such a program are uncertain, HECO will embark on a pilot residential home energy audit effort that would be offered to HECO customers and would be designed to encourage customers to adopt energy efficient behavior and install measures such as those offered by the Energy Solutions for the Home program.

Since the scope of the audit has not been determined, the anticipated cost of this pilot was not detailed. Information on the pilot program will be provided at the next scheduled IRP-related reporting date.

31 HECO discussed the DPP concept with the AG in an IRP-4 DSM technical session on May 25, 2007 and in more detail on August 3, 2007.

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7.1.4 Summary

HECO used a comprehensive analytical and collaborative process involving extensive advice and input from the HECO Advisory Group (“AG”) and trade allies, review of best practices from other utilities and lessons learned from its own experience gained over the past 12 years of implementing a variety of DSM programs. The resulting portfolio of DSM programs was designed to aggressively acquire energy conservation resources in a cost effective manner as HECO anticipates future resource needs. That is, there are net benefits of the DSM programs to the ratepayers when compared to the revenue requirements necessary if the DSM programs were not pursued, regardless of the structure of administrative structure of DSM. The impact of transitioning the administration of all energy efficiency DSM programs to a non-utility, third-party administrator is unknown at this time. However, the maximum achievable potential and resulting cost effective DSM resource portfolio are independent of the administrative structure. HECO’s administrative costs were used as a proxy for the third-party administrator’s costs. As more information becomes available, HECO will update its resource plans. HECO will work with the third-party administrator to provide a smooth transition in which customers are continuously encouraged to pursue cost effective energy efficiency improvements.

HECO recommends the implementation of the nine DSM programs described in this chapter to capture untapped market potential. Below is a summary of the parameters from the proposed portfolio of programs that was passed to the integration analysis phase. This includes projected impacts on energy and peak demand savings, required expenditures, and preliminary cost effectiveness.

7.1.4.1 Projected Impacts and Expenditures

Table 7.1-30 summarizes the projected aggregate savings and the projected expenditures for the proposed portfolio of energy efficiency programs. Energy savings in the first year of the IRP-4 period are projected to be over 63,000 MWh, with peak demand reductions of 55 megawatts (including free riders, at the gross generation level). In year 15 of the program, the gross energy and peak demand are projected to be nearly 648,000 MWh and 198 MW lower than if the DSM Programs were not implemented.

Table 7.1-30 Aggregate Gross Level Savings and Expenditures

Year 5 Year 10 Year 15 Year 20 Year 2009 2010 2011 2012 2013 2018 2023 2028 Cumulative Impacts (Includes Free Riders and Gross System Level ) Peak Demand Reduction (MW) 55.0 73.2 86.1 98.8 111.1 163.0 197.8 200.0 Energy Savings (MWh) 63,084 123,958 183,962 243,964 303,967 485,573 647,898 660,148 Annual Expenditures ($000) Implementation$ 8,369 $ 7,514 $ 7,809 $ 8,104 $ 8,414 $ 10,139 $ 12,217 $ 14,722 Incentives$ 11,857 $ 12,703 $ 13,273 $ 13,742 $ 14,178 $ 15,927 $ 17,412 $ 18,792 Total$ 20,226 $ 20,217 $ 21,082 $ 21,847 $ 22,591 $ 26,066 $ 29,628 $ 33,514

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7.1.4.2 Cost Effectiveness

Table 7.1-31 and 7.1-32 present the benefit-cost test results from the participant, utility (UC), total resource cost (TRC), and rate impact measure (RIM) perspectives. As can be seen from the tables, the programs result in benefits of over $535 million over the lifetime of the programs at a total cost of $400 million. This yields a positive benefit-cost ratio of 1.34.

In general, HECO believes that its DSM programs should all have positive net benefits according to the TRC test perspective to be considered “cost-effective.” However, as mentioned earlier with regard to specific programs, the overall determination of cost effectiveness in the IRP process should take into account all of the goals and objectives of IRP (including the availability of non-quantifiable benefits, the impact of the programs on the utility’s financial integrity, supporting Hawaii’s state energy policies and objectives and the rate impact of the programs).

Table 7.1-31 Cost Effectiveness TRC Test Results

Dollars B/C Program Lifetime Lifetime Net Ratio Benefits Costs Benefits Total Resource Cost Test Results: Commercial & Industrial Energy Efficiency $153,880,521 $88,607,142 $65,273,379 1.74 Commercial & Industrial New Construction $60,219,199 $40,769,708 $19,449,491 1.48 Commercial & Industrial Custom Rebates $106,066,793 $85,873,654 $20,193,139 1.24 Energy Solutions for the Home $54,475,769 $45,608,002 $8,867,767 1.19 Residential Efficient Water Heating $33,465,825 $70,059,671 ($36,593,846) 0.48 Residential New Construction $33,866,138 $41,981,293 ($8,115,155) 0.81 Residential Low Income $27,299,564 $12,427,413 $14,872,151 2.20 Residential Direct Load Control $21,435,912 $10,606,643 $10,829,269 2.02 Commercial & Industrial Direct Load Control $44,439,030 $4,070,609 $40,368,421 10.92 TOTAL $535,148,751 $400,004,135 $135,144,616 1.34 TOTAL (without RDLC and CIDLC) $469,273,809 $385,326,883 $83,946,926 1.22

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Table 7.1-32 Other Benefit Cost Test Results for All Programs

B/C Ratio

Program Utility RIM Participant Cost Test

Commercial & Industrial Energy Efficiency 0.40 3.48 6.24

Commercial & Industrial New Construction 0.39 2.71 5.69

Commercial & Industrial Custom Rebates 0.40 4.41 3.77

Energy Solutions for the Home 0.43 2.58 4.05

Residential Efficient Water Heating 0.30 0.88 1.97

Residential New Construction 0.39 1.30 3.34

Residential Low Income 0.38 2.20 8.21

Residential Direct Load Control 0.95 0.95 NA

Commercial & Industrial Direct Load Control 0.61 0.89 NA

TOTAL 0.41 2.05 4.49

TOTAL (without RDLC and CIDLC) 0.39 2.49 4.39

7.2 Distributed Generation Resources

7.2.1 Overview

Distributed generation (“DG”) resources include a variety of electric power generation technologies, typically installed at the locations of energy usage or on the utility’s electric distribution system. Firm DG systems include reciprocating engines and combustion turbines, which can be fired on either fossil or renewable fuels such as diesel, synthetic natural gas, propane, biofuels, landfill gas, or digester gas. Intermittent renewable DG types that are commonly available are photovoltaic (“PV”) systems and wind turbines.

In terms of potential utility system benefits, DG can displace utility central station generation fuel and variable O&M costs. Firm DG in sufficient quantities, appropriate

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locations, and with suitable operating characteristics can help defer new central station generating capacity and new distribution facilities, especially DG which is dispatchable by the utility. Renewable DG that does not require fuel such as PV provides environmental benefit and potential energy cost stabilization benefits to customers and the utility.

With regard to potential utility system impacts, DG, like all generating resources, must be suitably interconnected and integrated within the utility’s electrical system to assure system safety and reliability. DG interconnection standards have been established to generally manage integration of DG installations with the electric grid. The degree of difficulty in interconnecting a DG resource is highly dependent on its size, technology type, and location, and on the characteristics of the electrical circuit into which the DG is being interconnected. From a macro-scale, integration of relatively large amounts of DG - when considered on an aggregate basis - on an isolated island grid may create additional operational challenges, for example, when significant amounts of DG are tripped off-line simultaneously in an underfrequency event. Ultimately, the benefits and costs of DG are highly site-specific.

For IRP-4, DG resources are categorized as follows: • Customer-owned Distributed Generation/Combined Heat and Power: Projects not dispatchable by the utility; • Utility Dispatchable Distributed Generation: Utility-owned and customer-owned DG, dispatchable by the utility; • Utility-sited Photovoltaics; and • Customer-sited Photovoltaics.

7.2.2 Hawaii Public Utilities Commission DG Proceeding

On January 27, 2006, the Commission issued Decision and Order No. 22248 (“D&O No. 22248”) in its Distributed Generation Investigative Docket No. 03-0371. In D&O No. 22248, the Commission indicated that its policy is to promote the development of a market structure that assures that DG is available at the lowest feasible cost, that DG that is economical and reliable has an opportunity to come to fruition, and that DG that is not cost effective does not enter the system. To help ensure that only cost- effective DG is installed by customers, the Commission determined that other customers should not be required to subsidize those who install DG. Thus, D&O No. 22248 requires that costs incurred by the electric utilities to accommodate DG, including costs of interconnection and of providing standby services, should be borne by the DG customer.

With regard to DG ownership, D&O No. 22248 affirmed the ability of the electric utilities to procure and operate DG for utility purposes at utility sites. As clarified by PUC Order No. 22375, dated April 6, 2006, “utility sites” includes property leased or otherwise

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obtained from customers for the utility to install DG for utility purposes. The Commission also indicated its desire to promote the development of a competitive market for customer-sited DG. Therefore, D&O No. 22248, as clarified, allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest reasonable cost alternative to meet that need, and (3) it can be shown that the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.

The PUC also found that: "The benefits of distributed generation to the grid may increase if the utility can dispatch the customer's units or coordinate their operation with the utility's own units. On the other hand, customers may wish to maintain control of the generation to assure sufficient power resources for themselves. The commission hereby requires the utility to use its best efforts to negotiate contracts that allow the utility to dispatch the customer's generation unit where dispatching the unit is economical and feasible, and coordinate their operation with the utility's own units."

D&O No. 22248 also required the Companies to establish reliability and safety requirements for DG, establish a non-discriminatory DG interconnection policy, develop a standardized interconnection agreement to streamline the DG application review process, establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services), and establish detailed affiliate requirements should the utility choose to sell DG through an affiliate. The Companies filed their proposed modifications to existing DG interconnection tariffs and their proposed unbundled standby rates for Commission approval in July and August 2006, respectively. By Order No. 23171, dated December 28, 2006, the Commission opened a new proceeding, Docket No. 2006-0497, to investigate the Companies’ proposed DG interconnection tariff modifications and standby rate tariffs.

In March 2008, the parties to the proceeding filed a settlement agreement with the PUC that a standby service tariff agreed to by the parties should be approved. The interconnection tariffs, with further modifications made in response to PUC information requests, were approved in April 2008. In May 2008, the Commission approved the settlement agreement on the standby service tariff.

7.2.3 Customer-Owned DG/Combined Heat and Power Resources

Firm DG systems equipped with thermal energy recovery systems, known as combined heat and power (“CHP”) systems, are highly energy efficient. HECO’s IRP-3 gave particular focus to CHP DG resources, given the potential for widespread deployment of CHP bolstered in large part by a utility CHP program.

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Since the filing of the HECO IRP-3 report in 2005, HECO has significantly reduced its forecast for CHP systems on Oahu. HECO’s updated short-term CHP forecast (dated July 27, 2006) used in its 2007 and 2008 Adequacy of Supply (“AOS”) reports projected that the peak reduction impacts of CHP installations would be lower than the impacts projected for the 2006 AOS report. 32 This comes as a result of (1) limitations set forth in the PUC’s decision and order in the DG docket as to the ability of HECO to provide customer-sited DG projects on a regulated utility basis, as described in Section 7.2.2, (2) new rules issued by the U.S. Environmental Protection Agency (“EPA”) which will require more stringent emission controls for stationary diesel engines in the near future, and (3) other uncertainties concerning customer-sited DG.

HECO’s action plan for CHP in the years 2006-2010, as described in Section 15.3 of the HECO IRP-3 Report, was to pursue PUC approval of a proposed utility CHP Program and Schedule CHP tariff in Docket No. 03-0366. On December 29, 2006, HECO withdrew its CHP tariff application and halted development work on a number of Oahu CHP projects, based on the determination that it would be difficult to implement CHP projects given the criteria of D&O No. 22248, as clarified. D&O No. 22248 does allow the utility to develop CHP projects on a limited basis, and in fact HECO’s subsidiary MECO is developing a CHP project on the island of Lana’i. However, there are no HECO CHP projects under consideration at this time.

With regard to the new EPA rules, on July 11, 2005, the EPA issued interim New Source Performance Standards (“NSPS”) requiring lower nitrogen oxides (“NOx”) emission levels for stationary diesel engines manufactured after April 1, 2006. On July 11, 2006 the EPA issued the final NSPS for stationary diesel engines, specifying the lower NOx emission requirements to take effect in January 2011. The NSPS also requires the use of lower sulfur diesel fuel, with the most stringent requirements taking effect in late 2010 for units built after April 1, 2006. Based on HECO’s understanding, the new NSPS could significantly increase the costs of future DG installations. This would especially impact the feasibility of future customer DG installations, including CHP.

DG development is also affected by uncertainties on economics, customer interest, and site-specific factors. On a macro-scale, the economic viability of CHP is highly sensitive to fuel and electricity prices. The energy efficiency benefits of a CHP system may not translate to overall cost savings for a customer if the CHP fuel cost (for diesel fuel oil, propane or synthetic natural gas) is significantly higher than the cost of fuel used to generate grid electricity. Furthermore, prospective CHP projects are subject to customer

32 For example, in the 2006 AOS report, the peak reduction impact of CHP in the year 2008 was forecasted to be 3.7 MW. In the 2007 AOS report, the peak reduction impact of CHP in the year 2008 is forecast to be 0.8 MW. The same CHP forecast is used in HECO’s 2008 AOS report.

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desire and support, which can be extremely variable. Also site-specific factors add uncertainty, as they may affect the feasibility of moving forward with a project even when the desire for CHP is strong.

Considering these factors, the July 27, 2006 Oahu CHP forecast assumed installation of up to 800 kW of new CHP in each of the years 2008-2011, after which the high costs of meeting the new EPA requirements was assumed to make CHP unattractive. As of the filing of the IRP-4 report in September 2008, HECO is aware of only one 800 kW CHP system under discussion on Oahu between a non-utility CHP developer and a customer, which could be placed in service as early as 2009. Given an approximate one-and-a- half to two-year lead time to contract for, design, permit, procure, install, and commission a CHP system, the IRP-4 assumes that no other new CHP units will be placed in service on Oahu before late 2010. Thus, only a little more than 1 MW of customer-owned CHP is assumed to be added during the planning period. HECO did not assume any utility-owned CHP in IRP-4.

7.2.4 Utility Dispatchable DG

Utility dispatchable DG includes utility-sited and customer-sited DG resources for which HECO has central dispatch control.

7.2.4.1 Utility-Sited Dispatchable DG

As described in the IRP-3 report and in HECO’s May 2007 Evaluation Report, HECO completed the installation of nine temporary 1.64 MW diesel-fired DG units in the fourth quarter of 2005, adding just under 15 MW of temporary dispatchable generating capacity at three HECO sites. Due to the continued need for additional reserve capacity mitigation measures, in 2006 HECO proceeded to install additional temporary DG units at utility sites. Six 1.64 MW DG units were installed in the fourth quarter of 2006, and three more 1.64 MW DG units were placed in service in May 2007, bringing the total temporary DG capacity to 29.5 MW.

At this time, HECO is not counting the 29.5 MW of temporary DG as part of its long term resource plan, due to the temporary nature of their installation. The units are anticipated to remain in service at least until sufficient amounts of long term capacity are installed. Besides providing reserve capacity, the temporary HECO DG units provide additional system operational flexibility and efficiency benefits. For these reasons, HECO will periodically evaluate the continued use of the temporary DG units, and the feasibility of upgrading the installations to extend their service capability.

7.2.4.2 Customer-Sited Dispatchable DG

Customer-sited, customer-owned DG can serve as a utility-dispatchable resource. As described in Section 7.2.2, the PUC directed the utilities to negotiate or require contracts

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that allow the utility to dispatch the customer’s generation unit where dispatching the unit is economical, and to make payments to the customer-generator for the dispatch, reflecting costs avoided by the utility. Consistent with this direction, HECO is pursuing development of dispatchable standby generation (“DSG”) agreements with customers to allow utility dispatch of customer owned standby generators.

As described in HECO’s IRP-3 Evaluation Report, DSG customers would be required to execute a DSG agreement and modify their operating permits and facilities as necessary to allow HECO to dispatch their units. The emergency power facility would primarily be funded and owned by the customer. HECO would contribute funding for certain equipment required to allow utility dispatch, and provide other payments and consideration to the customer for the utility dispatch rights.

HECO’s DSG concept is based in large part on the DSG program run by Portland General Electric Company (“PGE”), the largest regulated electric utility serving Oregon. Since the inception of its DSG program in 2000, PGE has contracted for over 50 MW of DSG capacity from various commercial and industrial customers in Oregon.

HECO is actively developing a DSG project with the State Department of Transportation Airports Division (“DOT Airports”) at the Honolulu International Airport. HECO is partnering with DOT Airports on the design of the DSG facility, and the DSG agreement is under negotiation. HECO anticipates filing of the DSG agreement to the PUC in the fourth quarter 2008. Based on current plans, the DOT Airports emergency generating facility would provide approximately 8 MW of HECO DSG capacity and be placed in service in 2010. HECO’s IRP-4 assumes 8 MW of utility dispatchable DG based on this project.

Additional DSG may be developed depending on the progress of the DOT Airports DSG project. Generally, HECO does not intend to provide DSG as a broad programmatic offering to customers. Instead, HECO anticipates development of a limited number of DSG projects on a one-off basis, in order to selectively focus on the projects that appear most cost effective and technically feasible. In approaching DSG on a more controlled and limited basis, HECO anticipates that it will be better able to optimize the benefits of DSG to ratepayers, consistent with the goals set forth by the PUC in D&O No. 22248.

7.2.4.3 HECO DG at Military Bases

HECO is evaluating the basis on which it could develop long-term HECO-owned DG at Oahu military bases to serve HECO’s system needs, while meeting Department of Defense (DOD) objectives and PUC requirements. In September 2007, DOD hosted a DG industry forum, seeking input from prospective DG providers to assist DOD in developing a request for proposals (RFP) to install privately owned DG at military installations state-wide. The DOD’s objectives in seeking DG at military bases include

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improving physical energy security, increasing use of renewable energy, and managing DOD energy costs.

The DOD has not yet issued a DG RFP. To the degree that military sites can be used by HECO to install DG resources that can serve HECO’s system needs, and to the extent that there is a legitimate system need for such DG resources, HECO will respond to the DOD DG RFP. HECO would likely seek to develop firm, dispatchable biofueled DG plants to help meet HECO’s need for firm generating capacity on Oahu, and to provide the military with enhanced energy security and renewable energy benefits. The actual size, type, location, and timing of such military-sited HECO DG is unknown.

7.2.5 Utility-Sited Photovoltaics

HECO’s IRP-3 Supply-Side Action Plan identified the development of multiple blocks of utility-owned photovoltaic (“PV”) systems to be installed on HECO sites. A total of 1.2 MW of such utility PV systems was planned. In 2006, HECO conducted an extensive evaluation of its Ward Avenue complex to determine the feasibility of installing utility-owned PV at the site. It was determined that the Archer substation rooftop presented the most viable and cost effective site for PV. HECO also determined that it was most cost effective to seek non-utility development of the PV system due to the non-availability of federal renewable energy investment tax credits to the regulated utility.

Based on these determinations, on March 22, 2007, HECO issued a request for proposals to non-utility PV developers, and ultimately awarded the project to Hoku Solar. HECO executed a solar energy power purchase agreement with Hoku Solar and filed it for PUC approval at the end of 2007. The PUC approved the agreement in May, 2008. Detailed design has been completed for the 218 kW (dc) system, and installation is planned to take place in October and November 2008.

HECO’s May 2007 Evaluation Report included a nominal 150 kW HECO-sited PV resource addition in 2007, a second 150 kW PV addition in the 2008-2009 timeframe, and subsequent increments of HECO-sited solar generation to be added later. The Archer PV project is intended as the first phase of the IRP plan. HECO will evaluate its experience in developing the Archer PV project and will consider additional increments of PV at utility sites such as Kahe valley. HECO will also broaden its efforts in the future to include other solar energy generating technologies such as concentrated solar thermal.

7.2.6 Customer-Sited Photovoltaics

Customer-sited PV may be owned by customers, independent PV developers, or, subject to PUC approval, the utility. For commercial customer sites, the most common business model has become an arrangement wherein an independent PV developer

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installs, owns, and operates a PV system at a customer’s site, then contracts for sale of the PV energy to the customer at a stabilized rate. The customer benefits from the stabilized PV energy rate with minimal upfront costs. The PV developer is able to make use of available federal and state investment tax credits.

Through the end of calendar year 2008, federal renewable investment tax credits are set at 30% of the cost of the PV system. However, unless action is taken by Congress, the federal renewable investment tax credit will revert to its original 10% level for PV systems placed in service after December 31, 2008. The Hawaii state renewable investment tax credit is set at 35% of the PV system cost.

Residential PV systems typically are installed using the more traditional model of the residential site owner purchasing the PV system from a PV supplier. On Oahu, a typical 3 kW residential PV system may cost anywhere from $9 to $10 per watt, meaning a range of $27,000 to $30,000 in installed cost for a homeowner, prior to tax credits. Residential investment tax credits are capped at $2,000 per system for the federal investment tax credit, and $5,000 per system for the state investment tax credit. Thus, net of tax credits, a typical residential PV system will cost a homeowner $20,000 to $23,000.

The customer-sited PV forecasts for IRP-4 were developed based on estimates for two separate markets: one for larger commercial customers with PV systems greater than 50 kW and one for customers with PV systems less than 50 kW. In IRP-4, 30 MW of customer-sited PV is assumed to be installed within the 2009-2013 action plan period, and 140 MW of customer-sited PV is assumed over the full 20 year planning period.

The larger PV system forecast was developed using estimates based on specific customer projects obtained through customer and vendor contacts. Additional "unknown" customer projects were added to the forecast in 2010 - 2012 to maintain an estimated annual increase in annualized kWh reduction from PV of about 20% per year.

The small PV system forecast was developed using the assumption that systems less than or equal to 10 kW are residential systems, and those greater than 10 kW are commercial systems. Historical information on registered and discovered (i.e., systems without agreements with HECO but were discovered by meter readers and other HECO personnel and pending signed agreements) systems was used. The estimated average increase in annualized kWh production from small PV systems was assumed at about 20% per year for 2008 - 2013.

The PV market is new to Hawaii and gaining in popularity. Various factors that could influence customer adoption of PV systems were considered in developing the non- customer specific estimates. These factors included: • Utility rates and expectation of continued high oil prices;

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• Tax credits; • Increasing popularity of stabilized-cost pricing contracts or leasing agreements being offered by third party PV providers (i.e., the systems are not owned by the customer who uses the energy and on whose land the PV system is located); • Infrastructure limitations including the limited number of trained installers and maintenance people, permitting process delays, and net energy metering program limits; • Increasing consumer awareness of clean energy and the attractiveness of Hawaii's market to the national PV industry.

Based on these qualitative considerations, an annual growth rate of 20% appeared to be reasonable for the action plan period. Beyond the action plan period, installation of 5 MW to 9 MW of PV was assumed to be installed each year, leading to a cumulative total of approximately 140 MW by the end of the 20 year planning horizon.

The large volume of PV inquiries HECO has received indicates there may be potentially larger growth in this market, but many of these inquiries are also from vendors or contractors in other specialties (e.g., roofing) trying to capitalize on the high level of public interest. Advancements in thin film PV technology and economies of scale in production of PV materials will further increase the market. However, there is a great deal of uncertainty as to what the actual growth in this area will be.

HECO is evaluating options for a utility PV program that facilitates installation of utility and third-party owned PV systems at customer sites to generate PV energy for the utility’s system. Essentially, HECO wishes to apply its experience with its Archer PV project to customer sites. As consideration for providing a PV generation site, the site owner may receive a site rental payment and/or use a portion of the PV energy generated at their site. Following its evaluation, HECO plans to file an application to the PUC for approval of a utility PV program in early 2009. Should such a program be implemented, potentially greater amounts of PV could be developed on Oahu within the 20-year planning period.

7.3 Supply-Side Resources

Supply-Side Resource Options

The new supply-side resources to be integrated into the system will be acquired primarily through a competitive bidding process in compliance with the Commission’s Competitive Bidding Framework, dated December 8, 2006. With the advent of competitive bidding, the usefulness of the supply-side resource option characterizations as provided in the Unit Information Forms has diminished.

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The IRP process will primarily determine the timing of the need for new resources and the attributes those resources should have. The actual resource that is acquired will be determined through a competitive bidding process. This is in contrast with the process used in previous IRP cycles where supply-side resource options were characterized in detail and a dynamic optimization computer program would determine the optimal generating unit type and size that should be added as well as the appropriate timing of the addition by applying the utility’s capacity planning criteria. The utility would then pursue the installation of that particular type and size of resource.

In this IRP-4 process, only certain sizes of each technology type were used since it was not necessary to identify the precise type and size of resource. The Request For Proposal to acquire the resource would allow a range of sizes and technologies to be bid.

The supply-side resource options used in IRP-4 were a subset of those used in HECO IRP-3. The costs in the HECO IRP-3 Unit Information Forms were escalated to current values. Table 7.3-1 below provides the cost data used in IRP-4.

Table 7.3-1 Conversion HECO's Existing Generation Units to Utilize Biofuels

Normal Top Capital Variable (Costs in 2009$) Load Cost Fixed O&M O&M (Net MW) ($/kW) ($000/yr) ($/MWH) Fuel Type Firm Resources CTA (1st 113 MW CT at site) 113 1,174 1,683 29.22 Biodiesel CTB (2nd 113 MW CT at site) 113 1,033 0 29.22 Biodiesel Conversion of CTA or CTB to STCC 170.1 749 2,937 5.26 Biodiesel Biomass Combustion Unit 25 3,948 6,601 5.40 Biomass Waste-to-Energy Unit 15.9 8,348 4,853 20.87 Solid Waste 6.6 MW DSG Unit at Hon Intl Airport 6.6 707 570 24.82 Biodiesel 6.6 MW DG Unit - Tier 2 CAT 6.6 1,239 180 12.41 Biodiesel 12.5 MW DG Unit - 1 Solar Titan 130 12.5 3,425 861 23.33 Biodiesel 25 MW DG Unit - 2 Solar Titan 130 25 3,330 1,723 23.33 Biodiesel 50 MW DG Unit - 4 Solar Titan 130 50 2,424 3,446 23.33 Biodiesel

As Available Resources 1 MW Fixed PV - (10) 100 kW systems 1 10,496 33 33.39 - 1 MW Single Axis Tracking PV - (10) 100 kW systems 1 12,633 41 34.14 - 1 MW Fixed PV - (500) 2 kW systems 1.1 14,897 68 61.23 - 1 MW Hybrid Fixed PV w/ Battery - (500) 2 kW systems 1.1 23,938 92 327.01 - 10 MW Wind Vestas V47 at Kahuku - (15) 660kW turbine 9.9 2,234 495 1.95 - 20 MW Wind Vestas V47 at Kahuku - (30) 660kW turbine 19.8 1,962 786 1.95 - Conversion of HECO’s Existing Generating Units to Utilize Biofuels

For the purposes of the integration analysis, it was assumed that HECO’s existing generating units could be converted to utilize biofuels instead of oil. HECO plans to

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conduct a test on one of its oil-fired steam units in 2009 to learn more about the considerations and impacts of using biofuel instead of oil in its steam units. The precise scope of work needed for a full-scale conversion of a steam unit has not yet been established. HECO estimates that a full-scale conversion that would include new pumps, burner equipment, piping, electrical equipment, storage tanks, engineering and construction would cost in the range of $5 million to $10 million per unit. For the purposes of the integration analysis, a capital cost estimate of $7 million was used for the conversion of each existing steam unit.

Resource Attributes

In order to attain higher levels of renewable energy and reduce the amount of fossil fuels consumed while meeting load growth and maintaining system reliability, a portfolio of renewable resources, both firm and non-firm, will need to be acquired. HECO anticipates that intermittent, as-available resources, such as wind or photovoltaic resources, will be a significant part of that portfolio of renewable resources.

Firm, dispatchable resources, such as steam units, are an essential part of the generation portfolio because these types of resources provide the necessary rotational inertia, load following, spinning reserve and frequency and voltage regulation to keep the system stable. These firm dispatchable resources offset the power fluctuations from intermittent, as-available resources.

To determine appropriate mixes of firm, dispatchable resources and intermittent, as- available resources, a number of detailed studies will need to be conducted. The scopes of the studies envisioned may include: • An evaluation of the spinning/non-spinning reserve requirements (i.e., minimum number of generating units that need to run or be available on standby) and underfrequency load shed requirements to maintain system stability for various operating and disturbance response scenarios and for increasing levels of intermittent penetration assumptions. The scope would include coordination with Automatic Generation Control, Local Frequency Control, and underfrequency load shedding, in addition to generating unit droop response. • An evaluation of the ability of storage technologies to provide ancillary services for the HECO grid. Storage technologies can help minimize curtailment of as-available resources. • Development of a model that can simulate the second-to-second and minute- to-minute system frequency and voltage given various system inputs (such as fluctuating power injections from intermittent resources or system disturbances and the pulsing from the Energy Management System). • Estimate the potential impacts of increased spinning reserve and uneconomic commitment of units on system heat rate, variable O&M costs, and number of

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starts on generating units in order to mitigate the effects of intermittent, as- available generation on the system. • Evaluate the interconnection requirements needed to accommodate a high penetration of wind energy. • Evaluate the potential operational impacts of high wind penetration on dispatch and system disturbance scenarios and dispatcher training/staffing requirements, and identify potential changes to existing operating policies and procedures. • Develop appropriate performance standards for intermittent, as-available generation to mitigate the impact the output of these types of resources may have on system power quality and grid stability.

Energy Storage

Since as-available resources generate energy according to the vagaries of nature and the times at which the energy is generated will not necessarily coincide with the time at which it is consumed, there may be times when there is more energy generated than can be consumed. This excess energy may be generated primarily during periods of low demand, such as during the late night and early morning hours, but they can occur at other times of the day. Energy storage can be used to absorb this excess energy. The stored energy can be discharged into the grid during periods of higher demand. This would reduce the amount of fossil fuel consumed. Energy storage can also be used to smooth the power fluctuations of as-available resources.

Energy storage can be in the form of chemical energy (battery energy storage systems) or potential energy (pumped storage hydro).

Factors that would need to be considered when determining whether or not it would be appropriate to integrate energy storage onto the system include, but would not be limited to: • The cost of the energy storage system. • The availability of sites for the energy storage system. • The amount of excess energy that is anticipated to produced over time. • The ability of the energy storage system to effectively mitigate the effects of intermittent, as-available generation’s power output fluctuations. • The cost differential between on-peak and off-peak energy generation.

Energy storage was not examined in detail in the integration analysis because it could not be determined how much excess energy would exist since the specific types of new, as-available resources would be selected via a competitive bidding process. However, HECO plans to investigate potential energy storage projects as discussed in Section 10.5.3 in the Action Plan.

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7.4 Generating Unit Retirement Evaluation

From time to time in the normal course of its system planning, HECO evaluates the feasibility of retiring certain existing generating units (or placing them on emergency reserve status) and replacing them with new generating units. Factors which are considered during this evaluation include, but are not limited to, the age and condition of the generating unit, the efficiency of the unit, the benefits that the unit provides to the utility system, the reliability of the unit, and the costs and benefits associated with any new generating unit.33

HECO examined the issue of generating unit retirements (or placing them on emergency reserve status) at a high level as part of the IRP-4 integration analysis. As explained in Section 8, integration analysis is the process by which demand-side, supply-side, and distributed generation resources are integrated into resource plans in different combinations in order to meet the forecasted electrical energy needs of a utility while meeting certain objectives such as minimizing total resource costs or keeping CO2 emissions within certain constraints. As a part of that analysis the Strategist model specifically analyzed the possibility of retiring the two oldest units on the HECO system, Waiau 3 and 4 in order to meet the mandate of Act 234 which requires that the aggregate CO2 emissions from power generating facilities be at or below 1990 levels by the year 2020. (See, Ventyx Integration Analysis Report attached as Appendix S). The Ventyx analyses indicated that the economic favorability of placing Waiau Units 3 and 4 on emergency reserve status is sensitive to load growth and fuel price assumptions.

In actual practice numerous factors must be considered to determine whether or not a generating unit should be retired, or alternatively, placed on emergency reserve status. These factors associated with retirement of a unit include, but are not limited to: • Whether the existing generation is required to meet existing demand and/or future load growth; • Amount of capital that would need to be invested to continue operating the existing unit safely over the long term; • Operating costs that will be incurred to operate the existing unit over the long term; • Projected reliability of the existing unit; • The existing unit’s role on the system in providing ancillary services (e.g., frequency and voltage regulation, spinning reserve) or other system benefits such as quick-starting capability;

33 For example, the retirement of existing units was evaluated in HECO IRP-2 (see Section 8.1.1 of the HECO IRP-2 report filed in Docket No. 95-0347) and in HECO IRP-3 (see Section 8.2.1 of the HECO IRP-3 report filed in Docket No. 03-0253).

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• Projected cost of fuel for the existing unit; • Availability of spare parts for the existing unit; • The availability of sites for new, firm generating capacity; • The cost of installing new, firm generating capacity that can provide the ancillary services needed by the system for stable operation; • Operating costs for the new generating unit; • Projected reliability of the new generating unit; • Projected cost of fuel, if any, for the new unit; • The new unit’s role on the system in providing ancillary services or other system benefits; • Impacts on the transmission system if existing generation is removed from one location and new generation is located elsewhere; • Environmental tradeoffs of replacing existing generation with new generation; • Whether any benefits may be applicable to permitting a new or replacement generating unit as a result of retiring the unit in question; • Replacing fossil-fueled generation with renewable generation to meet statutory requirements such as meeting Renewable Portfolio Standards or reducing CO2 emissions; • Replacing fossil-fueled generation with renewable generation to comport with state energy policy (reduce dependency on fossil fuels, use indigenous renewable resources, etc.); • Uncertainties in rates of load growth or future peak reduction benefits of energy efficiency DSM programs; • Uncertainty in project-completion timelines for new generation. (For example, the timing of a unit retirement or a unit’s placement on emergency reserve status would depend on the timing of new generation coming on line.); • Uncertainties associated with new technologies that may be integrated into the grid. (For example, the utility must meet its obligation to serve, even if that means relying on fossil-fueled generation until technical maturity and market acceptance of the new technology is proven.)

Additionally, there are unique factors associated with placing a unit on emergency reserve status which must be considered. These include but are not limited to:

Actions that would need to be taken to place the unit in emergency reserve status. Examples of candidate actions include placing nitrogen “blankets” in heat exchangers and other mechanical equipment to prevent corrosion, de-energizing or isolating electrical equipment, flushing and preserving all fuel handling equipment, isolating mechanical equipment and instrumentation, and setting up a maintenance program to

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maintain the condition of all equipment so that they can all be restarted when needed for emergency purposes.

The cost of taking the actions to place the unit in emergency reserve status.

Actions that would need to be take to permanently retire the unit. Examples of candidate actions include removal and salvaging of retired equipment, flushing and isolation of all fuel handling equipment, disconnection of electrical services, and disconnection of water, steam and other piping.

The cost of taking actions to permanently retire the unit.

Whether the permits for the unit allow for such purposes or can be modified if necessary to accommodate such purposes.

The possibility of using the site of the unit, if permanently retired, for other purposes.

The cost of preparing the site of the unit, if permanently retired, for other purposes.

As a part of this process, Waiau Units 3 and 4 were identified as units that could potentially be retired or placed on emergency reserve status or retired because they are the oldest units on the HECO system and may be difficult to convert to use biofuels. As of 2008, they are 61 and 58 years old, respectively. Each unit provides approximately 46 MW-net each of capacity. These two units had among the highest Equivalent Forced Outage Rates (“EFOR”) among HECO’s steam units in the past five years. Also, their maintenance costs are high relative to the other units on the system.

Honolulu Units 8 and 9 are the next oldest units. As of 2008, they are 54 and 50 years old, respectively. These two units also had relatively high EFORs. However, these two units would not be good candidates for retirement because they provide critical voltage support for the downtown area and critical subtransmission and distribution circuits are connect to the power plant.

Upon consideration of many planning factors evaluated as a part of the IRP-4 process, the Company has determined that Waiau Unit 3 should be placed on emergency reserve status or permanently retired after Campbell Industrial Park (“CIP”) CT-2 has been placed into service and is providing firm capacity to the system. In order to replace the capacity to be lost by the removal of Waiau Unit 3 from active service, additional capacity must be installed in the 2014 timeframe. HECO will issue a Request For Proposal to acquire that capacity. (See Section 10.3.7.)

The installation of CIP CT-2, the placement of Waiau Unit 3 on emergency reserve status (or its retirement), and the implementation of an RFP process to acquire capacity in the 2014 timeframe are all part of a closely-tied “package” because of their relationship to one another. The installation of CT-2 provides sufficient generating capacity and dispatchable power on the system to enable HECO to begin removing

Docket No. 2007-0084 7-44 September 2008 HECO IRP-4 Chapter 7: Resource Options

certain existing fossil-fueled generating capacity from the system. The removal of Waiau Unit 3 from the system advances the need for additional capacity to 2014, and that additional capacity will be acquired through a competitive bidding process.

HECO also plans to place Waiau Unit 4 on emergency reserve status or permanently retire the unit. The timing of when this occurs will be a function of many factors, including but not limited to, projected system demand (including the peak reduction benefits of energy efficiency DSM and load management programs), the EFOR of all units on the system (utility and IPP), the actual amount of capacity on the system (including that to be installed by the successful bidder in the RFP for the 2014 increment of capacity), the extent to which the characteristics of the unit (e.g., its ramp rates or shorter startup time relative to the other, larger steam units) can help integrate large increments of intermittent, as-available generation (such as wind generation) onto the system, and the extent to which additional new generating capacity can better provide characteristics that can help integrate increments of intermittent, as-available generation (in which case Waiau Unit 4 could be removed from the system). Whether the unit is placed on emergency reserve status or permanently retired will also depend on the types of studies and analyses described earlier in this section.

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Docket No. 2007-0084 7-46 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

8 INTEGRATION ANALYSIS

8.1 Overview and Background

Integration analysis is the process by which demand-side, supply-side, and distributed generation/combined heat and power (DG/CHP) resources are integrated into resource plans in different combinations in order to meet the forecasted electrical energy needs of a utility while meeting certain objectives, such as minimizing total resource costs or keeping CO2 emissions within certain constraints. For HECO IRP-4, integration analysis was done in four phases. In the first phase, eight scenarios were developed to define the high and low boundaries of certain key parameters, such as sales and peak demand, fossil fuel prices, and the value of carbon, to quantify the range of uncertainty that was involved with planning for the future. In the second phase, a draft Benchmark Plan was developed. The draft Benchmark Plan utilized the inputs that portrayed a reasonably expected future (e.g., the sales and peaks that HECO believed would be a reasonable representation of the future under a given set of circumstances). In the third phase, sensitivity analyses (i.e., the test of uncertainty of forecasted inputs) were performed to determine how the draft Benchmark Plan would change as key input parameters were changed. Finally, in the fourth phase, the Benchmark Plan was developed that encompassed the results shown in the prior three phases, with experienced planning and management judgment applied to account for conditions, circumstances and factors that cannot be captured in a computer model.

The integration analysis incorporates the inputs that include the following which are discussed in separate chapters in this report: • Sales and peak forecast • Fuel price forecast • Demand-Side Management forecast • Supply-Side Unit Information Forms (UIFs)

The integration analysis develops the plan that economically achieves the following legislative and operating requirements: • Renewable Portfolio Standard • Act 234 – greenhouse gas legislation • HECO’s reliability standard

The integration analysis simulates the demand-side and supply-side resources required to meet the customer demand where the transmission and distribution infrastructure supports the efficient running of the system (i.e., where it is assumed that there are no transmission or distribution system constraints).

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The integration analysis was performed using the Strategist model, which was used in developing all of HECO’s previous IRP plans. Strategist is an integrated planning system that employs dynamic programming to develop optimal portfolios of resources and analyze all functional areas of utility planning. A description of the Strategist model can be found in Appendix T, section 6.

The Strategist modeling work was divided between Ventyx and HECO. The first three phases of the integration analysis was performed by Ventyx, a leading business solutions provider to global energy, utility, communications, and other asset-intensive organizations. The fourth phase required input from HECO’s planning and management groups. HECO relied upon Ventyx, the developer of the Strategist computer model, for their modeling expertise and analytical capability. The Integrated Resource Planning Division oversaw the process to ensure consistency in the modeling assumptions that was used by these two groups.

8.2 Phase One: Development of the High and Low Scenarios

HECO first identified the key inputs that could affect the composition of the resource plans. The three major inputs that create differences between the scenarios are as follows: • Sales and peak forecast • Fossil fuel price forecast • Value of carbon (carbon tax or cap & trade)

The other inputs to the model remained constant in all of the eight scenarios analyzed in phase one.

Because biofuels are such a new resource to the electric utility industry, at the time of HECO IRP-4’s phase one analysis, HECO was only able to develop a single biofuels price outlook. As HECO progressed with the Integration Analysis, HECO was able to develop a high scenario for the biofuels price outlook.

The eight scenarios identified below were intended to define the “boundaries” for the range of uncertainty in the IRP-4 analysis, and a High and Low forecast was developed for each input. Therefore, given that there are three data series, each with a high and low forecast, the number of combinations that result is eight as follows:

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Table 8.2-1 Scenarios

Fossil No. Sales and Peak Fuel Price Forecast Value of Carbon 1 High High High 2 High High Low 3 High Low High 4 High Low Low 5 Low High High 6 Low High Low 7 Low Low High 8 Low Low Low

The sales and peak forecast was the most significant driver for the high and low scenario analysis. There was a significant difference in the amount of additional supply- side capacity that the Strategist model identified that would be required to meet the higher customer demand in the high versus the low sales and peak Forecast. The Strategist model had difficulty in identifying the significantly higher amount of renewable resources capacity needed to comply with the Greenhouse Gas Legislation. If the high sales and peak forecast were to occur, the system would dispatch an amount of renewable resources above what is justified by pure economic dispatch, causing a slight increase in energy costs to the system. However, this high sales and peak forecast is not considered likely to occur. Rather, this scenario identifies the mitigating factors that would be needed if it were to occur.

The fossil fuel price forecast was the second most significant driver for the sensitivity analysis. There was a significant difference in the type of additional supply-side resources that the Strategist model identified that would be required to meet the legislative and operational requirements. The higher the fossil fuel price, the greater the amount of additional non-fossil fuel resources selected by the Strategist model as the economic resource. In the low fossil fuel price scenarios the emergency reserve status of Waiau 3 and 4 was needed to shift load from fossil fuel resources to renewable resources in order to comply with the Renewable Portfolio Standard and the Greenhouse Gas Legislation.34 In the high fossil fuel price scenarios, the economic dispatch of units loads the renewable resources sufficiently to comply with the Renewable Portfolio Standard and the Greenhouse Gas Legislation.

34 Any decision to place Waiau Units 3 and 4 on Emergency Reserve status or to retire those units will be dependent upon a number of interrelated factors as discussed in Section 7.4.

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The value of carbon was the third most significant driver for the sensitivity analysis. The value of carbon represents carbon emission legislation, such as Lieberman-McCain: Climate Stewardship and Innovation Act of 2007 (S.280), which is discussed in Section 4.4. There was only a little difference that resulted in the type of additional supply-side resources that the Strategist model identified that would be required to meet the legislative and operational requirements. The value of carbon was assessed on every ton of CO2 that was emitted; therefore, the high value of carbon scenario did have a higher Total Resource Cost than the low value of carbon scenario, but with very little difference in the renewable resources that were selected.

The full impact of the value of carbon is a part of the sales and peak impact and the fossil fuel price impact. A high value of carbon has a price sensitivity impact on customer demand, the rule being the higher the cost attached to carbon emissions, the higher the energy price to customer resulting in a lower level of demand from customers. The sales and peak forecast was adjusted by 6% to reflect the impact to customer demand for energy (see Section 4.9 for a description of that adjustment). A high value of carbon has a fuel price impact on fossil fuel oil prices, the rule being the higher the value of carbon, the higher is the relative price of fossil fuel oil (which have higher CO2 emissions) in comparison to non-fossil fuel resources (which have lower CO2 emissions). 8.3 Phase Two: Development of the Draft Benchmark Plan

The Draft Benchmark Plan was developed after analyzing the results from the first phase of the analysis (i.e., the high versus low scenario analysis). The following inputs were identified as being best representative of the future: • Base sales and peak forecast (*) • High fossil fuel price forecast • High value of carbon

(*) The base sales and peak forecast that was utilized in the Draft Benchmark Plan was roughly the mid point between the high and low scenarios used in the phase one analysis. The sales and peaks are discussed in Chapter 6.

The Draft Benchmark Plan, as with the phase one analysis, utilized the Strategist model that would identify the most economical solution that meets the legislative and operational requirements. This plan identified the following resources: • Biofuels fired central station simple cycle combustion turbine (SCCT) units • Wind power • Biomass generating unit • Biofuels conversion of existing HECO baseload units

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• Biofuels fired central station SCCT conversion to combined cycle CT (i.e., addition of a heat recovery unit) • Biofuels fired distributed generation units

Figure 8.3-1 Draft Benchmark Plan

Draft Benchmark Plan ( 109 MW) ( 156 MW) Demand-Side Management ( 30 MW) ( 140 MW) Customer-owned Photovoltaics ( 1 MW) ( 1 MW) Customer-owned Distributed Generation/Combined Heat & Power ( 8 MW) ( 8 MW) Utility Dispatchable Distributed Generation 110 MW 6 MW Firm CT Biofuel RE 70 MW Firm RE 25 MW Firm RE 100 MW Firm RE RE 6 MW Firm 100 MW Non-Firm RE RE 100 MW Non-Firm 70 MW 25 MW Firm RE BT Kahe 3 RE Firm Biofuel Testing 710 MW HECO Biofuel Conversion 25 MW Firm RE (Biofuel Testing on a HECO Steam Unit in 2009) BC 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 Action Plan

A nominal 110 MW biofueled combustion turbine (CT) was selected by the Strategist model for 2009 and 2010 due to a capacity shortfall and due to the timing that is required for supply side resources to be installed. The Draft Benchmark Plan’s 2009 CT is the Campbell Industrial Park CT-1 (CIP CT-1) project that was approved by the Commission on May 23, 2007 in Decision and Order No. 23457 in HECO Docket No. 05-0145. A nominal 110 MW biofueled CT is identified as a resource (labeled 100 MW firm renewable energy on chart above) to meet the capacity shortfall that still exists after the installation of CIP CT-1. A discussion of this shortfall can be found in the HECO Adequacy of Supply Letter dated January 30, 2008 that was filed with the Commission, and included in Appendix O Since these CTs are biofueled, they emit only 25% of the

CO2 emissions of No. 2 diesel oil on a lifecycle basis and they contribute to the attainment of the Greenhouse Gas Legislation and Renewable Energy Portfolio requirement.

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A large (100 MW non-firm renewable energy) group of wind power resources was selected by the Strategist model for 2012 and another 100 MW increment in 2015 due to its zero CO2 emission and its relatively low capital cost per MW of capacity compared to other resources such as PV. In the 20-year planning period, wind resources are selected early, allowing its high capital cost per MW of capacity to be amortized over a long period. In contrast, small distributed generation units that have lower capital costs per MW of capacity were selected in the latter portion of the planning horizon. Wind resources are non-firm resources; however, their energy is produced with zero CO2 emissions, which contributes to the attainment of the Greenhouse Gas Legislation and Renewable Energy Portfolio requirement.

A 25 MW biomass generating unit was selected by the Strategist model for 2018. This firm capacity resource uses a renewable energy fuel source that is considered as emitting zero CO2 emission on a lifecycle basis and contributes to the attainment of the Greenhouse Gas Legislation and Renewable Energy Portfolio requirement.

The conversion of 710 MW of capacity from HECO’s baseload steam units from fossil fuel to biofuels was selected by the Strategist model during the period 2016 through 2020. A conservative assumption was made that the HECO units will consume a blended fuel of 75% biofuels and 25% LSFO. This conservative assumption allows HECO to incorporate other renewable resources and technologies, while illustrating HECO’s commitment to biofuels in this IRP-4 planning period. Almost all of the baseload units were selected for the biofuels conversion, the exception being Waiau 8 since sufficient renewable resources were available to meet the Renewable Portfolio Standard and Act 234 Greenhouse Gas Legislation.

In 2026 and 2028 the addition of a heat recovery steam generator (HRSG) to the biofuel CT adds an additional 70 MW of firm capacity in each year. A HRSG takes the exhaust heat from the CT to generate steam for a turbine generator with zero additional fuel, and therefore zero incremental CO2 emission and contributes to the attainment of the Greenhouse Gas Legislation and Renewable Energy Portfolio requirement.

Biofuel fired distributed generation (DG) units are selected by Strategist in the following years:

2023 6 MW

2024 25 MW

2025 6 MW

2027 25 MW

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These DG units are firm capacity and since they are biofuel fired units, they emit only

25% of the CO2 emissions of No. 2 diesel oil on a lifecycle basis. A discussion of this low CO2 emission is discussed in Chapter 4 on global warming.

Large customer owned photovoltaic (PV) resources were not selected by the Strategist model in the Draft Benchmark Plan due to the present high capital costs per MW of non- firm capacity associated with a PV project, in comparison to other renewable resources. In the phase three Sensitivity Analysis the PV resources were selected under scenarios where the fossil fuel oil and biofuel prices were projected to be even higher than in the phase one High and Low Scenario Analysis. However, although large customer PV was not selected, 140 MW of small customer owned PV projects by the year 2028 are embedded in HECO’s plan.

HECO IRP-4 looked specifically at placing older, less efficient generating units on emergency reserve status. Emergency reserve means that a generating unit has been removed from daily operation on HECO’s system. Layup procedures are performed that preserve the integrity of the unit while it is unused over an extended period. These units are not dismantled so that they can be recalled to service if an unforeseen emergency arises. The possibility of placing Waiau units 3 and 4 on emergency reserve status. Emergency reserve status was analyzed. Although the Strategist model in deriving the Draft Benchmark Plan did not specifically select emergency reserve status for Waiau 3 and 4, they were neverthelessincluded in the Benchmark Plan and the Preferred Plan due to their importance for plan flexibility (as is discussed in §8.5) considering the uncertainty of the modeling inputs, in this particular case the sales and peak forecast. 35

The Draft Benchmark Plan represents the actual resources and timing of the Strategist model to meet the requirements of the Renewable Portfolio Standard and for Act 234’s Greenhouse Gas Legislation, in the most economical manner, as explained in the Integration Analysis report by Ventyx in Appendix T chapters 2 and 3. In contrast, the Benchmark Plan (which is discussed in Section 8.5) starts with the results of the Draft Benchmark Plan, then include other resources that the Sensitivity Analysis and High and Low Scenario Analysis indicate are important for plan flexibility. Finally, the Preferred Plan which is discussed in Chapter 10 starts with the Benchmark Plan, then includes the impact of Competitive Bidding (including any anticipated request for waivers from Competitive Bidding).

35 As discussed in Section 7.4, any decision to select Emergency Reserve status or retire Waiau Units 3 & 4 will be dependent upon a number of interrelated considerations.

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8.4 Phase Three: Sensitivity Analysis on the Draft Benchmark Plan

The Sensitivity Analysis on the Draft Benchmark Plan quantified the change to the plan that resulted from changes to the following inputs: • Sales and peak forecast • Fuel price forecast (both fossil fuel and biofuel) • Stricter greenhouse gas legislation • Emergency reserve status of Waiau 5 and 6

Similar to the findings in the phase one analysis, the sales and peak forecast was the most significant driver for the Sensitivity Analysis. There was a significant difference in the amount of additional supply-side capacity that the Strategist model identified that would be required to meet the higher customer demand in the high versus the low sales and peak forecast.

In the high sales and peak sensitivity analysis run, difficulty arose in getting sufficient firm renewable resources. Conversion of all of HECO’s baseload units and the conversion of Kalaeloa Partners, LP’s (KPLP) 208 MW combined cycle combustion turbine unit to biofuels was required. KPLP’s existing power purchase contract expires in 2016, and HECO will explore in contract negotiations getting KPLP to convert from fossil fuel oil to biofuels. However, since HECO cannot force KPLP to convert to biofuels under the terms of the existing PPA, HECO’s Draft Benchmark Plan focused on the resources that were within its control. Furthermore, the probability of the high sales and peak forecast occurring is considered small; however, this sensitivity analysis identified the resources that HECO will need in order to comply with both the legislative and operational requirements.

Also similar to the findings in the phase one analysis, the Fossil Fuel Price Forecast was the second most significant driver for the Sensitivity Analysis. There was a significant difference in the type of additional supply-side resources that the Strategist model identified that would be required to meet the legislative and operational requirements. The results indicated that the higher the fossil fuel price, the greater the amount of additional non-fossil fuel resources are selected by the Strategist model as the economic resource.

The price of fossil fuel will also be a significant determining factor in any decision to place Waiau units 3 and 4 on emergency reserve status. In order to meet the legislative requirements of the Renewable Portfolio Standard and Act 234’s Greenhouse Gas

Legislation, load generated from existing fossil fuel units that emit higher levels of CO2 needed to be shifted to renewable energy resources that emit lower levels of CO2. In the low fossil fuel price sensitivity analysis, Waiau 3 and 4’s incremental energy cost was

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close to the system’s incremental energy cost and therefore, those units would be committed on a regular basis. To be in compliance with the Renewable Portfolio Standard and Act 234, it will likely be necessary to either place Waiau units 3 and 4 on emergency reserve status or appropriately retire those units to effectively shift load form older, less efficient follisl fuel units to renewable energy units. 36

8.5 Phase Four: Development of the Benchmark Plan

The Benchmark Plan started with the results from the Draft Benchmark Plan (as discussed in Section 8.3), then included other resources that the Sensitivity Analysis and High and Low Scenario Analysis indicate were important for plan flexibility (e.g., the emergency reserve status for Waiau 3 and 4). This was an attempt to incorporate elements that will allow HECO to deal with the uncertainty that exists within a long range planning process. Computerized modeling assumes that there is certainty predicting the future where specific inputs are processed with complex algorithms that utilizes a set of rules to specify the goals and limits, and derives the optimal solution. The Benchmark Plan incorporated key considerations from the Strategist runs in order to develop a plan that will be flexible, and therefore ready to deal with the uncertainty of the future regarding the inputs, in particular as with the sales and peak forecast and the fuel prices forecast.

36 Any decision to place Waiau Units 3 & 4 on Emergency Reserve status or retire those units will be based upon a number of related factors as discussed in Section 7.4.

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Figure 8.5-1 Benchmark Plan (2009-2018)

Benchmark Plan (2009-2028) ( 109 MW) ( 156 MW) Demand-Side Management (including SWAC)

( 30 MW) ( 140 MW) Customer-sited Photovoltaics ( 1 MW) ( 1 MW) Customer-owned Distributed Generation/Combined Heat & Power

( 8 MW) ( 8 MW) Utility Dispatchable Distributed Generation

CT 110 MW Biofuel

CT 100 MW Firm

ER Waiau 3 Emergency Reserve

RE 50 MW Firm

ER Waiau 4 Emergency Reserve

797 MW HECO BT BC Biofuel Conversion Kahe 3 160 MW Non-Firm (including Emerging RE Biofuel Technologies such as OTEC) Testing RE 16 MW C&C Waste-to-Energy

RE 50 MW Firm

RE 100 MW Firm

Explore Placing an Additional ER HECO Unit on Emergency Reserve

100 MW Firm RE

Explore Placing an Additional ER HECO Unit on Emergency Reserve

09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 Action Plan

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The 110 MW firm capacity in 2009 and the 100 MW firm capacity in 2010 were in the Benchmark Plan; however, due to practical constraints in building the 100 MW firm capacity increment, it was moved from 2010 to 2011. The inclusion of the second 100 MW capacity increment reflects the need to add firm capacity to overcome the reserve capacity shortfall that is forecasted to exist after the installation of the Campbell Industrial Park CT-1 (CIP CT-1) project (as discussed in Section 8.3).

The emergency reserve status of Waiau 3 is coupled with the second 100 MW firm capacity increment in 2011 as is discussed in more detail in Section 7.4.

HECO’s baseload unit conversion from fossil fuels to biofuels assumes the same 2009 test on the Kahe 3 generating unit; however, the conversion of the baseload units is shown as beginning immediately after the completion of the Kahe 3 test. This would reflect HECO’s ability to move quickly toward a higher RPS percentage, more rapid compliance with Act 234, and a sooner transition away from fossil fuels, depending upon the cost and availability of suitable biofuels and upon the ability to take the units out of service to convert the units to use the new fuel.

A large (100 MW) group of wind power resources that was selected by the Strategist model for 2012 and another 100 MW increment in 2015 in the Draft Benchmark Plan have been modified to a 160 MW wind resource in 2012 (labeled on the chart as 160 MW Non-Firm including Emerging Technologies such as OTEC) and a 50 MW firm capacity increment that will be installed in 2014 and will be discussed next. The benefit of wind power resources is that their energy is produced with zero CO2 emission, which contributes to the attainment of the Greenhouse Gas Legislation and Renewable Energy Portfolio requirement.

The generic 25 MW biomass generating unit that was selected by the Strategist model for 2018 was replaced with a 16 MW waste-to-energy generating unit expected in 2012. This is to reflect the latest information that HECO has regarding the City and County of Honolulu’s plan for the expansion of the HPOWER facility. This firm capacity resource uses a renewable energy fuel source that is considered as emitting zero CO2 emission on a lifecycle basis and contributes to the attainment of the Greenhouse Gas Legislation and Renewable Energy Portfolio requirement.

The 50 MW firm capacity increment added in 2014 reflects the need for firm capacity due to the placement of Waiau 3 on emergency reserve status. If the unit is not placed on emergency reserve status, the additional 50 MW increment of capacity may not be needed in 2014. This is discussed in greater detail in Section 7.4.

The Draft Benchmark Plan included two 100 MW non-firm capacity increments – one in 2012 and the other in 2015 – and both were modeled as wind power units. The

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Strategist modeled the wind resources as “load modifiers.” This means that, in effect, they had the characteristics of firm capacity. As a result, these resources were able to defer the need for firm capacity. In reality, wind resources are not firm capacity, and firm capacity would not be deferred with the addition of as-available wind generation. Therefore, this effect had to be adjusted by removing the two wind resources from the modeling run, then rerunning the model to reset the timing of firm capacity resource additions. This was a very time consuming approach that was applied only on running on the Draft Benchmark Plan and not in all of the sensitivity runs. After the timing of the firm capacity units was reset, the model was rerun once again with the wind resources re-entered into the plan in order to capture the beneficial attributes of the wind resources.

The emergency reserve status of Waiau 4 is coupled with the 50 MW Firm capacity increment in 2014 allowing HECO to shift more of the power generation from fossil fuel resources to biofuel resources. The emergency reserve status of Waiau 4 also adds flexibility to HECO’s long range plan by incorporating an element that has a shorter lead time than what is required for the installation of a new nominal 50 MW firm capacity resource. Details regarding the future of Waiau 4 on the HECO system are set forth in Section 7.4.

The remaining supply side resources that were identified in the Draft Benchmark Plan in the 2020 through 2028 time period were replaced by two 100 MW firm capacity increments, using two 50 MW biofueled distributed generation (DG) units installed in 2021 and two 50 MW biofueled DG units in 2027. These biofueled DG units allow HECO to continue to meet its CO2 emissions limit as specified in Act 234’s Greenhouse Gas Legislation and the Renewable Portfolio Standard as load continues to grow after 2020. However, these DG units represent 200 MW of firm capacity increments that are expected to be required in the future; and will be revisited in HECO IRP-5 (or through the planning process that replaces HECO IRP-5). The selection of the timing was based on having sufficient firm capacity, while continuing to meet the Renewable Portfolio Standard and the Greenhouse Gas Legislation.

Coupled with the 100 MW firm capacity DG increment in 2021 and again in 2027 is HECO’s plan to explore the possibility of laying up more HECO cycling units on emergency reserve status. These additional emergency reserve units would be premised on HECO having sufficient reserve capacity that would allow laying up these units. This would occur if the customer demand is lower than anticipated and that there are no long term derates on existing or future supply side resources, and that the DSM programs are being implemented as forecasted.

The assumptions for the Draft Benchmark Plan were developed between May 2007 and May 2008. During the running of the different phases of the analysis, HECO developed some newer assumptions and data that were not able to be included into the Draft

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Benchmark Plan. This more current data was incorporated into the Benchmark Plan which reflects the latest data that was available for Strategist modeling purposes as of July 2008. Although planning is a continuous process, the Benchmark Plan is a “snap shot” that captures the latest available data for HECO’s long range planning purposes that can be run on the Strategist model. The Preferred Plan, which is discussed in the next chapter, takes the Benchmark Plan and converts each specific resource type into a generic capacity block that will have a Request For Proposal as specified in the Competitive Bidding Docket.

8.6 Objectives and Measures

The 14 objectives and measures that were developed in the beginning of the HECO IRP-4 process were compared against the results derived from the Benchmark Plan as discussed in Section 8.5. HECO was successful in attaining these objectives and measures as shown below, with the exception of the slight underachievement on the DSM cumulative MW impact in 2015, which was back on track by 2020, and the temporary generating system reliability reserve capacity Shortfall in 2010 which was achieved with the 100 MW Firm Capacity scheduled for 2011.

Table 8.6-1 Objectives and Measures (2010-2028)

2010 2015 2020 2028 Goal 5% 7.5% 10% TBD Renewable Electrical Energy (%) Results 5% 34.0% 55% 53% RPS Difference 0% 26% 45% N/A Goal 10% 15% 20% TBD Total RPS (%) Results 12% 42% 63% 60% Difference 2% 27% 43% N/A Goal TBD TBD TBD TBD

CO2 HECO (Million Tons) Results 4,153,459 3,215,546 2,340,433 2,956,799 Global Difference N/A N/A N/A N/A Warming Goal TBD TBD TBD TBD

CO2 System (Million Tons) Results 7,482,405 6,582,527 5,757,635 6,281,017 Act 234: 1990 Emission 6,411,293 Tons Difference N/A N/A N/A N/A Goal 195 200 205 210 Water Potable Water Consumption (kGal/day) Results 195 200 205 210 Difference 0 0 0 0

2010 2015 2020 2028 Goal 221,787 390,030 525,549 536,131 Cumulative MWh Results 540,020 663,620 811,510 839,060 Difference 318,233 273,590 285,961 302,929 Goal 85 125 151 153 Cumulative MW Results 92.4 123.4 152.8 155.8 DSM Difference 7.4 -1.6 1.8 2.8 Goal 195 200 205 210 Low Income Program Expenditures Results 195 200 205 210 Difference 0 0 0 0 Goal TRC>1 TRC>1 TRC>1 TRC>1 Portfolio Cost-Benefit Results TRC>1 TRC>1 TRC>1 TRC>1 Difference Achieved Achieved Achieved Achieved

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2010 2015 2020 2028 Goal TBD TBD TBD TBD Utility Dispatchable DG (MW) Results8888 DG / CHP Difference N/A N/A N/A N/A Goal TBD TBD TBD TBD Customer CHP (MW) Results 0.5 0.5 0.5 0.5 Difference N/A N/A N/A N/A Goal No Shortfall No Shortfall No Shortfall No Shortfall Reliability Generating System Reliability Reserve Results 20 - 80 MW No Shortfall No Shortfall No Shortfall Capacity Shortfall Difference 20 - 80 MW Achieved Achieved Achieved Goal TBD TBD TBD TBD Rate Increase (annual pct. Increase) Results -0.3% 4.4% 2.8% 3.5% Customer Difference N/A N/A N/A N/A Impact Goal TBD TBD TBD TBD Bill Impact Results$ 168 $ 209 $ 239 $ 314 600 kWh Residential Bill - $168 - 7/08 Difference N/A N/A N/A N/A

8.6.1 Renewable Portfolio Standard

The renewable electrical energy percentage goals were achieved by a significant margin as shown in the table below. The majority of the renewable energy generation is from the conversion of HECO’s baseload units from fossil fuel to biofuels.

Table 8.6-2 Renewable Portfolio Standard Renewable Electrical Energy Percentage

Renewable Portfolio Standard Renewable Electrical Energy Percentage

2010 2015 2020 2028

HPOWER 335 338 339 339 AES Municipal Solid Waste1 40 40 40 40 Biomass 0 612 743 640 HECO Biofuel Generation 10 1,435 3,045 3,304 New Wind Generation 192 479 479 Hon. C&C Municipal Solid Waste Addition 0 117 117 117 Photovoltaic Facilities 4 4 4 4 Total Renewable Energy Generation 388 2,738 4,767 4,923

Sales 7,837 8,057 8,652 9,333

RPS Electrical Energy Generated Using 5% 34% 55% 53% Renewable Energy Sources Percentage

1 AES MSW of 40 GWh is the 2005 - 2007 average. All figures are in GWh from the Strategist Benchmark Plan run except the AES MSW and the calculated RPS Electrical Energy Generated Using Renewable Energy Sources Percentage. RPS Renewable Energy Generated % = Total Renewable Energy Generation ÷ Sales The Total Renewable Portfolio Standard Percentage goals were achieved by a significant margin as shown in the table below. The majority of the goal was achieved from the conversion of HECO’s baseload units from fossil fuel to biofuels.

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Table 8.6-3 Renewable Portfolio Standard Total RPS Percentage

Renewable Portfolio Standard Total RPS Percentage

2010 2015 2020 2028

Total Renewable Energy Generation 388 2,738 4,767 4,923

Electrical Energy Savings Using Renewable Displacement Technologies Solar Water Heating 85 97 109 109

Electrical Energy Savings Using Energy Efficiency Technologies EE Pre-2009 Participants 340 340 340 340 EE 2009-2028 Participants 109 176 226 231 Subtotal 449 516 566 571

Total 922 3,351 5,441 5,603

Sales 7,837 8,057 8,652 9,333

RPS Electrical Energy Generated Using 12% 42% 63% 60% Renewable Energy Sources Percentage

8.6.2 Global Warming

The reduction of both the HECO and the system greenhouse gas emissions, in particular

CO2, was achieved mainly through the conversion of HECO’s baseload units from fossil fuel to biofuels as shown in the graph below.

Docket No. 2007-0084 8-15 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

Figure 8.6-1 System Carbon Dioxide Emissions

System Carbon Dioxide Emissions

8,000,000

7,000,000 6,411,293 Tons of Carbon Dioxide 1990 Emission Level for the System on Oahu 6,000,000

5,000,000 New Municipal Solid Waste Generation New HECO Biofuel Generation 4,000,000 Independent Power Producer HECO Biofuel Conversion 3,000,000 HECO Fossil Fuel Tons of Carbon Dioxide Carbon of Tons 2,000,000

1,000,000

0 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Year

8.6.3 Potable Water Consumption

Potable water consumption is assumed to be achieved based upon the estimates from HECO’s Engineering Department which was the basis for both the determination of the goal and of the forecast. Potable water consumption is not a variable that is modeled within the Strategist model.

8.6.4 Demand Side Management

The DSM cumulative MWh was achieved as shown in the table below that lists the impact of each program. The results are from the output of the Strategist model.

Docket No. 2007-0084 8-16 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

Table 8.6-4 Demand Side Management Cumulative MWh Demand Side Management Cumulative MWh

2010 2015 2020 2028

Residential Efficient Water Heating Program 3,760 15,960 28,150 35,610 Residential New Construction Program 3,250 13,760 23,390 29,660 Energy Solutions for the Home Program 8,750 25,870 43,360 44,740 Residential Low Income Program 3,610 14,410 22,100 27,240 Commercial and Industrial Energy Efficiency Program 20,910 87,880 138,000 166,000 Commercial and Industrial New Construction Program 8,000 33,740 54,100 65,940 Commercial and Industrial Customized Rebate Program 13,120 55,690 98,000 128,000 Pre-2009 Participants 478,620 416,310 404,410 341,870

Total 540,020 663,620 811,510 839,060 The DSM cumulative MW was achieved as shown in the table below that lists the impact of each program. The results are from the output of the Strategist model.

Table 8.6-5 Demand Side Management Cumulative MW

Demand Side Management Cumulative MW

2010 2015 2020 2028

Residential Efficient Water Heating Program 1.1 4.0 6.9 8.6 Residential New Construction Program 1.7 6.3 10.8 13.5 Energy Solutions for the Home Program 3.4 9.0 14.9 15.1 Residential Low Income Program 1.0 3.5 5.5 6.7 Commercial and Industrial Energy Efficiency Program 3.9 14.3 21.7 25.6 Commercial and Industrial New Construction Program 1.5 5.5 8.6 10.5 Commercial and Industrial Customized Rebate Program 2.1 7.9 13.8 17.4 Residential Direct Load Control Program 20.5 20.5 20.5 20.5 Commercial and Industrial Direct Load Control Program 24.1 32.5 33.2 33.4 Interruptible Contract Service (Rider I) 4.3 4.3 4.3 4.3 Pre-2009 Participants 28.8 15.5 12.8 0.2

Total 92.4 123.4 152.8 155.8 The low income program expenditures and the portfolio cost-benefit are not variables considered in the Strategist model. A discussion of these goals can be found in the discussion of DSM in Chapter 7.1.

8.6.5 Utility Dispatchable Distributed Generation / Customer Combined Heat and Power

IRP-4 includes 8 MW of installed capacity for utility dispatchable DG icorresponding to the Honolulu International Airport’s DSG facility. As described in the Action Plan,

Docket No. 2007-0084 8-17 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

additional DSG projects may be evaluated, and HECO will periodically evaluate the continued use of 29.5 MW of temporary DG at its substations.

The 0.5 MW of Customer CHP is reflected in the Sales and Peak Forecast, Section 6.1.

8.6.6 Reliability

The Strategist model requires sufficient capacity to meet the generating system reliability reserve capacity. The 2010 shortfall of 20 – 80 MW is due to the delay in timing of the 100 MW firm capacity increment from 2010 to 2011 due to practical constraints, and is discussed in the 2008 Adequacy of Supply letter in Appendix O

8.6.7 Customer Impact

The methodology used in determining the customer impact in terms of the rate increase (annual percentage rate) and the bill impact (for a 600 kWh Residential Bill) is illustrated below for the calculation from 2010 to 2015 Bill Impact and Rate Increase. The values for the 2020 and 2028 calculation will follow the same methodology.

Figure 8.6-2 Methodology Flow Chart Methodology Flow Chart

Strategist Model 2009 2010 2011 2012 2013 2014 2015 Utility Cost $1.312B $1.303B $1.533B $1.504B $1.541B $1.597B $1.621B

Annual Pct. Chg. ’09-’10 ’10-’11 ’11-’12 ’12-’13 ’13-’14 ’14-’15 -0.7% +17.6% -1.9% +2.5% +3.6% +1.5%

600 kWh Bill 2009 2010 2011 2012 2013 2014 2015 $169.15 $167.95 $197.55 $193.82 $198.69 $205.83 $208.91

Bill Impact 07/2008 2010 2015 $168.82 $167.95 Objectives $208.91 and Rate Increase 2010 2015 Annual Percentage Rate -0.3% Measures +4.5%

HECO July 2008 ECAC Filing HECO 2009 TY Rate Case Cost of the 600 kWh Residential Bill Cost of the 600 kWh Residential Bill

Hawaiian Electric Company, Inc. 4 Integrated Resource Planning - CTS July 2008

Docket No. 2007-0084 8-18 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

The 2010 bill impact is calculated using the Strategist model’s results for Utility Cost (UC) for 2009 and 2010; and using the $169.15 estimated 600 kWh Residential Bill that is filed in HECO’s 2009 test year rate case direct testimony, Docket No. 2008-0083. The Strategist model calculated the 2009 and 2010 UC as $1.312 billion and $1.303billion, respectively. This 0.7% decrease is applied to the $169.15 residential bill to estimate the 2010 bill at $167.95 [i.e., (100% – 0.7%) x $169.15 = $167.95]. The reason for the slight decrease in the estimated customer bill for 2010 is the forecasted decrease in the base scenario fuel price forecast, as shown in Section 6.2.

The rate increase (annual percentage increase) for 2008 to 2010 is based on the July 2008 Residential Bill of $168.82 and the 2010 estimated Residential Bill of $167.95, which derives a 0.3% annual percentage decrease. This same methodology is used for calculating the 2015, 2020, and 2028 Bill Impact and Rate Increase.

The costs that the Strategist model considers include the fuels, production and maintenance, capital projects, and taxes. This methodology used to estimate the bill impact and rate increase (annual percentage increase) is that any cost not directly modeled within Strategist will increase at the same percentage rate case as what was calculated for the costs associated with the UC.

8.7 Higher Level of Reliability

At this time, HECO is not advocating a revision to its 4.5 years per day loss of load reliability guideline.37 HECO does recognize that from an “obligation to serve” perspective, ever-increasing levels of reliability are a desirable objective, and that tradeoffs, such as the increased costs to achieve this objective, should be examined38. HECO has quantified the potential costs for implementing a higher level of reliability, and has determined that the (CT proxy) capital cost impacts of migrating to a 10 years per day are significant, in the range of $60 – 100 million if consistently implemented over the next 20 year period.

This premium to migrate from the current 4.5 year per day reliability guideline to a higher 10 years per day reliability guideline may have merit in the future, as the demand-side

37 In December 2004, Shaw Power Technologies, Inc. (“Shaw PTI”) completed a review of HECO’s capacity planning reliability criteria, and concluded in relevant part, “the current reliability guideline of 4.5 years to experience one loss of load day is reasonable for both a regulated vertically integrated utility on Oahu and for a competitive environment should one evolve”. The entire Shaw PTI review, which describes HECO’s capacity planning criteria and surveys the criteria of other utilities worldwide, was filed as an appendix to HECO’s IRP-3 in Docket 03-0253 (starting on Appendix page P-4, with conclusion stated on page P-37). 38 In Docket No. 05-0145 (Campbell Industrial Park Generating Station and Transmission Additions Project), the Consumer Advocate stated that HECO’s capacity planning criteria may need to be revised when considering Hawaiian Electric’s lack of interconnection with other utilities and the tradeoff between cost and reliability be revisited (Testimony of Mr. Joseph Herz, CA-T-1, page 8, lines 13-16 and page 8, lines 13-16).

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and supply-side resource planning environment continues to increase in complexity, creating more uncertainty in the calculated results. One potential means to address the ever increasing planning uncertainty and complexity is to revise the capacity planning guideline. If the existing Loss of Load Probability of 4.5 years per day does not provide an adequate cushion to respond to quickly-changing assumptions, many of which the utility has little or no control over, then the utility could plan with a more stringent guideline, which would accelerate the need for firm capacity. Such an approach would not eliminate quickly changing assumptions, but it would add a measure of conservatism in recognition that the uncertainties undoubtedly exist.

Another method of addressing the uncertainty of planning assumptions -- that does not explicitly change the reliability guideline -- is to assess a range of possible forecasts, and determine how reserve capacity shortfall results are affected by factors such as changing customer loads and unit availability.

Method

To assess the differential capital costs between two resource plans of differing reliability levels, HECO sought a method that simplifies the understanding of cause and effect. This objective resulted in the use of a CT proxy method, which assumes that the capital costs for a simple cycle combustion turbine are a reasonable proxy for quantifying capital expenditures for firm capacity. Other resources such as coal units, combined- cycle combustion turbine units, or biomass (steam) units tend to have higher capital costs that are offset by lower fuel costs. The uncertainty in these results is impacted by the assumed fuel prices used, and can occasionally result in distortions caused by the advance or delay in the installation of fuel-efficient units. HECO’s approach quantifies “pure capacity costs,” and illustrates the potential ramifications of a higher reliability guideline on the resulting costs of implementation.

To perform the differential analysis, a resource plan was designed around the existing 4.5 years per day reliability guideline (base case). The resource plan used simple cycle CTs to satisfy the requirements for firm capacity. The revenue requirements necessary to install the CTs for this base case were then summed to determine the total capital costs required.

A separate resource plan was designed around the higher 10 years per day reliability guideline (higher reliability case). As in the base case, simple cycle CTs were used to satisfy the requirements for firm capacity. However, because the guideline was more stringent, increments of capacity were needed more frequently, such that the necessary capital revenue requirements were higher than the base case.

The difference between the base case and higher reliability case capital revenue requirements are in the range of $60-100 million in net present value if consistently

Docket No. 2007-0084 8-20 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

implemented over a period of 20 years. These costs are based on a proxy CT of a nominal 110 MW and installed capital costs of $110-125 million (in 2007$).

The resource plans and associated capital costs for the proxy CTs are illustrated in Table 8.7-1 below. Differences may not tie due to rounding.

Table 8.7-1 Comparison of Proxy CT Timing and Plan Revenue Requirements for Current and Higher Generating System Reliability

Year Base Plan CTs PV Rev Req Higher PV Rev Req PV RR (Cap Cost in for Proxy CT Reliability for Proxy CT (High-Base) millions, 2007$) Capital (Base) Plan CTs Capital in millions, in millions, (with Cap (High) in 2007$ 2007$ Cost in millions, millions, 2007$ 2007$)

2009 CT ($125) $18 CT ($125) $18 $0

2010 20 20 0

2011 CT ($110) 32 CT ($110) 32 0

2012 31 CT ($125) 46 15

2013 27 45 17

2014 24 39 15

2015 21 35 13

2016 CT ($125) 31 31 (1)

2017 30 27 (4)

2018 27 24 (3)

2019 24 CT ($110) 30 6

2020 21 28 8

2021 18 25 7

2022 CT ($110) 24 22 (2)

2023 22 19 (4)

Docket No. 2007-0084 8-21 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

2024 20 17 (3)

2025 17 CT ($125) 22 5

2026 15 21 6

2027 13 19 5

2028 CT ($125) 18 16 (2)

Total $454 $534 $80 NPV

8.8 Transmission Analysis

8.8.1 Transmission Considerations in the IRP-4

As explained earlier, performing the load flow simulations is a very complex and lengthy undertaking, even for a single assumption for the timing, size, and location of future generating units. In IRP, numerous possible resource plans can be generated through the resource optimization process. Even though these possible resource plans are narrowed to a smaller set (less than two dozen plans), sensitivities are run to determine the impact of different sales and peak forecasts, different fuel price forecasts, different DSM and CHP program sizes, and other parameters on unit selection and timing. This sensitivity analysis multiplies the number of scenarios that must be assessed.

Furthermore, for customer-owned DG/CHP units, particular sites may be identified. But because the timing of installation is driven primarily by the customer, there is much uncertainty as to when the units will be installed. Hypothetically, DG/CHP units can be incorporated into the IRP process in several ways, such as: 1) using area specific DG/CHP assumptions, in which case transmission planning scenarios would have to evaluate a large number of scenarios (i.e. low, base, and high forecasts, various central station generation scenarios, single and/or double transmission line contingency analysis, and various location and sizes of DG/CHP), would require an excessive amount of time for the analysis and would introduce a high degree of uncertainty with respect to whether actual levels of DG/CHP can be achieved in specific areas; 2) using area specific DG/CHP assumptions and selecting several scenarios to evaluate, which would reduce the amount of time for the analyses, but would still have a high degree of uncertainty, or 3) using DG/CHP forecasts on a system-wide level and allocating the impacts based on the methodology described earlier in this section for the transmission planning process. Due to the compressed timeframe required for this analysis and the new objectives and uncertainty in the assumptions with respect to the size and location

Docket No. 2007-0084 8-22 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

of the resources obtained through the Competitive Bidding Framework for the HECO IRP-4 analysis, HECO performed a transmission analysis in which transmission capital costs were calculated for the preferred plan. The analysis identified system upgrades that may be needed should the plan be implemented as proposed. However, if the size, timing, or locations of the assumed resources change as projects are selected through the Competitive Bidding process, the results of the analysis will also change.

In order to account for the impacts from DG/CHP in the long-term analyses, without identifying specific locations for the DG/CHP units, HECO allocated forecasted DG/CHP and any additional DG/CHP above what is already being forecasted on a system-wide basis using the historical loading at the transmission substations. Load flow simulations were used to identify the transmission capital projects that would be needed to accommodate the generation additions specified in the preferred plan. A complete copy of the transmission study can be found in Appendix R. In addition, the finalist resource plans include existing plans and costs to address criteria violations and reliability concerns that have been identified outside of the IRP-4 process.

8.8.2 East Oahu Transmission Project

The purpose of the East Oahu Transmission Project (EOTP) is to address several transmission problems concerning Oahu’s 138 kV transmission system in the eastern half of the island. First, an overload situation with one of the three 138 kV transmission lines that transport power to the Koolau/Pukele service area in the Northern 138 kV transmission corridor could occur beginning in 2005, whenever the other two lines are out of service (“Koolau/Pukele Overload Situation”). Second, an overload situation with one of the three 138 kV transmission lines that transport power to the Downtown area in the southern 138 kV transmission corridor could occur after the year 2024, whenever the other two lines are out of service (“Downtown Overload Situation”). Third, Pukele substation, located at the end of the northern 138 kV transmission corridor, would be without power if the two 138 kV transmission lines serving it were to be lost. Pukele substation serves critical loads such as Waikiki, State Civil Defense, Hawaii Air and Army National Guard Headquarters, and the University of Hawaii (“Pukele Substation Reliability Concern”). And fourth, Archer substation, Kewalo substation and Kamoku substation, all located in the southern 138 kV transmission corridor, would be without power if the two 138 kV transmission lines serving Archer substation were to be lost (“Downtown Substation Reliability Concern”). Kewalo substation receives power from Archer substation via two 138 kV transmission lines, and Kamoku Substation receives power via one 138 kV transmission line from Kewalo substation. These substations serve critical loads such as the Honolulu Police Department Headquarters and the Hawaii Convention Center.

Docket No. 2007-0084 8-23 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

HECO proposes to implement the EOTP in two independent phases. Implementing the proposed project in two phases has been proposed to address near erm transmission problems, such as the Koolau/Pukele Overload Situation and a part of the Pukele substation reliability concern, which includes Waikiki, in a more timely manner.

Phase 1 involves the installation of 0.5 miles of underground ductline for 46 kV sub- transmission lines, and related work at eight substations, in order to interconnect three 46 kV circuits out of the Pukele substation, at the end of HECO’s northern 138 kV transmission corridor, to four 46 kV lines connected to HECO’s southern 138 kV transmission corridor. Phase 1 includes: (1) the installation of six underground 46 kV lines in the Ala Moana, McCully, Moiliili, and Kapahulu areas, (2) a 138 kV/46 kV transformer installation at the existing Kamoku substation with associated protective relaying, (3) a 46 kV/12 kV transformer installation at the existing Makaloa substation with associated switchgear, (4) various switching and reconnections on the existing 46 kV and 12 kV systems near Makaloa and McCully substations, (5) the removal of existing 46 kV and 12 kV cables between Makaloa and McCully substations, (6) the removal of an existing 46/12 kV transformer and associated switchgear from the McCully substation, and (7) modifications of various existing distribution substations in the Honolulu area.

Phase 2 involves the installation of 1.9 miles of underground ductline for 46 kV subtransmission lines, and related work at one substation, in order to interconnect four out of the five remaining 46 kV circuits out of the Pukele substation to three other 46 kV lines connected to HECO’s southern 138 kV transmission corridor. Phase 2 includes: (1) the installation of three underground 46 kV lines in the Kakaako, Makiki, and McCully areas, and (2) a 138 kV/46 kV transformer installation at the existing Archer substation with associated protective relaying. Refer to Figure 2, which is Figure 2-2 in HECO’s filed Environmental Assessment for the EOTP in Docket No. 03-0417. On August 24, 2007, HECO received a proposed Decision and Order from the PUC approving phase 1 and phase 2 of the EOTP project

8.8.3 AES-CEIP #2 138 kV Transmission Line

The generating units in the Campbell Industrial Park (CIP) connect to the main HECO transmission grid via two existing 138kV transmission lines. A third transmission line connecting the CIP generation to the grid is needed for the following reasons:

Ensuring System Reliability: Taking one of the two transmission lines serving CIP out of service for maintenance leaves only a single transmission line to transport all of the power produced by the generators located there. If that single transmission line then tripped unexpectedly, all of the power generated in the CIP area would need to be replaced almost instantaneously by the spinning reserve from the other Oahu generating stations. Since the spinning reserve on the system is typically maintained at 180 MW

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(the capacity of the largest unit on the HECO system), CIP generation is presently limited to a maximum of 180 MW whenever either of the two lines is out of service.

Until recently, this 180 MW CIP generation restriction has not been critical because HECO has tried to coordinate maintenance of the transmission line with the maintenance of the existing CIP generating units or had sufficient generation capacity elsewhere in its systems. Because of the substantial growth in energy use over the past few years, it is no longer safe to continue this practice. The construction of a third transmission line to serve the CIP area is needed to ensure that line maintenance can be accomplished without putting all of the CIP generation at risk.

Preventing Existing Transmission Line Overloads: The existing CIP transmission lines will be at risk for overload conditions upon installation and full load operation of a new combustion turbine. Thus, the entire HECO system will be at risk.

To satisfy these needs, a two-mile long 138kV transmission line within the Campbell Industrial Park will be constructed from HECO's AES substation to its CEIP substation.

8.8.4 Honolulu-School-Iwilei 46kV Transmission Circuits

The Honolulu power station (Honolulu PP) is connected to the 138kV transmission system through four 46kV underground circuits (two circuit connecting to the School Street substation and two circuits connecting to the Iwilei substation. There is a single circuit between the School Street and Iwilei substations which completes the loop for this 46kV network system. See Figure 8.8-1. A portion of the Honolulu PP generation feeds the local Honolulu Bus load (Honolulu and Kakaako distribution substations). The remaining Honolulu generation is transmitted to the rest of the HECO system through four 46 kV underground circuits that connect the Honolulu PP with the Iwilei and School 46 kV substations. Net export of Honolulu PP capacity has increased over historical levels due to the Honolulu bus load decreasing due to some of the load being shifted to the 25 kV distribution systems and the Honolulu power plant being run at higher dispatch levels, and during periods of lower Honolulu bus load.

HECO has initiated a study to review the loading on these cables and identify any potential overloads during contingency conditions. If overload conditions are identified, solutions such as load shifting and/or increasing the power flow capacity of these circuits will be reviewed and a preferred solution developed.

Docket No. 2007-0084 8-25 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

Figure 8.8-1 Honolulu-School-Iwilei 46kV Transmission Circuits

Figure 3

8.8.5 Waiau 46kV Bus

Included in the preferred plan is the placement of Waiau 3 and Waiau 4 on emergency standby status. Waiau 3 and 4 are connected to the 138kV system through a 46kV bus that also provides power to distribution substations from Mililani to Aiea. Without either Waiau 3 or Waiau 4 online, there is a limit on how much load can be served off of the Waiau 46kV bus without causing a low voltage violation on the system. The loads in the area do exceed that limit. However, the economic dispatch of Waiau 3 and 4 generators during the higher load periods of the day normally provided sufficient voltage support to the bus such that the load limit can be increased to cover the increasing load. If Waiau 3 and 4 are put on emergency standby status and are not normally committed as they are now, mitigation measures would be needed to avoid a low voltage condition on the bus. Potential solutions would be to shift load off the bus to other substations. To do this additional capacity may be needed at the other substations to support this added load.

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8.8.6 Halawa-School, Halawa-Iwilei, Makalapa-Airport Reconductoring

These three circuits serve loads from the downtown area to the eastern end of the southern transmission corridor which ends at Kamoku Substation. These are the circuits that are involved with the “Downtown Overload Situation” noted above in the EOTP project description in Section 7.10.2.2.

As the non-firm generation in the preferred plan is added to the system, energy from those resources must be taken on the system before any of the HECO cycling units such as the Honolulu generating units. As such, as the non-firm generation is added to the system, the power generated by those resources could displace the generation currently produced by the Honolulu Power Plant since the Honolulu units are near the end of the dispatch order. However, the Honolulu units would still be needed should the non-firm generation not be available. The power generated from the Honolulu Power Plant currently reduces the power flow on these circuits by serving the demand that those circuits would otherwise need to serve.

Therefore displacing the Honolulu Power Plant generation with western or northern non- firm resources, which is where these resources are likely to be located, will worsen the “Downtown Overload Situation”, to the point where these circuits would need to be upgraded using higher current carrying conductors. A large reduction in the load served by these lines, if sufficiently large (on the order of 50 MW, with no future load growth) may defer the need for this reconductoring project. However, further study would be needed to assess any large load reduction project and the risk of not attaining this level of load reduction through DSM would need to be taken into account.

In 2013, approximately 201 MW of non-firm generation is estimated to be added to the HECO system. If these non-firm resources are operating at near their rated output, assuming the current economic dispatch order and 180 MW of spinning reserve, the generating units at HPP may not be required to run under normal operation conditions. Without the HPP generating units helping to serve the Downtown load, all power for the Downtown area is coming via the Halawa-School, Halawa-Iwilei, and Makalapa-Airport- Iwilei circuits.

If one of the three transmission lines is taken out for maintenance and a second line trips out unexpectedly, the remaining line is at risk for overloading. A future study would analyze the overload conditions and evaluate the options available to increase the power flow capacity to serve the Downtown load. For the purposes of the IRP, reconductoring the three lines serving the Downtown area was the assumed solution and would ensure line maintenance can be accomplished without risking line overloads.

Docket No. 2007-0084 8-27 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

8.8.7 AES-CEIP #3 Addition

After the addition of the 110 MW CT in 2009 and the associated AES-CEIP #2 line, the generating units in the Campbell Industrial Park will connect to the main HECO transmission grid via three 138kV transmission lines.

Maximum export of a generating station is one of the conditions that the transmission system would need to accommodate per HECO’s transmission planning criteria. Two 50 MW Firm generating resources are assumed to be installed in the Campbell industrial area by 2017. At that point, the system would be at risk for overload if maximum export from generating units in the CIP area is achieved. Adding the AES-CEIP #3 line would prevent the risk of line overloads should one of those lines trip. The AES-CEIP #2 line is designed to accommodate the AES-CEIP #3 line when it is needed.

8.9 Fuel Diversity and Fossil Fuel Generation Efficiency

In the Commission’s Order No. 23312, dated March 21, 2007, in Docket No. 03-0253 (HECO IRP-3), the Commission, among other things, ordered that “[t]he consideration of the fuel diversity and fossil fuel generation efficiency issues mandated by Sections 111(d)(12) and 111(d)(13) of PURPA, as amended by the Energy Policy Act of 2005, is deferred to HECO’s IRP-4 proceeding.”

On June 30, 2008, the Commission issued a letter to HECO, the Consumer Advocate and others stating:

Sections 111(d)(12), 111(d)(13) and 112(b)(3)(A) of the Public Utilities Regulatory Policies Act of 1978 (“PURPA”), as amended by the Energy Policy Act of 2005, require the Public Utilities Commission (“Commission”) to complete its consideration and make a determination of the following matters governing fuel diversity and fossil fuel generation efficiency, no later than August 8, 2008: [footnote 1 omitted]

(12) FUEL SOURCES – Each electric utility shall develop a plan to minimize dependence on 1 fuel source and to ensure that the electric energy it sells to consumers is generated using a diverse range of fuels and technologies, including renewable technologies.

(13) FOSSIL FUEL GENERATION EFFICIENCEY (sic) – Each electric utility shall develop and implement a 10-year plan to increase the efficiency of fossil fuel generation.

Please provide a statement describing your position, if any, on whether the commission should adopt, modify, or decline to adopt in whole or part, the standards articulated above.

On July 14, 2008, HECO responded to the Commission’s June 30, 2008 letter. HECO stated that its position on this matter was unchanged from its position stated in a

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January 31, 2007 letter to the Commission in Docket No. 03-0253 (HECO IRP-3) on the same matters regarding fuel diversity and fossil fuel generation efficiency. In its January 31, 2007 letter, HECO stated that “the Commission should decline to adopt in whole or part the two federal standards.” HECO also stated that “HECO plans to address matters governing fuel diversity and fossil fuel generation efficiency in its HECO IRP-4 report.”

On August 8, 2008, the Commission issued an Order Declining to Adopt PURPA Standards on Fuel Diversity and Fossil Fuel Generation Efficiency in Docket No. 2007- 0084 (HECO IRP-4) (“Order Declining to Adopt PURPA Standards”). Section III of the Order Declining to Adopt PURPA Standards stated:

The Commission declines to adopt, for HECO, the two federal standards on fuel diversity and fossil fuel generation efficiency.

HECO’s long-term resource plan diversifies HECO’s fuel sources by incorporating a wide array of renewable resources, including wind energy, waste-to-energy, biofuels, photovoltaic resources, and ocean thermal energy conversion. Fuel diversity is addressed in several sections of the HECO IRP-4 report. These sections include the May 2005 Black & Veatch IRP-3 Supply-Side Portfolio Updates that describes each of these renewable energy resources that are identified in the Benchmark Plan shown in Section 8.5, and Section 6.2.1(biofuels).

With respect to fossil fuel generation efficiency, HECO addressed this matter in its letters, dated January 31, 2007 and July 14, 2008, to the Commission in Docket Nos. 03-0253 (HECO IRP-3) and 2007-0084 (HECO IRP-4), respectively. In summary, HECO stated:

HECO notes that the fuel efficiency standard cannot be applied to the fossil-fuel fired generation owned by independent power producers (“IPPs”). In any event, the IPPs have incentives to maintain and improve the efficiencies of their generating units, to the extent it is cost effective for them to do so, by virtue of the energy pricing provisions in their power purchase agreements (“PPAs”). This was recently evidenced by the mechanical efficiency upgrades implemented by Kalaeloa Partners, L.P. (“KPLP”) in 2004, which had the additional benefit of allowing KPLP to provide additional firm capacity to HECO. These upgrades were incorporated in amendments to the KPLP PPA, which were approved by the Commission in Decision and Order No. 21820, filed May 13, 2005, in Docket No. 04-0320.

The fuel efficiency standard also is unnecessary in the case of utility-owned generation, because the fixed heat rate provision in their Energy Cost Adjustment Clauses provides the HECO utilities with substantial incentive to maintain and improve the fuel efficiency of their generation.

Docket No. 2007-0084 8-29 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

In HECO IRP-4, HECO analyzed the generation efficiency of its fossil fuel fleet. Table 8.9-1 below summarizes the composite system heat rate by year for HECO’s fossil fuel generation based on the benchmark plan. 39

Table 8.9-1 Fossil Fuel Generation Efficiency, in Btu/kWh-net, for Benchmark Plan

Fossil Fuel 2009 10,177 2010 10,174 2011 10,169 2012 10,186 2013 10,184 2014 10,180 2015 10,069 2016 10,109 2017 10,150 2018 10,239 2019 10,443 2020 11,630 2021 11,528 2022 11,600 2023 11,627 2024 11,608 2025 11,624 2026 11,693 2027 11,666 2028 11,744 It can be seen that, in general, fossil fuel efficiency is expected to decline over time as the benchmark plan is implemented. There are two primary reasons for this. First, the long-term resource plan calls for converting HECO’s baseload generating units to biofuels so that eventually only its cycling units, which have lower generating efficiencies than baseload units, would remain on fossil fuels. Second, as more renewable resources are added to the system, the fossil fueled generating units will operate at lower, less efficient load levels. It should also be noted that if spinning reserve levels need to be increased to mitigate the effects of the fluctuating outputs of as-available resources, such as wind or photovoltaics, fossil fuel efficiency could be degraded further. This is because higher levels of spinning reserve would require that the fossil fueled generating units, which would carry the spinning reserve (or regulating reserve) would

39 The table of heat rate values is illustrative. The heat rates were derived by the Strategiest model that is different from the model used for the rate case purposes. The Strategist model uses a load duration curve to determine generating unit dispatch and is generally less accurate compared to the hourly chronological production simulation model used for rate cases in terms of generating unit energy production and fuel consumption. The Strategist model is used in IRP because it is designed for the type of dynamic optimizations that need to be performed in IRP for resource selection. The outputs from Strategist are not calibrated as they are in the rate cases because in IRP, the intent is to identify general trends rather than determine absolute values.

Docket No. 2007-0084 8-30 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

need to operate at lower, less efficient levels in order to provide the spinning or regulating reserve.

See Appendix Q Fuel Diversity and Fossil Fuel Generation Efficiency • HECO’s letter, dated January 31, 2007, to the Commission in Docket No. 03-0253 (HECO IRP-3) • HECO’s letter, dated July 14, 2008, to the Commission in Docket No. 2007-0084 (HECO IRP-4)

8.10 HECO LSFO Fuel Storage

On December 11, 2007, HECO submitted an application to the Commission in Docket No. 2007-0409 requesting approval to commit funds for the renovation of its Barbers Point Fuel Oil Tank No. 131. On April 16, 2008, the Consumer Advocate submitted its Statement of Position in this docket. They stated, “the Consumer Advocate hereby states that it does not object to the Commission’s approval of the requested relief described in the instant application.”

Within their Statement of Position, the Consumer Advocate stated:

“Although the near future plans are to run the next CEIP generating unit as a simple- cycle CT unit to meet peak demand, it is difficult to determine the impact the unit will have on the Company’s LSFO requirements when it is part of a 2-on-1 combined cycle unit in the future. [footnote 15 excluded] Further, the Consumer Advocate notes that it is difficult to determine the Company’s LSFO requirements or use of biofuels without further studies (e.g., integrated resource plan (“IRP”)) in place.”

“As a result, based on the above, the Consumer Advocate does not object to the Company’s claim that there is a continued need for Tank 131 to mitigate current risks to HECO’s LSFO supply. The Consumer Advocate notes that the Company may in the near future be requesting Commission approval to renovate Tanks 132 and 133. Prior to these requests, HECO is expected to file its next integrated resource plan in June 30, 2008, (i.e., HECO’s IRP-4). [footnote 16 excluded] As such, the Consumer Advocate anticipates that such information from HECO’s IRP-4 will allow for better assessment of the Company’s future LSFO requirements and the associated infrastructure to maintain such requirements.”

On May 15, 2008, the Commission issued Decision and Order No. 24228 in Docket No. 2007-0409 approving HECO’s request to commit funds for the renovation of its Barbers Point Fuel Oil Tank No. 131.

Docket No. 2007-0084 8-31 September 2008 HECO IRP-4 Chapter 8: Integration Analysis

Although the Commission did not explicitly state in Decision and Order No. 24228 that HECO needed to evaluate the need for Tanks 132 and 133 in HECO IRP-4, the section below provides a broad, qualitative assessment of future fuel storage capacity to respond to the Consumer Advocate’s Statement of Position in that docket.

Over the long-term, HECO’s IRP-4 anticipates a reduction in fossil-fuel consumption, including LSFO. It is expected that biofuels will play a significant role in this reduction. Nonetheless, HECO’s existing LSFO infrastructure should be kept operationally viable for at least two reasons: 1) the scope and timing of transitioning to biofuels is not certain at this time, and 2) HECO anticipates that the future bulk storage requirement of biofuels can be accommodated by the existing LFSO storage infrastructure, such that the existing LSFO infrastructure will continue to be needed regardless of the type of liquid fuel burned (i.e., the requirement for bulk fuel storage will not be eliminated, even if the type of fuel being consumed changes over time). HECO will reassess the LSFO and biofuel bulk storage requirements and the alternatives for meeting these requirements as it proceeds with the Kahe Unit 3 Biofuel Co-firing Project, as part of the application process for the planned refurbishment of Tanks 132 and 133 at the Barbers Point Tank Farm, and also as part of the on-going IRP process.

Docket No. 2007-0084 8-32 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

9 PREFERRED PLAN

9.1 Preferred Plan

The Preferred Plan is HECO’s 20-year long range plan that identifies the capacity blocks that will be selected through the competitive bidding process, following the framework specified in Docket No. 03-0372, Decision and Order No. 23121, Instituting a Proceeding to Investigate Competitive Bidding for New Generating Capacity in Hawaii. The development of the Preferred Plan starts with the results of the Benchmark Plan and determines the appropriate “capacity block” and the attributes that will be included in the Request For Proposals that will be issued. The Preferred Plan differs from the Benchmark Plan in that only capacity blocks with the resource attributes are identified, as opposed to the Benchmark Plan where specific resources were selected as proxies for the analysis. The development of the Preferred Plan also incorporates the constraints that were not able to be modeled in the Strategist model, and identifies if any waivers to the competitive bidding process need to be requested.

Docket No. 2007-0084 9-1 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

9.1.1 Preferred Plan Development from the Benchmark Plan

Figure 9.1-1 Preferred Plan (2009-2028)

Preferred Plan (2009-2028) ( 109 MW) ( 156 MW) Demand-Side Management (including SWAC)

( 30 MW) ( 140 MW) Customer-sited Photovoltaics ( 1 MW) ( 1 MW) Customer-owned Distributed Generation/Combined Heat & Power ( 8 MW) ( 8 MW) Utility Dispatchable Distributed Generation

CT 113 MW Biofuel

RE 100 MW Firm

ER Waiau 3 Emergency Reserve

RE 50 MW Firm

ER Waiau 4 Emergency Reserve

797 MW HECO BT BC Biofuel Conversion Kahe 3 Biofuel RE 35 MW Non-Firm RE 100 MW Firm Testing Explore Placing an Additional RE 100 MW Non-Firm ER HECO Unit on Emergency Reserve

RE 50 MW Firm 100 MW Firm RE

Explore Placing an Additional ER HECO Unit on Emergency Reserve

RE 16 MW C&C Waste-to-Energy

RE 50-125 MW Non-Firm Emerging Technology (such as OTEC)

09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 Action Plan

Docket No. 2007-0084 9-2 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

The differences between the Preferred Plan and the Benchmark Plan are (1) the nominal 110 MW firm renewable energy generation in 2011 is now a 113 MW biofueled CT, and (2) the 160 MW of wind power in 2012 in the Benchmark Plan and is replaced with the following capacity blocks: • 50 MW of non-firm capacity spanning the years 2011 through 2013 for emerging technologies (such as OTEC) to reflect the Sea Inc.(SeaSolar)40 25-100 MW and Lockheed-Martin Corp. OTEC projects. • 35 MW non-firm capacity in 2012 to reflect the Honua Technologies Inc.(Honua)40 6 MW waste-to-energy plant and First Wind Holdings Inc. (First Wind)40 30 MW wind power projects. • 100 MW non-firm capacity in 2013.

The specific resources in the IRP preferred plan are:

Demand-side Management – utility and third party programs resulting in 156 MW of reduction to the system peak load over the 20-year planning period using energy efficiency and load control measures including seawater air conditioning.

Customer-sited Photovoltaic – 140 MW of customer-sited photovoltaic systems is anticipated to be installed over the 20-year planning period. These photovoltaic systems could be net-metered or non-net-metered systems. The utility will also pursue a program to provide customers with a utility-facilitated third party-owned option.

Customer-owned Distributed Generation/Combined Heat and Power – 1 MW of Customer-owned DG/CHP generation is anticipated to be installed over the 20-year planning period. Activity in this area has slowed in recent years and is not expected to be significant in large part because of its reliance on high cost diesel fuel.

Utility Dispatchable Distributed Generation – 8 MW of utility dispatchable customer-owned DG over the 20-year period.

113 MW Biofuel Combustion Turbine in 2009 – This utility project is currently under construction in Campbell Industrial Park and is expected to be completed in 2009.

40 SeaSolar’s 25 to 100 MW OTEC facility, Honua’s 6 MW waste-to-energy facility, and First Wind’s 30 MW wind power facility are grandfathered projects and not subject to competitive bidding as specified in Decision and Order No. 23121. During the HECO IRP-4 Integration Analysis, the grandfathered projects were considered confidential and therefore not modeled in the Benchmark Plan. It wasn’t until the end of the Integration Analysis that HECO received permission from all three companies to discuss their projects, and there wasn’t sufficient time to re-run all of the analyses to explicitly model these specific projects.

Docket No. 2007-0084 9-3 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

100 MW Firm Renewable Energy Generation in 2011 and Waiau 3 Retirement or Emergency Reserve – Given HECO’s desire to accelerate the transition to using more renewable energy generation and the system’s current need for additional dispatchable firm capacity, HECO intends to submit a request for a waiver from competitive bidding in the fourth quarter of 2008 and plans to submit an application for approval to expend funds to install a second biofueled combustion turbine at CIP. Once the additional capacity is operational, HECO intends to take Waiau 3 generating unit off the HECO system and either retire Waiau 3 or place Waiau 3 into emergency reserve status.

50 MW Firm Renewable Energy Generation in 2014 and Waiau 4 Retirement or Emergency Reserve – This resource block is firm capacity needed to maintain the generation planning criteria and will also allow, once operational, the placement of Waiau 4 generating unit into a status similar to Waiau 3. Hawaiian Electric plans to acquire this block through a competitive bidding process. The proposal to meet this capacity might also be met by a Hawaiian Electric response to a military RFP for distributed generation, depending on the requirements of the military RFP and whether Hawaiian Electric’s response is the winning bid. In the case of the military RFP, it is anticipated that Hawaiian Electric would need to seek a waiver from competitive bidding in order to submit a bid to the military. In addition, Hawaiian Electric’s other options may be a combine-cycle conversion of a biofuel CT as the utility proposal in a competitive bidding process.

100 MW Non-firm Renewable Energy Generation in 2012-2014 – This resource block would be filled by the result of the renewable energy RFP currently being conducted by Hawaiian Electric, which includes a process for evaluating non- conforming proposals, if any.

35 MW Non-firm Renewable Energy Generation in 2012 - 2014 – This resource block is anticipated to be filled by a waste-to-energy project by Honua and a wind project in Kahuku by First Wind. Both projects are “grandfathered” from the PUC’s competitive bidding requirement.

50 MW Firm Renewable Energy Generation in 2017 – This resource block is firm capacity needed to serve future load growth and the capacity will be acquired through a competitive bidding process.

Boiler Biofuel Assessment and Conversion of Existing Steam Generating Units – This represents the testing of boiler biofuel in Kahe 3 generating unit, and if successful, the co-firing or conversion of all baseload generating units (Kahe units 1 through 6, Waiau 7 and 8) to boiler biofuel. Currently, Hawaiian Electric’s other units that use low sulfur fuel oil are not candidates for co-firing or conversion due to their lower system energy contribution compared to the anticipated conversion cost. The conversion of 797 MW of Hawaiian Electric-

Docket No. 2007-0084 9-4 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

owned generation represents a conversion of 66% of the Hawaiian Electric- owned generating capacity to boiler biofuel.

16 MW Waste-To-Energy Generation – This is a placeholder for future action by the City and County of Honolulu on increasing its municipal solid waste handling capability. The timing and implementation of such a resource is inherently dependent on the City and County’s actions to meet its waste disposal needs, therefore a waiver from the competitive bidding process may be appropriate and such a waiver may be requested when plans for the waste-to-energy facility are more definite.

50 - 125 MW Non-firm Emerging Renewable Energy Technology – This resource block is anticipated to be met by emerging technologies such as the ocean thermal energy conversion (OTEC) project proposed by SeaSolar Power International which is “grandfathered” from competitive bidding, the OTEC project proposed by Lockheed, or by any emerging technology that may come forward.

100 MW Firm Renewable Energy Generation in 2021 and 2027 – These resource blocks are needed to serve future load growth and is planned to be procured through competitive bidding.

Explore Additional Units in Emergency Reserve Status in 2021 and 2027 – The addition of firm capacity in 2021 and 2027 would allow, once they are operational, the consideration of placing additional existing fossil-fuel generating units into emergency reserve status similar to Waiau 3 and 4.

9.2 Competitive Bidding Strategy

The decision to proceed with acquiring generation resources either through competitive bidding or through a waiver is made in accordance with the Public Utilities Commission’s Framework for Competitive Bidding (“Framework”). The Framework states, in part that, competitive bidding, unless the Commission finds it to be unsuitable, is established as the required mechanism for acquiring a future generation resource or a block of generation resources, whether or not such resource has been identified in a utility's IRP. The Framework provides for the following conditions and possible exceptions:

Competitive bidding will benefit Hawaii when it: • facilitates an electric utility's acquisition of supply-side resources in a cost- effective and systematic manner; • offers a means by which to acquire new generating resources that are overall lower in cost or better performing than the utility could otherwise achieve; • does not negatively impact the reliability or unduly encumber the operation or maintenance of Hawaii's unique island electric systems;

Docket No. 2007-0084 9-5 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

• promotes electric utility system reliability by facilitating the timely acquisition of needed generation resources and allowing the utility to adjust to changes in circumstances; and • is consistent with IRP objectives.

Under certain circumstances, to be considered by the Commission in the context of an electric utility's request for waiver, competitive bidding may not be appropriate. These circumstances include: • when competitive bidding will unduly hinder the ability to add needed generation in a timely fashion; • when the utility and its customers will benefit more if the generation resource is owned by the utility rather than by a third-party (for example, when reliability will be jeopardized by the utilization of a third-party resource); • when more cost-effective or better performing generation resources are more likely to be acquired more efficiently through different procurement processes; or • when competitive bidding will impede or create a disincentive for the achievement of IRP goals, renewable energy portfolio standards or other government objectives and policies, or conflict with requirements of other controlling laws, rules, or regulations.

Other circumstances that could qualify for a waiver include: (i) the expansion or repowering of existing utility generating units; (ii) the acquisition of near-term power supplies 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; and (iv) the acquisition of power supplies needed to respond to an emergency situation.

The Commission also has the authority to waive the Framework or any part thereof upon a showing that the waiver will likely result in a lower cost supply of electricity to the utility's general body of ratepayers, increase the reliable supply of electricity to the utility's general body of ratepayers, or is otherwise in the public interest.

When a competitive bidding process will be used to acquire a future generation resource or a block of generation resources, the generating units acquired under a competitive bidding process must meet the needs of the utility in terms of the reliability of the generating unit, the characteristics of the generating unit required by the utility, and the control the utility needs to exercise over operation and maintenance in order to reasonably address system integration and safety concerns.

The Framework for Competitive Bidding requires that “an electric utility’s IRP shall specify the proposed scope of the RFP for any specific generation resource or block of resources that the IRP states will be subject to competitive bidding.” (See Section II.B.1 of the Framework for Competitive Bidding.) Following are the proposed scopes of the

Docket No. 2007-0084 9-6 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

RFPs for the resources identified in the Preferred Plan to be acquired via competitive bidding:

Nominal 50 MW Firm Capacity Resources in 2014 and 2017 – The IRP-4 Plan calls for a 50 MW Firm Capacity addition in 2014 and 2017. The competitive bidding efforts for these increments of capacity would be expected to begin in the 2009 and 2012 timeframes respectively. While the specific attributes for these resources are still under consideration, a high level list of potential characteristics for this resource are provided at this time. The specific attributes resulting from this high level list, and any others that may develop, are expected to be further refined as the RFP is developed. This list of potential characteristics include the following: renewable fueled or primarily fueled by a renewable resource; capable of cycling duty, capable of being fully dispatchable from minimum to full load by the utility, capable of load following, providing frequency and voltage support according to standards determined by the utility. Quick-starting capability, high ramp rate capability, and ability to provide spinning reserve and perhaps other related attributes may be desired in order to help accommodate future intermittent, as-available renewable resources that may be determined through the technical study efforts of the Hawaii Clean Energy Initiative. Depending on the location of the resource, black start capability may be called for. As previously indicated, detailed specifications for this resource will be developed at the time the RFP is developed.

Nominal 100 MW Firm Renewable Energy Resources in the 2021 and 2027 Timeframe – The IRP-4 Plan identifies a 100 MW Firm Capacity addition in 2021 and 2027. The competitive bidding efforts for these increments of capacity would be expected to begin approximately 5 years in advance of these dates. While the specific attributes for this resource are still under consideration, a high level list of potential characteristics for this resource are provided at this time. The specific attributes resulting from this high level list, and any others that may develop, are expected to be further refined as the RFP is developed. This list of potential characteristics include the following: renewable fueled or primarily fueled by a renewable resource; capable of cycling duty, capable of being fully dispatchable from minimum to full load by the utility, capable of load following, providing frequency and voltage support according to standards determined by the utility. Quick-starting capability, high ramp rate capability, and ability to provide spinning reserve and perhaps other related attributes may be desired in order to help accommodate future intermittent, as-available renewable resources that may be determined through the technical study efforts of the Hawaii Clean Energy Initiative. Depending on the location of the resource, black start capability may be called for. As previously indicated, detailed specifications for this resource will be developed at the time the RFP is developed.

Docket No. 2007-0084 9-7 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

9.3 Forthcoming Waiver Request for Renewable Firm Capacity in 2011

A nominal 100 MW firm renewable energy resource is required in the 2011 timeframe in order to (1) permit the HECO system to more effectively integrate increasing levels of intermittent and variable renewable generation resources (such as wind energy and photovoltaics) thereby enabling HECO to meet and ideally exceed its RPS goals, (2) allow HECO to replace a 46 MW fossil-fueled generating unit with a renewable resource generating unit, and (3) enable HECO to deliver on its fundamental “obligation to serve” by maintaining an appropriate and responsible level of firm generating capacity on Oahu. The HECO system is operating with a shortfall in its firm capacity reserves as explained below and a shortfall is expected to continue even assuming full success in acquiring the projected peak demand reduction benefits of the DSM and load management programs, and after the 2009 commercial operation of the new 113 MW simple-cycle combustion turbine (“CIP CT-1”) at Campbell Industrial Park (“CIP”),41 which is presently under construction. Given HECO’s desire to accelerate the transition to using more renewable resource generation and the current need for additional dispatchable firm capacity, the resource that is best able to meet the system needs in a reasonable time-frame is an additional biofueled combustion turbine. HECO has a unique, but time-limited opportunity to install a fuel-flexible simple-cycle combustion turbine to meet these needs. Since HECO has already obtained the necessary major permits (such as the air permit) for an additional combustion turbine at its CIP site and an Environmental Impact Statement that includes an additional combustion turbine has already been accepted with a finding of no significant impact, HECO has identified the next nominal 100 MW firm renewable energy resource as a 113 MW biofueled combustion turbine to be located at CIP. HECO anticipates that a second combustion turbine can be in service at CIP (“CIP CT-2”) as soon as 2011, but more likely in the 2012 timeframe. The energy future of Hawaii has changed to emphasize renewable energy. HECO is ready to meet its “obligation to serve” with CIP CT-2, a renewable resource firm capacity project.

9.3.1 Overview

HECO has a responsibility to facilitate the sustainable renewable energy future of Hawaii. For HECO, this future is characterized by increased use of renewable resources, increased energy efficiency, load management and demand response programs, and a reduction in the use of fossil-fueled resources. HECO plans to make this migration while maintaining the levels of reliability that customers have come to expect and deserve. Simultaneously achieving the objectives of increasing the use of renewable energy resources and maintaining an appropriate level of reliability sounds straight-forward, but the ability to integrate new renewable resources, decrease Hawaii’s

41 CIP CT-1 was approved in Docket No. 05-0145.

Docket No. 2007-0084 9-8 September 2008 HECO IRP-4 Chapter 9: Preferred Plan

dependence on fossil-fueled resources while dispatching generating resources “on demand” to adjust for rapidly occurring imbalances between energy supply and demand is a significant task. It is a challenge that HECO is preparing to and will meet; the goal of which will result in meeting the customers’ needs for energy while maintaining system reliability.42

It is important to note that the ability to advance the placement of renewable energy on HECO’s system is due largely in part to the relatively new use of biofuels in electric generating equipment. The use of biofuels advances renewable energy in two significant ways. First, it allows for the placement of additional intermittent and variable renewable energy resources on HECO’s system while preserving the attributes necessary for system reliability, including load following, frequency response, voltage control and on-line operating and spinning reserves. Second, the feasibility of biofuels, such as biodiesel, offers a migration path which reduces dependence on fossil-fuels by allowing the replacement of fossil fuel units with biofueled units and through fuel switching in current fossil-fueled units.

Firm, dispatchable biofueled generating units, particularly those that can be placed in service in a matter of minutes (rather than hours) and those that have high ramp rate capability, facilitate the placement of non-firm renewable energy or as-available energy (such as wind and photovoltaics) on the system. By and large, energy from renewable resources on Oahu, with the exception of H-POWER which provides firm capacity, may not be available when needed due the vagaries of nature (i.e., the wind may not blow or the may not shine). Thus, in order to ensure that the lights go on when our customers turn on a light switch, there needs to be a reliable source of firm capacity always available for dispatch. The very nature of biofueled combustion turbine generating units provides a firm and flexible source of renewable energy backup capacity that can easily and quickly be started during the periods when potential non- firm renewable generation is not available.

HECO has investigated the use of biofuels in combustion turbines, and plans to deploy this technology with CIP CT-1. Over time, HECO plans on converting its existing baseload steam units to run on biofuels and on placing existing older, cycling steam units (which may be more difficult to convert to run on biofuels) on emergency reserve status, thus allowing residual-oil-fired generation to be replaced by renewable energy

42 If HECO does not have a sufficient amount of firm and dispatchable electric generating capability on Oahu to account for contingencies such as generating unit failures or demand for electricity being greater than forecast, then HECO will not be able to provide electric service to some or all of HECO’s customers should such contingencies occur. While HECO cannot guarantee an absolute, uninterrupted level of electrical service (that type of reliability would require layers of redundancy in all aspects of HECO’s system at an inordinate cost), HECO can provide a reasonable level of generating system reliability for its customers if allowed an adequate amount of firm capacity reserves on HECO’s system.

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biofueled generation. The pace at which this plant conversion and plant replacement strategy can occur will be facilitated by the experience to be gained from the operation of new biofueled generating units such as CIP CT-1 and CIP CT-2. The pace will also depend upon the results of the biofuel testing to be conducted on Kahe Unit 3 in 2009.

Currently, HECO plans on placing Waiau Unit 3 on emergency reserve status or retiring the unit after the planned biofuel-fired CIP CT-2 is placed into service and is providing dispatchable firm capacity to the system. With the removal of Waiau Unit 3 from active service, the need for additional firm capacity advances to the 2014 timeframe. HECO plans to issue a Request for Proposal to acquire that capacity. (See Section 10.3.7.) Thus, the installation of a biofueled combustion turbine will provide sufficient new firm generating capacity and dispatchable fast ramping cycling power on the system to enable HECO to begin removing certain existing fossil-fueled generating capacity from the system and provide needed firm generation flexibility in its place to accommodate expected variable renewable generation (such as wind and photovoltaics) added to HECO’s system in the near future.

9.3.2 Need for Additional Renewable Firm Capacity Following CIP CT-1 in 2009

As a result of evaluations performed during the IRP-4 process, HECO is planning on installing at CIP another nominal 113 MW biofueled combustion turbine generating unit (i.e., CIP CT-2). CIP CT-2 will help HECO meet several objectives and goals, including but not limited to, encouraging additional intermittent and variable renewable energy resources, reducing the amount of fossil fuel used to generate energy, promoting the use of biofuels and meeting its customers’ needs for reliable electric service.

9.3.3 CIP CT-2 will Support Additional Intermittent and Variable Renewable Energy Generation on HECO’s System

First and foremost, as a public utility, HECO has an obligation to serve its customers. Having sufficient reliable generation is essential in meeting that obligation. Intermittent and variable renewable energy generation such as wind may not be able to provide HECO with energy when HECO’s customers really need it. However, making sure that HECO’s obligation is met does not in any way mean that HECO is not pursuing renewable energy resources. HECO will rely on a portfolio of renewable resources, many of which produce energy on an “as-available” basis (e.g. when the wind blows and the sun shines). However, the utility must meet customer demand for power at all times regardless of whether or not the as-available sources can instantaneously produce it. While HECO contemplates that tools such as wind forecasting will improve in the future, this improved accuracy in the forecast of as-available resource output will be of value only if HECO has the ability to respond to the forecast by deploying firm, dispatchable renewable generation alternatives. Without the ability to adequately respond, a forecast for low winds may merely be a forecast for impending customer load shedding.

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Therefore, to complement the future as-available resources, HECO needs firm, dispatchable renewable generation with quick-starting and high ramp rate capability that can be reliably called upon when needed. More specifically, CIP CT-2 would provide a flexible source of backup capacity powered by renewable resources (biofuels) that can easily and quickly be started during the periods when potential non-firm renewable generation is not available, or is rapidly dropping off. Moreover, CIP CT-2 ramp rates allow for rapid increases or decreases in MW output to compensate for decreases or increases in MW output from as-available intermittent generation.

CIP CT-2 cycling ability will also not impede the acceptance as-available renewable energy in low-load hours. HECO’s load varies on an hourly basis, where the MW demand at, for example, 3 or 4 am in the morning may be roughly half of the MW demand during the peak demand hours for that day. HECO already has a core fleet of utility and IPP generating units that are baseloaded and as presently configured, cannot be turned off during this low load period. Adding to the list of baseload units would reduce the amount of intermittent renewable generation that can be accepted during low load periods, and therefore, HECO desires generation that can be cycled with regularity. CIP CT-2 will be a firm, renewable resource that is designed with this cycling capability.

9.3.4 CIP CT-2 will Reduce Fossil Fuel Consumption by Allowing Waiau 3 to be Taken Off-line

As explained in further detail in section 7.4, CIP CT-2 will allow Waiau 3 to be taken out of service. From time to time in the normal course of planning, HECO evaluates the feasibility of retiring existing generating units and replacing them with new generating units. This evaluation also includes examining at a high level the alternative of placing older, less efficient generating units on emergency reserve status43 as part of IRP-4 integration analysis rather than assuming the finality of retirement. After consideration of factors such as the age, condition, reliability, and operating cost of Waiau 3, as well as the desire to reduce fossil fuel generation and help facilitate the integration of as- available renewable generation onto the grid, HECO determined that the 46 MW-net capacity of Waiau 3 (which is the oldest unit on the HECO system at 61 years old and which may be difficult to biofuel) should be placed on emergency reserve status or retired after CIP CT-2 has been placed into service. The installation of CIP CT-2 will provide sufficient firm, dispatchable renewable generating capacity on the system to

43 A generating unit placed on emergency reserve status is out taken of the daily operation of HECO’s system and preserved for an extended period of time. However, since it may take a month or more to bring back a generating unit from emergency reserve status, a unit on emergency reserve status would be beneficial in dealing with a long term unforeseen emergency such as the catastrophic failure of another unit. Until a reactivation, for all practical purposes, a unit on emergency reserve status is unavailable to HECO’s system. Retirement of a generating unit will not provide for reactivation if needed. A retired unit is permanently unavailable to HECO’s system.

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enable HECO to remove the existing fossil-fueled Waiau 3 generating unit from the system in the shortest time possible.

9.3.5 CIP CT-2 will Provide Needed Reserve Capacity

On January 30, 2008, HECO filed its 2008 Adequacy of Supply (“AOS”) filing, which evaluated HECO’s reserve capacity using a Reference Scenario44 and alternative scenarios. Through this analysis, HECO determined that there is an immediate need on HECO’s electrical system for the firm generating capacity provided by CIP CT-2. HECO does not have enough reserve capacity to assure its customers that they all will still have reliable electric service (in accordance with its generating system reliability guideline) if one or more generating units are unexpectedly forced out of service, or actual demand exceeds the forecasted demand.45 HECO has an existing need for additional generating capacity now to meet HECO’s generating system reliability standard and in the near future to meet the forecasted customer demand. The 2008 AOS concluded that HECO would have a reserve capacity shortfall46 in the range of 30 to 90 MW in 2011, up to a range of 70 MW to 130 MW in 2014, if CIP CT-1 is installed in mid-2009. Following the 2008 AOS filing, a new load forecast was produced and analyzed. While the March 2008 Short Term Sales & Peak forecast has shown continued lower peaks than those of previous forecasts, based in part on actual declining peak demand in recent years, it does not eliminate the risks illustrated by the plausible scenarios in the sensitivity analysis. Moreover, it is important to note that HECO has no assurances that the peaks

44 The 2008 AOS Reference Scenario was calculated using a computer-based simulation model for each year through 2014 under a reference set of assumptions, including: (1) continued acquisition of residential and commercial load management impacts, including modifications to these programs to add residential air-conditioning load control and commercial and industrial demand load response elements; (2) implementation of HECO’s Interim DSM Proposals in July 2006 and its enhanced energy efficiency DSM programs beginning in mid-2007, (3) the inclusion of approximately 29.5 MW of temporary, HECO-sited distributed generation through 2009 (reflecting installations in 2005, 2006, and 2007), and (4) the addition of the CIP simple-cycle combustion turbine in July 2009. Starting in January 2010, the Reference Scenario analysis does not include capacity from the temporary distributed generation units at HECO sites after the CIP combustion turbine is added in mid-2009. This was done to more accurately reflect the true reserve capacity situation at this time, without considering contributions from temporary mitigation measures such as the distributed generators. The distributed generation units could be left in service beyond 2009, but they were not designed as long- term generating resources. 45 Unlike most other utilities on the mainland, HECO does not have access to an energy market that can be the power provider of last resort. When supply is unable to meet demand, load will be shed until balance is restored. HECO is continuing to pursue demand response program which provide incentives to select customers for curtailing load, but it is anticipated that load will continue to grow over time, even with existing and future demand response participants. 46 “Reserve capacity shortfall” is the amount of additional firm generating capacity needed to restore the generating system Loss of Load Probability to greater than the 4.5 years per day reliability guideline. For example, the number “-50” would indicate that 50 MW of firm generating capacity would have to be added, in order for the expectation of not being able to satisfy demand due to insufficient generation to occur no more than once every 4.5 years.

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estimated in the sales and peak forecasts will occur precisely as anticipated. For example, forecast peaks are derived on a weather normalized basis, whereas actual demand for electricity is highly influenced by weather conditions experienced over relatively short periods of time. Dry bulb and wet bulb temperatures (as measured by cooling degree days and relative humidity) can significantly impact the electricity demand for electric powered cooling equipment such as air conditioning and refrigeration. Thus, actual weather conditions in a future year may be a significant driver of any difference between actual peak experienced and forecast peak demand. HECO’s generation system must be capable of serving the actual peak, the actual weather conditions encountered in any given year, no matter how unusual the weather.

In general, planning assumptions for periods beyond one or two years into the future are less certain, but these are precisely the timeframes that HECO must analyze as it contemplates adding new sources of firm generation.47 A typical method for dealing with this inherent uncertainty is to perform multiple scenarios with differing assumptions. The utility can then evaluate the sensitivity of results to a range of input assumptions. This scenario approach is what HECO did for its 2005, 2006, 2007, and 2008 AOS filings, and generally, HECO finds that there are many scenarios which put reliability at risk if HECO stops adding firm generation after CIP CT-1. HECO’s efforts are focused to stay “ahead of the game” by installing sufficient firm, dispatchable renewable energy generation based on a range of plausible futures.

Uncertainty in EE DSM transition to 3rd party administration

There are uncertainties in long-term projections for energy-efficiency that are administered by the company. This uncertainty is magnified when a third-party administrator takes control of the energy efficiency DSM programs. For example, there could be unanticipated delays in establishing administrative policies and procedures, hiring staff, developing the programs, and marketing the programs to customers. These delays could translate into load reductions that are lower than forecast. Currently, HECO has one of the most successful energy efficiency DSM programs in the nation. A seamless administrative transition which maintains such a high level of performance is a worthy objective, but it is also prudent to analyze the risks associated with reduced DSM impacts in the near-term. Lower than anticipated DSM impacts will result in higher utility loads, and higher utility loads in turn drive the need for firm generation.

Utility loads can change faster than the utility’s ability to respond, due to the time lags needed to install new generation.

47 Planning assumptions are inherently uncertain, which means that there is always a risk of being wrong when decisions are based on forecasts with limited accuracy. On the other hand, failing to execute a plan until perfect clarity is reached is not “planning,” it is “reacting.” With the significant lead time involved in the addition of new firm capacity resources, a reactive mode to resource additions is undesirable.

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For the 2008 AOS, HECO assessed a scenario where organic load growth is higher than forecast, and/or peak reductions from energy efficiency DSM and load management DSM are less than anticipated. The alternative Higher Load Scenario uses a very simple assumption: adjusted peaks are higher by 60 MW in comparison to the Reference Scenario. Such a scenario is possible, for example, if (1) customer acceptance and/or awareness is less than expected in the case of the load management DSM programs, or HECO’s enhanced energy efficiency DSM programs; (2) electricity use is higher than that projected by the August 2007 Sales and Peak forecast; or (3) a combination of these factors occurs to some degree in the future. In this scenario, the reserve capacity shortfall ranged between 90 MW in 2011 to 130 MW in 2014.

If loads turn out to be lower than anticipated, system reliability is not adversely affected. The resulting increase in reserve capacity does not hinder HECO’s ability to keep the lights on, even if the downward trend occurs rapidly. On the other hand, when loads turn out to be higher than anticipated, reliability can be affected if the upward trend occurs over a short period of time. For example, obtaining an air permit for a new generating unit can be a critical path item that takes years to complete, including the approval process. While HECO can work to expedite long-lead items, there are limitations to what can practically be accomplished. In the meantime, a reserve capacity shortfall will persist, putting the system at risk for outages.

Potential for extended outages

In addition to scenarios with differing system loads, HECO analyzed the sensitivity to an additional two-month outage of a 90 MW unit, as a proxy for real-life, unplanned outages that have occurred in the past, and may occur again in the future. For example, HECO Waiau Unit 8 experienced a forced outage in October 2005 due to a feedwater heater failure that also damaged the turbine. Forced outage repairs were completed in February 2006. Forward-looking EFOR assessments and planned maintenance schedules do not fully capture this type of unplanned, prolonged unavailability, and therefore it is prudent to evaluate this scenario. The two-month 90 MW Outage Scenario appears to add approximately 10-30 MW to the reserve capacity shortfall. The moderate increase in reserve capacity shortfall is a function of when (in the year) the 90 MW is unavailable. HECO elected to perform this sensitivity using neither the “best” nor “worst” time of the year to make the 90 MW unavailable. In a real life situation, however, it is not likely that HECO will have control over when an extended-duration outage of a HECO or IPP unit occurs, and therefore, the analytical results of this scenario should not be misinterpreted as the “typical” impact on system reliability.

HECO also used either Kahe 3 or Kahe 4 as the proxy unit, simulating an additional period of unavailability lasting two months, beginning in June of each year. Either Kahe 3 or Kahe 4 was selected because these units are neither the largest nor smallest MW units on the system, but something in between that effectively represents many units on

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the system and the most numerous size class of baseload generation. Similarly, the June through July timeframe was selected because it is a period of “middle-of-the-road” system demand. This period is neither the worst time for a unit to be unavailable, nor the best. The result of this scenario is that HECO may not be able to serve all of its customers without having CIP CT-2.

Historical Year EFOR Sensitivity

For the 2008 AOS, HECO performed a sensitivity analysis assuming a 2004 EFOR for HECO generating units, to assess what the reserve capacity shortfall might look like if HECO were to experience EFOR which were the same as a year in the recent past. HECO did not select the “worst case” results, as use of 2005 EFOR data in the sensitivity analysis would have likely produced an even higher reserve capacity shortfall. Instead, HECO selected the moderately higher actual EFOR experienced in 2004 as a proxy for future years. Evaluation of this scenario is important, as the application of a multi-year “average” of unit EFOR data (the methodology used to determine the Forward-looking EFOR assumption used in the Reference Scenario) can mask the peaks and valleys of individual unit EFOR which occur in real-life. This scenario increases the reserve capacity shortfall in the range of 10-20 MW.

Sensitivity Analysis using March 2008 Short Term Sales & Peak Update

The 2008 AOS used a load assumption that was based on an August 2007 sales & peak update, overlaid with updated estimates for DSM and Load Management. Subsequent to the filing of the 2008 AOS on January 30, 2008, HECO developed a March 2008 Short Term Sales & Peak forecast with moderately lower peaks. HECO performed two additional sensitivity analyses to determine how the reserve capacity shortfall would be affected by the change in forecasted system peaks.

The first sensitivity analysis used the March 2008 Short Term Sales & Peak forecast in place of the 2008 AOS Sales & Peak forecast in the Reference Scenario. As expected, the reserve capacity shortfall results are less severe than calculated in the 2008 AOS Reference Scenario. However, the reserve capacity shortfall does persist, and ranges between 0 MW to 50MW in the years 2011 to 2014.

The second sensitivity analysis used the March 2008 Short Term Sales & Peak forecast along with the two-month 90 MW outage scenario described in the 2008 AOS. The purpose of performing this scenario was to understand how factors that reduce the reserve capacity shortfall (such as lower peaks) can be offset by factors that increase the reserve capacity shortfall (such as an extended-duration outage). In this scenario, the reserve capacity shortfall ranged between 20 MW in 2011 to 80 MW in 2014.

In sum, while the March 2008 Short Term Sales & Peak forecast expands the range of possible energy futures, it does not eliminate the risks illustrated by the plausible

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scenarios in the sensitivity analysis. The reserve capacity shortfall results for selected scenarios from the 2008 AOS, as well as the two sensitivity scenarios based on the March 2008 Short Term Sales & Peak forecast ranges between 0 MW to 90 MW in 2011, and between 50 MW to 130MW in 2014.

Prudent to proceed, although uncertainty in the planning assumptions exist

The results of the sensitivity analysis indicate that even with forecasted lower loads to be served, the addition of CIP CT-1 alone is not enough to eliminate the reserve capacity shortfall. In large part, this is due to the magnitude of the reserve capacity shortfall prior to the installation of CIP CT-1. The installation of CIP CT-1 does add approximately 110 MW of firm capacity, but it does NOT provide a cushion of 110 MW. Rather, this increment of capacity addresses an existing deficit and cannot cover the range of potential futures that HECO may face in the years that follow. Mitigation measures such as temporary HECO-sited DG have been used to cope with the existing deficit, but they have not been designed and implemented as long-term supply-side solutions. Further, HECO’s ability to install DG at additional company sites is limited, primarily due to technical, zoning, and space considerations.

A longer-term solution which increases the amount of renewable generation is to couple the installation of a significant increment of biofueled generation with the placement of existing fossil-fueled generation on emergency reserve status or possible retirement. This is HECO’s approach for CIP CT-2, where LSFO-fired Waiau 3 will either be placed on emergency reserve or retired. This strategy will help to achieve HECO’s objective of more rapidly transitioning the system to a predominantly renewable energy future. Moreover, even after CIP CT-2 is installed, dispatchable firm capacity resources will still be needed in future years (for load growth and continued fossil-fueled plant replacement). Oahu’s system peaks may not increase each and every year, but over the long term, customers will likely continue to drive system peaks higher, on average. In time, more dispatchable firm capacity renewable generation after CIP CT-2 must be installed, both for load growth and to allow for a reduction in generation from fossil- fueled resources (e.g., in addition to placing Waiau 3 on emergency reserve or retiring the unit, Waiau 4 could also be placed on emergency reserve or retired after new, firm capacity renewable generation is installed in response to HECO’s planned request for proposal (“RFP”) seeking such resources in the 2014 timeframe).

9.3.6 CIP CT-2 is Consistent with HECO’s Portfolio Approach to Resource Planning

HECO’s approach to long-term energy planning is to employ a diverse portfolio of demand-side resources and renewable supply-side resources. HECO’s installation of CIP CT-2 is consistent with that goal. As the only electric utility on Oahu, HECO needs to create a reliable and effective power system. Having a full portfolio of renewable resources will enable HECO to reach that goal quicker and more effectively. For

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example, adding only as-available renewable energy such as wind, photovoltaics and the like to HECO’s system is not practical, detrimentally impacting HECO’s ability to meet its obligation to serve. However, by combining highly flexible and dispatchable firm capacity renewable generation in balance with as-available renewable generation, HECO can simultaneously meet customer needs while more rapidly progressing to a much more renewable energy future.

HECO’s pursuit of CIP CT-2 does not reduce the importance of the other portfolio elements. In fact, the sooner CIP CT-2 is placed in-service, the sooner HECO can more effectively integrate increasing levels of intermittent and variable renewable generation resources (such as wind and photovoltaic energy). For example, HECO is actively negotiating with three renewable developers on a “grandfathered” basis, in an effort to secure as-available renewable energy. The addition of CIP CT-2 will enable the effective and timely addition of these non-firm renewable generation resources to the HECO system. Moreover, HECO is conducting a 100 MW renewable energy RFP and the fundamental characteristics of the CIP CT-2 unit (e.g. quick-starting and fast ramping capabilities) will facilitate and balance the intermittent and variable output of renewable resources like wind and photovoltaic energy.

In essence, all of the renewable energy components will be working in concert to achieve HECO’s near-term and long-term objectives, and none are precluded by the installation of CIP CT-2. Indeed, as discussed below, HECO will be requesting a waiver from the Commission’s Framework for Competitive Bidding (“CB Framework”) for CIP CT-2 and if such waiver is obtained and the CIP CT-2 application is approved, HECO will be able to facilitate and absorb more as-available renewable energy in a quicker time frame than without the waiver.

9.3.7 A Waiver of Competitive Bidding is Needed to Expeditiously Achieve These Goals

HECO requires dispatchable firm capacity renewable generation of sufficient size to enable the effective addition of other intermittent and variable renewable generation resources (such as wind and photovoltaics) in the portfolio mix, to allow Waiau 3 to be placed on emergency reserve status or be retired, and to address the likelihood of a continuing reserve capacity shortfall. In order to expeditiously implement CIP CT-2 to help HECO meet these objectives, including but not limited to, reducing the amount of fossil fuel run generation, promoting the use of biofuels and meeting its customers’ need for reliable electric service, HECO will be requesting a waiver from the Commission’s CB Framework in order to expedite the in-service date of this unit to meet as soon as practicable the aforementioned objectives and secure the public interest benefits that this generation resource brings to all Oahu customers. This request will be presented in more detail in a separate application to be filed in the fourth quarter of 2008. A brief overview of some of the reasons that a waiver is necessary is discussed below.

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HECO is currently in the process of procuring non-firm, renewable generation from a competitive bidding process. As described during the course of the competitive bidding docket, the time and resources needed to conduct a bidding process are significant, and HECO now has firsthand experience in the effort required. An outside consultant has been used to provide guidance, and an independent observer has been contracted to oversee the process. HECO believes there is limited opportunity to significantly expedite the process with additional internal or external resources, and that a minimum of 23 months would elapse between release of the draft RFP and submittal of the project(s) PUC application. Moreover, this timeframe does not even include the time needed to retain the services of an independent observer and obtain PUC approval of the contract for services, prepare the draft RFP and model contract documents, the time needed for the PUC to approve the project(s) application, or the construction time needed to build the final project. In addition, eligible projects would need to have critical permits (such as proper zoning and air permit), as well as other potential requirements such as an approved Environmental Impact Statement (“EIS”), in hand or in progress. These prerequisites can take years to develop and acquire, and preclude alternatives which are targeted for service in the 2011 to 2012 timeframe.

As will be explained in further detail in the application for waiver, there is a unique, but time-limited opportunity for HECO to accelerate and secure the acquisition of another renewable fuel combustion turbine unit. Obtaining a waiver for CIP CT- 2 at this time will allow HECO to proceed with an application for CIP CT-2. HECO would want PUC approval before committing to purchase CIP CT-2. The option to purchase CIP CT-2 under the existing Siemens’ contract for CIP CT-1 expires June 1, 2010. If HECO exercises its right for CIP CT-2 prior to June 2010, the contract calls for Siemens to deliver the combustion turbine unit (“CT”) within 22 months of the notice to proceed. As HECO understands from Siemens, Siemens will honor their contract with HECO but is otherwise removing this CT model from their standard combustion turbine production line. Accordingly, after the option period expires, it is unlikely that HECO will be able to obtain this CT model. The consequences of not being able to obtain this CT model are, among other things, that the air permit would need to be modified (likely to be a lengthy process), the site has been laid out for this type of unit and a different unit may pose additional complications, and the in-service date for the new unit would likely be significantly extended.

There are numerous other advantages from a timing perspective, such as the CIP CT-2 site has been designated as a generating facility on the Public Infrastructure Map Amendment and has an approved EIS which accommodates the addition of a second CT. No additional properties or easements are required. From a land use and EIS perspective, the CIP site is unlike any other site in that a new generating unit such as CIP CT-2 can be accommodated in the timeframes required. These elements are a key

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factor in HECO’s decision to seek a waiver, rather than pursue a bidding process with projects that could not offer these advantages to the project schedule.

Moreover, there are a number of additional factors which would allow HECO to install CIP CT-2 sooner than anyone else. For example, HECO already has a site for the CIP CT-2. Existing fuel infrastructure, communication facilities, water treatment and storage facilities and central control/administration building at CIP will facilitate the installation of CIP CT-2 (e.g., in comparison to development of a greenfield site). Additional transmission line and other related system infrastructure is being installed as a part of the CIP CT-1 project, and aside from unit interconnection, no significant transmission infrastructure is required with the installation of CIP CT-2. In addition, HECO has already accomplished two major milestones in obtaining the approval of an air permit and an EIS that includes CIP CT-2.

In sum, the installation of dispatchable firm renewable generating capacity via CIP CT-2 offers unique scheduling advantages that are not available through other options (e.g., such as development of a military site). As a result, HECO has the ability to install CIP CT-2 as soon as 2011, but more likely in the 2012 timeframe.

9.4 Other Potential Waiver Requests

9.4.1 Waiver for Lockheed OTEC

The 50 to 125 MW block of emerging renewable energy technology in the IRP Preferred Plan could be partially met by an OTEC project in which Lockheed-Martin is currently performing initial testing of the technology. These tests and their results will not be available in time for Lockheed to respond to HECO’s 100 MW RE RFP. Therefore, although HECO is not seeking a waiver from competitive bidding for this block of generation at this time, a waiver may be requested at a future date depending on the results of Lockheed’s testing and the specifics of a project that may be ultimately proposed. Such an OTEC project could increase the reliable supply of electricity and promote the development of cost-effective renewable energy. HECO will determine whether to seek a waiver when details of the project become more definite.

9.4.2 Waiver for Military DG

The 50 MW firm renewable energy generation in 2014 could be partially met by a HECO response to a military RFP for distributed generation. The military has indicated the possibility of issuing an RFP for distributed generation at military installations state-wide (see section 7.2.4.3). Although HECO is not seeking a waiver from the competitive bidding process for this block of generation at this time, a waiver may be requested at a future date if the military issues such a RFP. In the event the military issues such a RFP and HECO desires to submit a proposal, HECO would presumably need to submit a binding proposal to install the DG project. A binding proposal from HECO will require

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HECO to have a waiver from the Commission’s competitive bidding process. It is envisioned that a request for waiver from competitive bidding for a military DG will delineate the basis for the waiver request, including the contribution to an increase in the reliable supply of electricity, the development of additional cost-effective renewable energy, and the benefit to all ratepayers of retaining this important electrical load on the HECO system.

9.5 Calculation of Future Avoided Cost

The utility should purchase renewable energy at prices that are increasingly de-linked from oil prices as the level of renewable generation increases and its inherent costs fall. Section 269-27.2(c), Hawaii Revised Statutes states:

“The commission’s determination of the just and reasonable rate shall be accomplished by establishing a methodology that removes or significantly reduces any linkage between the price of fossil fuels and the rate for the nonfossil fuel generated electricity to potentially enable utility customers to share in the benefits of fuel cost savings resulting from the use of nonfossil fuel generated electricity. As the commission deems appropriate, the just and reasonable rate for nonfossil fuel generated electricity supplied to the public utility by the producer may include mechanisms for reasonable and appropriate incremental adjustments, such as adjustments linked to consumer price indices for inflation or other acceptable adjustment mechanisms.” [emphasis added]

If pricing for renewable energy is linked to the price of oil, consumers will not receive the benefits of stable energy pricing or from reduced costs if the cost to produce the renewable energy is below the cost of producing an equivalent amount of energy using fossil fueled generation. As the level of renewable generation increases or as the inherent cost of producing renewable energy fall, the benefits of delinking renewable energy pricing from the price of oil become greater.

To avoid paying too much for renewable resources, the costs that are avoided by adding renewable resources to the system should be considered. Avoided costs have typically been determined using a resource-in/resource out methodology as described in Appendix B, “Avoided Cost Methodology,” of HECO’s Electric Utility System Cost Data report, filed with the Commission on June 30, 2006, in accordance with the Commission’s Rule 6-74-17. Avoided energy costs are typically calculated using a similar Non-Utility Generation (“NUG”)-in/NUG-out methodology as described in the Updated Stipulation to Resolve Proceeding, dated December 29, 2006, in Docket No. 7310, and approved by the Commission’s Decision and Order No. 24086, dated March 11, 2008.

To employ the resource-in/resource-out or NUG-in/NUG-out methodology, a base plan (alternatively called “reference” or “benchmark” plan), needs to be established. The base plan needs to identify parameters such as (1) specific timing and size (in MW) of

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each resource addition, (2) specific operating and maintenance characteristics, such as energy output profiles, efficiency profiles, and maintenance requirements, of each resource addition, and (3) specific installed costs and operating costs of each resource addition.

The Commission has recognized in other types of proceedings that IRP plans are dynamic and not fixed plans. For example, the resource plan used to compute avoided costs is not necessarily the utility’s approved IRP plan, but is its most current resource plan, which takes into account current circumstances such as those that are reflected in an IRP plan evaluation, or a biennial PURPA data filing. (See, e.g., Docket No. 97-0102, Decision and Order No. 16717 (November 25, 1998), page 7.) This is consistent with the approach taken in other jurisdictions. (See, e.g., Re Houston Lighting & Power Co., 158 P.U.R.4th 335, 340-41, 348 (Texas P.U.C. 1994).) [Ref: HELCO IRP-3, page 8-38]

The determination of avoided costs is case-specific. For example, HELCO’s IRP-3 analysis, based on the modeled costs for a resource, indicated that a geothermal resource in the 2022 timeframe is the cost-effective supply-side selection. For the purposes of determining avoided costs for renewable resources, the geothermal unit may be used as a “benchmark resource.” Under circumstances where use of this particular resource results in negative avoided energy costs for the renewable resource for which avoided costs are being determined, an alternative resource, such as a biofueled simple cycle combustion turbine, may be considered. [Ref: HELCO IRP-3, page 8-28, footnote 37]

In cases where the specific resource or characteristics of the resource are not known, a proxy unit, such as a combustion turbine may be used to represent the resource in the plan.

Avoided costs may also be determined from the costs the utility would incur if it installed a renewable resource itself.

One of the objectives in meeting consumer energy needs is to increase the proportion of renewable energy in meeting those needs, not to displace one type of renewable energy for another. If generating units utilize biofuels, those biofuel costs should be considered costs that cannot be avoided by energy generated by another renewable resource (e.g., wind or solar) that does not consume fuel.

Avoided costs may also be established through a competitive bidding process where the lowest bid may be considered the avoided cost, all other factors being equal.

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Docket No. 2007-0084 9-22 September 2008 HECO IRP-4 Chapter 10: Action Plan

10 ACTION PLAN

10.1 Demand-Side

10.1.1 Transition Energy Efficiency DSM Programs to Public Benefit Fund Administrator

HECO will continue to operate a broad and aggressive portfolio of DSM programs for up to six months after January 1, 2009, the projected initiation date of the third party administrator. (See PUC’s Order to Initiate the Collection of Funds for the Third Party Administrator of Energy Efficiency Programs in Docket 2007-0323 issued on July 2, 2008). Upon selection of the third-party administrator, HECO will work with the administrator to provide a smooth transition in which customers are continuously encouraged to pursue cost effective energy efficiency improvements. Furthermore, as more information becomes available regarding the transition to the third-party administrator, HECO will update its resource and action plans to reflect the transition at the next scheduled IRP-related reporting date.

HECO’s DSM resource portfolio includes seven energy efficiency and two demand response DSM programs and three pilot programs as outlined below:

HECO’s DSM energy efficiency programs: • Commercial and Industrial Energy Efficiency Program (“CIEE”) • Commercial and Industrial New Construction Program (“CINC”) • Commercial and Industrial Customized Rebate Program (“CICR”) • Energy Solutions for the Home (“ESH”) • Residential Efficient Water Heating Program (“REWH”) • Residential New Construction (“RNC”) • Residential Low Income (“RLI”)

HECO’s DSM demand response programs: • Commercial and Industrial Direct Load Control Program (“CIDLC”) • Residential Direct Load Control Program (“RDLC”)

HECO’s DSM pilot programs: • SolarSaver Pilot Program (“SSP”) • Residential Customer Energy Awareness Program (“RCEA”) • Dynamic Pricing Pilot (“DPP”)

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It also includes a Home Energy Audit Pilot, which has not yet been filed with the Commission.

In Order No. 23717, filed on October 12, 2007, the Commission opened Docket No. 2007-0341 instituting a proceeding to review HECO’s DSM reports and requests for program modifications, and ordered that such reports and requests be filed in the subject docket. HECO will continue to provide information to the Commission and interested parties on the progress and costs of the DSM programs in the subject docket.

Below is a summary of the estimated savings and expenditures over the Action Plan period. The cumulative load reduction and energy savings impacts resulting from HECO’s energy efficiency and demand response DSM programs for 2009-2013 are approximately 111 MW and 304,000 MWh, as shown in Table 10.1-1 and Table 10.1-2. A summary of the program expenditure schedule for 2009-2013 is shown in Table 10.1-3 below.

Table 10.1-1 Summary of Cumulative Peak Impacts (MW) of All DSM Programs (Not Reduced by Free Riders at the Gross System Level)

Year 2009 2010 2011 2012 2013 CIEE 3.4 6.9 10.3 13.8 17.2 CINC 1.4 2.9 4.3 5.7 7.2 CICR 1.6 3.3 4.9 6.6 8.2 ESH 2.5 4.5 6.0 7.5 9.0 REWH 0.9 1.7 2.6 3.5 4.3 RNC 1.1 2.2 3.4 4.5 5.6 RLI 0.6 1.2 1.8 2.4 3.0 RDLC 18.7 18.7 18.7 18.7 18.7 CIDLC 24.8 31.8 34.1 36.1 37.9 Total 55.0 73.2 86.1 98.8 111.1

Table 10.1-2 Summary of Cumulative Energy Savings (MWh) of All DSM Programs (Not Reduced by Free Riders at the Gross System Level)

Year 2009 2010 2011 2012 2013 CIEE 23,379 46,757 70,136 93,514 116,893 CINC 9,798 19,596 29,394 39,191 48,989 CICR 12,626 25,252 37,878 50,504 63,130 ESH 8,058 13,908 18,886 23,864 28,842 REWH 3,767 7,533 11,300 15,067 18,834 RNC 2,823 5,645 8,468 11,291 14,113 RLI 2,633 5,267 7,900 10,533 13,166 Total 63,084 123,958 183,962 243,964 303,967

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Table 10.1-3 Summary of Expenditure Schedule for All DSM Programs ($000)

Year 2009 2010 2011 2012 2013 CIEE 3,426 3,512 3,609 3,709 3,811 CINC 1,707 1,745 1,795 1,848 1,903 CICR 1,825 1,866 1,925 1,984 2,047 ESH 1,672 1,638 1,696 1,747 1,799 REWH 2,903 2,990 3,079 3,170 3,264 RNC 1,788 1,871 1,957 2,046 2,140 RLI 956 982 1,010 1,040 1,069 RDLC 1,813 1,822 1,869 1,915 1,962 CIDLC 4,136 3,791 4,142 4,388 4,596 Total 20,226 20,217 21,082 21,847 22,591 Elements of the DSM Action Plan:

HECO to continue to manage the seven energy efficiency programs (CIEE, CINC, CICR, ESH, REWH, RNC, RLI) for up to six months after January 1, 2009, the projected initiation date of the third party administrator.

HECO will work with the administrator to provide a smooth transition of the existing energy efficiency DSM programs in which customers are continuously encouraged to pursue cost effective energy efficiency improvements.

HECO to continue to implement the two demand response (RDLC, CIDLC) DSM programs.

File applications to extend the two demand response (RDLC, CIDLC) DSM programs beyond December 2009.

HECO will evaluate other technologies to target for load control within the RDLC program.

HECO will evaluate the technical and cost benefits of using an Advanced Metering Infrastructure to facilitate load management programs as described in Section 10.1.2 below.

Continue to implement the SolarSaver Pilot (SSP) program. Based on the results of evaluation studies, HECO may file an application to extend the program beyond June 30, 2010, which is the expiration of the current pilot program period.

Continue to aggressively promote energy awareness and education among the residential customers through the Residential Customer Energy Awareness (RCEA) program.

Docket No. 2007-0084 10-3 September 2008 HECO IRP-4 Chapter 10: Action Plan

Implement the Dynamic Pricing Pilot (DPP) program upon Commission approval as described in Section 10.1.2 below.

10.1.2 Continue RCEA/Energy Awareness

The RCEA program was initially approved as a two year pilot program beginning in 2007 and ending in 2008. As mentioned in Section 7.1.3.10, the Commission convened a status conference on May 12, 2008 in Docket No. 2007-0323 to discuss among other things the continuation of the DSM programs during the transition period to the third party administrator and the disposition of the DSM pilot programs. During this status conference, HECO pointed out that the RCEA program had been very useful and helpful in advancing the DSM programs as evidenced by the unprecedented success of the DSM program in 2007 and early 2008. HECO will be submitting an evaluation report of the RCEA pilot program by September 30, 2008, to allow the Commission time to review and approve the continuation of the program beyond 2008 if so desired, in order to avoid any loss of progress in the RCEA program.

10.1.3 Continue SolarSavers Pilot Program

The SSP Program was approved by the Commission as a three year program in Decision and Order No. 23531, issued on June 29, 2007. HECO will continue to implement the SolarSaver Pilot Program through June 30, 2010. The annual expenditures in years 2 and 3 based on an estimated 100 installations per year are as follows:

Table 10.1-4 SolarSaver Pilot Program Incremental Budget ($)

Year 2 Year 3

SolarSaver Administrator 75,000 77,500

SolarSaver Installations 500,000 575,000

Repair Insurance 46,000 46,000

Marketing 15,000 15,000

Delinquent Payments 1,350 1,500

Bad Debt 10,000 11,500

Utility Billing Administrator 15,000 15,000

Utility Incremental Costs 10,000 10,000

Evaluation 10,000 10,000

Total 682,350 761,500

Docket No. 2007-0084 10-4 September 2008 HECO IRP-4 Chapter 10: Action Plan

HECO proposes to undertake the following tasks over the next two years:

Based on the results of process evaluation studies, HECO may modify how it implements the SSP program

Continue to look for other sources of funding the SolarSaver Fund

Work closely with the third party administrator as many of the administrative activities of the SSP program are closely related to the REWH program

10.2 Customer-choice Action Items

10.2.1 Implement Advanced Meter Infrastructure (AMI) Initiative

HECO will evaluate the overall technical and cost benefits of using Advanced Metering Infrastructure (AMI) to facilitate load management programs, including those that can help regulate frequency.

The proposed AMI project will provide two way communications for both the utility and the customer. For the utility, communication from the meter permits the utility to cost- effectively collect time-based customer consumption information that will permit the utility to bill customers through time-based rates such as time-of-use rates and dynamic pricing. Communication from the utility to the meter will provide operational benefits and enable cost effective ratchet resets and start and stop service, for example. Communication from the utility to end-use controls can change the settings for and activate load interruptions under load management and dynamic pricing programs. Signals from the end-use controls can confirm that the settings were received correctly and that controls operate as designed when activated by the utility.

For the customer, communications from the meter (indirectly through the utility system) can provide timely information about real-time consumption including the impact on electricity use and cost from changes in behavior that the customer may take (e.g., turning off the lights, etc). Communication from the customer to end-use controls on the customer’s premise can change customer-controllable options on utility sponsored remotely controlled thermostats, for example.

The control and communication attributes of AMI help to facilitate utility demand-side management efforts. Demand-side management in Hawaii is focused on the following strategies: • Energy efficiency and conservation • Load shifting (or valley filling) • Peak shaving

Docket No. 2007-0084 10-5 September 2008 HECO IRP-4 Chapter 10: Action Plan

Energy efficiency and conservation behavior on the part of customers is likely to be reinforced if positive behaviors are reinforced by timely results. The cost effective collection of time-based information from customer meters made possible by smart AMI meters, and the subsequent placement of that information on the Internet for the customer to view, made possible by a meter data management system, will provide more timely and informative feedback than a monthly bill. Thus, energy savings from turning off lights or electronic equipment, for example, can be observed on a very timely basis, and positively reinforce and sustain that behavior in the future.

Load shifting, or the movement of load away from a peak period to an off-peak period, lowers peak demand and contributes to the deferment of the next generating unit addition into a future period. Time-of-use rates are rates that differ by periods of the day, based on a utility’s cost of generating electricity at varying levels of demand, allowing customers to vary their demand and usage in response to such prices and manage their energy costs by shifting usage to a lower cost period or reducing their consumption overall. In order to bill time-of-use rates properly, time-based energy consumption information must be cost effectively collected and delivered to the utility. Smart meters that collect time-based consumption data and a meter data management system serving as an intelligent repository for that data, are part of the AMI project and will facilitate the cost effective collection and delivery of the information for billing.

In addition to contributing to unit addition deferral, shifting load to off-peak periods helps accommodate renewable energy resources. Many renewable energy resources, including wind, provide substantial generation during the off-peak periods, due to the nature of the renewable resource. Utility generation needed to be on-line during the off- peak periods often cannot reduce electrical output to a level low enough for the utility to accept all of the renewable energy being provided. Therefore, some of the renewable energy cannot be accepted and thus is in excess of the level of energy that can be purchased by the utility. However, if enough load is shifted from a peak period to an off- peak period, then more of the renewable energy can be accepted into the system during off peak periods. Thus, AMI, in facilitating time-of-use rates, also facilitates the utility’s ability to accept more renewable energy during off-peak periods.

The third DSM strategy, peak shaving, is addressed by the Companies’ demand response programs. These programs effect demand reductions during critical peak periods through pricing incentives and signals. Critical peak periods occur when the utility experiences, or anticipates it will experience, difficulty meeting the demand. A critical peak period could occur, for example, when a generating unit experiences a sudden, unanticipated outage.

HECO has two existing DSM load management (demand response) programs, the Commercial and Industrial Direct Load Control (CIDLC) and the Residential Direct Load Control (RDLC) programs, which reduce load through direct control of load control

Docket No. 2007-0084 10-6 September 2008 HECO IRP-4 Chapter 10: Action Plan

switches installed on customer loads. In exchange for allowing these load control switches to be installed, program participants are paid an incentive. The switches are activated when system frequency drops to predetermined levels and interrupt customer loads. (System frequency drops when aggregate customer demand is higher than the output that electricity generators on-line are able to provide.) If the amount of load curtailed restores the balance between customer load and the supply of generation, the system stabilizes. The switches can also be activated if HECO anticipates in advance that it will have difficulty meeting customer demand for electricity. The switches are restored to their original state once the critical peak period is over.

HECO's proposed Dynamic Pricing Pilot (DPP) program reduces load during critical peak periods in a similar manner. Under the DPP program central air-conditioning thermostats that can be remotely controlled by HECO are installed rather than load control switches. To reduce customer demand, HECO would send commands to the thermostat to raise the temperature set points. DPP program participants are paid an incentive based on the amount of energy saved during all critical peak periods.

These three demand response programs can be implemented with HECO’ existing one- way paging communication. However, the AMI project can enhance these demand response programs by establishing two-way communication between the utility and the load control devices (including the thermostat setting) to activate the devices or to change device settings (such as the thermostat set point temperature increase). The load control devices will also be able to communicate back to the utility (something that the current paging system cannot do) to confirm the settings and confirm whether or not the devices were activated as they were designed to do. This information is important to identify malfunctioning devices and to conduct comprehensive program evaluation, measurement, and verification.

The above programs effect load reductions in a single step, i.e., all devices are activated at the same time to achieve the maximum amount of load reduction in an effort to restore or maintain system frequency stability. Once the critical peak period is over, the devices are restored to their original state. The load control devices are activated in a partial phased arrangement and restored in a partial phased arrangement to help maintain grid stability. The dynamic management of load control devices also helps to maintain grid stability in an environment with fluctuating renewable resources connected to the grid, such as wind. Thus, load control devices have the potential to act as load following resources that can help “regulate” frequency or help prevent large frequency excursions.

For demand response resources to help regulate frequency, the software that activates the load control devices must be able to activate and restore the devices in coordination with changes in system frequency. Direct load control generally is not used to regulate frequency at this time, since this involves matching load and generation on a continuous

Docket No. 2007-0084 10-7 September 2008 HECO IRP-4 Chapter 10: Action Plan

basis. This is currently managed through the droop response of generators and the control of generator output through the Automatic Generator Control component of the Energy Management System.

The Company intends to explore the extent to which properly designed direct load control measures can assist in providing the substantial ancillary services that will be required to integrate substantial amounts of intermittent, fluctuating renewable electrical energy (such as that generated from wind farms) into its system. For example, one of the most important issues will be managing the system impacts (including frequency impacts from large wind farms) of sustained ramp down events that could occur when the wind drops. Such events could potentially be managed through a combination of resources such as increased spinning reserves, and on-site battery energy storage systems that slow the rate of the ramp down events, as well as direct load control resources, other load management resources, and distributed standby generation in the event the magnitude of the sustained ramp down exceeds the on-line reserves. AMI would facilitate the acquisition of the additional load management resources as they develop.

In summary, the AMI project will facilitate DSM strategies (including energy efficiency, peak shifting, and peak shaving) and the accommodation of additional renewable energy. Load management and frequency regulation are key elements of these strategies. Thus, evaluation of the overall technical and cost benefits of using AMI to implement both elements will be undertaken.

The following table provides current estimates of expenditures for the Companies’ AMI program48

Table 10.2-1 AMI Program (Current Estimates of Expenditures) ($000)

Prior 2008 2009 2010 2011 2012 Total

AMI Project- 0.79 0.76 1.02 4.74 17.87 16.49 41.67 Oahu

The following table provides a projected timetable for implementation of the AMI project on Oahu49. The timetable is contingent upon an estimated approval timeframe for the Companies’ AMI application.

48 Excludes any R&D program expenditures involving AMI technology. 49 The Companies’ AMI Project will continue on Maui and the Big Island, subsequent to completion of AMI deployment on Oahu.

Docket No. 2007-0084 10-8 September 2008 HECO IRP-4 Chapter 10: Action Plan

Table 10.2-2 AMI Program (Timetable)

Conduct Pilot AMI Projects 2007-2009 (AMI Network and Meter Data Management System)

AMI Business Case Analysis 2007-2008

Prepare and Submit PUC application 2008

Obtain PUC approval 2009

Implement Meter Data Management System 2010

Start Commercial AMI Network Deployment 2010

AMI Meter Deployment on Oahu (3 years) 2011-2013

10.2.2 Implement Residential Time-of-Use (TOU) (Enabled or Enhanced by AMI)

With the Commission’s approval of HECO’s 2005 rate case effective June 20, 2008, a residential time-of-use rate option (Schedule TOU-R) is now available to all HECO residential customers. This optional service is limited to 1,000 residential customers on a first come first served basis until the new Customer Information System (CIS) is implemented. Separate charges for energy use during the priority peak (Monday through Friday, 5pm to 9pm), mid-peak (Monday through Friday, 7am to 5pm; Saturday, Sunday, & Holidays, 5pm to 9pm), and off-peak hours (Daily, 9pm to 7am; Saturday, Sunday, & Holidays, 7am to 5pm) are defined. In HECO’s 2009 rate case, revisions to the Schedule TOU-R are proposed to improve the usability of the rate, such as shorter on-peak (3pm to 8pm daily) and longer off-peak hours and a greater price differential between on-peak and off-peak usage.

Should HECO be permitted to install “smart” meters at customer premises prior to the approval of the forthcoming Advanced Metering Infrastructure application, it is HECO’s intent that when these customers are provided with “smart” meters they also be placed on existing TOU rates approved by the Commission, on an opt-out basis.

10.2.3 Implement Demand Response (Enabled or Enhanced by AMI)

Direct Load Control Programs

Unlike the Energy Efficiency DSM programs, the load management DSM programs will continue to be administered by the utilities. HECO will continue to implement the RDLC and CIDLC programs. HECO will file applications to extend the RDLC and CIDLC

Docket No. 2007-0084 10-9 September 2008 HECO IRP-4 Chapter 10: Action Plan

programs beyond December 2009. Peak demand impacts and annual expenditures are as stated in Tables 10.1-1 and 10.1-3 respectively.

HECO will evaluate other technologies such as split air conditioning systems to target for load control within the RDLC program.

To further increase enrollment, HECO will aggressively market the Voluntary Load Control and Small Business Direct Load Control options within the CIDLC program.

HECO will evaluate the technical and cost benefits of using an AMI to facilitate load management programs as described in Section 10.1.2 above.

Dynamic Pricing Pilot Program

On April 24, 2008, HECO filed its application for a Dynamic Pricing Pilot (“DPP”) Program in Docket No. 2008-0074. HECO is proposing to run the DPP program for approximately one year. Upon approval of the application, implementation will consist of the following tasks:

Table 10.2-3 Timeline for Implementation

Task Months

1. Recruit participants 1 - 3

2. Purchase and install hourly load data meters and remote-controlled 3 - 4 thermostats.

3. Test day-ahead notification 5

4. Test same-day notification 6

5. Designate and implement remaining eight critical periods 7 - 16

6. Survey participants 5 - 16

7. Evaluate program impacts 17 - 18

HECO estimates the DPP program will result in approximately 270 kW of demand reduction from 600 pilot program test participants during 10 test events. The per participant estimates used to derive the 270 kW demand reduction assume that customers participating in the pilot reduce their demand in a manner similar to the California Statewide Pricing Pilot study which tested customer responsiveness to a critical peak pricing rate design.

The program’s incremental costs total $337,500, as shown in Table 10.2-4. While the pilot duration is 12 months, the budget extends over three years because program

Docket No. 2007-0084 10-10 September 2008 HECO IRP-4 Chapter 10: Action Plan

activity is expected to start before the end of 2008 with participant recruitment, followed by 12 months of implementation, followed by evaluation efforts in 2010.

Table 10.2-4 Dynamic Pricing Pilot Program Incremental Budget ($)

Year 1 Year 2 Year 3 Total

Customer Incentives 0 11,000 0 11,000

Outside Services

Thermostats/Pagers 50,000 20,000 70,000

Administration/Installation 26,000 20,000 46,000

Software Hosting 16,500 9,000 25,500

Event Communications 0 20,000 20,000

Evaluation

Recruit/Educate/Surveys/Analysis 40,000 10,000 30,000 80,000

Evaluation Meters 90,000 90,000

Total Outside Services 222,500 74,000 30,000 326,000

Total 222,500 85,000 30,000 337,500

Redesign of the Commercial Rate Schedules

HECO is proposing to redesign the commercial rate schedules in its test year 2009 rate case, Docket No. 2008-0083 in order to simplify rates and make them easier for customers to understand and use. For all commercial demand schedules, Schedule J, Schedule P, and proposed Schedule DS, HECO proposes a single demand charge rate. Further, HECO proposes a single energy charge rate for all commercial rate schedules. With this rate design, commercial customers can assess the bill impact in kW or kWh consumption more clearly and transparently.

10.2.4 Evaluate Green Pricing Tariff Options

The policy objective of increasing renewable energy resources reduces our state’s dependency on oil, enhances energy security, and hedges against the impact of changes in oil prices to the extent that the price of renewable energy is delinked from oil prices. In the short term, acquisition and accommodation of additional renewable resources will likely raise electricity prices. However, the hedge benefit of renewable energy will contribute to more stable electricity bills.

Docket No. 2007-0084 10-11 September 2008 HECO IRP-4 Chapter 10: Action Plan

Some customers have expressed an interest in securing the benefits of certain green attributes associated with the renewable energy. A green pricing tariff that separates those attributes from the renewable energy commodity would offer those attributes to customers on a voluntary basis. HECO is prepared to assist the Commission in evaluating options and provide its recommendations for a preferred green pricing tariff.

10.3 Customer-sited Distributed Generation

10.3.1 Facilitate Photovoltaics

HECO will monitor developments affecting customer-sited PV and plans to file an application for PUC approval of a utility PV program during the first half of 2009. As described in Section 7.2.6, HECO will base its PV program on participation by customers who own PV sites and third party PV developer-owners. HECO’s main objectives will be to facilitate installation of PV via the higher economies of scale associated with a utility program, and to enhance the integration of PV into the electric grid. HECO expects that significant interest in PV will continue throughout the 2009-2013 period, due to high grid energy rates, the desire by customers to stabilize their energy costs, and the renewable energy drivers for the technology. The lowering of the federal investment tax credit to 10% beginning in 2009 may stall or delay implementation of PV, at least until Congress takes concrete action to reinstate the higher 30% tax credit. HECO is also aware that within the state, PV developers have begun to see greater challenges in attracting investors for large projects, due to limitations on use of the state tax credit. HECO will take these tax credit issues into account in the design of its utility PV program.

10.3.2 Dispatachable Standby Generation

HECO will continue to develop the Honolulu Airport dispatchable standby generation (DSG) project. HECO anticipates filing for PUC approval of a DSG agreement between HECO and the State Department of Transportation by the end of 2008. In 2009, HECO hopes to obtain the PUC’s approval for the DSG agreement and to commit funds to the project, and to begin construction. The anticipated in-service date for the project is in the third quarter of 2010.

The significant mutual benefits that DSG provides to the DSG customer and the utility make it worthwhile for HECO to explore further project opportunities during the Action Plan. A number of potential DSG customers have expressed interest in HECO conducting DSG feasibility evaluations. HECO plans to perform these in earnest following PUC review of the Airport DSG project.

10.3.3 Monitor CHP

Although CHP development on Oahu has not been shown to be economically feasible thus far, and more restrictive EPA emission requirements for stationary engines will add

Docket No. 2007-0084 10-12 September 2008 HECO IRP-4 Chapter 10: Action Plan

costs to CHP systems, HECO will continue to monitor the feasibility of CHP, particularly biofueled CHP. The economic picture for biofuel-fired CHP systems may improve under certain scenarios, such as if a substantial carbon tax is imposed on fossil-fuel generators. HECO’s consideration of CHP will include whether any CHP should be owned and/or operated by the utility in order to meet utility system needs.

10.4 Supply-Side

10.4.1 Install 113 MW Biofuel CT in 2009

HECO’s IRP-4 Preferred Plan continues to identify the next conventional supply-side resource as a nominal 110 MW simple-cycle combustion turbine (CIP1) with a commercial operation date of July 2009. The five-year Supply-Side Action Plan includes work activities involving planning, permitting, engineering, and construction activities to support a July 2009 commercial operation date. Construction of this project started in May 2008. HECO is continuing with engineering design and permitting activities such as processing building permits to ensure it has the necessary government approvals to construct the power plant as required by the planned installation date.

CIP1 will be installed at HECO’s Barbers Point Tank Farm and will require installation of a two-mile long 138kV transmission line from HECO’s AES substation to its CEIP substation, all within the Campbell Industrial Park area. This line will be the third transmission line connecting the CIP generation to the transmission grid.

This third transmission line is needed to ensure system reliability and to prevent line overloads. Currently, HECO’s generating units in the Campbell Industrial Park connect to the main transmission grid via two existing 138 kV transmission lines.

Taking one of the two transmission lines serving CIP out of service for maintenance leaves only a single transmission line to transport all of the power produced by the generators located there. If that single transmission line then tripped unexpectedly, all of the power generated in the CIP area would need to be replaced almost instantaneously by the spinning reserve from the other Oahu generating stations. Since the spinning reserve on the system is typically 180 MW, CIP generation is presently limited to a maximum of 180 MW whenever either of the two lines is out of service.

Until recently, this 180 MW CIP generation restriction has not been critical because HECO coordinated the maintenance of the transmission line with the maintenance of the existing CIP generating units or had sufficient generation capacity elsewhere in its system. Because of the substantial growth in energy use over the past few years, it is no longer practical to continue this practice. Therefore, the construction of a third transmission line to serve the CIP area is needed, with or without installation of more generation in the CIP area, to ensure that line maintenance can be accomplished without putting at risk the loss to the system of all of the CIP generation.

Docket No. 2007-0084 10-13 September 2008 HECO IRP-4 Chapter 10: Action Plan

Also, the two existing 138 kV transmission lines connecting the CIP generation to the main HECO transmission grid will be at risk for overload conditions upon installation and operation of a new nominal 100 MW combustion turbine. If an overload occurs, permanent conductor damage could occur, resulting in a prolonged unavailability of all CIP generation. Therefore, to obviate these risks, a two-mile long 138kV transmission line within the CIP will be constructed from HECO's AES substation to its CIP substation.

Table 10.4-1 provides a summary of the major milestones and provides an estimated capital expenditure schedule for the SCCT unit and the associated 138 kV transmission line.

Table 10.4-1 Summary of Major Milestones for CIP CT-1 Unit Addition

Major Milestone Date

Submitted Covered Source/PSD Permit Application to October 2003 DOH

Submitted PUC Application June 2005

Published an Environmental Impact Statement (EIS) August 2005 Preparation Notice

Complete Final Environmental Impact Statement (EIS) August 2006

Receive Covered Source/PSD Permit from DOH May 2007

Receive PUC Approval to Commit Funds May 2007

CT Release for Manufacture August 2007

Start Construction of Generating Station May 2008

Start Construction of Transmission Line August 2008 (est.)

CT Delivery October 2008

Transmission Line in Service June 2009 (est.)

CT In Service July 2009 (est.)

Docket No. 2007-0084 10-14 September 2008 HECO IRP-4 Chapter 10: Action Plan

Table 10.4-2 Estimated Capital Expenditure Schedule for CIP CT-1 Unit Addition and Transmission Line ($000)

Prior 2008 2009 2010 2011 Future Total

Labor 976 1,123 1,237 0 0 0 3,336

Materials 14,186 36,795 12,595 0 0 0 63,576

Outside Services 6,431 45,143 30,4580 0 0 82,082

Other 33 0 0 0 0 0 33

Overheads 733 1,581 1,456 0 0 0 3,769

AFUDC 1,006 3,793 6,245 0 0 0 11,044

Total 23,366 88,433 51,991 0 0 0 163,840

10.4.2 Pursue Projects “Grandfathered” from Competitive Bidding

On December 8, 2006, the Commission issued Decision and Order No. 23121 (“D&O 23121”) in Docket No. 03-0372, wherein offers to sell as-available energy by non-fossil fuel producers that were received by HECO before December 8, 2006 would be “grandfathered” from competitive bidding. There were three eligible proposals: 1) First Wind’s proposal for a 30 MW wind farm at Kahuku; 2) Honua Power’s proposal for an approximate 6 MW waste-to-energy facility at Campbell Industrial Park; and 3) Sea Solar Power International’s proposal for a nominal 100 MW ocean thermal energy conversion facility in the ocean directly in front of Kahe power plant. Each developer proposed to deliver as-available energy.

In June 2007, HECO requested additional information from each developer to determine the viability of their projects. HECO would continue to negotiate for power purchase contracts, outside of the competitive bidding environment, with the developers whose proposals were determined to be viable in the near term. Those proposals that were determined to be not sufficiently matured would have the opportunity to submit competitive bids in response to the 100 MW renewable energy Request For Proposals.

HECO evaluated the information provided by each developer, and determined that each project had sufficiently robust plans to merit continued negotiations. In the case of Sea Solar Power International’s project, HECO determined that because there was no commercially operational facility, HECO would enter into a power purchase contract in two phases. During the proof-of-concept phase, HECO would not be obligated to accept more than 25 MW of as-available energy. Following successful demonstration of the

Docket No. 2007-0084 10-15 September 2008 HECO IRP-4 Chapter 10: Action Plan

performance of the facility, HECO would contract for scheduled energy from the entire facility.

On April 30, 2008, the Commission issued Order No. 24170 in Docket No. 03-0372, wherein HECO was required by September 2, 2008 to reach agreement with any or all of the three developers and to submit fully executed term sheets with each of those developers. The term sheets were to include information on 1) the scope of the project (i.e. technology, capacity, and location); 2) the manner in which the energy will be delivered (i.e. as-available, scheduled); 3) the term of the agreement, projected in- service date, and key milestones, including, but not limited to, proof of concept and any phases of the project; 4) performance standards; and 5) pricing. HECO submitted executed term sheets with each of the three developers on September 2, 2008. On September 8, 2008, the Commission issued a letter directing HECO to submit, no later than October 9, 2008, schedules for each of the three projects that include timelines for the completion and execution of the power purchased contracts and the planned installation and in-service dates for each project. Negotiations for a power purchase contract with each developer based on their term sheets are ongoing.

10.4.3 Continue 100 MW Renewable Energy RFP

In June 2008, HECO issued its Final Request for Proposals (“RFP”) for the supply of up to approximately 100 megawatts (“MW”) of long term (i.e. 20 years) renewable energy for the island of Oahu under a Power Purchase Agreement (“PPA”), the terms of which would be negotiated between HECO and the seller. The RFP is the first prepared in accordance with the PUC’s Competitive Bidding Framework issued in December 2006.

The resources sought under this RFP would commence commercial operation in the 2010-2014 timeframe, with a preference for resources that achieve commercial operation before 2013. The resources proposed will be evaluated with respect to impacts to the HECO system, adherence to HECO’s performance standards, and their ability to be installed within this preferred timeframe which encourages projects that require no more than modest infrastructure improvements.

The schedule for the RFP is as follows:

Docket No. 2007-0084 10-16 September 2008 HECO IRP-4 Chapter 10: Action Plan

Table 10.4-3 HECO Renewable Energy RFP Schedule

Event Anticipated Dates

Issue Draft RFP and Contract Forms February 8, 2008

Prospective Bidders May Submit Initial Questions Thru Technical Conference

Technical Conference on RFP with Interested Parties. March 14, 2008

Prospective Bidders File Comments on the Draft RFP April 14, 2008

HECO Files Proposed Final RFP and Contract Forms May 19, 2008 with the Commission

Independent Observer Submits Comments and May 19, 2008 Recommendations on the Proposed Final RFP

Opportunity for Participants to Comment on Proposed June 2, 2008 Final RFP and Independent Observer Recommendations

Commission Review and Approval of the Final RFP and June 18, 2008 Contract Forms

Final RFP Posted to the Company’s Website June 19, 2008

Bidders Conference Held July 14, 2008

Submit Notice of Intent to Bid July 19, 2008

Due Date for Proposals September 25, 2008

Selection of Short-Listed Bidders December 2008

HECO Completes Interconnection Studies for Short- June 2009 Listed Bidders

Selection of Award Group August 2009

Execution of Contracts December 2009

Submit Contracts for Commission Approval December 2009

10.4.4 Install 100 MW Firm Renewable Generation in 2011-2012

HECO’s Final Preferred Plan identifies the addition of a nominal 100 MW block of firm, renewable capacity in 2011. HECO plans to submit request for a waiver from the CB

Docket No. 2007-0084 10-17 September 2008 HECO IRP-4 Chapter 10: Action Plan

Framework in the fourth quarter of 2008 so that it may install a second 113 MW simple- cycle combustion turbine (CT-2), using biodiesel as its primary source of fuel, at its Campbell Industrial Park Generating Station. An application for approval to expend funds for the installation of CT-2 will be submitted to the Commission in the fourth quarter of 2008 .

The five-year Supply-Side Action Plan includes work activities involving planning, permitting, engineering, and construction activities to support a 2011 commercial operation date. 50

Table 10.4-4 provides a summary of the major milestones for the CIP CT-2 unit.

Table 10.4-4 Summary of Major Milestones for CIP CT-2 Unit

Major Milestone Date

Submit Waiver Request and PUC Fourth Quarter 2008 Application

Upon PUC approval of waiver request Order CT and application

Start Construction CT Order + 16 months

CT Delivery CT Order + 22 months51

CT In Service CT Order + 30 months

Table 10.4-5 Estimated Capital Expenditure Schedule for CIP2 Unit Addition ($000)

Prior 2008 2009 2010 2011 2012 Future Total Labor 0 95 358 528 166 0 0 1,147 Materials 0 0 10,309 37,440 13,555 0 0 61,304 Outside Services 0 147 1,265 6,644 31,272 444 0 39,772 Other 00000000 Overheads 0 70 296 532 147 0 0 1,045 AFUDC 0 5 254 2,971 6,404 0 0 9,634 Total 0 317 12,482 48,115 51,544 444 0 112,902

50 The schedule contains uncertainties and are HECO’s best estimate of the circumstances. For example, the CT will not be ordered from the vendor until the waiver request and PUC application for this project are approved, and HECO cannot predict with accuracy when this milestone will occur. HECO anticipates that a second combustion turbine can be in service at CIP as soon as 2011, but more likely in the 2012 timeframe. 51 The purchase contract between HECO and Siemens for CIP1 includes an option for HECO to purchase a second CT provided the order is placed no later than June 1, 2010. The guaranteed delivery time for the second CT is approximately 22 months following placement of the order.

Docket No. 2007-0084 10-18 September 2008 HECO IRP-4 Chapter 10: Action Plan

10.4.5 Determine Whether to Place Waiau 3 in Emergency Reserve or Retire the Unit

Evaluate the factors described in Section 7.4 to determine whether Waiau 3 should be placed on emergency reserve status or retired.

10.4.6 50-125 MW non-firm Emerging Technology (Such as OTEC)

HECO encourages the development of renewable energy employing emerging technologies. As such, HECO is willing to enter into power purchase contracts with developers of non-firm emerging technology projects. Those projects which have a capacity of 5 MW or less are exempt from competitive bidding and will be considered for contract negotiations. Those projects which have a capacity greater than 5 MW are required to bid under the competitive bidding framework rules specified in D&O No. 23121 in Docket No. 03-0372.

10.4.7 50 MW Firm Capacity Generation in 2014

The IRP-4 Preferred Plan calls for a 50 MW firm capacity addition in 2014. The competitive bidding efforts for this capacity would be expected to begin in the 2009 timeframe. While the specific attributes for this resource are still under consideration, a high level list of potential characteristics for this resource are provided at this time. The specific attributes resulting from this high level list, and any others that may develop, are expected to be further refined as the RFP is developed. This list of potential characteristics include the following: renewable fueled or primarily fueled by a renewable resource; capable of cycling duty, capable of being fully dispatchable from minimum to full load by the utility, capable of load following, providing frequency and voltage support according to standards determined by the utility. Quick-starting capability, high ramp rate capability, and ability to provide spinning reserve and perhaps other related attributes may be desired in order to help accommodate future intermittent, as-available renewable resources that may be identified through the technical study efforts of the Hawaii Clean Energy Initiative. Depending on the location of the resource, black start capability may be called for. As previously indicated, detailed specifications for this resource will be developed at the time the RFP is developed.

10.4.8 Potential Utility Bid for Military Distributed Generation Projects RFP

The DOD, in its solicitations for statements of interest and in its 2007 DG industry forum, indicated that it will seek proposals to develop PV and/or biofuel fired DG at Pearl Harbor, Hickam Air Force Base, Marine Corps Base Hawaii Kaneohe Bay, and . Should the military request proposals for DG, HECO plans to respond with proposals for HECO-owned, firm, biofueled DG, located at the military bases but interconnected to the HECO grid, that can be used to meet the needs of both the HECO

Docket No. 2007-0084 10-19 September 2008 HECO IRP-4 Chapter 10: Action Plan

system and the DOD. The actual type, size, location, and timing of such DG resources will depend on how the military structures their RFP, the sites made available, and HECO’s system needs. With regard to PV, at such time that HECO has made suitable progress in its development of a utility PV program, HECO would encourage the DOD to consider partnering with the utility and third party PV developer-owners in a similar manner.

10.4.9 50 MW Firm Capacity Generation in 2017

The IRP-4 Preferred Plan calls for a 50 MW firm capacity addition in 2017. The competitive bidding efforts for this capacity would be expected to begin in the 2012 timeframe. While the specific attributes for this resource are still under consideration, a high level list of potential characteristics for this resource are provided at this time. The specific attributes resulting from this high level list, and any others that may develop, are expected to be further refined as the RFP is developed. This list of potential characteristics include the following: renewable fueled or primarily fueled by a renewable resource; capable of cycling duty. When on-line, the unit should be capable of being fully dispatchable from minimum to full load by the utility and shall be capable of load following, providing frequency and voltage support according to standards determined by the utility. Quick-starting capability, high ramp rate capability, and ability to provide spinning reserve and perhaps other related attributes may be desired in order to help accommodate future intermittent, as-available renewable resources that may be determined through the technical study efforts of the Hawaii Clean Energy Initiative. Depending on the location of the resource, black start capability may be called for. As previously indicated, detailed specifications for this resource will be developed at the time the RFP is developed.

10.4.10 Determine Whether to Place Waiau 4 in Emergency Reserve or Retire the Unit

Evaluate the factors described in Section 7.4 to determine whether Waiau 4 should be placed on emergency reserve status or retired.

10.4.11 Conduct Biofuel Assessment in 2009 on Kahe 3 Using LSFO/Biofuel Blend

The use of liquid biofuels (e.g., ethanol, biodiesel, vegetable oils) in electric power generating units represents a potential option to increase HECO’s renewable energy portfolio. However, information regarding the utilization of biofuels in internal combustion engines, combustion turbines, and steam generation boilers to generate electricity remains limited. Before biofuels can be used on a commercial basis, there exists a need to build the utility’s knowledge base on the technical feasibility, operational requirements, and economic viability of firing stationary power generating units with biofuels.

Docket No. 2007-0084 10-20 September 2008 HECO IRP-4 Chapter 10: Action Plan

To that end, HECO is engaged in a multi-phased program consisting of the following phases: (1) biofuels screening investigation; (2) evaluation of generating unit performance and emissions; (3) investigation of key generating unit operational issues; and (4) demonstration of biofuel usage in utility power generating units. The University of Hawaii completed phase 1 in 2004, Southwest Research Institute completed phase 2 in 2006, and Black & Veatch completed phase 3 in 2007. HECO is currently engaged in planning activities for a utility-scale demonstration project in phase 4 of the program.52

Kahe 3 Biofuel Co-Firing Project

In Phase 4, HECO will conduct Kahe 3 biofuel co-firing tests in its steam boiler whereby a biofuel will be blended with low sulfur fuel oil at various blend levels to evaluate performance, emissions, and operations. To date, several vegetable oils and products derived from these oils are being evaluated (i.e., crude palm oil, refined, bleached and deodorized palm oil, palm fatty acid distillate, palm stearin, and jatropha) at a fuel specification laboratory. A biofuel type or property range of biofuel will be selected for large quantity sourcing and procurement for testing purposes.

The data and operating experience gained from the co-firing tests will help HECO evaluate the technical feasibility of firing biofuels in its units on a commercial scale. Ongoing activities include fuel compatibility evaluations, equipment and site assessments, test plan development, permitting and approval acquisition, and fuel sourcing and procurement. Other project development activities will include the design, specification, procurement, and installation of process equipment, controls, securing a storage facility and testing and tuning of the controls after installation.

Planning, permitting, and fuel procurement activities will occur in 2008 and the first half of 2009. HECO plans to conduct approximately a month-long test campaign on one of its tangentially-fired steam boilers in the fourth quarter of 2009.

Transition activities to the use of biofuels in HECO generating units may start in the 2010-2011 timeframe if demonstration-scale testing proves successful and no long-term negative impacts on equipment and operations are discovered. Although firing of low sulfur fuel oil will be preserved at HECO, commercial use of biofuels in a few HECO steam generating units on Oahu may occur in 2011-2012.

52 As part of Phase 4, MECO conducted biodiesel testing in its diesel engines and combustion turbine at Maalaea Power Plant in 2007.

Docket No. 2007-0084 10-21 September 2008 HECO IRP-4 Chapter 10: Action Plan

Table 10.4-6 Summary of Expenditure Schedule ($000) of K3 Biofuel Co-Firing Project

Prior 2008 2009 2010 2011 2012 Total

K3 Biofuel Co- 245 143 649 Firing Project53

Table 10.4-7 Summary of Major Milestones K3 Biofuel Co-Firing Project

Develop Biofuel specifications & piping diagrams Aug 2008

Develop RFP and negotiate with bidder for fuels contract Sep 2008

DOH notification (Approval) Dec. 31, 2008

Approval of PUC application for fuel differential cost Dec 2008 recovery. If not approved, may place a hold on the project

Authorize K3 biofuel co-firing project to order equipment Jan 2009

Authorize biofuel procurement Jan 2009

Completion of bulk fuel oil storage tank modification to Aug 2009 store the Biofuel

Scheduled maintenance outage period for Kahe 3 Sep-Oct 2009

Start Kahe 3 boiler test on biofuel blend Oct. 17, 2009

10.4.12 Conduct Biofuel Assessment For Substation DG

As described in Section 7.2.4.1, HECO will periodically evaluate the longer term use of its approximate 30 MW of substation DG. Although installed as temporary mitigation generation, the units provide operational flexibility and efficiency and their quick start capability may prove valuable as intermittent renewables such as wind are added to the grid. Consistent with HECO’s renewable goals, if the substation DGs are to be kept in long term service, HECO desires that they be converted to biodiesel operation. With this in mind, in the fourth quarter of 2008, HECO will commission biodiesel emissions tests of an identical Caterpillar DG unit located at the Hawthorne Power System facility in San Diego, California. HECO will develop plans for additional, longer run-hour biodiesel

53 EPRI’s cost share to date is about $200,000. HECO will seek additional cost share from EPRI in 2009 in the amount of HECO’s share. HECO will also have capital expenditures for equipment that will be used for this planned test and will remain as used and useful.

Docket No. 2007-0084 10-22 September 2008 HECO IRP-4 Chapter 10: Action Plan

testing in future years, depending on the success of the emissions tests and whether a decision is made to keep the DG units in operation over a longer term.

Table 10.4-8 Summary of Expenditure Schedule ($000) Substation DG Biofuel Co-Firing Project

Prior 2008 2009 2010 2011 2012 Total

Substation DG Biofuel Co-Firing (1) TBD TBD TBD TBD TBD Project

Note: (1) Substation DG project is subject to EPRI agreement and EPRI funds will be used for this study, estimated at $100,000.

10.4.13 Conversion of Existing Generating Units to Biofuel

HECO is evaluating the use of various biofuels in their existing generating units. As part of this larger scope, longer term effort, HECO will be conducting a full scale evaluation of biofuel co-firing in Kahe Unit 3 in late 2009. The results of the Kahe Unit 3 biofuel co-firing evaluation will be used to assess the potential for the use of biofuels and biofuel blends in other HECO units.

10.4.14 Explore Additional Utility-sited PV Projects

In 2009, HECO will evaluate its experience in developing the Archer PV project with an outside developer and will consider additional increments of PV at utility sites such as Kahe valley and Waiau power plant. One consideration will be the status of available tax credits, as the federal investment tax credit for solar installations will lower to 10% for systems placed in service in 2009 and beyond, unless Congress reinstates the higher 30% tax credit. For the Kahe site, HECO will also consider the feasibility of (CSP). The amount of land in Kahe is relatively small compared to that of U. S. mainland CSP installations, but developers may still find the site suitable for smaller scale CSP installations. Depending on the outcome of HECO’s evaluation, HECO may initiate an RFP process by the end of 2009 for development of additional utility-sited PV and/or CSP. If the generating resource being sought is greater than 5 MW, it will be subject to the Competitive Bid Framework, meaning the RFP process is initiated by issuance of a draft RFP. If the solar generating resource is not subject to the Competitive Bid Framework, HECO a final RFP could be issued by the end of 2009. Based on its Archer PV project experience, HECO anticipates that a utility- sited solar generating resource could be placed in service within two years from issuance of a final RFP.

Docket No. 2007-0084 10-23 September 2008 HECO IRP-4 Chapter 10: Action Plan

10.5 Energy Delivery

10.5.1 Complete The East Oahu Transmission Project

The project involves two independent phases, phase 1 and phase 2. Phase 1 involves the interconnection of three 46kV circuits from the Pukele substation, at the end of HECO’s northern 138kV transmission corridor, to four 46kV lines connected to HECO’s southern 138kV transmission corridor. Phase 2 involves the interconnection of four out of the five remaining 46kV circuits from the Pukele substation to three other 46kV lines connected to HECO’s southern 138kV transmission corridor. The implementation of this project would allow electrical loads currently being served exclusively from Pukele substation in HECO’s northern 138kV transmission corridor to also be served from the Kamoku and Archer substations in HECO’s southern 138kV transmission corridor through the 46kV system. Phase 1 is anticipated to be in-service June 2010. Phase 2 is tentatively planned to be in-service in May 2012, however, this date is dependent on coordination with various City & County of Honolulu initiated projects for King Street.

Table 10.5-1 EOTP Costs as for July 2008 Actuals ($000)

Prior 2008 2009 2010 2011 2012 Total

EOTP Ph. 1 31,489 5,264 12,355 8,127 57,235

EOTP Ph. 2 1,378 142 385 1,969 10,035 2,600 16,509

Total 32,867 5,406 12,740 10,096 10,035 2,600 73,744

Table 10.5-2 EOTP Milestones

Milestone Target Year

EOTP Ph. 1 – Start Construction (started in June 2008) 2008

EOTP Ph. 1 – Major equipment arrive on island 2009

EOTP Ph. 1 - In-service 2010

EOTP Ph. 2 – Start detailed engineering 2009

EOTP Ph. 2 – Order long-lead equipment 2009

EOTP Ph. 2 – Start construction milestone is under evaluation, needs 2010 to be coordinate with City agencies

EOTP Ph. 2 - In-service milestone is under evaluation, needs to be 2012 coordinate with City agencies

Docket No. 2007-0084 10-24 September 2008 HECO IRP-4 Chapter 10: Action Plan

10.5.2 Install Interconnection Facility for all Central Station Generating Facilities in the Plan

The central station generating facilities within the action plan include the 110MW CT in 2009 and a firm100 MW renewable resource in 2011. These facilities are assumed to be located in the Campbell Industrial Park (CIP) area. The AES-CIP #2 138kV circuits described in section 10.4.2 of the action plan will be installed with the 110 MW CT in 2009. Once the AES-CIP #2 circuit is installed, the three circuits out of the CIP area (AES-CIP #1, AES-CIP #2, and Kalaeloa-Ewa Nui) will accommodate the 100 MW firm resource in 2011. Substation equipment additions will be needed to interconnect the generation to the HECO system. These upgrades are estimated to cost approximately $5,000,000.

10.5.3 Investigate Integration of Additional As-Available Resources on Oahu

Due to the intermittent nature of the wind and sun, a high penetration of as-available wind and solar resources on isolated electric grid systems can impact the electric utility’s ability to maintain system stability. HELCO and MECO are currently dealing with a high penetration of variable wind energy on their islands, and managing this variability using dispatchable generating units consisting of a mix of steam boilers, diesel generators, and combustion turbines. HELCO and MECO have generating units (diesel and combustion turbines) that can respond more quickly to fluctuating wind energy production, as opposed to HECO’s steam boiler units that cannot respond as quickly.

With the recent negotiations for a commercial wind farm on the north shore of Oahu, possible additional wind farm(s) resulting from the Company’s Request for Proposals for Renewable Energy Projects (Docket No. 2007-0331), and interest by large wind farm developers on neighboring islands to transport this energy to Oahu via undersea cables, HECO may be faced with challenges of integrating these potential wind farms and other renewable energy projects on the HECO grid.

Large Scale Wind Study

HECO, the State, and Federal government have developed an aggressive goal of reaching supplying 70% of Hawaii’s energy needs through renewable energy resources by 2030 through the Hawaii Clean Energy Initiative. A significant contribution towards meeting this goal is the integration of intermittent resources such as wind. The high variability and low to no inertia provided by these systems presents a significant challenge to their integration into small islanded system like HECO’s. As challenging as it is, HECO is committed to maximizing the integration of these types of renewable resources on to it system. To this end, HECO is embarking on a Large Scale Wind

Docket No. 2007-0084 10-25 September 2008 HECO IRP-4 Chapter 10: Action Plan

Study to integrate 300 to 400 MW of wind energy on its system from neighbor island sites in addition to the 100 MW of as-available energy from the HECO Renewable RFP, while maintaining the stability, reliability, and operability of the HECO system.

Building upon the lessons learned at HELCO and MECO, who are currently among the world leaders in the percentage of wind power integrated on its systems, HECO has learned that the total amount of intermittent generation that can be integrated on a system is dependent upon the performance of the first installation up to the last. Therefore, HECO has developed performance requirements in the model PPA developed for the Request for Proposals for Renewable Energy Projects (Docket No. 2007-0331) that will limit the ramp rates for each project and thereby allowing more room for other projects to be integrated on the system. However, these performance requirements were developed to accommodate the projects in the RFP and the grandfathered proposals submitted prior to the issuance of the Generation Bidding Framework by the Commission. They were not developed to reach penetration levels beyond those projects.

To incorporate additional generation from wind resources, a comprehensive study is needed to: 1) determine the stability limits of integrating large amounts of wind via HVDC systems; 2) verify the detailed characteristics and capabilities of HECO’s existing generating units and control system such as the EMS, since these units and systems will need to be able to provide the stability and capacity to balance the intermittent generation; 3) determine the characteristics of the intermittent resources and the extent to which geographic diversity and forecasting can contribute to its integration to the HECO system; 4) evaluate the effectiveness and maturity of different storage technologies used to mitigate the variability of intermittent resources; 5) develop the operating rules needed to ensure the stability, reliability, and operability of the system; 6) given a target level of integration from the work above, determine the performance standards for the intermittent generation to ensure the stability and reliability of the system; 7) review the impacts of these resources on the system operation and ensure that there are adequate tools and resources to ensure that save and reliable operation of the system.

This study will likely be a multi year effort as HECO moves through this process step by step to learn more about the limits of the system as well as the details of potential projects that can be incorporated in the study. The cost and schedule for this effort is still being developed. However, there are studies that are getting underway in 2008 to lay the foundation for the rest of the study. One study is focused on the system stability limits of the existing HECO system and the high level electrical connections that would be needed for large off-shore wind integration. The cost for this is included in the 2008 cost given below for the Large Wind Integration Study. Another is the Oahu Electrical System Analysis Study that is described below.

Docket No. 2007-0084 10-26 September 2008 HECO IRP-4 Chapter 10: Action Plan

Oahu Electrical System Analysis Study

As part of the Large Wind Integration Study, HECO is planning to commission a modeling study called the Oahu Electrical System Analysis. This study will develop and utilize computer models to simulate the effects of the integration of future wind farms (and other intermittent renewable resources) by evaluating the challenges of integrating intermittent renewable energy into the electrical grid, evaluating the impact of currently planned renewable expansion scenarios on HECO’s grid operation, and formulating controls, storage and interconnection recommendations to help achieve the renewable energy targets for the island. This study is similar to the ongoing Maui Electric Analysis for the MECO system; however, HECO will need to tailor the Oahu study according to the unique characteristics of HECO’s electric system. For example, the type, number, size and mix of electrical generating facilities on Oahu are very different than those on the Big Island and Maui.

HECO is currently discussing the scope, schedule, and budget for the Oahu Electrical System Analysis with the consultant and is planning to execute the contract by late 2008. It is envisioned that the study will be completed by the end of 2009. Applicable findings and solutions to help HECO integrate high as-available renewable resources, yet maintain system reliability and stability, would be evaluated, and possibly implemented, in the 2010-2012 timeframe.

Table 10.5-3 Summary of Expenditure Schedule ($000) for Integration of As-Available Resources

Prior 2008 2009 2010 2011 2012 Total

Large Wind Integration 80 TBD TBD TBD TBD Study

Oahu Electrical System Analysis 75 652 TBD TBD TBD Study

Notes: Study budget and statement of work is under negotiations and subject to final agreement. HECO will seek USDOE and HNEI cost share for this project.

Docket No. 2007-0084 10-27 September 2008 HECO IRP-4 Chapter 10: Action Plan

Table 10.5-4 Summary of Major Milestones of Integration of As-Available Resources

The detailed scope and schedule for the Comprehensive

Plan is under development

Sign agreement with HNEI for Oahu Electrical System Sep 2008 Analysis study

Complete phase 1 of Oahu Electrical System Analysis Sep 2009 study

Develop phase 2 scenarios and budget of theOahu Sep 2009 Electrical System Analysis Study

Complete phase 2 Oahu Electrical System Analysis study Mar 2010

Notes: Oahu study schedule is subject to final statement of work and schedule.

10.5.4 Honolulu – School, Halawa – Iwilei 46 kV Study

A study of these circuits is in progress and is expected to be completed by the end of 2008. Should any criteria violations be identified as a result of this study, a preferred solution will be developed and, if required, a PUC application submitted for approval.

10.5.5 Waiau 46 kV Bus

HECO is currently developing plans to shift load away from the Waiau 46kV bus to reduce a low voltage condition upon the loss of one of the 138kV sources serving the bus. To the extent that Waiau 3 and Waiau 4 are placed on emergency standby status, the risk of a low voltage condition increases. Installation of an 80 MVA transformer at the Ewa Nui substation and the extension of a new 46kV circuit will decrease the load off the Waiau bus. The cost for this project has not been finalized, however the preliminary milestones are provided below.

Table 10.5-5 Waiau 46kV Milestones

Develop a scope of work for the project 2008 - 2009

Prepare and submit PUC application 2009

Obtain PUC approval 2009

Order long lead item (transformer) 2010

Begin construction 2012

Project in service 2012

Docket No. 2007-0084 10-28 September 2008 HECO IRP-4 Chapter 10: Action Plan

10.5.6 Halawa – School, Halawa-Iwilei, Makalapa – Airport-Iwilei 138 kV Study

The need for the reconductoring of these lines will depend on the resources picked in the renewable energy RFP, as well as the progress of the grandfathered as-available projects. As as-available generation is added to the system it would displace generation from the Honolulu power station and thereby increase the power flows required on these three circuits. These potential overloads on these lines will be revisited in the course of the interconnection requirements studies conducted for these projects. Load reductions to the east of these lines due to DSM projects on the order of 50 MW, with more in the future to offset load growth, would be needed to defer the need to address the overload potential on these lines. The cost for reconductoring these lines is approximately $17,300,000.

10.6 Research, Development, and Demonstration

Various issues relating to the development of renewable energy in Hawaii, such as resource and siting availability, technical maturity, dispatchability, and economic viability, need to be addressed and successfully managed. To meet this challenge, HECO is implementing renewable energy activities that incorporate a three-pronged approach: • Pursue commercially available renewable energy generation in the near term; • Pursue activities that can increase the number of intermittent renewable energy technologies (i.e., wind on the electric grid); and in parallel • Accelerate research, development and demonstration (RD&D) activities for emerging technologies and resources that are not currently commercially available or economically viable in the near term.

These activities will to help ensure that HECO is not only taking action to use as much renewable energy as is commercially and economically viable today, but is also helping to develop future sources of renewable energy.

10.6.1 Investigate Hawaii-based Bioenergy Crop Production

To address the state’s energy dependence on foreign oil, many stakeholders in Hawaii are currently evaluating the prospects of establishing a viable local biofuel supply industry. A necessary component of this evaluation is the research of biofuel crops that can be successfully grown in Hawaii.

In addition to evaluating and preparing for commercial utilization of biofuels, HECO is assisting in the research and development of local biofuel production. HECO provided seed funding in 2007 and 2008 to the Hawaii Agriculture Research Center (“HARC”) on a biofuels agriculture crop research project. HARC is conducting research and

Docket No. 2007-0084 10-29 September 2008 HECO IRP-4 Chapter 10: Action Plan

administrating the additional research work of the University of Hawaii at Manoa’s College of Tropical Agriculture and Human Resources (“CTAHR”) and University of Hawaii at Hilo’s College of Agriculture, Forestry and Natural Resources Management (“CAFNRM”). HARC, CTAHR, and CAFNRM are each responsible for separate projects in the research effort. Tasks include establishing test plots of Moringa oleifera and jatropha on Molokai to evaluate growth performance and nutrient utilization, establishing test plots of jatropha on Oahu to develop a method to increase uniformity of growth and yield in the field, and establishing test plots of hybrid oil palm on the Big Island to evaluate growth performance. HECO plans to continue its support for biofuels research and development to HARC in 2009 and throughout the Action Plan period.

Table 10.6-1 Summary of Expenditure Schedule ($000) Biofuel Agriculture Crop Research

Prior 2008 2009 2010 2011 2012 Total

Biofuel Agriculture Crop 50 50 50 50 50 50 Research

Note: HECO will continue seed R&D monies to HARC, UHM and UHH researchers to continue their biofuel agriculture crop research in Hawaii. EPRI cost share to date is $100,000 and HECO will seek EPRI cost share for future years.

Table 10.6-2 Summary of Major Milestones Biofuel Agriculture Crop Research

2009, 2010, Continue to seed R&D funds to researchers 2011, 2012

10.6.2 Investigate Plug-in Hybrid Vehicles

HECO is participating in a research, development, and demonstration (RD&D) project with the National Laboratory (INL) to convert a hybrid Toyota Prius into a plug-in hybrid electric vehicle (PHEV). The vehicle modifications entail the installation of a retrofit battery/charging package by a third party vendor that would allow the converted Prius to be plugged into a standard 120 volt wall outlet for battery charging. As part of this project, INL will install on-board data logging equipment to record fuel efficiency and electricity usage. Collection of demand load profile through Advanced Metering (AMI), and system integration with demand response and load control management strategies will enable HECO to evaluate charging technology control and savings potential, Time of Use requirements for PHEV applications, and to gain valuable insight on the overall smart grid connection impact of future electric vehicle technology.

Docket No. 2007-0084 10-30 September 2008 HECO IRP-4 Chapter 10: Action Plan

Table 10.6-3 Summary of Expenditure Schedule ($000) for PHEV

Prior 2008 2009 2010 2011 2012 Total

Idaho National Laboratory 2554 355 TBD TBD TBD Conversion

Note: INL cost share is approximately $12,000 for vehicle conversion from hybrid to PHEV, data collection, evaluation and reporting.

Table 10.6-4 Summary of Major Milestones for PHEV

PHEV conversion Dec 2008

One year monitoring Dec 2009

Final Report Jan 2010

Note: PHEV conversion schedule is subject to their consultant availability, thus this schedule could change.

10.6.3 Investigate Potential Energy Storage Projects

Due to the existing high penetration of as-available renewable energy resources on the Big Island and Maui and the potential for high penetration in the future on Oahu, HECO continues to monitor and evaluate energy storage system development and technologies such as pumped storage hydroelectric (PSH), battery energy storage systems (BESS), and short-term mitigation offered by buffer technologies like HECO’s patented- Electronic Shock Absorber (ESA).

Pumped storage hydroelectric studies have been conducted for Oahu and neighbor island locations. Although no PSH facilities have been installed on Oahu, PSH remains a technology of interest due to its large storage capacity and ancillary benefits capabilities. HECO plans to continue the assessment of potential new PSH applications on Oahu, thus gaining additional information on project concepts, cost estimates, and operating data.

Battery energy storage systems are a potential energy storage technology applicable in Hawaii. The types of BESS include sodium nickel chloride, sodium sulfur, vanadium redox, lithium ion, lead acid, and others. In general, the module size of BESS range

54 Estimated cost of a Hybrid Toyota Prius 55 Estimated cost to set up test charging spot

Docket No. 2007-0084 10-31 September 2008 HECO IRP-4 Chapter 10: Action Plan

from 1 kW to 2 MW with storage varying from seconds to hours depending on the storage application. The size of BESS can be increased by increasing the number of modules. HECO will continue its evaluation of BESS technologies and applications, and participate in demonstration BESS projects if warranted, throughout the IRP-4 five-year Action Plan period.

To help stabilize operation of grid-connected wind turbines and minimize power fluctuations on an electric grid that is connected to a number of wind farms, HECO, HELCO, and MECO have teamed with a private company to develop the ESA to help the electric utility ride through short duration power fluctuations (frequency, voltage, etc.) from the wind farm caused by the variable nature of wind. After HECO received a patent for the ESA in 2005, a demonstration ESA system was built and tested at the HELCO Lalamilo wind farm site in 2006. Although the ESA was damaged in the October 2006 earthquake, HECO continues to evaluate the prospects of building a new unit for further demonstration and commercial application testing.

HECO has been in early communications with EPRI personnel for a possible study on a new concept related to above-ground compressed air energy storage (CAES) in Hawaii. Underground CAES has not been actively pursued in Hawaii because Hawaii does not have the geological structures (e.g., air tight salt domes) for underground CAES and its underground geology is generally fractured and likely not able to store high pressure air. The size of above-ground CAES systems could be about 15 MW for 2 hours (or 30 MWh). HECO will continue discussions with EPRI and possibly other consultants on a study to help HECO’s evaluation of Hawaii-sited above-ground CAES. This technical assessment and feasibility study is targeted for 2008-2010.

In addition to the above activities, HECO will continue to keep abreast of commercial and emerging energy storage technologies through its membership with the Electric Power Research Institute (EPRI) and interactions with industry. For example, energy storage vendors have made technical presentations to HECO engineers on PSH and sodium sulfur BESS. In addition to internal research, commissioned studies, and communications with industry contacts, HECO engineers have visited commercial and demonstration scale projects and research laboratories for energy storage related to PSH, nickel metal hydride and sodium sulfur BESS, and flywheels. These activities will continue throughout the IRP-4 five-year Action Plan period.

Based on a proposal submitted to the USDOE in August 2007, the USDOE awarded $7 million to a team led by HNEI to develop and deploy distributed energy technologies that can help ameliorate the issues (power fluctuation issues, frequency, etc. arising from wind generation) related to wind energy integration on an electric utility grid. Additional funding will be contributed by the various team partners, which include HECO, MECO, General Electric, Columbus Electric Cooperative, the New Mexico Institute of Mining and Technology, Sentech and UPC Wind. The more than three-year project will first be

Docket No. 2007-0084 10-32 September 2008 HECO IRP-4 Chapter 10: Action Plan

developed on a laboratory and pilot scale at research facilities on the U. S. mainland, and eventually deployed on Maui in the 2010-2011 timeframe.

Table 10.6-5 Summary of HECO Expenditure Schedule ($000) for Key Energy Storage

Prior 2008 2009 2010 2011 2012 Total

Above Ground 0 (1) (1) CAES

USDOE Award 40,000 40,000 40,000

Notes: (1) Above ground CAES study is subject to final statement of work and schedule.

Table 10.6-6 Summary of Major Milestones of Key Energy Storage Projects

Above ground CAES study agreement Oct 2008

Complete above ground CAES study Dec 2009

USDOE Project, Commencement of Funding Oct 2008

USDOE Project, R&D Phase 2008-2010

USDOE Project, Implementation Phase 2010-2011

10.6.4 Other Miscellaneous R&D Projects

As part of HECO’s renewable energy activities to increase the renewable portfolio in the long term, HECO is pursuing a broad range of initiatives and research, development, and demonstration (RD&D) projects to facilitate and accelerate the development of emerging renewable energy technologies in Hawaii. HECO’s memberships in the Electric Power Research Institute (EPRI, the research arm of the electric utility industry), American Council on Renewable Energy (ACORE), Utility Wind Integration Group (UWIG), and others keep HECO abreast of technology advances and is a core component of its RD&D thrust. HECO will continue to attend EPRI and renewable energy conferences, seminars and workshops and renewable energy manufacturers and projects sites when appropriate. In addition, HECO will continue to seek partnerships with federal, state, and county governments, the University of Hawaii, and other entities to increase its renewable energy portfolio. Some RD&D projects include, but are not limited to, those described below.

Ocean Resources • Ocean Energy Project

In February 2008, Oceanlinx Limited, an Australian-based high-tech company, announced plans to provide up to 2.7 MW of electricity to MECO from Hawaii’s first wave

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energy project that could be operational by the end of 2010. The project would involve two to three floating wave platforms offshore of Pauwela Point on the northeast coast of Maui. Oceanlinx is currently preparing an environmental impact statement for the project and pursuing appropriate permits and approvals. HECO and MECO are negotiating a power purchase agreement with Oceanlinx. HECO will monitor the technical and operational performance of the Oceanlinx project during the IRP-4 Action Plan period. • Ocean Current Energy Resource Assessments

HECO is engaged in the assessment of ocean current energy resources in Hawaii and the applicable technologies with potential for deployment. In 2004, HECO participated in a project headed by EPRI to demonstrate the feasibility of and assess cost and performance of wave energy devices.

HECO, HELCO and MECO commissioned a study to assess the ocean current/tidal resource around the islands of Oahu, Big Island, Maui, Molokai, and Lanai so that HECO, HELCO, and MECO, and other stakeholders can evaluate the potential for ocean current . The current status of current/tidal turbine technology also was evaluated to determine its potential in Hawaii. Although the study indicated that the ocean current/tidal resource is too small to sustain viable operation of current/tidal turbine technologies being developed today, HECO will continue to monitor and evaluate technological developments and applicability in Hawaii. • Navy Wave Energy Demonstration

Under a DOD Small Business Innovation Research (SBIR) grant, the Navy is partnering with Ocean Power Technologies (OPT) to assess the technical and economic feasibility of ocean wave energy. An at-sea demonstration of a 20-kW buoy wave energy system is being conducted at Kaneohe Marine Base. HECO provided engineering support regarding interconnecting to the electric grid. HECO continues to monitor the developments of this demonstration project. • National Marine Renewable Energy Centers

Hawaii Natural Energy Institute (HNEI) was selected by the Department of Energy (DOE) to establish one of two National Marine Renewable Energy Centers. HNEI is a research unit and is part of the School of Ocean and Earth Science and Technology at the University of Hawaii. The DOE will provide a grant to HNEI of approximately $1 million per year for as many as five years to conduct renewable energy research and development of technologies that harness the power of waves and ocean thermal energy conversion. The Hawaii center will be a public-private partnership that will serve as a national information clearinghouse for the marine renewable energy industry that will collect and disseminate information on best practices in research. Maui Electric Company (MECO) will participate through the design, development and deployment of hardware to support testing of wave

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energy technologies and HECO will participate through sharing of non-proprietary data and through technical assistance in analysis of promising commercial scale wave energy systems. MECO and HECO’s in-kind participation over the 5-year period will be $1.7 million and $250,000, respectively.

Hydrogen and Fuel Cells • Hawaii Fuel Cell Test Facility

HECO continues its partnership with HNEI, U.S. Department of Defense (DOD), and UTC Fuel Cells on the Hawaii Fuel Cell Test Facility. Operational since April 2003 and housed in approximately 4,000 square feet of warehouse space at HECO’s Ward Avenue facility, HNEI continues its research to evaluate the performance and reliability of production-sized, single-celled, fuel cell stack designs, materials, and fuels. HECO plans to continue supporting the operation of the Hawaii Fuel Cell Test Facility through the IRP-4 Action Plan period. • Hydrogen Power Park Study

HECO and HELCO are partnering with DBEDT, HNEI, Sentech, Sunline, Stuart Energy, and UTC Fuel Cells in a project to introduce and demonstrate hydrogen-based infrastructure in Hawaii.

Solar Energy • Sun Power for Schools Program

HECO, HELCO, and MECO are in their 11th year of the Sun Power for Schools program with the State of Hawaii Department of Education. Through the Sun Power for Schools program, HECO utilities will continue to install photovoltaic systems at Hawaii public schools using voluntary customer contributions and by providing in-kind utility contributions, including engineering, project management, administration, advertising, and marketing support. To date, 27 public schools comprising about 36 kW have received photovoltaic systems (14 on Oahu, six on the Big Island, and seven in Maui County). HECO, HELCO, and MECO plans to extend the Sun Power for Schools program for at least another two years (2009-2010).

The number of photovoltaic installations that can be installed in a given year is a function of the amount of customer contributions and utility resource availability. HECO is currently working on the fifteenth installation at Wheeler Middle School in central Oahu with completion targeted in early 2009.

HECO and the State of Hawaii Department of Education developed educational materials through a grant from the U.S Department of Energy’s Million Solar Roofs program. The material was provided to public high school teachers. HECO, HELCO and MECO also conducted workshops for public high school and middle school teachers

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and participated in their Solar Sprint program, in which students evaluate their solar cars in field tests.

Table 10.6-7 Summary of Expenditure Schedule ($000) of General Renewable Energy Research & Development

Prior 2008 2009 2010 2011 2012 Total

General Renewable 4,599 1,095 1,658 1,658 1,658 1,658 Energy R&D

10.7 Other Action Items

10.7.1 Implement Renewable Energy Infrastructure Program

Assuming Commission approval of the REI program and the related REIP surcharge, the next steps would entail the HECO Companies filing applications for specific projects under the REI program. The applications would provide supporting details for specific REI program projects, including project need, description, scope, cost estimates, and the proposed cost recovery mechanism, including the estimated REIP surcharge factor associated with the project. Assuming Commission approval of a specific project application, the HECO Companies would install and/or implement the project. After the project has been deemed used or useful for utility purposes, the HECO Companies would include the project in the REIP surcharge.

10.7.2 Participate in Hawaii Clean Energy Initiative

Hawaiian Electric Company’s action plan related to HCEI is to continue to participate (along with Hawaii Electric Light Company and Maui Electric Company) in each of the four HCEI working groups. In addition, the Hawaiian Electric Companies will continue to work with other members of each working group and the State, by providing relevant system information, providing information specific operational and planning challenges for each of the utility systems, and to work with other working group members to identify potential solutions and develop plans for achieving the HCEI objectives.

Because the timing of future HCEI actions is unknown, specific timing of the HCEI working group action items are similarly undetermined at this point. Depending upon the outcome of the HCEI, among other considerations, Hawaiian Electric may submit an update to its IRP-4 filing.

10.7.3 Delink Schedule Q (Avoided Cost) from Fossil Fuel Price

In April, 2008, the Public Utilities Commission opened Docket No. 2008-0069, initiating an investigation to consider the methodology used for calculating Schedule Q payment

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rates (Schedule Q is a form of feed-in tariff with an established payment rate for qualifying projects). The stated purpose of the investigation is to determine whether or not the current methodology used for calculating Schedule Q payment rates comply with Act 162.

Parties to the docket include Hawaiian Electric, HELCO, MECO, KIUC, and the CA.

The preliminary issues identified by the PUC for the docket, include:

What is the appropriate methodology or methodologies for calculating Schedule Q payment rates given the applicable law, including HRS 269-27.2 (c), the Public Utilities Regulatory Policy Act of 1978, as amended, and Hawaii Administrative Rules Chapter 6-74.

Whether the methodologies for calculating Schedule Q payment rates proposed by the Hawaiian Electric Companies (fixed payment rates over the term of the Schedule Q contract, similar in concept to that filed in Docket No. 7310. and a contract term of 5 years) are reasonable and comply with all applicable laws.

Whether a methodology other than the methodologies proposed by the Hawaiian Electric Companies for calculating Schedule Q payment rates should be adopted by the commission, and, if so, is the methodology reasonable.

Based on the procedural schedule issues by the PUC, the docket is expected to run through March 2009 when responses to Statements of Positions are due.

10.7.4 Explore Decoupling Utility Revenues from Electricity Sales

HECO is in the process of examining ways to decouple or remove the link between utility revenues and utility kWh sales. Under the current regulatory practice, HECO has a financial incentive to increase kWh sales once base rates are established in a general rate case, an incentive that is inconsistent with the energy efficiency and conservation efforts that the Company promotes. HECO sees the benefits of a properly constructed decoupling mechanism as one that removes the bias for increasing kWh sales while providing periodic adjustments of rates to match changes in operating and capital expenses. Such a decoupling mechanism would fit the unique characteristics of Hawaii’s service territory and cost structure, continue to provide an incentive to the utilities to pursue aggressive energy efficiency and renewable energy, and provide an opportunity for the utilities to achieve fair rates of return without the need for frequent rate cases. Timing for a HECO decoupling proposal to the Commission is dependent upon HECO’s current rate proceeding and discussions with stakeholders.

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Docket No. 2007-0084 10-38 September 2008 HECO IRP-4 Chapter 11: IRP Advisory Group Statement of Position

11 IRP ADVISORY GROUP STATEMENT OF POSITION

Throughout the IRP-3 planning process, HECO sought the suggestions and comments from not only the Advisory Group members, but also the public. HECO took all the suggestions and comments under advisement in developing the Benchmark and Preferred Plan. The final Advisory Group meeting was held on August 5, 2008 where HECO presented its Preferred Plan and Action Plan, and asked for feedback from the Advisory Group members. The meeting minutes and Advisory Group members’ comments are provided in Appendix F. HECO also invited all members of the Advisory Group to submit Statements of Position or final comments on the IRP-4 process and the HECO’s IRP-4 Preferred Plan by September 5, 2008. The Advisory Group members were informed that these Statements of Position or final comments were to be included in the HECO IRP-4 report as a way to increase transparency and understanding of the complexities of the issues discussed during the IRP-4 process. One Advisory Group member submitted a Statement of Position that in support of the overall tone and direction of the plan, and includes detailed comments and questions for HECO to consider as it prepares the actual plan. The Statement of Position is included below:

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Docket No. 2007-0084 11-6 September 2008