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Committee on Alternatives to Indian Point for Meeting Energy Needs, National Research Council: Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs
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http://www.nap.edu/catalog/11666.html Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs Committee on Alternatives to Indian Point for Meeting Energy Needs, National Research Council

Committee on Alternatives to Indian Point for Meeting Energy Needs Board on Energy and Environmental Systems Division on Engineering and Physical Sciences ALTERNATIVES TO THE Indian Point Energy Center FOR MEETING NEW YORK ELECTRIC POWER NEEDS Copyright © National Academy of Sciences. All rights reserved.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

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Washington, DC 20001 NOTICE: The project that is the subject of this report was approved by the Governing Board of the National Research Council, whose members are drawn from the councils of the National Academy of Sciences, the National Academy of Engineering, and the Institute of Medicine. The members of the committee responsible for the report were chosen for their special competences and with regard for appropriate balance.

This report and the study on which it is based were supported by Contract No. DE-AT01-04TD45037 (Task Order No. 6) from the U.S. Department of Energy. Any opinions, findings, conclusions, or recommendations expressed in this publication are those of the author(s) and do not necessarily reflect the view of the organizations or agencies that provided support for the project.

International Standard Book Number: 0-309-10172-7 Cover: The transmission network links generating plants, including Indian Point, with demand centers in all parts of New York State. Map courtesy of the New York State Independent System Operator. Indian Point Energy Center image courtesy of Entergy Corporation.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

The National Academy of Sciences is a private, nonprofit, self-perpetuating society of distinguished scholars engaged in scientific and engineering research, dedicated to the furtherance of science and technology and to their use for the general welfare. Upon the authority of the charter granted to it by the Congress in 1863, the Academy has a mandate that requires it to advise the federal government on scientific and technical matters.

Dr. Ralph J. Cicerone is president of the National Academy of Sciences.

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The National Research Council was organized by the National Academy of Sciences in 1916 to associate the broad community of science and technology with the Academys purposes of furthering knowledge and advising the federal government. Functioning in accordance with general policies determined by the Academy, the Council has become the principal operating agency of both the National Academy of Sciences and the National Academy of Engineering in providing services to the government, the public, and the scientific and engineering communities. The Council is administered jointly by both Acad-emies and the Institute of Medicine. Dr. Ralph J. Cicerone and Dr. Wm. A. Wulf are chair and vice chair, respectively, of the National Research Council.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

v COMMITTEE ON ALTERNATIVES TO INDIAN POINT FOR MEETING ENERGY NEEDS LAWRENCE T. PAPAY, NAE,1 Consultant, Chair DAN E. ARVIZU, National Renewable Energy Laboratory JAN BEYEA, Consulting in the Public Interest PETER BRADFORD, Bradford Brook Associates, Ltd.

MARILYN A. BROWN, Oak Ridge National Laboratory ALEXANDER E. FARRELL, University of California, Berkeley SAMUEL M. FLEMING, Consultant GEORGE M. HIDY, Envair/Aerochem JAMES R. KATZER, NAE, Consultant PARKER D. MATHUSA, New York State Energy Research and Development Authority TIMOTHY MOUNT, Cornell University FRANCIS J. MURRAY, JR., Consultant D. LOUIS PEOPLES, Nyack Management Company, Ltd.

WILLIAM F. QUINN, Argos Utilities LLC DAN W. REICHER, New Energy Capital Corporation JAMES S. THORP, NAE, Virginia Polytechnic Institute and State University JOHN A. TILLINGHAST, NAE, Tillinghast Technology Interests, Inc.

Project Staff Board on Energy and Environmental Systems (BEES)

ALAN CRANE, Study Director DUNCAN BROWN, Senior Program Officer (part time)

JAMES J. ZUCCHETTO, Director, BEES PANOLA GOLSON, Program Associate Consultants General Electric International, Inc.

Optimal Energy, Inc.

1NAE, National Academy of Engineering.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

BOARD ON ENERGY AND ENVIRONMENTAL SYSTEMS DOUGLAS M. CHAPIN, NAE,1 MPR Associates, Inc., Chair ROBERT W. FRI, Resources for the Future (senior fellow emeritus), Vice Chair RAKESH AGRAWAL, NAE, Purdue University ALLEN J. BARD, NAS,2 University of Texas, Austin DAVID L. BODDE, Clemson University PHILIP R. CLARK, NAE, GPU Nuclear Corporation (retired)

MICHAEL L. CORRADINI, NAE, University of Wisconsin, Madison E. LINN DRAPER, JR., NAE, American Electric Power, Inc. (emeritus)

CHARLES GOODMAN, Southern Company DAVID G. HAWKINS, Natural Resources Defense Council MARTHA A. KREBS, California Energy Commission DAVID K. OWENS, Edison Electric Institute WILLIAM F. POWERS, NAE, Ford Motor Company (retired)

TONY PROPHET, Carrier Corporation MICHAEL P. RAMAGE, NAE, ExxonMobil Research and Engineering Company (retired),

MAXINE SAVITZ, NAE, Honeywell, Inc. (retired)

PHILIP R. SHARP, Harvard University SCOTT W. TINKER, University of Texas, Austin Staff JAMES J. ZUCCHETTO, Director DUNCAN BROWN, Senior Program Officer (part time)

ALAN CRANE, Senior Program Officer MARTIN OFFUTT, Senior Program Officer DANA CAINES, Financial Associate PANOLA GOLSON, Program Associate JENNIFER BUTLER, Financial Assistant 1NAE, National Academy of Engineering.

2NAS, National Academy of Sciences.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

vii Preface The Indian Point Energy Center, with two operational nuclear reactors, is in a densely populated region about 40 miles north of midtown Manhattan. On September 11, 2001, one of the hijacked planes flew past the plant on the way to the World Trade Center. This incident heightened concerns that a terrorist attack on the reactors or the spent fuel pools might cause a catastrophic release of radioactivity and led to calls for the plant to be closed.

The Indian Point Energy Center is a vital part of the sys-tem supplying electricity to the New York City region. Any significant interruption of power to New York City also could have serious consequences, as shown by the relatively brief blackout that occurred in August 2003. The system de-livering power to New York City consumers must be highly reliable, and that depends on having adequate generating ca-pacity available.

This dichotomy led the U.S. Congress to request a study from the National Academies on potential options for re-placing the energy services provided by Indian Point. The request, initiated by Representative Nita M. Lowey of New Yorks 18th District, was directed to the U.S. Department of Energy, which in turn arranged for the study with the Na-tional Research Council (NRC) of the National Academies.

The NRC established the Committee on Alternatives to Indian Point for Meeting Energy Needs to conduct the study.

Committee members were selected from industry, academia, national laboratories, and other organizations for their ex-pertise on electric power technology and systems and on is-sues specific to New York. Biographical sketches of the com-mittee members are presented in Appendix A.

The committee was charged with fulfilling the following statement of task:

The National Academies National Research Council will form a committee to review options for replacing current electric power generation from the Indian Point Energy Cen-ter (New York) nuclear facilities with alternative means for meeting electric power demand and associated energy ser-vices. The study may include consideration of fossil-fuel-based options (e.g., coal-fired or natural-gas-fired power generation), renewable-energy-based options (e.g., wind, solar, biomass), imports of required electrical energy, and energy efficiency measures, or some combination thereof.

The study should include an assessment of the pros and cons of the alternatives to the continued operation of the Indian Point nuclear power plants. The study will not result in the choice of an option but will compare options based on the criteria adopted by the committee.

In 2005, the committee met twice in Washington, D.C.,

and once in White Plains, New York, to gather information from public sources. The committee was particularly inter-ested in the feasibility of implementing the various options on a scale sufficient to replace the 2,000 megawatts of elec-tric power now produced by Indian Point and to address the resulting economic, environmental, and societal impacts. It procured the services of General Electric International, Inc.,

to model the New York electric system and how the options would affect reliability. It also contracted with Optimal En-ergy, Inc., to detail the efficiency improvements that could be made in the New York City area, based on its statewide assessment for the New York State Energy Research and Development Authority. The committee also met twice in closed session to discuss results and progress on this report and held numerous conference calls. Details of the meetings are provided in Appendix B.

The report focuses exclusively on options for replacing current electric power generation and ancillary services from Indian Point. In accordance with the original request, it does not examine the potential for terrorist attacks on Indian Point, nor their probability of success or possible consequences. It makes no recommendations as to whether Indian Point should be closed or how that decision could be implemented.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

viii PREFACE vide the other services required to maintain the reliability of the electric system should a decision be made to close the Indian Point plant.

This report presents the committees findings. It is the result of a great deal of effort on the part of many highly qualified experts. I greatly appreciate the efforts by the com-mittee members and their enthusiasm, dedication, and in-sights in conducting this study and preparing the report. The committee operated under the auspices of the NRC Board on Energy and Environmental Systems and is grateful for the able assistance of James Zucchetto, Alan Crane, Panola Golson, and Duncan Brown of the NRC staff.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

Acknowledgments The Committee on Alternatives to Indian Point for Meet-ing Energy Needs is grateful to the many individuals who contributed their time and effort to the National Academies National Research Council (NRC) study. The presentations at committee meetings provided valuable information and insight on energy options and constraints in the New York area. The committee thanks the following individuals who provided briefings:

Beth Tritter, Office of Congresswoman Nita M. Lowey, Philip Overholt, U.S. Department of Energy, John Kucek, Oak Ridge National Laboratory, Lawrence Pakenas, New York State Energy Research and Development Authority, John Plunkett, Optimal Energy, Inc.,

Randall Swisher, American Wind Energy Association, Harry Vidas, Energy and Environmental Analysis, Inc.,

Philip Fedora, Northeast Power Coordinating Council, Bill Quinn, Argos Utilities, LLC, Juanita Haydel, ICF Consulting, Michael R. Kansler, Entergy Nuclear Northeast, Steve Mitnick, Conjunction, LLC, Howard Tarler, New York State Department of Public

Service, The Honorable Andrew J. Spano, Westchester County Executive, The Honorable Michael Kaplowitz, Westchester County Board of Legislators, Bruce Biewald, Synapse Energy Economics, Inc.,

Alex Matthiessen, Riverkeeper, Fred Zalcman, Pace Law School Energy Project, Garry Brown, New York Independent System Operator, Michael Forte, Consolidated Edison, Carl Seligson, Economic and Strategic Consultant, N.Z. Shilling, GE, and Paul A. DeCotis, New York State Energy Research and Development Authority.

This report has been reviewed in draft form by individu-als chosen for their diverse perspectives and technical exper-tise, in accordance with procedures approved by the NRCs Report Review Committee. The purpose of the independent review is to provide candid and critical comments that will assist the institution in making its published report as sound as possible and to ensure that the report meets institutional standards for objectivity, evidence, and responsiveness to the study charge. The review comments and draft manuscript remain confidential to protect the integrity of the delibera-tive process. We wish to thank the following individuals for their review of this report:

David Bodde, Clemson University, William L. Chameides (NAS), Environmental Defense, Douglas M. Chapin (NAE), MPR Associates, Inc.,

Michehl R. Gent, Summit Power, Leonard S. Hyman, RJ Rudden Associates, Paul Komor, University of Colorado, Gerald L. Kulcinski, University of Wisconsin, Harold N. Scherer, Jr. (NAE), Board of Directors, New York Independent System Operator, Robert J. Thomas, Cornell University, Harry Vidas, Energy and Environmental Analysis, Inc.,

Carl Weinberg, Weinberg Associates, and Irvin L. (Jack) White, formerly with Pacific Northwest National Laboratory and New York State Energy Research and Development Authority.

Although the reviewers listed above have provided many constructive comments and suggestions, they were not asked to endorse the conclusions or recommendations, nor did they see the final draft of the report before its release. The review of this report was overseen by George Hornberger (NAE),

University of Virginia. Appointed by the National Research Council, he was responsible for making certain that an inde-pendent examination of this report was carried out in accor-ix Copyright © National Academy of Sciences. All rights reserved.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

x ACKNOWLEDGMENTS dance with institutional procedures and that all review com-ments were carefully considered. Responsibility for the final content of this report rests entirely with the authoring com-mittee and the institution.

The committee offers special thanks to Mark Sanford, Gene Hinkle, and Gary Jordan at GE Energy and to John Adams and William Lamanna at the New York Independent System Operator for their efforts on the committees sce-nario analysis. The committee also benefited from an analy-sis of energy efficiency opportunities by John Plunkett and Optimal Energy, Inc.

The committee is also very appreciative of the contribu-tions of Erin Hogan, Paul DeCotis, and John Spath of the New York State Energy Research and Development Author-ity; Benjamin Sovacool of Oak Ridge National Laboratory; and Lynn Billman, Robert Margolis, Brian Parsons, Ralph Overend, Rich Bain, Phil Shepherd, and Walter Short of the National Renewable Energy Laboratory.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

xi Contents ABSTRACT 1

SUMMARY

AND FINDINGS 3

1 INTRODUCTION 8

Background, 8 Electricity Supply and Demand, 8 The Indian Point Energy Center: Description and Role, 14 Community Concerns, 14 Criteria for Evaluating Replacement Options, 15 Conduct of the Study, 16 Organization of the Report, 17 References, 17 2 DEMAND-SIDE OPTIONS 18 Demand Growth in the Indian Point Service Area, 18 Potential of Demand-Side Options, 20 Definition of Demand-Side Options and Measures of Potential, 21 Current Programs Operating in the Indian Point Territory, 23 The Potential for Additional Energy-Efficiency Improvements, 26 The Potential for Future Demand Response, 27 The Potential for Expanded Combined Heat and Power, 29 The Potential for Expanded Distributed Photovoltaics, 29 Summary, 30 Impediments to Demand-Side Programs, 31 References, 33 3 GENERATION AND TRANSMISSION OPTIONS 35 Existing Generating Capacity, 35 Potential New Generating Capacity, 36 Technologies Considered, 36 Overall Considerations, 40 Electrical Transmission, 40 Existing Transmission, 40 New Transmission, 41 Reliability and Reactive Power, 42 Reliability, 42 Reactive Power, 43 References, 43 Copyright © National Academy of Sciences. All rights reserved.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

xii CONTENTS 4 INSTITUTIONAL CONSIDERATIONS AND CHANGING IMPACTS 44 Regulation, Finance, and Reliability, 44 The New York State Electricity Market, 44 The Permitting Process with Article X, 50 Social Concerns, 51 Environmental Regulation, 51 Energy Security, 56 Socioeconomic Factors Including Indirect Costs to the Public, 56 References, 57 5 ANALYSIS OF OPTIONS FOR MEETING ELECTRICAL DEMAND 59 The NYISO Starting Point, 59 The Committees Reference Case, 60 Replacement Scenarios, 62 Results of Reliability Analyses, 63 Operational and Economic Impacts, 66 Analytical Considerations, 67 Fuel Diversity: Impact on NYCA Reliance on Natural Gas for Generating Electricity, 68 Projected Impact on the Wholesale Price of Electricity, 69 Impact on the Annual Variable Cost of Producing Electricity, 71 Sensitivity to Higher Fuel Prices, 72 Comparing the Results with Criteria, 73 References, 74 APPENDIXES1 A Committee Biographical Information 77 B Presentations and Committee Meetings 82 C Acronyms 84 D Supply Technologies 86 D-1 Cost Estimates for Electric Generation Technologies, 87 D-2 Zonal Energy and Seasonal Capacity in New York State, 2004 and 2005, 94 D-3 Energy Generated in 2003 from Natural Gas Units in Zones H Through K, 104 D-4 Proposed Pipeline Projects in the Northeast of the United States, 105 D-5 Coal Technologies, 106 D-6 Generation TechnologiesWind and Biomass, 110 D-7 Distributed Photovoltaics to Offset Demand for Electricity, 118 E Paying for Reliability in Deregulated Markets 124 F Background for the System Reliability and Cost Analysis 144 F-1 The NYISO Approach, 145 F-2 Notes on the MARS-MAPS Simulations, 148 G Demand-Side Measures 169 G-1 Demand Reduction, 170 G-2 Estimating the Potential for Energy-Efficiency Improvements, 171 G-3 Estimating Demand-Response Potential, 175 G-4 Estimating Photovoltaics for Demand Reduction, 176 1Appendixes D through G are reproduced on the CD-ROM that contains the full report but are not included in the printed report owing to space limitations.

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Tables, Figures, and Boxes xiii TABLES 2-1 Weather-Normalized Annual Electricity Use, Past and Forecast, in Giga-watt-Hours per Year, for Three New York Regions and Statewide, Selected Years from 1993 Through 2015, 19 2-2 Weather-Normalized Summer Peak Power, Past and Forecast, in Mega-watts, for Three New York Regions and Statewide, Selected Years from 1993 Through 2015, 19 2-3 Current Photovoltaic (PV)-Related Policies in New York State, 24 2-4 Committee Estimation of the Potential of Energy-Efficiency Programs in New York Control Area Zones I, J, and K, Selected Years Between 2007 and 2015 (MW), 27 2-5 Committee Estimation of Potential Peak Reduction from Demand-Response Programs in New York Control Area Zones I, J, and K, Selected Years Between 2007 and 2015 (MW), 29 2-6 Committee Estimation of Potential Peak Reduction from Combined Heat and Power in New York Control Area Zones I, J, and K, Selected Years Between 2007 and 2015 (MW), 29 2-7 Committee Estimation of Potential Peak Reduction from Photovoltaics in New York Control Area Zones I, J, and K, Selected Years Between 2007 and 2015, 30 3-1 Approximate (Noncoincident) Summer Peak Load and Capacity in New York State, by Region, 35 3-2 Potential Generating Technologies Considered by the Committee for Re-placing Indian Point, 37 3-3 Nominal Transfer Capability Between New York Regions, 41 4-1 Estimated Future Emission Allowance Prices, 54 4-2 Annual Costs for Allowances to Replace Indian Point Generation, Without CO2 Control (Regional Greenhouse Gas Initiative Baseline Scenario, No CO2 Control), 55 4-3 Annual Costs for Allowances to Replace Indian Point Generation with CO2 Control (Regional Greenhouse Gas Initiative Reference Scenario), 55 5-1 NYISO Base Case Peak Load and Known New York Control Area (NYCA)

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xiv TABLES, FIGURES, AND BOXES 5-3 Capacity Additions Assumed for Cases b2 and c2, 64 5-4 Summary of Illustrative Resources Assumed to Maintain NYCA Reliability, 64 5-5 Results of Reliability Analyses, 65 5-6 Benchmark of the Consumption of Natural Gas, Coal, and Oil for 2005 and 2008: Annual Fuel Consumption in Trillion Btu, 69 5-7 Projected Impact on Electrical Generation Based on Natural Gas for 2008 to 2015, with Sensitivity to Fuel Price, 69 5-8 MAPS-Projected Impact on Electricity Wholesale Price, 70 5-9 Projected Impact on Annual Variable Operating Cost, 72 D-1-1 Summary Cost Estimates: Total Cost of Electricity (in 2003 U.S.

dollars per kilowatt-hour) for Generating Technologies Examined by the Committee, 87 D-1-2 Cost Components for Electricity Generation Technologies, 88 D-1-3a Energy Information Administration National Average Cost Estimates (2003 dollars), 89 D-1-3b Energy Information Administration National Average Cost Estimates (2003 dollars), 90 D-1-4a Energy Information Administration Regional Cost Estimates (2003 dollars), 91 D-1-4b Energy Information Administration Regional Cost Estimates (2003 dollars), 92 D-1-5 University of Chicago National Average Cost Estimates (2003 dollars), 92 D-1-6 University of Chicago Regional Cost Estimates for the New York Control Area (2003 dollars), 93 D-1-7 New York City Fuel Prices ($/MMBtu), 93 D-2-1 Summary of Summer and Winter Capacity, Energy Production, and Energy Requirements in the New York Control Area, by Zone, 94 D-2-2 Summer Zonal Capacity, by Fuel, 2004 and 2005, 95 D-2-3 Winter Zonal Capacity, by Fuel, 2004 and 2005, 96 D-2-4 Annual Energy Production, by Fuel, 2004 and 2005, 97 D-2-5 Summary of New York Control Area Generation Facilities Energy Production by Fuel Type as of January 1, 2005, 98 D-2-6 Summary of New York Control Area Generation Facilities Winter Capacity, by Fuel Type, as of January 1, 2005, 99 D-2-7 Summary of New York Control Area Generation Facilities Summer Capacity, by Fuel Type, as of January 1, 2005, 100 D-2-8 Summary of New York Control Area Generation Facilities Energy, by Fuel Type, as of January 1, 2004, 101 D-2-9 Summary of New York Control Area Generation Facilities Winter Capacity, by Fuel Type, as of January 1, 2004, 102 D-2-10 Summary of New York Control Area Generation Facilities Summer Capacity, by Fuel Type, as of January 1, 2004, 103 D-3-1 Natural Gas Consumption for Electricity in Zones H Through K, 2003, 104 D-3-2 Natural Gas Consumption for Electricity in Zones H Through K, 2004, 104 D-3-3 Estimated Natural Gas (NG) Consumption of a 2,000 MW Combined-Cycle Unit with a 95 Percent Capacity Factor, 104 D-5-1 Electricity Cost from Coal with Emissions Controls, 108 D-6-1 Estimate of Potential Impact of Renewable Generation Technologies on Indian Point Service Area, 111 D-6-2 Quantitative Estimates of Wind Potential in Indian Point Zones, 113 Copyright © National Academy of Sciences. All rights reserved.

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TABLES, FIGURES, AND BOXES xv D-6-3 Biomass Potential Applicable to Indian Point, 115 D-7-1 Estimated Distributed Photovoltaics in the Indian Point Service Area in the Accelerated Deployment Scenario, 118 D-7-2 Current and Projected Distributed PV Cost (2005 dollars), 120 D-7-3 Current PV Related Policies in New York State, 121 D-7-4 Accelerated PV Deployment Scenario for New York (2005 dollars), 123 E-1 Locational ICAP Requirements and Installed Capacity for NYCA in 2005-2006, 130 E-2 The Capacity Factors in 2003 of Major Generating Units in New York City and Long Island, 135 E-3 New Generating Units Proposed for the NYCA in 2004, 141 E-4 New Generating Units Proposed for the NYCA in 2005, 142 F-2-1 NYISO Initial Base Case Capacity Details Adopted for the MARS Analysis, 150 F-2-2 Electricity Generation Load and Capacity Representing NYISO Initial Base Case, 151 F-2-3 NYISO Initial Base CaseQualifying Additions to Capacity (MW), 153 F-2-4 Committees Screening StudyEarly Shutdown with Assumed Compensation from Planned NYCA Projects and Added Energy-Efficiency and Demand-Side-Management Measures (MW), 154 F-2-5 Committees Screening StudyEnd-of-License Shutdown with Assumed Compensation from Planned NYCA Projects and Added Energy-Efficiency and Demand-Side-Management Measures (MW), 155 F-2-6 NYISO Initial Base Case with Alternate New England Transmission ConstraintsProjected NYCA Reliability Loss-of-Load Expectation (LOLE) and Reserve Margin, 155 F-2-7 Committees Screening Study: Impact on Reliability and Reserve Margins of Shutting Down Indian Point Without Adding Compensatory Resources: Comparison of the NYISO Initial Base Case with Early-Shutdown and End-of-Current-License Shutdown Cases, 156 F-2-8 Committees Screening Study: Impact on Reliability and Reserve Margins of Shutting Down Indian Point and Adding Compensatory Resources from Announced Projects, Beyond NYISO Initial Base Case (Table F 3): Comparison of Early Shutdown and End-of-Current-License Shutdown, 157 F-2-9 Reference Case: Illustrative Additional Resources Beyond the NYISO Initial Base Case to Meet Load Growth and Scheduled Retirements and Ensure Reliability Criteria Are Met, and Including Reliability Results If Indian Point Is Closed Without Further Compensation, 158 F-2-10 Early Shutdown of Indian Point with Compensatory Resources, Case b2, 159 F-2-11 End-of-Current-License Shutdown of Indian Point with Compensatory Resources, Case c2, 160 F-2-12 Early Shutdown of Indian Point with High-Voltage Direct Current (HVDC) Cable, Case b3, 161 F-2-13 End-of-Current-License Shutdown of Indian Point with Compensatory Resources Including 1,000 MW HVDC Transmission Lines, Case c3, 162 F-2-14 Early Shutdown of Indian Point with Higher Efficiency and Demand-Side Management, Case b4, 163 Copyright © National Academy of Sciences. All rights reserved.

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xvi TABLES, FIGURES, AND BOXES F-2-15 End-of-Current-License Shutdown of Indian Point with Higher Efficiency and Demand-Side Management, Case c4, 164 F-2-16 Early Shutdown Without Compensatory Resources Beyond the Reference CaseImpact on NYCA Reliability (Loss-of-Load Expectation) and Reserve Margin, Case b1, 165 F-2-17 End-of-Current-License Shutdown Without Compensatory Resources Beyond the Reference CaseImpact on NYCA Reliability (Loss-of-Load Expectation) and Reserve Margin, Case c1, 165 F-2-18 Committees Reference CaseImpact on NYCA Reliability (Loss-of-Load) Expectation and Reserve Margin, 165 F-2-19 Early Shutdown with Additional Compensatory ResourcesImpact on NYCA Reliability and Reserve Margin, Case b2, 165 F-2-20 End-of-Current-License Shutdown with Additional Compensating ResourcesImpact on NYCA Reliability and Reserve Margin, Case c2, 166 F-2-21 Additional Compensatory Resources, Including 1,000 MW North-South HVDC Transmission LineImpact on NYCA Reliability and Reserve Margin, Cases b3 and c3, 166 F-2-22 Additional Compensatory Resources, Including Higher Energy Efficiency and Demand-Side-Management PenetrationImpact on NYCA Reliability and Reserve Margin, Cases b4 and c4, 166 F-2-23 Projected Impact on the Annual Variable Cost of Operation for the Northeast Region, NYCA, and Zones H Through K: All Scenarios, 2008-2015, Including Percentage Change from Benchmark of 2008 NYISO Initial Base Case, 167 G-1-1 Economic Potential: Annual Savings (in megawatt-hours) for Top Eight Residential Energy-Efficiency MeasuresZones J and K, 2007, 2012, and 2022, 170 G-1-2 Economic Potential: Annual Savings (in megawatt-hours) for Top Ten Commercial Energy-Efficiency MeasuresExisting Construction End Use in Zones J and K, 2007-2022, 170 G-4-1 Current and Projected Distributed PV Cost, 177 G-4-2 Accelerated PV Deployment Scenario for the New York City Area, 177 FIGURES S-1 New York Control Area load zones, 4 1-1 The New York Control Area high-voltage transmission network, 10 1-2 Average daily load and peak hour load in New York City, 11 1-3 New York Control Area load zones, 12 1-4 Generating capacity in the NYCA, by fuel type, 2005, 13 1-5 Capability of generating plants by NYCA zone and generator type, 13 2-1 Past and projected trends in real residential electricity price in New York state relative to 1980, 20 2-2 Effects of demand-reduction programs on daily power demand, 21 2-3 Global photovoltaic market evolution, by market segment, 1985 to 2004, 23 2-4 Phased-in programmable potential for expanded demand-side options in the Indian Point service territory (in megawatts of peak reduction), 30 Copyright © National Academy of Sciences. All rights reserved.

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TABLES, FIGURES, AND BOXES xvii 4-1 Projections made by NYISO in 2004 and 2005: summer reserve margin for generating capacity in the New York Control Area, 49 5-1 NYISO reliability projections, 61 5-2 Approximate additional resources needed, 63 5-3 Impact on NYCA reliability loss of load (LOLE) of shutting down Indian Point without additional resources beyond the reference case, 63 5-4 Capacity assumed to meet load growth and compensate for retiring Indian Point, 66 5-5 Loss-of-load expectation after compensation, 66 5-6 Projected reserve margin for End-of-License (EOL) Shutdown of Indian Point with Compensation (Case c2), 67 D-4-1 Proposed Northeast pipeline projects, 105 D-5-1 Emissions control options for coal-fired generation, 106 D-5-2 Past and projected U.S. emissions from fossil power generation, 1965 to 2030, 107 D-5-3 Types of power plants, 108 D-7-1 Global PV market evolution by market segment, 1985 to 2004, 119 D-7-2 An accelerated PV market development path for New York (all estimates are 2005 dollars), 122 E-1 North American additions in historical perspective, 126 E-2 Locational installed capacity requirements for Long Island and New York City for 2005-2006, 130 E-3 Average total cost of production (in dollars per megawatt-hour generated) for a representative peaking unit, 132 E-4 Daily zonal spot prices ($/MWh), January 2000 to July 2005, for New York City in the balancing (real-time) market at 2:00 p.m. on the first day of each month shown, 133 E-5 Average price-duration curves in the balancing market for May-April in New York City (in dollars per megawatt-hour) for 2000-2001, 2002-2003, and 2004-2005, 134 E-6 Projections made in 2004 and 2005 of the summer reserve margin for generating capacity in the New York Control Area, 140 G-4-1 Accelerated PV market development path for the New York City area, 178 BOXES 1-1 Keeping Competitive Markets Operating, 9 4-1 The Cost of Replacing Indian Point: In Theory, 45 4-2 The Cost of Replacing Indian Point: In Practice, 46 5-1 Reliability Criteria, 60 5-2 Multi-Area Reliability Simulation (MARS) Model, 62 5-3 Multi-Area Production Simulation (MAPS) Software Model, 68 Copyright © National Academy of Sciences. All rights reserved.

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1 Abstract This report presents the work of the Committee on Alter-natives to Indian Point for Meeting Energy Needs. It reviews various options that are available for replacing the 2,000 megawatts of energy produced by the two nuclear reactors at Indian Point and assesses some of the requirements and im-pacts of installing the options in an appropriate time frame.

The Indian Point Energy Center is a key part of the elec-tric power system that serves New York City and densely populated surrounding areas. Maintaining reliability of elec-tric supply in the area is essential.

Even with Indian Point operating, new capacity will be needed to meet expected growth in the region and to replace other generating plant retirements. Replacing the two oper-ating Indian Point generation units would add to the com-plexity of the task. Options are constrained by various tech-nological, regulatory, financial, and infrastructure factors that must be considered in planning for a reliable electric energy supply for southeastern New York State.

Based on all of the information available to it, the com-mittee identified no insurmountable technical barriers to the replacement of Indian Points capacity, energy, and ancil-lary services. However, significant financial, institutional, regulatory, and political barriers also would have to be over-come to avoid threatening reliability. As this report dis-cusses, many replacement options exist, and if a decision were definitely made to close all or some part of Indian Point by a date certain, the committee anticipates that a technically feasible replacement strategy for Indian Point could be achievable. A replacement strategy would most likely con-sist of a portfolio of the approaches discussed in this report, including investments in energy efficiency, transmission, and new generation.

While the committee is optimistic that technical solutions do exist for the replacement of Indian Point, it is consider-ably less confident that the necessary political, regulatory, financial, and institutional mechanisms are in place to facili-tate the timely implementation of these replacement options.

The importance of this issue cannot be overstated in devel-oping options for maintaining a reliable electric energy sup-ply for the New York City metropolitan area. The report discusses in greater detail various aspects of this challenge and includes specific conclusions and findings.

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3 Summary and Findings This report presents the work of the Committee on Alter-natives to Indian Point for Meeting Energy Needs. For over a year, the committee reviewed a wide range of potential options and assessed the feasibility of implementing these options on a scale and a timetable sufficient to replace the capacity, energy, and essential ancillary services now pro-vided by the two operating nuclear reactors at Indian Point.

The committee recognizes the magnitude and the com-plexity of the issue that it was asked to study. Indian Point Units 2 and 3 provide about 2,000 megawatts (MW) of baseload generating capacity in one of the most densely populated areas in the nation. Its output represents 11 per-cent of the total generating capacity in southeastern New York (i.e., Long Island, New York City, and Westchester County) and 23 percent of the electric energy delivered in this region.

Based on all of the information available to it, the com-mittee has identified no technical obstacles that it believes present insurmountable barriers to the replacement of Indian Points capacity, energy, and ancillary services. As this re-port discusses, a wide and varied range of replacement op-tions exists, and if a decision were definitely made to close all or some part of Indian Point by a date certain, the com-mittee anticipates that a technically feasible replacement strategy for Indian Point would be achievable. Replacements for Indian Point would be in addition to generating and trans-mission capacity needed for expected growth in the region and because of other plant retirements.

The report does not propose a single solution to the replacement of Indian Point. That was neither the com-mittees directive nor its mission. Indeed, from the commit-tees analysis, no right or clearly preferable supply alter-native to Indian Point emerged. A replacement strategy for Indian Point would most likely consist of a portfolio of the approaches discussed in this report, including investments in energy efficiency, transmission, and new generation.

While the committee is optimistic that technical solutions do exist for the replacement of Indian Point, it is consider-ably less confident that the necessary political, regulatory, financial, and institutional mechanisms are in place to facili-tate the timely implementation of these replacement options.

The importance of addressing the nontechnical barriers can-not be overstated in developing options for maintaining a reliable electric energy supply for southeastern New York State. The report discusses in greater detail various aspects of this challenge and includes specific conclusions and findings.

Reliability is a key consideration, especially during peak demand. Adequate generating and transmission capacity ex-ists to replace Indian Point during nonpeak hours, although costs might be significantly higher because Indian Point is the low-cost baseload unit. Reliability of power supply de-pends on several factors, including fuel availability, genera-tion reserve, peaking load, and the growth in electric demand, both locally and regionally. An element of a reli-able electricity supply also involves the stability of the transmission-distribution system. In general, the electric system in the Northeast is carefully balanced to account for the location and operation of baseload generating plants, as well as peaking units. In southeastern New York, the reliability criteria also impose specific locational resource requirements, reflective primarily of New York City and Long Islands situation as very large demand centers at the end of the transmission grid. For these reasons, the committees analysis has focused on replacement strategies, that is, on electric energy supply and demand options, pri-marily in southeastern New York (Zones H, I, J, and K; see Figure S-1).

Adding to the complexity of choice is the issue of cost to customers and taxpayers, which could include the costs of both closing Indian Point and providing replacement re-sources. For example, if the plants life were shortened, com-pensation might be owed to the owner. Costs of maintaining site security would be required to keep the spent nuclear fuel secured. There is considerable uncertainty over how the cost of replacement resources, higher fuel prices, and air quality Copyright © National Academy of Sciences. All rights reserved.

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4 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER offsets would be addressed in a deregulated wholesale elec-tric market in which price is no longer based on the cost of production but rather on an open competitive bidding pro-cess under which all bidders get the same price as the last successful marginal winning bid. Also of concern are poten-tial indirect costs to the community at large and state and local governments, including any loss of tax base from the plant, labor dislocation, or loss of income from reduced plant operations that might be associated with the closure of the Indian Point facility.

Indian Point sits on the banks of the Hudson River whose protection has been a focal point of the American environ-mental law movement, so it is no surprise that a complex web of federal and state environmental regulations must also be considered in evaluating replacement resources for In-dian Point. These include air quality, water quality, and ther-mal discharge requirements; regulations regarding toxic re-leases; and regional and perhaps eventual federal initiatives to reduce greenhouse gas emissions. New power plants can be permitted only under the most stringent environmental review processes, and such projects are also subject to local zoning and land use controls.

CONCLUSIONS AND FINDINGS The issues associated with the potential shutdown of In-dian Points two operating nuclear units are complex and interrelated. These issues impact the total energy system for New York State, the Northeast region, and beyond. Any analysis of the consequences and potential alternatives to the closure of Indian Point units cannot occur in a vacuum without reference to the context of other events unfolding in the state.

In analyzing replacement options for Indian Point, the committee examined the broader profile of New York States electric power system to identify what, if any, other existing resources might be available to replace some portion of the energy and capacity now provided by Indian Point. Most germane to its evaluation of replacement options for Indian Point, the committee learned that even with the Indian Point units operational, New York State will require system rein-forcements, above those already under construction, as soon as 2008 in order to meet its projected demand for electricity and maintain system reliability in the Lower Hudson Valley and New York City area served by the Indian Point units.

The states need for additional electric power resources in-creases rapidly thereafter. Based on currently scheduled re-tirements and demand growth projections by the New York Independent System Operator (NYISO), 1,200 to 1,600 MW from new projects that are not yet under construction could be needed by 2010, and a total of 2,300 to 3,300 MW by 2015. Closing Indian Point would increase by 2,000 MW New Yorks need for additional electric resources, which could be in the form of new generating capacity, transmis-sion lines, improved energy efficiency, and demand-side management.

This need for new resources is occurring at a time when it is problematic whether the existing legal, regulatory, and fi-nancial mechanisms provide sufficient incentive to build new resources in New York. The committee estimates that the generating capacity currently under construction will be in-sufficient to meet projected peak demand in 2009, given cur-rently announced retirements. With the expiration in 2003 of its siting statute, Public Service Law Article X, New York State has no law designed to facilitate an integrated environ-mental review and siting of new power plants. NYISO has A

B B

E G

H F

E D

C I

K J

FIGURE S-1 New York Control Area load zones. SOURCE: New York Independent System Operator.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

SUMMARY

AND FINDINGS 5

just completed its first Comprehensive Reliability Planning Process, and as this report explains in detail, it remains to be seen whether NYISOs new market and pricing rules will provide sufficient economic incentives to stimulate invest-ment in new electric resources. Developers and financial markets will look for investment opportunities with the best combination of high payback and low risk, whether they are in New York or not. If price signals in New York are low, the markets will wait until they rise. Given the time that it takes to obtain a suitable site, navigate the regulatory issues and obtain permits, and then construct a power plant, new generating capacity may not be available until reserves are dangerously low. Forestalling a crisis may require extraordi-nary efforts on the part of policy makers and regulators.

The committee examined two time frames for the pos-sible closure of Indian Point: (1) when the current operating licenses expire for the two reactors in 2013 and 2015; and (2) an accelerated schedule of 2008 and 2010. The general conclusions that the committee reached concern the overall ability to replace the capacity and energy required if the In-dian Point units were shut down in either of the two time frames. The committee also reached agreement on eight spe-cific findings associated with generation, transmission, and demand-side options; reliability; physical and political in-frastructure; the environment; and cost considerations if an early shutdown of Indian Point is effected. The committee emphasizes that the inability to successfully meet any of the requirements set forth in its eight findings would place the general conclusions in jeopardy.

General Conclusion (2013-2015)

The committee concludes that with sufficient time, planning, authority, and investment incentives, options are possible for replacing Indian Point. The Indian Point units could be retired at the end of their current operat-ing licenses (2013 and 2015) without causing a major dis-ruption of power capacity in southeastern New York if sufficient resources were added by 2015 to cover antici-pated system retirements and the expected growth in de-mand, as well as the shutdown of Indian Point. To achieve this goal, the committee estimates that an additional 5,000 to 5,500 MW, or roughly 500 MW per year, in new resources (a combination of generation, transmission, and demand-side actions) would need to be added by 2015.1 The 3,300 MW in new resources that are estimated to be required even if Indian Point continues to operate is less than 10 percent of New Yorks current capacity, and it should be achievable over the next 9 years. The additional 2,000 MW of new resources required if Indian Point is closed should also be achievable if the conditions discussed below are met.

General Conclusion (2008-2010)

The committee concludes that an earlier shutdown of the Indian Point units would be much more difficult to accomplish. In 2008, when Unit 2 (1,000 MW) would be closed, New York will have very little if any excess capac-ity. To replace it, the committee estimates the need for an additional 700 MW in generating capacity, assuming that demand-side programs could reduce peak demand by several hundred megawatts. By 2010, with the closure of the second unit (1,000 MW), an additional 1,300 to 1,400 MW in replacement generating capacity would be needed, assuming that demand-side measures would con-tinue to increase, totaling 650 MW in peak-demand re-ductions. That is in addition to the 1,200 to 1,600 MW that will be needed even with Indian Point operating. In the committees view, this extraordinary challenge could only be met with the firm commitment of a variety of New York government leaders and tight cooperation among many agencies. Such collaboration may be un-precedented, so the difficulty of achieving it should not be underestimated. The impacts discussed for the 2013-2015 scenario would be magnified, with potentially even greater added costs. If new generating capacity is not constructed in a timely manner, system reliability would be threatened. Not only could reserve margins drop be-low standards, but existing generating units would likely show lower reliability as they are run beyond their nor-mal operation schedule.

Finding 1: Governmental Mechanisms and Regulatory Policy The committee recognizes that maintaining a reliable sup-ply of electricity for New York City and southeastern New York State is a primary objective for public policy and es-sential to the regions health and economic well-being. How-ever, the committee finds that current governmental mecha-nisms and regulatory policy may limit New York States ability to address in a timely and effective manner the capac-ity, energy, and ancillary consequences of closing Indian Point. The committee finds that in order to provide alterna-tives to Indian Point Units 2 and 3, a more considered long-range strategy is likely to be necessary. This strategy would be based on a detailed assessment of the current market struc-ture and might well require significant changes in New Yorks current laws and regulatory policies, such as reautho-rization of the states Article X power plant siting process and reestablishment of the State Energy Planning Board and 1All projections in this report should be understood to be approximate at best. Not only are estimates of load growth uncertain, but assumptions of where new generating and transmission capacity will be added, constraints on system operations, and the analytical methodology that is used would all affect the estimates of reliability and the calculated need for new capacity.

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6 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER the state energy planning process, in order to ensure the con-tinued reliability of the states electric system.

Finding 2: Market and Financial Uncertainties The committee notes that even with the continued opera-tion of the Indian Point units, New York State already faces challenges in satisfying the projected growth in its electric demand and in maintaining system reliability. While con-ceptual planning to address these needs is under way through the New York Independent System Operator and other enti-ties, the response of electric power developers, suppliers, and distributors is uncertain, given the current state of evolu-tion of New Yorks market. Indian Point represents a signifi-cant asset, both in terms of capacity and energy, especially for electric customers in southeastern New York, and if In-dian Point is retired, replacement of its 2,000 MW capacity will place a substantial additional burden on the states elec-tric supply system.

Finding 3: Transmission Options The committee finds that improvements in transmission capability could significantly relieve congestion in the New York system and facilitate the delivery of power from exist-ing and potential electric generation resources to the New York City area. Such improvements should include modifi-cations to the states existing transmission system and the possible installation of new direct current transmission. A West-to-East line (550 MW) has been proposed across the Hudson River, and a new North-to-South transmission line (up to 1,000 MW) for better access to upstate and Canadian electric resources is under investigation. These lines could supply useful capacity in the 2010 and 2015 time period, respectively, if a variety of institutional and financial issues can be resolved. The committee notes that increasing the importation of power into southeastern New York would also increase the need to install additional reactive power equip-ment to maintain system voltage within the region, but this problem is relatively easy to solve.

Finding 4: Demand-Side Options The committee finds that substantial cost-effective op-portunities exist for investment in demand-side technologies that could reduce demand for electricity in southeastern New York. These could include a phase-in of programmable en-ergy efficiency and demand-response programs, along with additions of distributed generation and combined heat and power units. These could provide reductions of more than 1,100 MW from projected peak demand by 2010 and 1,700 MW by 2015. The committee notes that these offsets are ambitious and would be in addition to the current effective programs with which the New York State Energy Research and Development Authority, the New York Power Author-ity, Consolidated Edison, and the Long Island Power Au-thority are already managing demand growth. The commit-tee finds that these offsets are achievable, but only if well-designed programs are implemented promptly and ad-ditional resources are provided to overcome many obstacles.

Finding 5: Supply-Side Options The committee finds that even with substantial additional investment in new transmission facilities and aggressive de-mand-side programs, additional generating facilities, above those already planned, would be required to compensate for the shutdown of the Indian Point units to maintain system reliability. While coal may be a reasonable generating alter-native for the 2013-2015 time frame, new near-term generat-ing solutions are most likely to be a mix of simple-cycle gas turbines and combined-cycle natural gas units. The use of the former would provide a short-term solution, but in the longer term, such units would probably be relegated to peak-ing usage. Owing to the nature of the New York City metro-politan region, renewable energy technologies are unlikely to contribute significant resources by 2015, with the pos-sible exceptions of offshore wind power and distributed pho-tovoltaics.

Finding 6: Alternative Fuel Availability and Security The committee finds that the availability and price of natural gas would be major considerations, and perhaps con-straints, in planning for new generating capacity to replace power from the Indian Point units. A large share of the 2,000 MW from Indian Point would likely be replaced with natu-ral-gas-fired generating plants, and that is over and above the several thousand megawatts of new gas-fired capacity that will be needed to meet the growing demand for energy in southeastern New York State. This increase in New Yorks dependence on natural gas for power production will stress supplies of natural gas. In addition, increased dependence on natural gas will reduce diversity of fuel supply for the New York electric system, also a serious concern.

Finding 7: Cost Considerations Cost is a key consideration in evaluating any scenario for the early retirement of the Indian Point units. Three main categories must be taken into account: (1) any compensation that might be due Entergy Nuclear for the early retirement of the Indian Point units; (2) replacement costs, including new generation and transmission, demand-side programs, in-creased demand for pollution offsets, and the increased price of fuel, particularly natural gas for power production; and (3) the financial impact to Westchester County, the Town of Buchanan where Indian Point is located, and surrounding Copyright © National Academy of Sciences. All rights reserved.

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SUMMARY

AND FINDINGS 7

communities from the loss of Indian Point tax revenues and the labor-commercial base. The committee found that it is difficult to make specific cost estimates for these items. Ul-timately, the price that consumers pay for electricity in south-eastern New York will reflect some of these costs. However, given the current market structure for the sale of electric power in New York, under which wholesale prices are set on a subregional zonal basis that reflects competitive bidding behavior, the committee could not satisfactorily determine the increase in the cost of electricity to consumers that might result from the closure of Indian Point. Some costs could be offset by demand-management practices, but new genera-tion, and perhaps new transmission, will likely increase wholesale electric costs, especially in the New York City metropolitan area, depending on competitive bidding in the open wholesale market.

Finding 8: An Integrated Approach Is Needed The committee emphasizes that its findings must be con-sidered as an integrated whole. Replacements for the energy, baseload capacity, and ancillary services currently provided by the Indian Point units will not happen just because they should. The construction and operation of new electric gen-erating facilities, natural gas pipelines, liquefied natural gas facilities, or electric transmission lines will each inevitably encounter hurdles that will have to be overcome if that project is to become a reality. Each facility needs a site, fi-nancing, permits, delivery contracts, and infrastructure agreements, and has facility-specific requirements. This is also true for any demand-side programs, which have their own timing, financial, marketing, and implementation chal-lenges to be worked out in order to achieve sufficient partici-pation by the general public.

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8 1

Introduction This report presents the work of the National Research Councils (NRCs) Committee on Alternatives to Indian Point for Meeting Energy Needs. It reviews the options that are available and assesses the feasibility of installing them on a scale sufficient to replace the 2,000 megawatts (MW) of electricity from the Indian Point Energy Center.

This chapter presents background information necessary to understand how replacements would be implemented. It also reviews how the committee conducted the analysis.

BACKGROUND Electricity Supply and Demand Electricity generally cannot be stored and must be gener-ated at virtually the same instant as it is used, which requires continuous control of the system.1 New York State has an integrated bulk power system, the New York Control Area (NYCA). Formerly, the New York Power Pool had coordi-nated the activities of the utility participants on the transmis-sion system. As competition was introduced into the New York electric system, utilities were required to divest their generating assets.2 The New York Public Service Commis-sion and the Federal Energy Regulatory Commission also required a more independent electric system operator. The New York Independent System Operator (NYISO) was cre-ated to operate the high-voltage transmission system and to provide a match of load requirements to generation sources in a manner that (1) ensures the reliability of the states power system; (2) facilitates open, fair, and effective competitive markets; (3) improves regional cooperation for operations and planning; and (4) ensures nondiscriminatory access to the electric system.

NYISO uses the locational-based marginal pricing (LBMP) system to accomplish its objectives. LBMP also provides price signals to providers of new generation and transmission. Thus, NYISO has assumed the power-dispatching role that integrated utilities used to carry out within their own jurisdictions, but on a statewide level.

NYISO uses auctions to select the lowest-cost suppliers con-sistent with transmission constraints, among other func-tions. Box 1-1 lists many of the market products that NYISO must monitor. Further details are provided in Chapter 4.

Competitive markets are still evolving, and it is not yet clear exactly how to ensure both reliability and low costs.3 NYISO also plans for future growth and makes recom-mendations for additional capacity, although it does not pick specific sites or technologies. Additional capacity is mainly built by developers, or merchant generators, which could have contracts for the power from a load serving entity (LSE) or which expect to be able to compete profitably in the auc-tion. Under some conditions, the New York Power Author-ity (NYPA) can build new capacity. NYISO has issued a request for proposals to deal with concerns over potential capacity shortfalls, but that process has just begun.

1Pumped storage facilities, currently the only practical form of large-scale power storage, use low-cost off-peak power to pump water uphill to a reservoir. The flow is reversed during peak hours when the power that can be regenerated is much more valuable. However, few sites are appropriate for pumped storage. Consolidated Edison attempted to build pumped stor-age on Storm King Mountain up the Hudson River near West Point, but the project was stopped for environmental reasons. Other storage technologies, including batteries, compressed air energy storage, and superconducting magnets, are still under development to reduce costs.

2Competition was introduced in part to avoid cost increases, such as had occurred in the 1970s and 1980s because of overbuilding. Those costs had largely been passed on to customers.

3Competitive markets, or restructuring, encompass (1) allowing gen-eration to be built by nonutilities; (2) breaking up vertically integrated utili-ties; (3) independently owned and operated transmission, with some degree of open access for all suppliers; (4) spot markets for electricity; (5) retail choice for some customers in some states (including New York); and (6) a substantial shift in regulatory jurisdiction from the states to FERC. They may also include competitive bidding for power supply and the inclusion of energy efficiency in competitive power procurement processes.

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INTRODUCTION 9

BOX 1-1 Keeping Competitive Markets Operating New Yorks large and varied power system requires a very com-plex set of functions for smooth and efficient operation. NYISO con-ducts energy market auctions in two phases: (1) the Day Ahead Market establishes forward contracts for each hour of the coming day; (2) the Real Time Market is conducted when the load actually occurs to pre-cisely match supply with demand. Most energy transactions in NYISO are conducted in the Day Ahead Markets. NYISO adds up the bids starting with the lowest cost for each time interval until it has sufficient power to meet projected demand. All bidders then receive the price set by the highest accepted bidder.

Other important functions include the Installed Capacity (ICAP)

Market, which is designed to ensure that load serving entities (LSEs, such as ConEd) have sufficient capacity available to serve their cus-tomers. The following are among the NYISO market products, as de-scribed in detail on the NYISO website (www.nyiso.com):

Energy Markets Day-ahead locational-based marginal pricing (LBMP) energy Real-time LBMP energy Ancillary Services Regulation service (frequency control)

Black start capability Voltage support service (reactive power)

Installed Capacity (ICAP)

Transmission Congestion Contracts Demand Response Programs Emergency Demand Response Program Special Case Resources (SCR)

Day Ahead Demand Response Program SOURCE: www.nyiso.com; accessed March 29, 2006.

Reliability standards are set by the New York State Reli-ability Council (NYSRC) in conjunction with the Northeast Power Coordinating Council (NPCC), which operates under the North American Electric Reliability Council (NERC).

NPCC standards also apply to New England and eastern Canada, while NYSRC standards are tailored to New Yorks particular situation (e.g., requirements for generating capac-ity in New York City and Long Island). NYSRC also sets the amount of installed generating capacity (ICAP) needed to meet the required reserve margin generating capacity at peak electrical load. Reserve margin criteria are set yearly for 1 year ahead (18 percent for 2006-2007) by NYSRC, which also specifies other allowable resources (e.g., specific loads that can be shut off on NYISOs order are equivalent to gen-erating capacity for meeting peak demand) to be included in the reserve margin and correspondingly to be used in calcu-lating the reliability. Finally, the Energy Policy Act of 2005 provides that the Federal Energy Regulatory Commission (FERC) will certify a single organization (expected to be NERC) that will propose and enforce mandatory reliability standards for the bulk-power system in the United States, subject to FERC approval.

A complicated network of high-voltage transmission lines is required to deliver the bulk power to load centers, which may be hundreds of miles from the generating stations.4 The bulk power system must be controlled very precisely to keep voltage and frequency within tight bounds and to operate reliably despite the occasional component failure. It also is important to keep the cost of electricity as low as possible, in part by operating the lowest-cost plants as much as possible.

The NYCA has about 38,000 MW of installed capacity within New York State and 4,000 miles of high-voltage transmission lines. Power also can be traded with intercon-nected control areas in New England, the Mid-Atlantic re-gion, and Canada. The NYCA high-voltage transmission system, including major substations, is shown in Figure 1-1.

Power demand fluctuates both during the day and over the year, as shown in Figure 1-2, so a variety of generating plants must be available to follow the load, including:

Baseload plants, to meet the steady part of the load.

Baseload facilities (such as the Indian Point units) produce power inexpensively. They typically operate all day and most of the year. They are generally nuclear or coal-fired steam generators. The Indian Point units are an important generat-ing resource in the NYCA owing to their low cost and their location near the load centers in New York City and Westchester County.

Peaking plants for periods of high demand. Combus-tion turbines, for example, are often deployed in simple cycle, and are used during periods of peak demand, because they can be quickly turned on or off. The operational flex-ibility of such peaking generators, however, is counterbal-anced by their low thermal efficiencies, which makes them expensive to operate.

Intermediate units, which also follow demand but are used more than peaking plants. An intermediate generator might use a combustion turbine in combination with a steam turbine to provide a wide range of operating flexibility. Com-bined-cycle facilities are typically fueled with natural gas and often have the capability of burning oil as an alternative fuel supply when supplies of natural gas are curtailed be-cause of high demand, usually during the winter. Modern 4Low-voltage distribution lines, which are not part of the bulk power system, carry the power to the end-use customer. Most outages that con-sumers experience are due to failures in the distribution system (e.g., trees falling on overhead lines), but these usually are repaired quickly and are not part of this study.

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10 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER gas-fired combined-cycle plants5 are much more efficient than older or simple-cycle gas turbines.

NYISO has divided the NYCA into 11 zones, shown in Figure 1-3, to assist in pricing and monitoring load flows on the transmission system. The key zones for this report are these:

H, which includes the northern portion of Westchester County, where Indian Point is located;

I, the rest of Westchester County;

J, New York City; and

K, Long Island outside of New York City.

In accordance with NYSRC standards, NYISOs goal is for the bulk power system to have sufficient capacity that outages will be less than 1 day in 10 years. This loss-of-load expectation (LOLE) is determined by using statistical de-scriptions of the historical availability of each generator and Monte Carlo calculation techniques to compute the expected number of days in a 10-year period when the load could not be supplied. The LOLE is used in determining how much additional generation a given area will require for expected load growth and is likely to continue to be used if Indian Point is closed.

In addition to sufficient capacity, diversity of fuels pro-vides another element of system reliability. Excessive de-pendence on one fuel source threatens system reliability if that fuel supply encounters shortages. Figure 1-4 displays the varied contributions of different fuels to the installed capacity (in megawatts) of the NYCA. Natural gas and oil represent 60 percent of the installed capacity, and coal, nuclear, and hydroelectric power account for 39 percent.

New Yorks new Renewable Portfolio Standard should im-prove fuel diversity. This standard requires 25 percent of electricity to be generated from renewable sources by 2013, compared with 19.5 percent now (mainly hydroelectricity, most notably from Niagara Falls).6 The electrical output (actual kilowatt-hours) generated by each fuel is not proportional to the generating capacity that uses that fuel. Gas and oil fuel about 38 percent of the total.

Coal, nuclear, and hydro power represents most (61 percent) of the power generated in 2004.

Generator owners in the NYCA operate a diverse mix of generation facilities. Figure 1-5 lists the power that can be generated in each NYCA zone, by technology, during the FIGURE 1-1 The New York Control Area high-voltage transmission network. SOURCE: New York Independent System Operator.

5These plants combine a gas turbine (similar to a jet engine) with a steam turbine that uses the waste heat from the gas turbine as its energy source.

The latest combined-cycle plants can be up to 60 percent efficient, almost twice as high as most coal or nuclear plants.

6Renewable resources include solar energy, wind, biofuels, and others.

Renewables are appealing for a variety of reasons, especially environmen-tal, but most forms have been expensive relative to fossil and nuclear en-ergy. Some technologies (e.g., wind) are now proving to be competitive, and progress in research and development on others is encouraging, as dis-cussed in Chapters 2 and 3. Hydroelectricity is a form of renewable energy, and New York State already receives an abundant supply from Niagara Falls and other sites, but it is questionable whether hydropower can be ex-panded significantly.

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INTRODUCTION 11 FIGURE 1-2 Average daily load (top) and peak hour load (bottom) in New York City. SOURCE: Personal communication with Timothy Mount, Cornell University, compiled from NYISO data, January 2006.

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12 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER summer-peak demand period.7 The diversity of generator technologies in the NYCA in itself adds to the reliability of the electrical system. Reliability also is a function of the lo-cation of the generating facilities relative to the load centers that they serve. Indian Point Units 2 and 3 (total 1,970,700 kW) are listed in the column Zone H and row Steam (PWR [for pressurized water reactor] Nuclear). The two units represent 12.5 percent of the total summer capability in Zones H, I, J, and K (NYISO, 2005). Indian Point is virtually the only generating facility in Westchester County.8 Even with adequate capacity, an electric grid may fail because of instability. Several types of instability may oc-cur, and they have different timescales and effects on cus-tomers. Voltage stability is most important in considering alternatives to Indian Point. The phenomenon of voltage col-lapse (in which voltage declines to unacceptable levels, as it did in Ohio in August 2003) is associated with insufficient reactive power.9 The existing generators at Indian Point can supply a large amount of reactive power when it is needed. It will be necessary to verify that alternatives to Indian Point would include sufficient reactive power to maintain accept-able voltage levels under all predicted loads.

Peak demand generally occurs during hot summer after-noons when air conditioning loads are highest. Demand on July 26, 2005, was 32,075 MW, a record for the NYCA.

Reliability is of greatest concern during hours of peak de-mand because at such times reserve capacity, both genera-tion and transmission, is at its lowest. Any equipment failure then can threaten continued supply if reserve capacity is too low. NYSRC has a general requirement that NYCA capacity must exceed expected peak demand by 18 percent to allow for failures.10 On July 26, the reserve margin was about 19 percent, indicating adequate reserve capacity for the state.

Regional distribution within the state, however, is more problematic. Upstate New York has some surplus capacity, but very little if any additional power can be delivered down-state because the transmission system is already congested during peak demand. Furthermore, electricity demand has been growing at over 2 percent per year in southern New York, so more capacity will be required in a few years to meet peak demand in that area. Chapter 2 includes an analy-sis of demand growth and the options for controlling it.

Chapter 3 discusses the possibility of building new power plants upstate and transmission lines to bring the power south.

In addition to controlling bulk power flows, NYISO must monitor and control reactive power. Insofar as reactive power cannot be produced by operating generators, it must be supplied by specialized equipment.

Several other factors extremely important in planning for the future of the bulk power system noted here are discussed further in Chapter 3. A reliable supply of electricity depends on a reliable supply of fuel to power the generators. New York has a diverse supply of fuels: hydroelectric, nuclear, A

B B

E G

H F

E D

C I

K J

FIGURE 1-3 New York Control Area load zones. SOURCE: New York Independent System Operator.

7Many generating plants can produce more power in the winter than in the summer. Cooler air is denser, so combustion turbines can be fed more fuel. Steam turbines also exhaust to a lower temperature and thus lower back pressure, increasing their efficiency.

8Zone I has about 3 MW of hydroelectric power and municipal waste generation in addition to the 2,000 MW from Indian Point; see Appendix D-2 for details.

9Reactive power is a complex phenomenon in alternating current power.

It is discussed further in Chapter 3 of this report.

10Reserve margin during off-peak hours is, of course, much higher. It is only high-demand hours that are of concern.

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INTRODUCTION 13 FIGURE 1-4 Generating capacity in the NYCA, by fuel type, 2005. SOURCE: New York Independent System Operator, Power Trends, April 2005.

FIGURE 1-5 Capability of generating plants by NYCA zone and generator type. See Figure 1-3 for a map of NYCA zones. SOURCE: New York Independent System Operator, Power Trends, April 2005.

coal, natural gas, and oil. Diversity is important because dis-ruptions can occur in fuel deliveries. In recent years, most new generation has been fueled with natural gas, but new supplies of gas are expected to be limited and expensive un-less new facilities for importing liquefied natural gas (LNG) are built. Natural gas is generally available during the sum-mer, but it may be curtailed in the winter when demand is high for residential and commercial heating. Oil is frequently used as a backup for natural gas in the winter, but it is expen-sive, pollutes more, and raises national security issues.

Environmental factors may control what types of facili-ties can be built where. In particular, air pollution regula-tions can limit the use of coal, the nations most abundant fossil fuel. New York has introduced new, lower standards Copyright © National Academy of Sciences. All rights reserved.

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14 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER for emissions of sulfur dioxide and nitrogen oxides, which would require expensive emissions controls on coal plants.

Carbon dioxide emissions are emerging as an issue. Con-cerns over global climate change are leading to restrictions on emissions of greenhouse gases, though not yet at the na-tional level. New York is part of the recently adopted Re-gional Greenhouse Gas Initiative, which will begin to limit emissions of carbon dioxide in 2008.

The changing institutional structure of the electric power industry in New York will also play an important role in efforts to replace Indian Point, as described in detail in Chap-ter 4 and in Appendix E. Formerly, under the regulated ap-proach, an integrated utility would determine its generating, transmission, and other needs, and build whatever was re-quired. A reasonable return on its investments was largely guaranteed by the states Public Service Commission. The introduction of competition in the industry has also intro-duced an element of uncertainty that affects the willingness of power companies to invest. The expiration of New Yorks siting legislation in 2003 represents another hurdle to build-ing new facilities.

Finally, societal impacts play an important role in guid-ing decision making with respect to the bulk power system.

These impacts can be seen in issues such as public opposi-tion to new generating or transmission capacity. Employ-ment issues can also be important for some facilities.

The Indian Point Energy Center: Description and Role Three reactors have been built at the 239-acre Indian Point site. Unit 1 was an early, small reactor that has been shut down since 1974. It is still onsite though not operable, be-cause demolition was deemed easier if carried out simulta-neously with the later reactors.

Indian Point Unit 2 was built by Consolidated Edison (ConEd), the utility that supplies power to Westchester County and New York City. Operating since 1974, Unit 2 is licensed until September 28, 2013. Until recently it produced 970 MW but has now been upgraded to 1,078 MW.

Construction of Indian Point Unit 3 was started by ConEd, but financial difficulties forced the utility to sell it to NYPA before completion. It has operated at 980 MW since 1976 and is licensed until December 12, 2015. It has now been upgraded to 1,080 MW.

In 2001 and 2002, the units were sold to Entergy Corpo-ration, an integrated energy company that owns and operates power plants. Both sales were accompanied by an agreement to purchase back the power generated by the plant for sev-eral years. These agreements are phasing out, and Entergy will soon be able to sell the power at a higher price, as most alternate fuels have risen considerably in cost over the past few years.

Entergy Nuclear operates 10 nuclear power plants, includ-ing the Indian Point Energy Center and the FitzPatrick plant in upstate New York. Since Entergy took over Indian Point, it has operated the plants extremely well. From 2003 to 2005, Unit 2 operated at a capacity factor of 96.6 percent and Unit 3 at 93.7 percent (NEI, 2006). The industry average is 89.6 percent. The two Indian Point reactors are among the low-est-cost generators in New York, and they operate whenever possible supplying base load power to the system. Together, they account for 5.3 percent of the total installed generating capacity in New York State, but they produce 10.1 percent of the electricity (Levitan and Associates, 2005).

Entergy can apply for license extensions for an additional 20 years of operation. The U.S. Nuclear Regulatory Com-mission would review the applications for confirmation that the reactors could be operated safely and in compliance with environmental regulations. The application process can take about 5 years, suggesting that Entergy would have to sub-mit the applications for Units 2 and 3 in 2008 and 2010, respectively.

Both units feed power into the transmission network at the nearby Buchanan substation. The power is delivered to load centers, mainly in New York City.

Indian Point is the largest generating station close to the major load centers in New York City, Westchester County, and Long Island and south of congestion points in the NYCA transmission system that prevent more power from being sent south during periods of peak demand. Indian Point also produces the lowest-cost power in the area. Thus, Indian Point is a critical component of both the reliability and eco-nomics of power for the New York City area. In addition, it produces much of the reactive power needed for reliable operation of the system. Replacing Indian Point will call for careful analysis of the choices that are made.

Community Concerns Community concerns about the Indian Point reactors have a long history (Wald, 1982), but prior to September 11, 2001, they had faded, with only a few people still expressing pub-lic concern that the dangerous amounts of radioactivity in the cores of the reactors might be released in an accident (Hu, 2002). Opinions were changed by the 2001 attacks on the World Trade Center (Purdy, 2003; Lombardi, 2002; Hu, 2002).

Since the Sept. 11 terrorist attacks, growing anxiety over the safety of nuclear power plants has transformed Indian Point from a fringe issue that only antinuclear crusaders care about to a mainstream concern, and not just for Westchester subur-banites, but for New York City and New Jersey residents, who had, until now, barely registered the plants existence 40 miles north of Midtown Manhattan. (Hu, 2002)

Scenarios leading to catastrophic releases were no longer easy to dismiss on the basis of fault-tree calculations and experience underlying previous assurances of safety, al-though the Nuclear Regulatory Commission and Entergy point out that it would be very difficult for an airplane or Copyright © National Academy of Sciences. All rights reserved.

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INTRODUCTION 15 attackers to cause a major release, and, in any case, security would be upgraded. Such assurances were not sufficient to allay public concern. In addition, concerns about accidents at or attacks on the spent fuel pools at Indian Point have been given new attention since 9/11 (Wald, 2005b). For instance, a National Research Council study (NRC, 2005) concluded that successful terrorist attacks against spent fuel pools, al-though difficult, are possible; the type of spent fuel pool at Indian Point, however, was not among those that the report considered most vulnerable. It should be noted that closing Indian Point would not by itself eliminate risk from the spent fuel, which may remain onsite for many years until a perma-nent storage disposal facility is ready.

In Westchester and surrounding counties, some 12 com-munity groups (Hu, 2002) have called for the plants closing (e.g., Riverkeeper, Public Citizen, and Indian Point Safe Energy Council).11 Activities by these groups, including ad-vertising and an HBO television special, have kept the issue of shutting down Indian Point on the political agenda.

Riverkeeper claims that a large radioactive release triggered by a terrorist attack on or accident at the facility could have devastating health and economic consequences.... (River-keeper, 2006). Entergy, many safety analysts in the industry, and the Nuclear Regulatory Commission are convinced that a terrorist attack, even if it occurred, would be extremely unlikely to result in a large radioactive release. Riverkeeper also is concerned with environmental damage to the Hudson River, especially to fish, eggs, and larvae (van Suntum, 2005). Here, the policy issue, which is currently in the courts, is whether or not the river cooling system should be replaced by a more expensive system (Hu, 2003).

A key community concern has been the perceived inabil-ity of emergency plans to work in the aftermath of an acci-dent or successful attack on the facility (Purdy, 2003; Lombardi, 2002). A state-sponsored study (Witt, 2003) found that the plans do not consider the possible additional ramifications of a terrorist caused release. Early evacuation is not a requirement of Nuclear Regulatory Commission and state emergency planning because scenarios that would lead to early fatalities are not considered credible, even after 9/11.

Yet the public appears to see early evacuation as crucial (Witt, 2003), which produces tension, because evacuation in the crowded New York metropolitan area is perceived by many to be impossible (Risinit, 2005). If many people at-tempted to evacuate or collect their families upon announce-ment of a potential release, the result could be gridlock (Witt, 2003; Westchester County, N.D.).

Local political leaders, such as Westchester County Ex-ecutive Andrew Spano, call for an Indian Point shutdown, bringing the resources of the county to bear on the cam-paign. Rockland County Executive Scott Vanderhoef has also called for closure before terror attacks (Purdy, 2003).

Congresswoman Nita Lowey, from New Yorks 18th Dis-trict, has expressed concerns about the Indian Point facility and was responsible for commissioning this National Re-search Council study. She has also introduced a bill to re-quire relicensed facilities to meet the same standards as those for new nuclear plants, which is currently not the require-ment of the Nuclear Regulatory Commission.

As one indication of concern about reactor accidents, Westchester County, in cooperation with New York State, has developed a program to provide potassium iodide to residents who live, work, or travel within the 10-mile Emer-gency Planning Zone (Westchester County, N.D.). Such tab-lets, if taken early enough, significantly reduce radiation doses to the thyroid, the major risk after the Chernobyl accident.

In addition, Westchester County has commissioned ex-pert studies on issues surrounding Indian Point (e.g., Levitan and Associates, 2005), as has Riverkeeper (Lyman, 2004; Komanoff, 2002; Schlissel and Biewald, 2002). The study for Westchester County highlighted the expense of an early shutdown of Indian Point, leading County Executive Spano to put his hopes on stopping Entergy in the relicensing pro-cess (Wald, 2005a).

Local opinion is by no means unanimous against Indian Point. Some political leaders are concerned that the plants have 1,200 employees and pay significant taxes to local schools and governments (Westchester County, 2003). Dan ONeill, mayor of Buchanan, New York, home of the plant, is supportive of the facility (Purdy, 2003). Others are con-cerned over the reliability of the New York City power sup-ply and potential increases in the costs of electricity.

CRITERIA FOR EVALUATING REPLACEMENT OPTIONS The opportunities or options for replacing the Indian Point power plant are constrained by various technological, regu-latory, and socioeconomic elements. These need to be taken into account in developing options for maintaining a reliable electric energy supply for southern New York State, while allowing for growth in the region.

Each of the constraints derives from somewhat different technological, regulatory, or cost considerations, many of which are unique to New York State. These constraints will affect both the choice and the timing of change in supply if Indian Point is considered for retirement.

For instance, the electricity supply available in New York currently relies heavily on Indian Point as a major baseload contributor to the power supply needed in the New York metropolitan area. Replacement of this capacity would re-quire major efforts in new generation, transmission, and de-mand management.

Reliability of power supply depends on several factors, 11Information detailing these concerns can be found at the websites for the respective organizations, including www.riverkeeper.org, www.citizen.

org, and www.ipsecinfo.org. Accessed March 2006.

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16 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER including fuel availability, generation reserve, peaking load, and the growth rate of demand locally and in the region.

Reliable electricity also hinges on the stability of the trans-mission-distribution system. In general, the NYCA system is carefully balanced to account for the location and opera-tion of baseload plants, as well as intermediate and peaking units. Balancing is complicated by the nature of the genera-tion, which includes not only conventional fossil and nuclear power sources but a variety of other technologies in the sys-tem, including hydroelectric units, wind power, and co-gen-erated power at industrial facilities.

Safety has motivated this study to a great extent. Concern for public safety associated with a nuclear power plant close to the New York metropolitan area is substantial. However, there are additional considerations related to energy security and public safety. Security of the plant site must be main-tained whether or not the plant is retired because it contains radioactive material, including stored spent fuel rods. An-other energy security concern is fuel availability. In particu-lar, most new generating units are fueled by natural gas, but gas supplies are limited and becoming increasingly expen-sive. Lengthy blackouts, whether caused by inadequate fuel supplies or transmission system instability, also threaten public health and safety. Imports of LNG may be required, but LNG also raises safety as well as energy security issues.

Adding to the complexity of decisions on closing Indian Point are issues of costs. Electricity costs are likely to rise if the areas low-cost power generator is retired. In addition, if the plants lifetime is shortened, compensation to the owner may be required. Furthermore, the site will continue to re-quire extensive security measures to protect the spent fuel until a more permanent storage facility is available. Costs are discussed in Chapters 4 and 5.

A complex web of environmental regulations must be considered with any alternative to the Indian Point plant.

Regulations include national and local air and water quality and thermal discharge requirements as well as the possibility of constraints on greenhouse gas emissions associated with carbon fuel combustion. At the present time, air quality con-straints are the most stringent for most alternative technolo-gies. These are generally specified in terms of emissions of material regulated as criteria pollutants or hazardous air pol-lutants under the Clean Air Act (CAA) and its amendments and other requirements for airborne toxic chemical releases.

New power plant sources are permitted only under very strin-gent constraints with regard to the CAA pollutants.

Finally, closing Indian Point and building new facilities, presumably at least partly elsewhere, would make signifi-cant differences in employment, tax base, and other commu-nity impacts. These changes might be positive or negative, but they must be included in the consideration of replace-ments for Indian Point.

Given the constraints corresponding to these criteria for the selection of options, the range of technologies available can be reduced substantially. It is unlikely that a 2,000-MW power plant would be built as an exact replacement for In-dian Point, to be available just as Indian Point was closed. A package of demand and supply options, the latter possibly including new transmission lines as well as new generation, seems more plausible. The committee uses the following cri-teria to judge the proposed replacement packages for Indian Point:

1. Would the combination of demand and supply options provide adequate energy to replace that provided by Indian Point?

2. Would the generation and transmission system be ad-equate to deliver the energy reliably to end users?

3. How would the new combination of demand and sup-ply options compare with Indian Point in terms of security of fuel supply for new generation?

4. How would economic costs, especially to the con-sumer, compare with continued operation of Indian Point?

5. How would environmental emissions and other im-pacts compare with continued operation of Indian Point?

6. What would be the impacts on local communities from closing Indian Point and replacing it with these options?

CONDUCT OF THE STUDY This study was initiated by the U.S. Congress in the fiscal year 2004 Appropriations for the U.S. Department of En-ergy. The Committee on Alternatives to Indian Point for Meeting Energy Needs was formed in accordance with Na-tional Research Council procedures. The committees state-ment of task is presented in the Preface. Biographical sketches of the committee members appear in Appendix A.

The committee held five full meetings over the course of the study. The first three meetings included open sessions at which many experts made presentations to the committee.

The second meeting was held in White Plains, New York, to allow local residents interested in the issue to attend.

Committee meetings and participants are listed in Appen-dix C. The projects website also invited viewers to submit comments.

In addition to the full committee meetings, several com-mittee subgroups also conducted many conference calls and collectively prepared sections of this report.

The committee also contracted for two expert analyses.

GE Energy built on its work with NYISO to analyze several scenarios for replacing the power from Indian Point. While NYISO generously allowed the committee to use its data-base, it should be noted that the scenarios were developed by the committee, not NYISO. Several members of the com-mittee met in Schenectady, New York, to discuss scenarios and analytical methodology with NYISO and GE Energy, in preparation for the committees analysis.

In addition, Optimal Energy of Bristol, Vermont, refined the 2003 analysis of energy efficiency potential that it had done for the New York State Energy Research and Develop-Copyright © National Academy of Sciences. All rights reserved.

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INTRODUCTION 17 ment Authority to focus on the regions that would be im-pacted by the closure of Indian Point.

ORGANIZATION OF THE REPORT There are two general options to consider in replacing Indian Point: reducing demand and increasing supply. As noted above, demand is increasing, but the growth rate can be controlled to some extent. Many efforts already are under way to increase the efficiency of use of electricity or to re-duce demand during peaks when reliability concerns are highest. Chapter 2 discusses how those efforts could be ex-panded if it were necessary to compensate for the loss of Indian Point. It also discusses distributed generation and how that could affect load growth and electricity reliability.

Supply options, discussed in Chapter 3, include new gen-erating units and transmission lines that can import power from underutilized generating plants in upstate New York and beyond. In recent years, almost all new generating plants have been fueled by natural gas, but those supplies are be-coming strained. Modifying the bulk power system can be complicated, and many factors must be considered. In par-ticular, reactive power has a large effect on transmission ca-pability. The reactive power supplied by Indian Point would also have to be replaced if its units are closed.

Chapter 4 discusses institutional factors and various im-pacts that might result from the replacement of Indian Point with the options discussed in Chapters 2 and 3. Most new generating plants and transmission lines would be built by private companies, which could face daunting obstacles of regulation and financing. New facilities also would create a set of environmental impacts different from those created by Indian Point.

Chapter 5 analyzes several scenarios to evaluate the im-pact of closing Indian Point and replacing it with these other options. The scenarios with compensatory actions to replace Indian Point are to be viewed as representative of the actions that could be taken, not as a recommended path. Other com-binations of options might prove less expensive or advanta-geous from other perspectives. Nor do these scenarios in-clude all of the costs that could be involved, such as buying Indian Point in order to close it, or disposing of the spent fuel now being stored onsite.

A series of appendixes follow. Appendixes D through G, which give additional details on the options considered and the committees analyses, are reproduced on the CD-ROM that contains the full report but are not included in the printed report owing to space limitations.

The committees findings and conclusions are discussed in the Summary and Findings that precedes this chapter. This report does not include recommendations as to whether In-dian Point should be closed.

REFERENCES Hu, W. 2002. Post-9/11, opposition to Indian Point plant grows. New York Times, April 24.

. 2003. Judge orders faster review of cooling unit at Indian Point. New York Times, April 10.

Komanoff, C. 2002. Securing Power Through Energy Conservation and Efficiency in New York: Profiting from Californias Experience. Avail-able at http://www.riverkeeper.org. Accessed April 2006.

Levitan and Associates. 2005. Indian Point Retirement Options, Replace-ment Generation, Decommissioning/Spent Fuel Issues, and Local Eco-nomic/Rate Impacts. Boston: Levitan.

Lombardi, K.S. 2002. Indian Point and the Big If. New York Times, March 31.

Lyman, E. 2004. Chernobyl on the Hudson? The Health and Economic Impacts of a Terrorist Attack at the Indian Point Nuclear Plant. Wash-ington, D.C.: Union of Concerned Scientists.

NEI (Nuclear Energy Institute). 2006. U.S. Nuclear Power Power Plant Capacity, Capacity Factor and Generation. Available at http://

www.nei.org/documents/U.S.%20Nuclear%20Power%20Plant%20 Capacity%20Capacity%20Factor%20and%20Generation.pdf. Ac-cessed April 2006.

NRC (National Research Council). 2005. Safety and Security of Commer-cial Spent Nuclear Fuel Storage: Public Report. Washington, D.C.: The National Academies Press.

NYISO (New York Independent System Operator). 2005. Comprehensive Reliability Planning Process (CRPP) and Reliability Needs Assessment.

Albany, N.Y. December 2005.

Purdy, M. 2003. Our towns: Gospel of Armageddon finds fertile ground near Indian Point. New York Times, January 26.

Risinit, M. 2005. Unlike Westchester, upstate Oswego welcomes nuclear power. The Journal News. Available at http://www.thejournalnews.

com/apps/pbcs.dll/article?AID=/20050626/NEWS02/506260355/-1/

spider/. Accessed June 26.

Riverkeeper. 2006. Available at http://www.riverkeeper.org. Accessed March 2006.

Schlissel, D., and B. Biewald. 2002. The Impact of Retiring Indian Point on Electric System Reliability. Cambridge, Mass.: Synapse Energy Eco-nomics.

van Suntum, L.R. 2005. The cost of nuclear power (Letter to the Editor).

New York Times, May 23.

Wald, M. 1982. Protests grow on Indian Point. New York Times, August 15.

. 2005a. County seeks deal on Indian Point, perhaps in vain. New York Times, June 19.

. 2005b. Study finds vulnerabilities in pools of spent nuclear fuel. New York Times, April 7.

Westchester County. N.D. Emergency Planning for Indian Point. Avail-able at http://www.westchestergov.com/indianpoint/. Accessed March 2006.

. 2003. Spano and Kaplowitz Announce Next Step in Effort to Replace Nuclear Energy at Indian Point. Available at http://www.

westchestergov.com/currentnews/2003pr/IndianPointRFP.htm. Ac-cessed April 2006.

Witt, J.L. 2003. Review of Emergency Preparedness at Indian Point and Millstone (Draft). Washington, D.C.: James Lee Witt Associates.

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18 2

Demand-Side Options DEMAND GROWTH IN THE INDIAN POINT SERVICE AREA The New York Independent System Operator (NYISO) prepares compilations of historic electricity usage patterns and forecasts future electricity demand in New York State.

Table 2-1 shows annual power consumption for selected years between 1993 and 2015 by region, in and around New York City and in the state, and Table 2-2 shows peak power requirements for the same years and areas. These consump-tion estimates are weather-normalized to enable compari-sons across a typical year of weather (e.g., electricity use during years with particularly cold winters or hot summers was reduced to reflect what would have occurred during years with more typical numbers of heating and cooling degree-days).

Electricity use in the New York Control Area (NYCA) as a whole grew at about 1 percent annually between 1993 and 2004 as shown in Table 2-1. Demand in western New York and the Upper Hudson Valley actually dropped during that period. All of New Yorks demand growth has been down-state, with Long Island growing at 2.2 percent annually, New York Cityeven with the events of September 11, 2001at 2.1 percent, and Zones H and I (most of the Lower Hudson Valley) at a rate of 1.4 percent.1 This growth seems to be driven in part by a continuing expansion of the strong ser-vice sector (including government, education, and health care) that characterizes much of the downstate region. The manufacturing that once anchored the upstate economy has been in decline since the 1970s.

Summer peaks (Table 2-2), due largely to air condition-ing, have grown more rapidly than has annual electricity use (Table 2-1), with Long Island seeing the highest growth in the state, followed by New York City and then the Lower Hudson Valley.

NYISO forecasts that the current growth rate in annual electricity use (though not that of peak-load growth) will continue out to 2015 in the Lower Hudson Valley, but with some slowing in New York City and Long Island (due to more limited opportunities for commercial and industrial ex-pansion and greater investment in demand-management pro-grams by Consolidated Edison). Consumption and peak load are forecast to grow at an approximately equal pace on Long Island and in New York City. Peak load is expected to grow slightly faster than consumption in the Lower Hudson Valley.

The projections of electricity demand in Tables 2-1 and 2-2 are predicated on the assumption that electricity prices will continue their historical decline, as shown in Figure 2-1.

This assumption in turn depends on assumptions of fuel prices, generating mix, capital costs, and other factors.

NYISOs demand forecasts are based on the relative trend in Figure 2-1, which was derived from analyses by the Energy Information Administration (EIA) for the Mid-Atlantic re-gion (Energy Information Administration, 2006).

Such projections are highly uncertain for several reasons, most prominently:

1. Natural gas, which is the source of a large and increas-ing share of New Yorks electric generation, has shown large swings in price in recent years. Some of this has been tempo-rary, for example owing to shortages in supply because of damage to equipment in the Gulf of Mexico region during the hurricanes of 2004 and 2005. More worrisome, however, has been the declining productivity of U.S. gas fields. The EIA expects gas prices to remain relatively stable over the next 10 years (Energy Information Administration, 2006).

That may be the case, but probably only if imports of lique-fied natural gas (LNG) are significantly increased. The only proposed LNG terminal in the state of New York, in Long Island Sound, faces vigorous opposition, as do other pro-1The growth rates for Zones H and I alone appear to be higher than the overall rate for the Lower Hudson Valley, since a different NYISO report (2004 Load and Capacity Data, p. 7, Table I-4) shows no growth in Zone G.

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DEMAND-SIDE OPTIONS 19 TABLE 2-1 Weather-Normalized Annual Electricity Use, Past and Forecast, in Gigawatt-Hours per Year, for Three New York Regions and Statewide, Selected Years from 1993 Through 2015 Lower Hudson Valley:

New York City:

Long Island:

New York State:

Year NYCA Zones G, H, Ia NYCA Zone J NYCA Zone K NYCA 1993 16,411 41,828 17,667 144,471 1997 16,206 44,676 18,185 148,008 2001 17,207 49,912 20,728 155,523 2005 19,625 52,836 23,178 164,050 2009 20,775 56,345 25,258 174,290 2013 22,610 58,949 26,598 180,710 2015 23,608 59,717 26,961 182,880 Growth per year:

1993-2004 1.421%

2.071%

2.222%

1.004%

2004-2015 1.913%

1.194%

1.659%

1.151%

aNYCA, New York Control Area; Zone G, Hudson Valley; Zone H, Northern Westchester County; Zone I, rest of Westchester County.

SOURCE: Adapted from NYISO (2005a), p. 25.

TABLE 2-2 Weather-Normalized Summer Peak Power, Past and Forecast, in Megawatts, for Three New York Regions and Statewide, Selected Years from 1993 Through 2015 Lower Hudson Valley:

New York City:

Long Island:

New York State:

Year NYCA Zones G, H, Ia NYCA Zone J NYCA Zone K NYCA 1993 3,337 8,365 3,595 27,000 1997 3,650 9,609 4,273 28,400 2001 4,421 10,424 4,901 30,780 2005 4,410 11,315 5,230 31,960 2009 4,849 11,965 5,580 33,770 2013 5,331 12,426 5,981 35,180 2015 5,590 12,648 6,112 35,670 Growth per year:

1993-2004 2.365%

2.610%

3.270%

1.382%

2004-2015 2.380%

1.190%

1.618%

1.166%

aNYCA, New York Control Area; Zone G, Hudson Valley; Zone H, Northern Westchester County; Zone I, rest of Westchester County.

SOURCE: Adapted from NYISO (2005a), p. 26.

Overall, if the price decline projected to start in 2006 does not occur, demand will be lower.

NYISOs new capacity-forecasting program is more rig-orous than in the past, but even the best demand forecasts are not destiny. They are simply estimates, based on guesses about a host of parameters, which may prove to be too high or too low. Price increases, economic downturns, changes in fuel prices and availability, policy changes, and technologi-cal advance have all contributed to surprises in years past.

Both in the 1970s and in late 1980s, serious power shortages were forecast for New York unless particular power plants posed projects. Natural gas is discussed further in Chapter 3.

If these supplies do not materialize, prices will rise and elec-tricity costs will follow.

2. Even if the costs of production can be defined well, the wholesale price is a function of the auctions that NYISO conducts to procure supplies, as discussed in Chapters 1, 4, and 5. Price can be either above or below historic levels, depending on how many bidders are participating. The long-term impact of the New York process on prices to consum-ers is still uncertain.

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20 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER FIGURE 2-1 Past and projected trends in real residential electricity price in New York State relative to 1980. SOURCE: NYISO (2005a).

were built. Not all were, but no shortages occurred, and the demand for energy services was unfailingly met. The 1980s saga of Long Islands Shoreham nuclear plant, which was eventually closed before it produced any electricity, is one example. It is no criticism of the NYISO forecasts to observe that they do not reflect the full range of possibilities that could come into being if circumstances so required (such as an emergency shutdown of the Indian Point Energy Center or of another large generating source) or if state policies emphasized energy efficiency on the same scale as in Cali-fornia, as discussed later in this chapter.

The range of policy options available to power system operators and regulators has grown wider in recent years. It now includes energy efficiency, load management, inte-grated resource planning, and performance-based rate mak-ing with incentives for cost-effective energy efficiency.

New York States spending on efficiency in the electric sector declined significantly in the mid-1990s, falling from a peak of some $300 million per year in the early 1990s to a low of some $50 million per year in 1996. The states only performance-based rate-making plan based on capping rev-enues2 lapsed in 1997. The New York State Energy Research and Development Authority (NYSERDA) now spends about

$150 million annually on energy efficiency programs, dis-cussed below (NYSERDA, 2005b). Comparing trends in consumption and peak load between 1993 and 1997 with those between 1997 and 2001 (Tables 2-1 and 2-2) suggests that the demand-side management (DSM) program cutbacks may have allowed demand to grow faster than it would have with stronger programs.

POTENTIAL OF DEMAND-SIDE OPTIONS The impacts of current and planned programs for reduc-ing electricity consumption and peak electrical loads could be among the most cost-effective replacements for the en-ergy provided by the Indian Point Energy Center. This sec-tion describes promising demand-side control options, in-cluding estimates of their achievable potential and barriers to their implementation. The focus is on the ability of de-mand-side options to reduce on-peak requirements of con-sumers for electricity. While Indian Point is a baseload plant, the biggest challenge to replacing its capacity occurs during summer and winter peaks when regional generating re-sources and transmission capacity are most constrained hence the focus on demand-side options that could displace peak loads. The ability of energy efficiency to reduce mega-watt-hours of electricity consumption and levels of consumer bills in the residential and commercial sectors is highlighted in Appendix G-1 (Demand Reduction).

2Revenue-cap plans are more compatible with energy efficiency than are the more common price-cap plans because they adjust revenues to avoid any loss in profitability arising from declining sales. Cost-effective energy efficiency can lower bills while raising prices (because the decline in con-sumption more than offsets the increase in prices).

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DEMAND-SIDE OPTIONS 21 Definition of Demand-Side Options and Measures of Potential Demand-Side Options This chapter considers two types of demand-side options:

Energy efficiency programs (principally in the commer-cial and residential sectors) and demand-response (DR) pro-grams (including permanent and callable resources), and

Distributed generation (DG), which is generally not dispatchable and thus not included in most electrical system reliability analyses. DG includes combined heat and power (CHP) systems and distributed photovoltaics (PV).

Energy Efficiency and Demand-Response Programs. En-ergy efficiency programs allow users to perform the same functions that they normally would, but with less energy consumption. When applied to electricity uses, improved efficiency reduces demand throughout the day, often with the greatest effect during peak demand. The left panel of Figure 2-2 shows a typical daily cycle of demand, low at night, rising during the day, and peaking during the late af-ternoon. The lower curve shows demand with improved effi-ciency of use. Energy-efficiency improvements can be ex-pensive, but once implemented they can save energy for many years. Reductions in peak-power requirements can also contribute to system stability in the event of sudden distur-bances such as a loss of system components or short cir-cuits.3 Furthermore, reducing peak demand means that gen-erating capacity and reserve margins can both be reduced.

Thus, investments in reducing peak demand through energy efficiency measures can have a value of 118 percent of the actual reduction in avoiding the addition of new capacity.4 Energy-efficiency mechanisms can include mandatory ef-ficiency standards for buildings and appliances; targeted fi-nancial incentives and assistance; codes; information and education programs; and research on energy-efficient tech-nologies (Silva, 2001, pp.96-104; Brown et al., 2005, pp.

45-60). They can take place in a variety of program areas, including residential lighting; single-family weatherization; nonresidential heating, ventilating, and air conditioning (HVAC); and new construction (National Energy Efficiency Best Practices Study, 2004). Stimulating greater investments in energy-efficiency measures is complex, however, since it involves multiple actors and agents, including varied con-sumers, vendors, independently owned utilities, unaffiliated distribution companies, and federal, state, and local agencies (Harrington and Murray, 2003).

One well-documented stimulant for energy efficiency is that of increased electricity prices. Most models of electric-ity markets incorporate an estimate of the price elasticity of demand for electricity. Consistent with past research, one recent study of price response based on 119 customers from New York State (Goldman et al., 2005) confirms that cus-tomers price response is generally modest. In particular, the surveyed customers had an average price elasticity of 0.11, which means that their combined ratio of peak to off-peak electricity usage declines by 11 percent in response to a dou-bling of peak prices (relative to off-peak prices). Thus, price Effects of Energy-Effects of Price-Efficiency Measures Response/Peak-Effects of Security-Response Programs Shaving Programs Time of Day (midnight to midnight) 0 24 0

24 0

24 FIGURE 2-2 Effects of demand-reduction programs on daily power demand. SOURCE: Adapted from Kirby et al. (2005); Gillingham et al.

(2004).

3The adequacy and security aspects of electrical system reliability are briefly discussed in NYISOs report Reliability Needs Assessment (NYISO, 2005a).

4The North American Electric Reliability Council has set a standard of 18 percent for reserve generation. This criterion has been adopted by the New York State Reliability Council.

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22 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER increases in the event of more-constrained supplies could produce a measurable reduction in demand, but the overall effect would be modest in magnitude. While long-term price elasticities of demand are likely to be larger, their impact would occur outside the time frame of interest for this report.

Demand-response programs focus on consumers actions to change the utilitys load profile. These programs are not aimed at saving energy so much as at shifting the time at which it is demanded, as shown in the middle set of curves in Figure 2-2 (Gillingham et al., 2004). Price-response pro-grams move consumption from day to night or curtail discre-tionary usage. Peak-shaving programs focus on reducing peaks on high-load days by requiring greater response dur-ing peak hours. These programs allow utilities to better match electrical demand with their generating and transmis-sion capacity. By changing the load curve for utilities, sys-tem reliability can be enhanced and new power plant con-struction can be avoided or delayed. Overall costs are reduced because peak power is more expensive than av-erage costs.

Demand-response programs allow consumers to respond to electricity prices directly, offering mechanisms to help manage the electricity load in times of peak electricity de-mand in order to improve market efficiency, increase reli-ability, and relieve grid congestion. Significant consumer benefits can also accrue from real-time demand-response programs, chiefly in the form of cost savings due to lower peak electricity prices, less opportunity for market manipu-lation by electricity providers, and additional financial in-centives to induce consumer participation in these programs.

Security-response programs enable utilities to drop loads in response to electric system contingencies. These programs can be implemented quickly and inexpensively, usually with the agreement of large users of electricity, who receive lower rates in return for relying on interruptible power. These pro-grams have no impact on the load except during peak peri-ods, as shown in the right-hand panel of Figure 2-2.

Distributed Generation. Distributed generation is the pro-duction of electricity at or close to its point of use. DG tech-nologies include internal combustion engines, fuel cells, gas turbines and microturbines, Stirling engines, hydro, and microhydro applications, photovoltaics, wind energy, solar energy, and waste and biomass fuel sources. DG is usually installed on the customer side of the meter and is not dispatchable by the utility. DG ranges in size from a few kilowatts (kW) to 20 or even 50 megawatts (MW). Recent manufacturer interest and sales growth have been particu-larly strong in the 50 kW to 5 MW range. An objective has also been to move away from traditional diesel generators, up to now a common but relatively dirty source of distrib-uted generation.

Combined heat and power, a subset of DG, generally in-volves reciprocating engines or turbines to drive electric gen-erators, with the waste heat captured and used for other pur-poses. Typically, CHP systems generate hot water or steam from the recovered waste heat and use it for process or space heating. The heat can also be directed to an absorption chiller where it can provide process or space cooling. CHP systems may offer economic benefits, security, and reliability.

Siting generation close to its point of use, as with CHP systems, enables greater use of a devices overall energy output. Historically the average efficiency of central-station power plant systems in the United States has been approxi-mately 33 percent, and until quite recently had remained vir-tually unchanged for 40 years. This means that about two-thirds of the energy in the fuel cannot be converted to electricity at most power plants in the United States and is released to the environment as low-temperature heat. CHP systems, by capturing and converting waste heat, achieve effective electrical efficiencies of 50 to 80 percent. Further-more, centrally located facilities typically lose 5 to 8 percent of their rated output through transmission and distribution losses.5 CHP systems, by being at or near the point of use, avoid most of these losses.

The improvement in efficiency provided by combined heat and power reduces emissions of carbon dioxide and usu-ally other air pollutants. Since CHP requires less fuel for a given energy output, it reduces the demand for key fuels such as natural gas, coal, and uranium.6 CHP can help re-duce congestion on the electric grid by removing or reducing load in areas of high demand and can also help decrease the impact of grid power outages. NYSERDA comments that energy savings [from CHP systems] represent a social ben-efit in lowering the pressure on fuel and electricity supply and infrastructure, thereby providing lower prices for all con-sumers.7 Mayor Michael Bloombergs New York City En-ergy Task Force, in considering options to reduce electrical capacity problems in the city, concluded that distributed resources can reduce or reshape electric system load and thereby mitigate the need for increased generation and/or transmission resources.... With appropriate policies and incentives, distributed resources are often the most readily available, cost-effective, and underutilized clean energy re-sources that can potentially reduce or defer the amount of required new electric supply from generation and transmis-sion systems. While it can take many years to plan, design and build electric generation plants, most distributed re-sources can be deployed within a year.8 A dispersed net-work of DG units is also less vulnerable to terrorism, whether from direct attacks or computer hacking, than a single large power station.

5Available at http://www.epa.gov/chp/what_is_chp/why_epa_supports_

chp.htm. Accessed October 3, 2005.

6Available at http://www.epa.gov/chp/what_is_chp/benefits.htm. Ac-cessed October 3, 2005.

7Available at http://www.nyserda.org/programs/pdfs/CHPFinalReport 2002WEB.pdf. Accessed October 3, 2005.

8Available at http://www.nyc.gov/html/om/pdf/energy_task_force.pdf.

Accessed October 3, 2005.

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DEMAND-SIDE OPTIONS 23 Photovoltaic (PV) technology generates electricity from sunlight in a system with no moving parts. PV units can be mounted on rooftops and left largely untended. This DG option, when installed for the end user, competes against retail, not wholesale, electricity rates. Since its production profile is nearly coincident with the summer peak demand, it can contribute significantly to grid stability, reliability, and security. Thus, from a planning perspective PV should be valued at a rate closer to the peak power rate than the aver-age retail rate.9 The cost of PV-generated electricity is ex-pected to decline considerably over the next decade, falling from a current cost of 20 to 40 cents per kilowatt-hour (¢/

kWh) to a projected cost of 10 to 20 ¢/kWh by 2016, less than the retail price of electricity in New York City (USDOE, 2004; Margolis and Wood, 2004; SEIA, 2004).10 Thus, PV may be in the economic interests of New York customers sooner than others in sunnier parts of the country.

Growth of the global PV market from 1999 to 2004 has averaged 42 percent annually (see Figure 2-3). Large-scale production will contribute greatly to continuing cost de-clines. As shown in Figure 2-3, the fastest growth was in the grid-connected residential and commercial segments.

Measures of Potential When evaluating the potential for additional demand-side options to be deployed in future years, four types of esti-mates are generally used.

Technical potential refers to the complete penetration of all applications that are technically feasible.

Economic potential is defined as that portion of the technical potential that is judged cost-effective.

Maximum achievable potential is defined as the amount of economic potential achievable over time under the most aggressive program scenario possible. It takes into account administrative and program costs as well as market barriers that prevent 100 percent market penetration.

Program potential is the amount of penetration that would occur in response to specific program funding mea-sures (Rufo and Coito, 2002; NYSERDA, 2003).

Current Programs Operating in the Indian Point Territory When assessing the additional potential for demand-side options in the Indian Point service territory, it is necessary to 0

200 400 600 800 1,000 1,200 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 Year Annual Installations (MW)

GridCommercial GridResidential GridUtility Remote Habitation Remote Industrial Consumer Power Consumer Indoor FIGURE 2-3 Global photovoltaic market evolution, by market segment, 1985 to 2004 (42 percent average annual growth). SOURCE:

Personal communication from Paula Mints, Senior Photovoltaic Analyst, Strategies Unlimited, Mountain View, Calif., February 11, 2005.

9PV power replaces power that the home owner or business owner would have had to buy from the grid. Therefore, its value is at the retail level. PV power usually peaks around midday, when sunlight is strongest. Air condi-tioning loads peak several hours later as buildings heat up, but a PV system would still be putting out a high fraction of its peak output at that time of day.

10There is wide variation in retail rates across New York State, but a New York City resident may pay over 20 ¢/kWh. See http://www.

dps.state.ny.us/bills.htm. Accessed March 2006. Commercial and indus-trial customers would pay less for larger quantities.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

24 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER characterize the programs that are currently in place and the results achieved to date. NYSERDA is spending a total of

$1.2 billion (or $175 million annually over a 7-year period) in public and private funds in the state of New York (NYSERDA, 2005a, p. ES-7). NYSERDA estimates that its programs have reduced peak demand by 860 MW and re-duced electricity consumption by 1,400 gigawatt-hours (GWh) annually. At a delivered price of about $0.03/kWh, NYSERDA estimates that the technical potential for its effi-ciency programs in New York State is 20,000 GWh and a cumulative 3,800 MW reduction of peak load by 2012, with corresponding forecasts for 2022 of 41,000 GWh and 7,400 MW.11 New York States 2002 State Energy Plan sets forth the goal of becoming a national leader in the deployment of dis-tributed generation technology and recommends that the state should take all reasonable steps necessary to facilitate the interconnection of DG and CHP resources into the elec-tricity system and increase the use of DG and CHP resources in the State.12 Progress has been made on several fronts over the past several years in advancing combined heat and power sys-tems in the United States. The Bush administration promoted CHP in its National Energy Plan, and the Energy Policy Act of 2005 directs states to consider adopting interconnection standards for CHP and to promote the development of CHP technologies. National model emissions regulations are un-der development by several organizations, and the Federal Energy Regulatory Commission (FERC) has issued small-generator interconnection standards as well as a model state rule.

Many states and regions are conducting their own rule-making processes on interconnection policies, emissions bar-riers, and tax issues for CHP. Most relevantly, the New York Public Service Commission has both reduced the standby electricity rate charges for CHP and set up an attractive natu-ral gas rate structure for CHP. Both of these actions apply in the Consolidated Edison service territory. New York State, through NYSERDA, also has the largest incentive program for CHP in the nation.

New York also has enacted policies aimed at encouraging the adoption of photovoltaic technology, as shown in Table 2-3. The result is a comprehensive set of incentives for residents and businesses to install PV. The incentives take the form of tax exemptions and credits, loan subsidies, re-bates (administered by the Long Island Power Authority and NYSERDA), and standard interconnection and metering rules that are exceeded in the Northeast only by New Jersey.

New Yorks existing rebate or buy-down program is administered by NYSERDA. It is called New York Energy

$mart and includes customers of all major investor-owned utilities. New York Energy $mart provides customers who purchase and install PV systems with a $4 per watt rebate.

This incentive, in combination with state tax credits and ex-emptions, has resulted in the installation of more than 1.5 MW by the summer of 2005. The program currently has $12 million allocated to its PV incentive program, of which about

$6.5 million has been reserved as installer/customer incen-tives. The remaining funding should take the program through 2006.

The following subsections describe the energy-efficiency, demand-response, and distributed-generation programs that are in operation or planned for implementation in the near future by the three major power providers in downstate New York: Consolidated Edison (ConEd), the New York Power Authority (NYPA), and the Long Island Power Authority (LIPA).

TABLE 2-3 Current Photovoltaic (PV)-Related Policies in New York State Incentive Description Sales tax exemption (R) 100% sales tax exemption.

Property tax exemption (C, I, R, A) 15-year tax exemption for all solar improvements.

Personal tax credit (R) 25% tax credit for PV (<10 kW) and solar hot water (SHW), capped at $5,000.

State loan program (C, I, R, A, G)

$20,000 to $1 million loan for 10 years at 4 to 6.5% below the lender rate for PV and SHW.

State rebate program (C, I, R, A, G)

$4 to $4.50/W (<50 kW) up to 60% of total installed costs. Investor owned utilities customers only.

Municipal utility rebate program (C, R, G)

$4 to $5/W (<10 kW). Long Island Power Authority customers only.

Interconnection standards (C, I, R, A)

Standard agreement for PV requires additional insurance and an external disconnect. Up to 2 MW maximum.

Net metering standards (R, A)

All utilities must credit customer monthly at the retail rate for PV systems under 10 kW.

NOTE: C = commercial, R = residential, I = industrial, A = agricultural, G = government.

SOURCE: Incentive data available at www.DSIRE.org. Accessed April 21, 2006.

11Paul A. DeCotis, NYSERDA, 2005. New York States Public Ben-efits Energy Efficiency Programs, presentation to the National Research Council Committee on Alternatives to Indian Point for Meeting Energy Needs, Washington, D.C., June 1, p. 5.

12Available at http://www.nyserda.org/sep/sepsection1-3.pdf. Accessed October 3, 2005.

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DEMAND-SIDE OPTIONS 25 Consolidated Edison Consolidated Edison has established demand-manage-ment subsidy programs as follows (Plunkett and Gupta, 2004):

Overarching goal: Reduce projected peak-load growth by 535 MW through demand management.

NYSERDA Systems Benefit Charge (SBC) II pro-grams: 250 MW (80 MW permanent) in ConEd service ter-ritory (already accomplished).

NYSERDA SBC III programs: 300 MW (120 MW per-manent) in ConEd service territory.

Incremental programs to provide 300 MW of peak-load reduction, including the following:

ConEd: up to 150 MW in constrained networks.

NYSERDA: up to 150 MW throughout ConEds ser-vice territory (after accomplishing the 550 MW in SBC II and III). Budget is $112 million.

The following measures are being emphasized in NY-SERDAs incremental programs:

Energy efficiency (goal of 68 MW)Commercial and Industrial Performance Program (CIPP), New Construction, Smart Equipment Choices, Energy $mart Loan Fund, Build-ing Performance Program, Flexible Technical Assistance.

Load management (goal of 55 MW)Peak Load Re-duction and Aggregated Load Reduction programs.

Distributed generation (goal of 27 MW)Clean DG Incentives Program for engines and microturbines.

New York Power Authority The following energy services programs are operated or planned by the New York Power Authority:

NYPA has committed $100 million a year for energy-efficiency projects through performance contracting with its private-and public-sector customers.

Cumulative reductions for 1987 through 2004 were 900 GWh and 194 MW.

Cumulative estimated emissions reductions were ap-proximately 491,000 tons of CO2; 1,350 tons of SO2; and 675 tons of NOx.

NYPA materials state that 1,200 energy-efficiency projects have taken place at approximately 2,200 public buildings across New York State.

Measures through NYPAs energy services programs are primarily lighting, motors, and HVAC and limited to a maximum payback period of 10 years.

NYPA also has established three renewable resources projects, including the following:

Nine fuel cell installations totaling 2.4 MW using waste gas produced from sewage plants.

18 rooftop photovoltaic systems with a combined ca-pacity of 570 kW.

As of December 31, 2004, 4 million electric-drive ve-hicle miles for hybrid-electric transit buses, all-electric school buses, station commuter cars, electric delivery trucks, electric low-speed vehicles, and other technologies.

Long Island Power Authority Beginning in May 1999, LIPA committed $355 million over 10 years for energy-efficiency projects, clean distrib-uted generation, and renewable technologies. Through the end of 2004, LIPA had spent approximately $170 million, or approximately $34 million a year. This Clean Energy Initia-tive is estimated by LIPA to have had the following impacts:

Annual savings are estimated at 330 GWh, with 326 MW of permanent demand reductions and 145 MW of curtailable demand reduction.

Annual emissions reductions are approximately 1,400 tons of SO2; 500 tons of NOx; and 355,000 tons of CO2.

Through the first 5 years of deployment, cumulative emissions reductions are estimated at 1.3 million tons of CO2; 1,900 tons of NOx; and 5,000 tons of SO2.

LIPA estimates that approximately 3,500 secondary jobs have been created as a result of the program.

The Clean Energy Initiative includes the following kinds of programs:

Residentiallighting and appliances, HVAC, and the Residential Energy Affordability Program (REAP), which provides free installation of efficiency measures and educa-tion for low-income households. In addition, LIPA launched the Solar Pioneer Program for photovoltaics in 1999, offer-ing customers a substantial rebate. The rebates budget is tied to LIPAs 5-year Clean Energy Initiative, with funding totaling $37 million annually (covering multiple technolo-gies). The Clean Energy Initiative is expected to receive funding through 2008. To date, 511 rebates have been dis-bursed for PV systems totaling more than 2.63 MW installed on Long Island. LIPAs rebate is currently set at $4/W.

Commercial and industrialcommercial construction and peak reduction programs.

Generalthe Customer-Driven Efficiency Program, providing custom assistance for residential and commercial customers; LIPAedge, a direct load-control program.

Research and developmentwind power, fuel cells, electric vehicles, hybrid-electric buses, tidal power, wave power, geothermal, and various electrotechnologies.

New York ENERGY STAR Labeled Homes Program introduced by LIPA with NYSERDA in July 2004.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

26 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER The Potential for Additional Energy-Efficiency Improvements The preceding review shows that New York State is reap-ing substantial gains from its programs for reducing electric-ity consumption. In fact, NYISO projects that the growth rate of consumption for the New York City area will be lower than in the recent past, in part because of these activities by NYSERDA, ConEd, NYPA, and LIPA. This subsection es-timates the potential for further gains if these programs are expanded.

Targets for Additional Energy-Efficiency Improvements One study (NYSERDA, 2003) estimates the potential for energy-efficiency improvements in New York State and pro-vides details for Zones J (New York City) and K (Long Is-land outside of New York City). The study focuses on 3 years2007, 2012, and 2022and analyzes residential, commercial, and industrial sectors separately. The study is based on detailed information about technologies (e.g., 87 technologies or technology bundles for commercial build-ings). It concludes that most of the economic potential for energy-efficiency improvements is concentrated in the commercial and residential sectors and not in the indus-trial sector.

For instance, NYSERDA (2003) forecasts that 3,726 GWh of economic potential would exist by 2007 in the resi-dential sector of New York City, and that this would grow to 4,461 GWh by 2012. The residential efficiency measures that hold the most promise include the following:

Lightingcompact fluorescent lightbulbs, fluorescent light fixtures, outdoor light controls, light-emitting diode (LED) nightlights, ceiling fans with fluorescent lights, mul-tifamily common areas with specular reflectors, motion sen-sors, and LED exit signs;

Coolingefficient central air conditioners, air source heat pumps, ground source heat pumps, duct sealing, duct insulation, room air conditioners, humidifiers, new-construc-tion HVAC systems;

Refrigeratorsupgrades to more efficient refrigera-tors, removal of second refrigerators or freezers;

Electronicscomputer monitors and central process-ing units (CPUs), laser printers, fax machines, exhaust fans, power supply, waterbed mattress pads, and waterbed replacement; efficient clothes washers; efficient televisions, VCRs, and DVD players;

Space heatingefficient furnace fans, programmable thermostats, ENERGY STAR windows, blower door guided air-sealing, attic insulation, wall insulation, foundation insu-lation, heating controls, heat-recovery ventilators, and im-proved baseboard systems; and

Domestic hot waterupgrade of heat-pump water heat-ers, upgrade of efficient well pumps, wastewater heat recov-ery, hot-water conservation measures, desuperheater off-ground source heat pumps.

In the commercial sector of New York City, NYSERDA (2003) forecast that 12,567 GWh of economic potential would exist by 2007 and that this would grow to 13,712 GWh by 2012. The commercial efficiency measures that hold the most promise include these:

Indoor lightinglamp ballasts, fixtures, specular re-flectors, compact fluorescent lightbulbs, high-efficiency metal halides, occupancy sensors controls, daylight dim-ming, LED exit signs;

Refrigerationhigh-efficiency vending machines, vending misers, high-efficiency refrigerators, high-effi-ciency reach-in coolers, high-efficiency ice makers, walk-in refrigeration retrofit package, heat pump water heater;

Coolinghigh-efficiency air conditioning, high-effi-ciency heat pumps, high-efficiency chillers, optimized HVAC systems, optimized chiller distribution and control systems, water source heat pump, ground source heat pump, emergency control, dual enthalpy control, high-efficiency stove hoods, high-performance glazing;

Ventilationemergency management system control, premium efficiency motor, variable-frequency drive;

Office equipmenthigh-efficiency CPUs, high-effi-ciency monitors, low-mass copiers, high-efficiency fax ma-chines, high-efficiency printers, high-efficiency internal power supplies;

Whole-building controlsretrocommissioing, com-missioning, integrated building design, high-efficiency trans-formers;

Water heatinghigh-efficiency tank-type water heater, point-of-use water heater, booster water heater, heat pump water heater;

Outdoor lightingLED traffic lights, LED pedestrian signs, pulse-start metal halides, compact fluorescent bulbs, improved exterior lighting design;

Space heatinghigh-efficiency heat pumps, water source heat pumps, ground source heat pumps, optimized HVAC systems, optimized chiller control systems, emer-gency management control systems, high-efficiency stove hood, high-performance glazing; and

Miscellaneoushigh-efficiency clothes washers, wa-ter and wastewater optimization.

A more detailed account of the potential for these measures appears in Appendix G-1.

NYSERDAs $175 million New York Energy $mart Pro-gram (funded by New Yorks Systems Benefit Charge pro-gram, through a surcharge to each consumers bill) has shown that efficiency programs can be successful. A 2004 evaluation of New York Energy $mart concluded that five efficiency programs have saved around 1,000 GWh from 2003 through 2004. The same review concluded that full Copyright © National Academy of Sciences. All rights reserved.

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DEMAND-SIDE OPTIONS 27 implementation of New York Energy $mart is expected to achieve 2,700 GWh in the next 2 years.

These programs already are accounted for in the NYISO demand projections. Expanding current programs and creat-ing new ones could achieve further gains in efficiency. If Indian Point is to be closed, that is one of the replacement options that can be considered.

Potential for Peak-Demand Reduction Energy-efficiency programs can save considerable elec-tricity, and the NYSERDA (2003) study documented that a great many improvements are available at modest cost. How-ever, not all improvements will save at the same moment.

The key consideration in the possible replacement of Indian Point is that of maintaining reliability during periods of peak load. By lowering overall demand, energy-efficiency pro-grams also reduce peak demand, but not by the total of all the improvements.

The committee estimated the peak-load reduction that might realistically be achieved as a result of efficiency pro-grams in the Indian Point region, as shown in Table 2-4.

Details of the estimation are provided in Appendix G-2, Es-timating the Potential for Energy-Efficiency Improvements.

It is unlikely that programs can be put in place with suffi-cient resources to deliver all of the maximum achievable potential. The program potential is estimated at half the achievable potential. This factor is intended to introduce ad-ditional conservatism into estimates of the potential for en-ergy efficiency. It is consistent with the estimate of Rufo and Coito (2002, Table 3-3) of the lower bound for advanced efficiency in California at one-half the higher bound for maximum achievable efficiency. The application of this fac-tor results in estimates for program potential that grow from a reduction of 420 MW in 2007 to a reduction of 550 MW in 2015.

Two final adjustments are shown in the bottom line of Table 2-4. First, some lead time is required to phase in and establish new programs and expand existing activities. Pro-grams established or expanded in 2006 will have very lim-ited effect in 2007. Therefore, the program potential of 420 MW in 2007 is reduced to a phased-in programmable poten-tial of 100 MW. The phased-in programmable potential is assumed to grow rapidly to 450 MW in 2010 and to reach the level of the full program potential of 550 MW by 2015. In addition, the committee expects that high fuel prices will increase the incentive to improve efficiency. Therefore the estimated phased-in programmable potential in 2015 is in-creased to 575 MW.

The estimates in Table 2-4 are consistent with those of other studies. The New York Energy $mart review noted above expected a reduction of peak demand of 880 MW within 2 years (statewide) as a result of program activities. A study presented to the New York State Public Service Com-mission concluded that the achievable potential for effi-ciency measures in New York City was 283 MW for resi-dential and 1,392 MW for commercial buildings over 10 years (Plunkett and Gupta, 2004).

Finally, a study of the energy-efficiency potential in the New York City area, sponsored by the Pace Law School Energy Project and the Natural Resources Defense Council, concluded that savings of 1,163 MW to 3,032 MW peak de-mand could be achieved by aggressive energy-efficiency programs within 2 years (Komanoff, 2002).13 To accomplish such reductions, the study suggested applying the rapid crash efficiency techniquestargeting the deployment of more efficient lighting, air conditioners, and appliance stan-dardsemployed by the state of California after its energy crisis in 2001. The extreme conditions associated with Californias 2001 programs are not the context within which options for Indian Point are being evaluated, but they do illustrate a higher bound of possibilities if energy efficiency were to become a political rallying cry in New York City.

The Potential for Future Demand Response Several of NYSERDAs existing programs illustrate the ability of demand-response programs to reduce peak electri-TABLE 2-4 Committee Estimation of the Potential of Energy-Efficiency Programs in New York Control Area Zones I, J, and K, Selected Years Between 2007 and 2015 (MW)

Reductions in Year Maximum Achievable Potential 2007 2008 2010 2013 2015 Zone I (Westchester County) 113 119 127 140 148 Zone J (New York City) 502 529 563 624 658 Zone K (Long Island outside of 226 239 253 285 297 New York City)

Total maximum achievable 842 887 943 1,046 1,103 potential Total program potential 420 440 470 520 550 (50% of achievable)

Phased-in programmable potential 100 200 450 525a 575a NOTE: Details of the estimation are provided in Appendix G-2, Estimat-ing the Potential for Energy-Efficiency Improvements.

aNote that the phased-in programmable estimates exceed the total program potential in these years. This reflects the fact that more efficiency investments are cost-effective with the increased price of fuels today, and this is likely to be the case well into the future. These figures are based on historic (and low, by todays standards) Energy Information Administration price forecasts to calculate cost-effective energy efficiency.

SOURCE: Derived from NYSERDA (2003).

13This lowest estimate included adjustments for climate, forecast un-certainties, and consumption patterns.

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28 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER cal loads for costs per kilowatt that are far lower than the cost of installing new peak capacity. Three of these programs alone have already avoided the need for over 700 MW of peak capacity:

Peak Load Reduction Program: avoids the need for be-tween 355 and 375 MW,

Enabling Technology for Price Sensitive Load Man-agement Program: avoids the need for 308 MW, and

Keep Cool Program: avoids the need for between 38 and 45 MW.

NYSERDA divides its efficiency programs into three types:

business/institutional (which include the Commercial and In-dustrial Performance Program, New Construction Program, and Peak Load Reduction Program); residential (which in-cludes the Keep Cool Program); and low-income (which in-cludes the Low-Income Assisted Multi-Family Program).14 In the studies referred to here, the prices reflect capacity costs and expenses for the downstate and urban areas. The analyses use avoided costs based on wholesale-electricity bid prices (rather than production costs), and they use en-ergy-efficiency load profiles to differentiate savings by time of day (NYSERDA, 2004b, p. 1).

The studies evaluating NYSERDA programs also distin-guish between proposed megawatts (demand target), enabled megawatts (coincident demand reduction), pledged mega-watts (based on self-reporting), and delivered megawatts (av-eraged hourly reduction). Most of the estimates below (un-less otherwise noted) refer to pledged megawatts. When some of the evaluations listed the delivered megawatts, they were typically only half the pledged rate. On the other hand, the estimated cost per megawatt of demand reduction is gen-erally much lower than that of new supply options.

Peak Load Reduction Program The Peak Load Reduction Program (PLRP), created in 2000, uses four different program segments:

1. Permanent demand-reduction efforts, which result in reduced demand through the installation of peak-demand-reduction equipment;

2. Load curtailment and shifting, through enrollment in the NYISO demand-response program;

3. Dispatchable emergency generator initiatives, which allow owners of backup generators to remove their load from the grid in response to NYISO requests; and

4. Interval meters, which reduce peak demand at the site of consumption.

The program avoids between 355 and 375 MW of peak demand. However, 340 MW of this is callable, and only about 15 to 20 MW are permanent. Participants that are call-able receive annual capacity payments and are required to perform when called. The program costs around $42.7 mil-lion over 8 years, or approximately $120/kW of peak-load reduction.

Enabling Technologies Program The Enabling Technologies Program (ETP), created in 2000, supports innovative technologies that enhance load serving entities (LSEs), curtailment service providers (CSPs), and NYISO. It directs customers to reduce load in response to emergency or market-based price signals. The technologies used include advanced meters, transaction-management software, and networking and communication solutions. As of 2003, the ETP has saved 308 enabled peak MW. The program costs around $34.4 million per 8 years, or approximately $110/kW of peak-load reduction.15 Together, the PLRP and ETP saved 174 MW in 2001, 311 MW in 2002, and 288 MW in 2003.16 Keep Cool Program The Keep Cool Program was started in 2001 and ended in 2003. It encouraged the replacement of old, inefficient air conditioners with new ENERGY STAR-rated room air con-ditioners and through-the-wall units. The program has two main components: it includes rebates and incentives for cus-tomers, and it uses a significant marketing campaign that encourages customers to shift appliance use to nonpeak peri-ods. As a result of the wide scope of its multimedia market-ing program, the Keep Cool Program resulted in about 361,000 units being replaced, of which 141,000 units were given incentives through the program.

The program is estimated to have avoided approximately 41 MW of peak demand in every year of the program. The program costs around $19.9 million over 8 years, or approxi-mately $490/kW of peak-load reduction.17 In conclusion, these three programs document the poten-tial for NYSERDA demand programs to cost-effectively re-duce peak loads.

Estimating the Potential for Demand Reduction The committee estimated the potential for demand-15An updated program evaluation report (Heschong Mahone Group, 2005) evaluated the Peak Load Reduction and Enabling Technologies Pro-grams together. It estimates peak reductions of 178 MW (p. 25), costs of

$28.8 million (Table 3-9, p. 24), for a cost per peak reduction of $163/kW.

16See NYSERDA (2004b, p. 34).

17An updated program evaluation report (Heschong Mahone Group, 2005) estimates peak reductions of 19.7 MW (Table 3-1, p. 16), costs of

$18.4 million (Table 1-3, p. 4), for a cost per peak reduction of $934/kW.

14For more on these programs, see the useful tables in New York En-ergy $mart Program Cost-Effectiveness Assessment (NYSERDA, 2004b,

p. 2-3).

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DEMAND-SIDE OPTIONS 29 response programs to reduce peak demand in the Indian Point service area, as shown in Table 2-5. Details of the estimation are provided in Appendix G-3, Estimating Demand-Re-sponse Potential.

In total, energy-efficiency and demand-response pro-grams in Zones I, J, and K are estimated to be able to deliver peak-demand reductions of 150 MW in 2007, rising to 650 MW in 2010, and 875 MW in 2015 (see Tables 2-4 and 2-5).

The Potential for Expanded Combined Heat and Power Many studies have assessed the potential for combined heat and power in New York State, with some looking more specifically at opportunities within the Consolidated Edison service territory and/or the relevant New York Control Area load zones in the vicinity of Indian Point.

A 2002 study in New York State (NYSERDA, 2002) noted that there are approximately 5,000 MW of CHP al-ready installed in the state; it assessed the technical poten-tial for additional CHP, that is, the remaining market size constrained only by technological limits. Technical poten-tial does not consider other factors such as capital availabil-ity, natural gas availability, and variations in consumption within customer application and size class. The report looked only at CHP, not at other DG technologies that do not in-volve heat production. It identifies nearly 8,500 MW of tech-nical potential for new CHP in New York at 26,000 sites.

Close to 74 percent of remaining capacity is below 5 MW and is primarily at commercial and institutional facilities.

The largest proportion of this capacity is in the ConEd service territory. NYSERDA (2002) identified almost 3,000 MW of technical potential among its customers, the largest opportunities being office buildings, hotels and motels, apartments, schools, and colleges and universities. The re-port also identified about 300 MW of CHP technical poten-tial among ConEd industrial customers, the largest opportu-nities being chemical and food plants and textile and paper manufacturers.

The NYSERDA (2002) study stressed that the actual market penetration of CHP will depend on several factors, including the economic advantage of CHP over separately purchased fuel and power, the sites with economic potential, and the speed with which the market can ramp up in the development of new projects. The study developed base case and accelerated case models for CHP market penetration; the models differed in terms of assumptions about power costs, standby rates, technology advances, CHP policy changes including tax incentives, and customer awareness and adoption rates. In the base case, an additional 764 MW of CHP is projected to be installed in New York State by 2012. Nearly 70 percent of this capacity (or 535 MW) is projected to be in the downstate region that includes Indian Point. In the accelerated case, cumulative market penetra-tion reaches nearly 2,200 MW statewide. About 60 percent (1,320 MW) of the penetration is projected in the downstate region in 2012.

Using a trajectory of market expansion for CHP similar to that for energy-efficiency and demand-response programs, the base case estimate of 535 MW in 2012 could be phased in to the marketplace as estimated by the committee and pre-sented in Table 2-6.

The Potential for Expanded Distributed Photovoltaics Photovoltaics can provide high-value peak-time power in a distributed fashion and with minimal environmental emis-sions. Thus, PV could contribute significantly to grid stabil-ity, reliability, and security (Perez et al., 2004). Rapidly de-clining PV costs could make this technology a significant contender for replacement power within the time frame of this study even though PV is an intermittent source of elec-tricity. Throughout the 2006-2015 period, installations would have to be subsidized, but the end result could be an important new energy source with many desirable attributes and a thriving industry.

TABLE 2-6 Committee Estimation of Potential Peak Reduction from Combined Heat and Power in New York Control Area Zones I, J, and K, Selected Years Between 2007 and 2015 (MW)

Reductions in Year 2007 2008 2010 2013 2015 Combined heat and power 100 200 450 550 600 NOTE: Zone I, southern part of Westchester County; Zone J, New York City; Zone K, Long Island outside of New York City. Details of the estima-tion are provided in Appendix G-3, Estimating Demand-Response Poten-tial.

SOURCE: Derived from NYSERDA (2002).

TABLE 2-5 Committee Estimation of Potential Peak Reduction from Demand-Response Programs in New York Control Area Zones I, J, and K, Selected Years Between 2007 and 2015 (MW)

Reductions in Year 2007 2008 2010 2013 2015 Demand-response programs 50 100 200 275 300 NOTE: Zone I, southern part of Westchester County; Zone J, New York City; Zone K, Long Island outside of New York City. Details of the estima-tion are provided in Appendix G-3, Estimating Demand-Response Potential.

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30 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER Unlike the options discussed above, projections of PV installations on the scale envisioned here cannot be based on current prices or U.S. programs and progress. Rather, the accelerated PV-deployment scenario described here is mod-eled on the Japanese program that provided a declining sub-sidy to residential PV systems over the past decade. Resi-dential PV installations expanded in Japan from roughly 2 MW in 1994 to 800 MW in 2004 (Ikki, 2005). Results are presented in Table 2-7; the analysis is in Appendix D-7, Distributed Photovoltaics to Offset Demand for Electric-ity, and Appendix G-4, Estimating Photovoltaics for De-mand Reduction. (The analysis of PV potential is based on solar insolation data from the National Solar Radiation Data Base of the U.S. Department of Energys National Renew-able Energy Laboratory [NREL]. This database has data from seven sites in New York State, including one site in New York City.) It might also be noted that, in January 2006, California announced a solar initiative with a goal of 3,000 MW of photovoltaics by 2017 (California PUC, 2006).

Summary Additional cost-effective demand-side investments in en-ergy efficiency, demand response, and combined heat and power facilities can significantly offset peak demand, as pre-sented in Tables 2-4 though 2-6. These new initiatives (be-yond those currently anticipated) could reduce peak demand by 1 GW or more by 2010 and 1.5 GW by 2015. If the cost of distributed photovoltaics can be brought to near-competitive levels over the next decade (see Table 2-7), demand-side measures could contribute 1.7 GW by 2015, thus approach-ing the capacity of Indian Point (about 2 GW).

The effectiveness of demand-side options in downstate New York, to date, has been variable owing to numerous obstacles to deployment, and forecasted program perfor-mance is always uncertain. However, there is a growing body of evidence from New York (through NYSERDA), Califor-nia, and other states and communities that demand-side op-tions can be implemented swiftly and cost-effectively. Con-clusions for each of the four demand-side opportunities are summarized in Figure 2-4.

Energy efficiency programs offer significant potential for peak-demand reduction. Based on prior assessments of hun-dreds of energy-efficiency measures for residential and com-mercial buildings, it is estimated that 100 MW of additional peak reduction could be achieved in 2007 if new and ex-panded programs were to begin in January 2006. This eco-nomic and programmable potential is assumed to grow to 450 MW in 2010 and to reach 575 MW by 2015 (Table 2-4).

The estimated potential for demand-response programs to reduce peak demand in the Indian Point service territory is based on the experience to date with three NYSERDA pro-grams that avoided the need for 715 MW of peak demand in the state of New York in 2004. Evaluations of the recent performance of these programs suggest that they offer a highly cost-effective mechanism for reducing peak demand.

Assuming that a doubling of program budgets could expand the demand reduction by 50 percent, the committee estimates that the Indian Point service territory has the potential for TABLE 2-7 Committee Estimation of Potential Peak Reduction from Photovoltaics in New York Control Area Zones I, J, and K, Selected Years Between 2007 and 2015 Achieved in Year 2007 2008 2010 2013 2015 Installed system cost ($/W) 7.36 7.02 6.34 5.40 4.80 Subsidy rate (%)

47 44 38 27 19 (declining to 0 in 2019)

Annual subsidy (million $)

29 36 56 74 72 (declining to 0 in 2019)

Annual installations (MW) 8.4 11.8 23.0 50.4 78.8 Cumulative installations (MW) 18.6 30.4 69.9 192.9 334.7 Reduction in peak demand (MW) 14 23 52 144 250 NOTE: Zone I, southern part of Westchester County; Zone J, New York City; Zone K, Long Island outside of New York City. Details of the estima-tion are provided in Appendix D-7, Distributed Photovoltaics to Offset Demand for Electricity, and Appendix G-4, Estimating Photovoltaics for Demand Reduction.

FIGURE 2-4 Phased-in programmable potential for expanded de-mand-side options in the Indian Point service territory (in mega-watts of peak reduction). Heavily hatched bars, energy-efficiency programs; dotted bars, demand-response programs; vertically striped bars, distributed heat and power; and lightly hatched bars, distributed photovoltaics.

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DEMAND-SIDE OPTIONS 31 expanded summer peak reductions of approximately 200 MW in 2010 and 300 MW in 2015 (Table 2-5).

The actual market penetration of combined heat and power will depend on several factors including fuel prices, standby rates, and the speed with which the market can ramp up its production and services. Under the assumption of ac-celerated deployment policies, the phase-in programmable potential for expanded CHP is estimated to grow from 100 MW in 2007 to 450 MW in 2010 and 600 MW in 2015 (Table 2-6).

Under an aggressive deployment scenario, it is estimated that 70 MW of distributed photovoltaics could be installed in the Indian Point service territory by 2010, and 335 MW by 2015 (Table 2-7). Realizing this accelerated scenario would require reductions in the cost of PV systems and a long-term commitment to expanding New Yorks existing PV pro-grams. Such an initiative could establish a self-sustaining PV market in New York, resulting in the continued growth in PV distributed power well beyond the time horizon of this study.

It should be noted that the discussion in this chapter has been relevant to the summer peak only. The New York Con-trol Area also has a winter peak that is about 80 percent of the summer peak. Some of the efficiency measures (e.g., air conditioners) discussed here will not apply in the winter, and PV will contribute little or nothing to the winter peak. The committee did not have the time or resources to examine the winter peak, but this analysis should be performed before it can be fully concluded that demand-side measures would play a large role in replacing the electric power from Indian Point. This analysis also should include a full assessment of the availability of natural gas to enable expanded CHP use in winter (curtailments of gas deliveries to electric generators already occur in the heating season) and the somewhat higher efficiency of many generators and transmission lines in cold weather.

Impediments to Demand-Side Programs If demand-side programs are so cost-effective, why are they not in more widespread use? If individuals or businesses can make money from energy efficiency, why dont they all just do so? If electricity providers can reduce demand more cheaply than they can deliver new energy supplies, why isnt energy efficiency a larger part of their services? These ques-tions can be answered in large part by describing the range of obstacles that prevent the full exploitation of energy effi-ciency, including misplaced incentives, distortions of fiscal and regulatory policies, electricity pricing policies, insuffi-cient and incorrect information, and others as discussed be-low. These are the targets that policies would have to ad-dress if demand-side options are to play their full role.

As suggested in that long list, the impediments to energy efficiency are numerous and variable. They depend on the characteristics of a region, the technology, and the supply infrastructure. At the outset, misplaced incentives inhibit energy-efficient investments whenever an intermediary has the authority to act on behalf of a consumer, but does not fully reflect the consumers best interests. The landlord-ten-ant relationship is a classic example of misplaced incentives.

Decisions about the energy features of a building (e.g.,

whether to install high-efficiency windows and lighting) are often made by people who will not be responsible for the energy bills. For example, landlords often buy the air condi-tioning equipment and major appliances, while the tenant pays the electricity bill. As a result, the landlord is not gener-ally rewarded for investing in energy efficiency. Conversely, when the landlord pays the utility bills, the tenants are typi-cally not motivated to use energy wisely. As a result, tenants have no incentive to install efficient measures benefiting the landlord, and the landlord has little incentive to invest in measures that benefit the tenant (Ottinger and Williams, 2002). About 90 percent of all households in multifamily buildings are renters, which makes misplaced incentives a major obstacle to energy efficiency in urban housing mar-kets such as New York City.

Distortionary fiscal and regulatory policies can also re-strain the use of efficient energy technologies. A range of these obstacles was recently identified in an analysis of projects aimed at installing distributed generation, which is modular electric power located close to the energy consumer; it includes photovoltaics, diesel generators, gas turbines, and fuel cells. Regulatory barriers to these new technologies in-clude state-to-state variations in environmental permitting requirements that result in significant burdens to project de-velopers. Utilities also set high uplift charges (a fee that taxes the amount of revenue gained from selling electricity) and demand fees (a charge that penalizes customers for displac-ing demand from utilities) that discourage the use of distrib-uted power systems (Allen, 2002). A recent study by the NREL found a variety of extraneous charges associated with the use of dispersed renewable technologies (Alderfer and Starrs, 2000). The senior editor of Public Utilities Fort-nightly described such charges as a major obstacle to the development of a competitive electricity market (Stavros, 1999, p. 37).

Electricity pricing policies can also prevent markets from operating efficiently and subdue incentives for energy effi-ciency. The price of electricity in most retail markets today is not based on time of use. It therefore does not reflect the real-time costs of electricity production, which can vary by a factor of ten within a single day. Because most customers buy electricity as they always haveunder time-invariant prices that are set months or years ahead of actual use consumers are not responsive to the price volatility of whole-sale electricity. Time-of-use pricing would encourage cus-tomers to use energy more efficiently during high-price periods. These market failures can be exacerbated by com-petitive wholesale markets, since generators have no incen-tive to promote efficiency or load management because they Copyright © National Academy of Sciences. All rights reserved.

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32 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER profit handsomely from high peak prices. Under current rate designs, LSEs also profit from throughput, finding their prof-its mitigated by energy efficiency programs. In this way, current market structures actually block price signals from reaching service providers (Cowart, 2001, p. vii).

In sum, because of these market barriers, neither electric-ity generators, transmission companies, nor consumers see the real value of efficiency. Without better price signals, it is challenging for the providers of energy-efficient products and services to transform consumer markets; as a result, in-centives such as rebates and tax credits for improved end-use technologies are needed above and beyond those that already exist.

Furthermore, insufficient and incorrect information can also be a major obstacle to energy efficiency. Reliable infor-mation about product price and quality allows firms to iden-tify the least costly means of production and gives consum-ers the option of selecting goods and services that best suit their needs. Yet information about energy-efficient options is often incomplete, unavailable, expensive, and difficult to obtain. With such information deficiencies, investments in energy efficiency are hindered. It is difficult to learn about the performance and costs of energy-efficient technologies and practices because the benefits are often not directly ob-servable. For example, residential consumers get a monthly electricity bill that provides no breakdown of individual end uses, making it difficult to assess the benefits of efficient appliances, televisions, and other products. The complexity of design, construction, and operation of commercial build-ings makes it difficult to characterize the extent to which a particular building is energy efficient.

While there are tools such as ENERGY STAR branding, studies have shown that many consumers do not understand them. Further compounding the problem of measuring gains from efficiency concerns the notion of take-back. When a device has a gain in energy efficiency, consumers have addi-tional resources to spend or save. Some of these resources may be spent on additional energy-consuming activities, which means that the full potential for energy savings does not materialize. Blumstein (1993, p. 970) noted that low-income programs have a higher than average take-back effect (the participants take back some of the energy saved by taking other actions to increase their comfort). Based on a recent review of a wide range of markets (Geller and Attali, 2005, Table 1), the take-back, or rebound, effect would ap-pear to be relatively small, generally ranging from 10 to 20 percent.

Decision-making complexities are another source of im-perfect information that can confound consumers and inhibit rational decision making. Even while recognizing the im-portance of life-cycle calculations, consumers often fall back to simpler first-cost rules of thumb. While some energy-effi-cient products can compete on a first-cost basis, many of them cannot. Properly trading off energy savings versus higher purchase prices involves comparing the time-dis-counted value of the energy savings with the present cost of the equipmenta calculation that can be difficult for pur-chasers to understand and compute. This is one of the rea-sons builders generally minimize first costs, believing (prob-ably correctly) that the higher cost of more efficient equipment will not be capitalized into a higher resale value for the building. Moreover, the decentralized nature of the construction industryhome to more than 100,000 builders in the United Statesusually means that those engaged in building design and construction have little interaction with one another. The result is lack of information awareness among builders, consumers, and specialists in the building process (Alliance to Save Energy, 2005; Loper et al., 2005).

The complexity of the building market is accompanied by confusing and uncoordinated institutional arrangements, with different government agencies sometimes in charge of regulating, implementing, and enforcing the same statute.

For example, 18 states have adopted the International En-ergy Conservation Code of 2003, while 9 states have energy codes that are more than a decade old or follow no energy code at all.

Energy efficiency is not a major concern for most con-sumers because energy costs are not high relative to the cost of many other goods and services. In addition, the negative externalities associated with the U.S. energy system are not well understood by the public. The result is that the public places a low priority on energy issues and energy-efficiency opportunities, which in turn reduces producers interest in providing energy-efficient products. In most cases, energy is a small part of the cost of owning and operating a building or a factory. Of course, there are exceptions. For low-income families, the cost of utilities to heat, cool, and provide other energy services in their homes can be a very significant part of their incomeaveraging 15 percent compared with 4 per-cent for the typical U.S. citizen. For energy-intensive indus-tries such as aluminum and steel, energy can represent 10 to 25 percent of their production costs. Many companies in these more energy-intensive firms have decided to incorpo-rate energy management as a key corporate strategy.

Since energy costs are typically small on an individual basis, it is easy (and rational) for consumers to ignore them in the face of information-gathering and transaction costs (Harrington and Murray, 2003, p. 3). However, the potential energy savings can be important when summed across all consumers. A little work to influence the source of mass-produced products can pay off in significant efficiency im-provements and emissions reductions that rapidly propagate through the economy owing to falling production costs as market shares increase.

Energy prices, as a component of the profitability of an investment, are also subject to large fluctuations. The uncer-tainty about future energy prices, especially in the short term, seems to be an important barrier. Such uncertainties often lead to higher perceived risks and therefore to more stringent investment criteria and a higher hurdle rate. An important Copyright © National Academy of Sciences. All rights reserved.

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DEMAND-SIDE OPTIONS 33 reason for high hurdle rates is capital availability. Capital rationing is often used within firms as an allocation means for investments, leading to hurdle rates that are much higher than the cost of capital, especially for small projects.

Lack of availability of energy-efficient technologies is also often a problem. For example, the purchase of heat-pump water heaters and ground-coupled heat pumps has been handicapped by limited access to equipment suppliers, installers, and repair technicians (Brown et al., 1991; Opti-mal Energy and the State Grid Corporation DSM Instruc-tion Center, 2005). The problem of access is exacerbated in the case of heating equipment and appliances; because they are often bought on an emergency basis, choices are limited to available stock. Retrofitting can also be expensive, time consuming, and intrusive for home owners and commercial enterprises, especially for businesses that cannot afford the downtime needed for installation. Building stock also turns over very slowly, suggesting that inefficient structures remain in use for decades (Ferguson and White, 2003, pp. 15-16).

Finally, managerial and commercial attitudes impede the use of energy-efficient technologies. In the manufacturing sector, energy-efficiency investments are hindered by a pref-erence for investments that increase output compared with investments that reduce operating costs (Hirst and Brown, 1990; Alliance to Save Energy, 1983; Sassone and Martucci, 1984). Similarly, electric utilities believe that they possess the duty and obligation to serve customers needs. Electric utility regulations have been built on ancient common law duty, known as the duty to serve the customer, applied to public utilities such as ferries, flour mills, and railroads. In the words of James Rossi, professor of law at Florida State University, In the public utility context the duty to serve requires service where it is not ordinarily considered profit-able. As one utility executive exclaimed in a recent edito-rial, We cant hide behind restructuring and deregulation.

Even with unbundled generation, the obligation to serve the load remains (Lovins et al., 2002, p. 88). Thus, the belief among utility managers and policy makers persists that they need only provide the energy that the customer requires, rather than reforming their customers consumption require-ments through energy-efficiency measures.

Collectively, these social, economic, and cultural impedi-ments greatly inhibit the use of demand-side options. Ag-gressive policy measures are required to overcome them.

REFERENCES Alderfer, R. Brent, and Thomas J. Starrs. 2000. Making Connections: Case Studies of Interconnection Barriers and Their Impact on Distributed Power Projects. National Renewable Energy Laboratory (NREL)/SR-200-28053. Golden, Colo.: NREL.

Allen, Anthony. 2002. The Legal Impediments to Distributed Generation.

Energy Law Journal 23: 505-523.

Alliance to Save Energy. 1983. Industrial Investment in Energy Efficiency:

Opportunities, Management Practices, and Tax Incentives. Washing-ton, D.C.: Alliance to Save Energy.

. 2005. Blueprint for Energy-Efficiency Acceleration Strategies for Build-ings in the Western Hemisphere. Washington, D.C.: Alliance to Save Energy, June 14.

Blumstein, Carl. 1993. The Cost of Energy Efficiency. Science 261(5124, August 20): 969-971.

Brown, M.A., L.G. Berry, and R. Goel. 1991. Guidelines for Successfully Transferring Government-Sponsored Innovations. Research Policy 20(2): 121-143.

Brown, Marilyn A., Frank Southworth, and Therese K. Stovall. 2005. To-wards a Climate-Friendly Built Environment. Pew Center on Global Climate Change, June. Available at http://www.pewclimate.org/. Ac-cessed April 21, 2006.

California PUC (California Public Utility Commission). 2006. California Solar Incentive Program. Available at http://www.cpuc.ca.gov/static/

energy/solar/. Accessed April 21, 2006.

Cowart, Richard. 2001. Efficient Reliability: The Critical Role of Demand-Side Resources in Power Systems and Markets. Report to the National Association of Regulatory Utility Commissioners. Regulatory Assis-tance Project. June.

Energy Information Administration. 2006. Annual Energy Outlook 2006.

Available at http://www.eia.doe.gov/oiaf/aeo/index.html. Accessed April 21, 2006.

Ferguson, Richard, and V. John White. 2003. Risky Diet: 2003. In Natu-ral Gas: The Next Energy Crisis. Los Angeles: Center for Energy Effi-ciency and Renewable Technologies. September.

Geller, H., and S. Attali. 2005. The Experience with Energy Efficiency Policies: Learning from the Critics. International Energy Agency.

Available at www.iea.org/textbase/papers/2005/efficiency_policies.pdf.

Accessed April 21, 2006.

Gillingham, K., R. Newell, and K. Palmer. 2004. Retrospective Review of Demand-Side Energy Efficiency Policies. Washington, D.C.: National Commission on Energy Policy.

Goldman, C., N. Hopper, R. Bharvirkar, B. Neenan, R. Boisvert, P. Cap-pers, D. Pratt, and K. Butkins. 2005. Customer Strategies for Respond-ing to Day-Ahead Market Hourly Electricity Pricing. LBNL-57128.

Berkeley, Calif.: Lawrence Berkeley National Laboratory.

Harrington, Cheryl, and Catherine Murray. 2003. Who Should Deliver Ratepayer Funded Energy Efficiency? Regulatory Assistance Project Survey and Discussion Paper. Montpelier, Vermont. May.

Heschong Mahone Group. 2005. New York Energy Smart Program Cost-Effectiveness Assessment. Prepared for New York State Energy Re-search and Development Authority. June.

Hirst, E., and M.A. Brown. 1990. Closing the Efficiency Gap: Barriers to the Efficient Use of Energy. Resources, Conservation and Recycling 3: 267-281.

Ikki, Osamu. 2005. PV Activities in Japan. Tokyo, Japan: RTS Corporation.

May.

Kirby, Brendan, Chuck Goldman, Grayson Hefner, and Michael Kintner-Meyer. 2005. Load Participation in Reserves Markets: Experiences in U.S. and Internationally. October.

Komanoff, Charles. 2002. Securing Power Through Energy Conservation and Efficiency in New York: Profiting from Californias Experience.

Pp. 1-22 in Report for the Pace Law School Energy Project and the Natural Resources Defense Council. May.

Loper, J., L. Ungar, D. Weitz, and H. Misuriello. 2005. Building on Suc-cess: Policies to Reduce Energy Waste in Buildings. Report to the Alli-ance to Save Energy. Washington, D.C. July.

Lovins, Amory, et al. 2002. Small Is Profitable: The Hidden Benefits of Making Electrical Resources the Right Size. Snowmass, Colo.: Rocky Mountain Institute.

Margolis, Robert M., and Frances Wood. 2004. The Role for Solar in the Long-Term Outlook of Electric Power Generation in the U.S. Paper presented at the IAEE North American Conference in Washington, D.C.,

July.

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34 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER National Energy Efficiency Best Practices Study. 2004. Best Practices Benchmarking for Energy Efficiency Programs. Crosscutting Best Prac-tices and Project Summary, December.

NYISO (New York Independent System Operator). 2005a. Comprehensive Reliability Planning Process Supporting Document and Appendices for the Reliability Needs Assessment. Albany, N.Y. December 21.

. 2005b. Comprehensive Reliability Planning Process and Draft Reli-ability Needs Assessment. Albany, N.Y. September 1.

NYSERDA (New York State Energy Research and Development Author-ity). 2002. Combined Heat and Power, Market Potential for New York State.

. 2003. Energy Efficiency and Renewable Energy Resource Development Potential in New York State. Final Report. August.

. 2004a. New York Smart Program Evaluation and Status Report. Final Report: Executive Summary, May.

. 2004b. New York Energy $mart Program Cost-Effectiveness Assess-ment. Submitted by Heschong Mahone Group. December.

. 2005a. 2004 Annual Report.

. 2005b. Financial Statements. March 31. Available at www.nyserda.org/

publications/financials05.pdf. Accessed April 21, 2006.

Optimal Energy and the State Grid Corporation DSM Instruction Center.

2005. DSM Strategic Plan for Jiangsu Province. Final Draft Report, February 11.

Ottinger, Richard L., and Rebecca Williams. 2002. 2002 Energy Law Sym-posium: Renewable Energy Sources for Development. Environmental Law 32: 331-362.

Perez, Richard, et al. 2004. Solar Energy Security. REFocus (July/

August): 24-29.

Plunkett, John, and Ashok Gupta. 2004. State of New York Public Service Commission: Proceeding on the Motion of the Commission as to the Rates, Charges, Rules and Regulations of Consolidated Edison Com-pany of New York, Inc. for Electric Service. December 15.

Rufo, Michael, and Fred Coito. 2002. Californias Secret Energy Surplus:

The Potential for Energy Efficiency. San Francisco: The Energy Foun-dation. September 23. Available at http://www.ef.org/news_reports.cfm

?program=viewall&sort=creationdate. Accessed April 21, 2006.

Sassone, P.G., and M.V. Martucci. 1984. Industrial Energy Conservation:

The Reasons Behind the Decisions. Energy 9: 427-437.

SEIA (Solar Energy Industries Association). 2004. Our Solar Power Fu-ture: The U.S. Photovoltaic Industry Roadmap Through 2030 and Be-yond. Washington, D.C.: Solar Energy Industries Association.

Silva, Patricio. 2001. National Energy Policy: Conservation and Energy Efficiency. Hearing Before the Subcommittee on Energy and Air Qual-ity of the House Committee on Energy and Commerce, June 22. Wash-ington, D.C.: Government Printing Office.

Stavros, Richard. 1999. Distributed Generation: Last Big Battle for State Regulators? Public Utilities Fortnightly 137(October 15): 34-43.

USDOE (U.S. Department of Energy). 2004. Solar Energy Technologies Program, Multi-year Technical Plan 2003-2007 and Beyond. Report DOE/GO-102004-1775. Washington, D.C.: Office of Energy Efficiency and Renewable Energy, U.S. Department of Energy.

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35 3

Generation and Transmission Options When an electric generating plant is retired, it usually is replaced with other generating capacityperhaps a new gen-erating unit or a new transmission line from an area with surplus power. Either or both reactors at the Indian Point Energy Center could be replaced with these options. How-ever, demand growth projected by the New York Indepen-dent System Operator (NYISO) for the New York City area (see Chapter 5) would require considerable additional ca-pacity even without the retirement of Indian Point. That growth can be moderated, as discussed in Chapter 2, but it is likely to be significant. The supply options discussed in this chapter must be adequate to handle growth, retirements of existing capacity, and the potential replacement of Indian Point, if reliability of supply is to be maintained.

This chapter discusses the options for generation, trans-mission infrastructure, and reactive power in New York. Dis-tributed generation is discussed in Chapter 2 with other end-user options because it generally is not dispatchable by NYISO and is not included in reliability calculations.

EXISTING GENERATING CAPACITY New Yorks existing electricity generation is a diverse supply resource, including natural gas, oil, coal, hydroelec-tric, nuclear, and wind power, as described in Chapter 1.

However, much of this generation is far from the large and growing load centers of the New York City area. Western New York (New York Control Area [NYCA] Zones A through E) has surplus of capacity, while New York City (Zone J) is an importer of power, as shown in Table 3-1. The Lower Hudson Valley (Zones G through I) currently has a capacity well above its load, but that will more than disap-pear if Indian Point is closed. Long Island also must have imported power available to meet its reserve requirement (NYISO, 2005b).

The NYCA, taken as a whole, had approximately 1,300 megawatts (MW) of excess summer resource capability in 2005, representing an excess reserve margin of 3.5 percent.1 However, the situation by 2008 will be tighter. NYISO ex-pects peak demand to increase by 1,370 MW, and capability may actually decline because of plant retirements. Thus, re-serve margins could be lower than the standard requires, even without the retirement of either of the Indian Point reactors.

In addition to the excess capacity in the western section of the state and the Upper Hudson Valley region, some underutilized capacity might be found in the neighboring control areas: the mid-Atlantic counterpart to the NYCA, known as Pennsylvania Jersey Maryland [PJM]; Canada; and New England. In the past 5 years, the NYCA imported approximately 10 percent of its energy requirements from PJM and Canada. The annual energy exchange between the NYCA and New England is essentially neutral. It is difficult to determine exactly how much capacity might be found (much of the key information is proprietary) and whether the TABLE 3-1 Approximate (Noncoincident) Summer Peak Load and Capacity in New York State, by Region Peak Load Capacity Zone (MW)

(MW)

West (A through E) 8,900 14,430 Upper Hudson Valley (F) 2,180 3,470 Lower Hudson Valley (G through I) 4,490 5,490 New York City (J) 11,150 8,940 Long Island (K, outside of NYC) 5,050 5,180 NOTE: Numbers are approximate and based on the summer of 2004.

SOURCE: NYISO (2005a).

1The NYISO (2005b) report Comprehensive Reliability Planning Pro-cess lists total capability of 38,772 MW and an expected peak demand of 31,960 MW (demand actually peaked at 32,075 MW in July 2005). The required capability with an 18 percent reserve margin is 37,395 MW. Thus there was an excess capability of 1,327 MW.

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36 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER transmission capacity (discussed later in this chapter) to de-liver it to the New York City area is available. In addition, with demand growing elsewhere and more retirements likely, current excess capacity may not be available in a few years.

Currently, at most only a few hundred megawatts could be imported to the New York City area during peak periods, and demand growth is likely to account for that in a few years (Hinkle et al., 2005; discussed in Chapter 5 of this report). Additional power could be imported during peak periods if the transmission grid was upgraded (and in nonpeak periods even without upgrades).

POTENTIAL NEW GENERATING CAPACITY Having concluded that the existing generation and trans-mission system could make little contribution to replacing Indian Point, the Committee on Alternatives to Indian Point for Meeting Energy Needs turned to the question of potential new generation. The committee examined 18 potential alter-native generating technologies for possible use in the Lower Hudson Valley/New York City region, including 5 natural-gas-based options, 5 coal-based options, 2 biomass options, 3 wind options, 2 solar options, and 1 advanced nuclear power plant option. Many of these technologies were deter-mined to be unlikely to make a significant contribution to the power needs of the New York Control Area in the time frame of this study. Appendix D-1, Cost Estimates for Elec-tric Generation Technologies, lists all of the technologies considered with their key cost elements, and Appendix D-2, Zonal Energy and Seasonal Capacity, presents data for comparisons of zonal energy and seasonal capacity, includ-ing the use of supplemental oil with gas turbines.

Technologies Considered Potential generating technologies include natural-gas-fired units, coal-fired units, biomass-powered units, wind systems, solar-based technologies, and advanced nuclear re-actors. Table 3-2 lists the technologies considered and some of their characteristics.

Natural Gas The use of natural gas as a relatively clean fuel for elec-tric power generation has grown rapidly over the past 20 years as the supplies became more available from various areas of the United States and Canada compared with the period of the mid-1970s. Appendix D-3, Energy Generated in 2003 from Natural Gas Units in Zones H Through K, shows power generation from natural gas in the New York City area in 2003 and 2004. It also shows that replacing all of Indian Points power with natural gas would require about a one-third increase in the consumption of gas for electricity.

The technologies that are currently used to convert natu-ral gas to electricity are much more efficient and reliable than earlier versions. The environmental benefits of natural gas relative to other fossil fuels are also a big advantage.

Unlike coal, the combustion of natural gas emits no oxides of sulfur, and emissions of nitrogen oxides can be held to standards through stack-gas emission-control systems.

Current supplies of natural gas cannot always accommo-date current, let alone increased demand for the product. The owners of gas-fired units in New York State are frequently required to power their gas-fired units with oil products dur-ing cold weather periods since the residential sector, with firm delivery service, has priority over the utility sector, which typically has interruptible service tariffs. Generators with backup fuel systems have been providing nearly 20 per-cent of the electric production derived from the gas turbine facilities in New York State (NYISO, 2005b). For future natural gas turbine facilities to contribute to the electric sys-tem during cold weather periods, they should have either backup fuel capability with adequate fuel inventory or firm natural gas pipeline capacity for these periods. Oil tanks could necessitate a larger site footprint, and the combustion of the oil would change the characteristics of the stack-gas emissions, which would have to be addressed. Appendix D-3 lists the oil products used in the overall production of electricity from gas turbines in the New York City area. Peak demand for electricity is higher in the summer than in the winter, and in summer, gas supplies are abundant. Therefore gas supplies are unlikely to affect reliability calculations as discussed in Chapter 5, which focus on the summer peak, but they could well become a constraint during the winter peak. In addition, the increased use of backup oil in the win-ter raises energy security and environmental issues.

The availability of natural gas in the general area of the Indian Point facility is a key parameter in evaluating alterna-tive generation technologies to replace the two nuclear units.

The Algonquin Pipeline system crosses the Hudson River close to the Indian Point power plant on the way to Con-necticut. Algonquins two pipes have a combined capacity of 1.15 billion cubic feet per day (bcf/d), providing natural gas from the Gulf of Mexico into New York and on to New England. New York diverts some 0.12 bcf/d of the gas be-fore it reaches Connecticut. A possibility exists that some of New Yorks share could be combined with one or more other supplies to assist in generating about 800 MW. The current and future gas supplies would be considered interruptible, since the market environment does not compensate genera-tors for the extra reliability from firm gas supplies or backup fuel supplies.

In addition, a new gas pipeline, the Millennium Pipeline, is currently being installed in New York State. Phase 1 of the project is expected to be complete by November 2006. The line comes from central New York and crosses the Al-gonquin system near the Ramapo Substation in Rockland County. This line also might supply enough gas for an addi-tional 1,000 MW beyond commitments to customers. The Lovett Power Station site could be served by either line. The Copyright © National Academy of Sciences. All rights reserved.

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GENERATION AND TRANSMISSION OPTIONS 37 three coal-fired units (totaling 431 MW) at the siteon the west side of the Hudson River just across from and south of the Indian Point siteare scheduled to be shut down by 2008, so that site might be available for new gas-fired tur-bines. Thus, there is likely to be enough gas to supply a sig-nificant amount of new capacity at Lovett Station or else-where in the area. In addition, other pipelines have been proposed, as shown in Appendix D-4, Proposed Pipeline Projects in the Northeast. However, two other factors must be considered: namely, the price of gas and other growing demands for the gas (also discussed in Chapter 5).

Current prices for natural gas have been high since the two hurricanes in 2005 damaged some of the infrastructure in the Gulf of Mexico (DOE/EIA, 2005). Also, the overall supply to the state does not appear likely to be increased after the Millennium Pipeline is completed, for the foresee-able future. If so, the New York City area may not be able to continue increasing its use of natural gas for the near term.

Furthermore, the longer-term gas supply picture is not en-couraging unless resources such as liquefied natural gas (LNG) imports are increased, and LNG imports are uncer-tain with respect to timing, volumes, and locations for termi-nal facilities. Investors will have little incentive to build greater pipeline capacity should the supply return only to pre-storm levels in the Gulf region.

Data suggest that gas production from western Canada is declining. Diversions to other users may further limit deliv-eries to New York. Gas production levels in eastern Canada have experienced poor performance to date, although some gas may become available from Canadian Grand Banks fields. Overall, imports from Canada are not likely to in-crease significantly unless LNG is routed through Canada. It should be noted that natural gas exploration has increased in the areas south of the Finger Lakes in New York State, and gas production is at record levels for that area (40 bcf per year, or enough for about 800 MW of power generation).

Although it seems as if sufficient gas might be available to replace Indian Point generating capacity, in fact all of the excess may well be committed some time before the plants are shut down. Electricity demand is growing in the New York City area, and several other plants are scheduled to be retired and must be replaced. All new generating capacity TABLE 3-2 Potential Generating Technologies Considered by the Committee for Replacing Indian Point Assumed Relative Potential Electricity Output at Additional Type of Plant Capacity (MW) by 2015a Cost (¢/kWh)b Peak Demandc Considerationsd Natural gas Conventional gas combined cycle 250 Large 4.4 High F, C Advanced gas combined cycle 400 Large 4.1 High F, C Advanced combined cycle with carbon sequestration 400 Small 6.4 High F, R, D Conventional combustion turbine (simple cycle) 160 Large 5.8 High F, C Advanced combustion turbine (simple cycle) 230 Large 5.3 High F, C Coal Pulverized coal 600 Large 3.7 High T, CC Pulverized coal supercritical 500 Large 3.8 High T, CC Integrated coal gasification combined cycle (IGCC) 550 Large 3.7 High T, D, CC IGCC with carbon sequestration 380 Small 6.0 High T, R, D Fluidized-bed coal 500 Large 4.7 High T, CC Renewable energy Biomass 80 Small 7.2 High Municipal solid waste landfill gas 30 Small 3.5 High P

Wind Large 100 Moderate 5.7 Low P

Medium 50 Small 6.0 Low P

Small 10 Small 9.9 Low Solar photovoltaics 5

Smalle 25.0 Moderate Solar thermal 100 Small 30.0 Moderate Advanced nuclear 1,000 Small 4.2 High T, P aLarge: the total contribution could be more than 500 MW. Small: the total is likely to be less than 100 MW. Rated on the basis of readiness of technology, fuel availability, siting difficulties, permitting time, and other factors.

bCosts are from Appendix D-1 and are representative for the nation, not the region, which is higher.

cHigh: virtually all of the maximum capacity can be expected to be available during peak demand. Moderate: at least half the maximum capacity is likely to be available during peak demand. Low: it cannot be counted on.

dF: additional fuel supply needed; R: research needed; D: demonstration needed; T: additional transmission needed; P: public acceptance questions; CC:

high carbon dioxide emissions (>1 lb CO2/kWh); C: moderate CO2 emissions (<1 lb CO2/kWh); no C means little or no CO2 emissions.

ePV may make a significant contribution as a demand-reduction technology, as discussed in Chapter 2.

SOURCE: See Appendix D-1.

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38 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER currently being built in New York State, over 2,000 MW, is gas-fired. As discussed in Chapter 5, as much as 1,600 MW could be needed by 2010 to meet reliability requirements even without closing Indian Point. Almost all of the generat-ing capacity in the planning stage that could be brought online by 2010 also is gas-fired (883 out of a total of 1,033 MW).

Advanced natural-gas combined-cycle turbine generation facilities can provide reliable and environmentally attractive electric production service to the New York City region, but the production costs are essentially driven by the price and availability of the natural gas obtained from distant sources.

At current prices, fuel costs alone are about 4 cents per kilo-watt-hour (¢/kWh) in combined-cycle plants and 6 ¢/kWh in simple-cycle plants. In comparison, coal and nuclear plants have fuel costs of only 1 to 2 ¢/kWh, although their operat-ing and capital costs are higher than for gas-fired plants.2 Table 3-2 shows estimates of the total costs of electricity for all the options considered by the committee. The breakdown by fuel operations and capital are in Appendix D-1, Cost Estimates for Electric Generation Technologies.

One possibility would be to replace older, simple-cycle gas turbines with modern combined-cycle plants. This switch, called repowering, can result in 50 percent more power from the same supply of natural gas. In New York City, the East River plant is being repowered, and two units at Astoria are expected to be repowered. Other plants could also be considered.

Coal Coal-based power production provides approximately 14 percent of the electric energy used in New York State, ver-sus some 50 percent for the nation as a whole. No coal-pow-ered facilities are located in Zones H, I, J, or K, but there are two small coal-fired units (at Lovett Station) in Zone G. The major coal-based electric generating facilities are located in western sections of New York State. The amount of coal-based electricity produced in the state decreased by 1 per-cent between 2004 and 2005. The closing of the Lovett Sta-tion coal-burning generators will reduce this even more.

Coal plants require larger sites than do natural gas plants, in order to accommodate the storage of a 30-day supply of coal, associated ash-management systems, and defined areas to accommodate storm-water-management programs. Coal plants, therefore, are located in areas where property values are relatively low. Land values in the Lower Hudson Valley and New York City areas are among the highest in the nation.

Environmental considerations such as stack-gas emis-sions, noise from unit trains bringing coal and removing ash, and cooling water requirements all contribute to major siting challenges when using any coal-based generation technol-ogy in major urban areas. Coal-based technologies that were considered and evaluated with respect to operating costs are discussed in Appendix D-5, Coal Technologies. Coal-based power plant technologies that could produce power for the New York City region would be located at some dis-tance from the region, requiring long transmission lines.

Therefore, the cost of the power would include transmission costs as well as production costs. In addition, some air qual-ity issues could arise, depending on the location of the asso-ciated site.

Coal plants also emit more carbon dioxide per kilowatt-hour produced. Technologies are being developed to capture and sequester the carbon dioxide, but that process will add significantly to the cost of the electricity. Appendix D-5 dis-cusses the technology (integrated gasification, combined cycleIGCCthat will be most appropriate for capture of carbon dioxide).

A new coal plant built upstate from the New York City area might be the lowest-cost replacement for Indian Point, even with a new transmission line. Thus it should be included in the list of options. However, the committee believes that it is unlikely for a coal facility to be permitted and constructed even in upstate New York by 2015, especially considering the uncertainties over carbon dioxide.

Biomass Biomass represents a renewable fuel source for power generation. In the New York City area, biomass consists of municipal solid waste, sewage sludge, wood waste, agricul-tural waste, and other residues. Today there are five waste-to-energy plants in the downstate area, with one in Zone H and four in the Zone K area. The total capacity for these five units is 166 MW, and collectively they produced 1,274 giga-watt-hours (GWh) of power in 2004 of the 52,000 GWh gen-erated in Zones H, I, J, and K. Methane derived from bio-mass sources can be burned in gas turbines, and biomass in a solid form can be burned directly or gasified. It also can be co-fired in coal-based plants, but as noted above, coal plants are unlikely to be sited in the zones of interest for a variety of reasons.

In the 1980s, there was a move to have a waste energy facility located in each of the five counties of New York City as a measure to assist the city in managing its wastes and to address the need for fuel diversification in the city. The plan was dropped by the New York City government primarily because of strong and widespread public opposition to waste-to-energy plants being located in the city. The principal con-cerns were air quality and health issues. Municipal solid waste and sewage sludge currently produced in the city are shipped out of state, even though todays technologies are cleaner and might engender less public resistance.

2Locational-based marginal prices for the NYISO-run wholesale power market are given at https://www.nyiso.com/public/market_data/pricing

_data.jsp. Accessed March 2006. As an example, the 4:00 p.m. wholesale clearing price of electricity on January 23, 2006, was 11.9 ¢/kWh in New York City.

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GENERATION AND TRANSMISSION OPTIONS 39 Biomass appears unlikely to be a significant new source of electricity for the New York City region. Additional in-formation on the potential of the biomass resources is con-tained in Appendix D-6, Generation TechnologiesWind and Biomass.

Wind Wind energy systems have entered the New York State market with some 100 MW of capacity installed by 2005, and more is expected. The wind facilities are located in the central and northern areas of the state. The New York State Energy Research and Development Authority (NYSERDA) has initiated a wind development program that is installing some 500 MW of new wind capacity as a component of the States Renewable Portfolio Standard development program.

This program mainly provides support to developers after the units are placed into service. The developer has the re-sponsibility to site, license, construct, and place into service its wind facility.

New York State has several excellent wind sites that are being evaluated by developers for near-term application. At this point, few land-based sites are located close to the In-dian Point facility that have the desired wind characteristics and available land to install wind turbines that could contrib-ute to the replacement of the generation from the Indian Point plants. A project has been proposed at a site in the ocean off the south shore of Long Island. This project is proceeding, but at a pace slower than originally anticipated, owing to rising costs. Experience with offshore wind projects is lim-ited, and the developers are monitoring projects located else-where in the world. The Long Island project and other off-shore sites have the resource potential for considerable generation of electric power, but no units have been installed there, and considerable opposition can be anticipated, as has occurred in Massachusetts.

Technically there is sufficient wind resource in New York State to replace the Indian Point units, but resolving site lo-cation and permitting issues is key to successfully placing units into service. The greatest challenge for using wind to replace large baseload electric generation units is the inter-mittent nature of the resource. The availability factor for wind is 30 to 40 percent, compared with about 90 percent for nuclear and coal plants, and the resource is available only when the wind is blowing, not when demand is high. Storage will smooth out the intermittent nature of the resource, but that technology is not yet readily available. The issues asso-ciated with expanding the use of wind in the state are dis-cussed in Appendix D-6.

Solar Solar energy can be used to generate electricity either through the use of solar photovoltaic (PV) systems or through solar thermal power generation technologies. Solar PV electricity is increasingly being used for many applica-tions around the world.

PV use has increased as the price of solar cells and the resultant power costs have decreased and the reliability of the products has risen to a level that is acceptable to consum-ers for some applications. PV applications are limited by the dependence on the availability of sunlight, but for some ap-plications either that does not matter or else a small amount of battery storage can suffice. The technology promises to grow substantially in the distributed-generation-systems market, as discussed in Chapter 2. PV would require large land areas to collect sufficient energy to contribute to the bulk power markets and is unlikely to be a factor in New York State by 2015, but rooftop-mounted systems supplying directly to the retail market could become significant.

Solar thermal generation involves the use of mirror-like collectors designed to focus sunlight onto metal surfaces, which in turn through various systems can produce a steam product. The steam is then used in a steam turbine to pro-duce electricity. One advantage of the solar thermal concept is that the energy of the Sun can be stored in a liquid mate-rial on a clear day and then later extracted to produce steam at night or on cloudy days. Solar thermal generation requires large land areas to house the collectors and very direct sun-light to be economically attractive. The earliest applications of solar thermal technologies will be in the deserts of the southwestern part of the United States. The specific charac-teristics of the PV technology are discussed in Appendix D-7, Distributed Photovoltaics to Offset Demand for Electricity.

Advanced Nuclear Several advanced nuclear technologies are being explored for possible application in the 2015-2020 time frame (EPRI, 2005). The concepts are being supported through programs initiated in part by the recently enacted federal Energy Policy Act of 2005. The Nuclear Regulatory Commission has certi-fied three designs, which could be started shortly after an appropriate site is found and certified. Several consortia of energy companies (including Entergy Corporation) are mov-ing forward on various plans. A site at Oswego, New York, on Lake Ontario, had been considered but is not part of any current plan. That site had strong local support and may be considered in future plans.

Nuclear power could provide New York State with an electric power option that has no carbon dioxide emissions (which contribute to global warming), and no contribution to acid rain or mercury contamination. However, the commit-tee concluded that a new nuclear plant in New York State is unlikely before 2015. One or two of the projects now being planned in other states might be completed by 2015, but most companies are likely to wait in order to see how these plans progress before starting more projects.

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40 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER Overall Considerations A variety of supply options could contribute to replacing one or both reactors at the Indian Point Energy Center. As suggested in the previous discussion and in Table 3-2, the committee concludes that advanced natural-gas-fired com-bined-cycle plants are the generation option capable of mak-ing the biggest contribution at the lowest cost by 2015. This position assumes the ability to site such facilities in the Lower Hudson Valley/New York City area, favorable eco-nomic and regulatory conditions for investors, sufficient ad-vance notice that the power will be needed, and a long-term fuel supply.

One option that could be considered in the near term is to locate some 2,400 MW of natural-gas-fired combined-cycle plants at the current Lovett Station site, described earlier in this chapter. The site is currently being used for electric pro-duction. However, the current operator is just emerging from bankruptcy and may not be in a position to develop any new facilities. If that issue can be resolved, the site could be de-veloped for natural-gas-and/or oil-fired generation. The site has a transmission corridor, with limited transmission cur-rently installed, a developed waterfront, and basic elements of infrastructure. However, environmental impacts would need to be addressed, as would fuel delivery.

The greatest challenge would be to secure sufficient natu-ral gas supplies to satisfy the projected production levels, including very high capacity factors. Two large natural gas lines are located near the Lovett Station site, and more natu-ral gas might be added to the two existing systems from gas wells located in the state. If new sources of gas and new pipelines are required, the issues of gas availability and price must be examined in much greater detail than that allowed by the committees resources.

Coal-based technologies potentially offer attractive pro-duction costs, but the physical requirements of a large plant site in the region of the Indian Point Energy Center, com-bined with air quality issues, new rail lines to bring in the coal, and related technical challenges limit potential oppor-tunities for investors to promote this fuel source for applica-tion in the greater New York City area. If natural gas prices remain high, a coal plant upstate with a new transmission line to the New York City area might be a cost-effective solution.

Both natural gas and coal plants emit carbon dioxide (coal plants emit about twice as much per kilowatt-hour as natural gas plants), which nuclear plants do not. New York is part of the Regional Greenhouse Gas Initiative (RGGI), which pro-poses to limit emissions of carbon dioxide and other green-house gases. Achieving RGGI goals will be more difficult if Indian Point is replaced, as discussed in Chapter 4.

New York State is supporting renewable energy develop-ment for power production, including a recently adopted Renewable Portfolio Standard. Nevertheless, renewables are unlikely to provide the Lower Hudson Valley/New York City area with a significant share of the power provided by Indian Point within the time frame of this study.

ELECTRICAL TRANSMISSION Existing Transmission Most Americans are generally unaware of the vast elec-trical transmission network that connects a myriad of power-generating stations to the local power lines servicing their homes and businesses. Electricity is typically generated in large central power stations at 13,800 volts (13.8 kV) then often stepped up to 345 kV through power transformers and associated equipment in order to transmit the power ef-ficiently over long distances. These high-voltage transmis-sion lines provide the backbone for the bulk electrical power system throughout the United States. Transmission lines, however, can be designed to be operated at voltages other than 345 kV. Other typical voltages for transmission lines in the United States include 765 kV, 500 kV, 230 kV, 138 kV, 115 kV, and 69 kV. Power system engineers select the opti-mal voltage for a particular transmission line based on a num-ber of design considerations, including the lines proximity to generation and customer load. In general, however, trans-mission lines with higher voltages are utilized to intercon-nect generating plants to the bulk power system.

The bulk power system in New York State is similar to that in many other regions throughout the United States and Canada. According to NYISO, the bulk power system in New York State, the New York Control Area, contains more than 10,000 miles of transmission lines with voltages equal to 115 kV and more. Figure 1-1 in Chapter 1 shows the ma-jor transmission facilities in the NYCA with voltages of 230 kV and greater.

The NYCA is electrically connected to neighboring con-trol areas in the northeastern United States and the Canadian provinces of Quebec and Ontario through special high-volt-age transmission lines, often referred to as ties or inter-faces, such as those shown in Figure 1-1. The total nominal transfer capability between the control areas in the Northeast is less than 5 percent of the total peak load of the region and is declining as a percentage of such load (NYISO, 2005b).

This minimal import and export capability over the ties among the Northeast regional control areas means that the NYCA power system places even greater reliance on the in-ternal generation resources located within a particular con-trol region.

Transmission constraints or bottlenecks are not just as-sociated with the constrained ties between New York and its neighboring control areas, however. The NYCA has several major transmission bottlenecks within New York State, which significantly affect the free flow of power on its bulk transmission system. In particular, the electrical transmis-sion system around southeastern New York State, including greater metropolitan New York City and Long Island, is se-Copyright © National Academy of Sciences. All rights reserved.

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GENERATION AND TRANSMISSION OPTIONS 41 verely constrained owing to a lack of adequate transmission capacity into this area. As a result of the limited transfer capability into southeastern New York State, this subregion must place greater reliance on the generating plants located within greater metropolitan New York City and Long Island.

As shown in Chapter 5, a new transmission line could de-liver a large fraction of the power provided by Indian Point.

Table 3-3 and Figure 1-1 further describe the approxi-mate location of the three major transmission constraints within the NYCA. The Total East Interface constrains power flowing from western New York State, PJM, and Canada into eastern New York State. The Central East Interface is located east of the Total East Interface and serves to further constrain power flowing from the west and central portions of the NYCA. Finally, the Upstate New York-Southeast New York (UPNY-SENY) Interface severely constrains power flowing into southeastern New York State from the rest of New York and from PJM and Canada.

NYISO has segmented the NYCA into 11 distinct zones, as explained in Chapter 1, to accommodate the location of the transmission interfaces and to respect the service territo-ries of the transmission owners. These NYCA zones (see Figure 1-3 in Chapter 1 of this report) function as separate pricing zones under the locational-based marginal pricing (LBMP) wholesale power market operated by NYISO.

Given the limited transfer capability shown in Table 3-3 at the transmission interfaces, and the supply-and-demand bal-ance for electricity, the southeastern New York zones (Zones H, I, J, and K) experience the highest average and peak prices within the NYCA. Table 1-1 in Chapter 1 shows the ap-proximate consumer load and associated generating capac-ity in each NYCA zone. Generating plants in southeastern New York are particularly valuable because they are on the high-demand side of the constraints. The Indian Point gen-erating plant is located in the premium southeastern New York Zone H; hence the consumers in Zones H, I, and J heavily rely on it to meet demand. It is therefore very impor-tant to take the bulk transmission system into account when the retirement of Indian Point Units 2 or 3 is considered.

New Transmission New transmission capacity, if designed to adequately in-crease the transfer capabilities among the Total East, Central East, and UPNY-SENY Interfaces, may provide a partial solution to the retirement of Indian Point, including system reliability benefits. Such new transmission capacity would likely come in the form of either an expansion of the existing high-voltage alternating current (HVAC) transmission sys-tems or the addition of new high-voltage direct current (HVDC) transmission facilities.

New AC transmission facilities may include the replace-ment of conductors on existing transmission facility struc-tures or the installation of new transmission facilities includ-ing new tower structures and related components. Such new AC transmission facilities may also require additional right-of-way land resources and potential system outages during construction periods. An expansion of the existing AC trans-mission system would likely serve to increase system reli-ability and decrease the marginal cost of electricity in south-eastern New York.

New AC transmission facilities may also be coupled with dedicated generation resources to further support New Yorks in-city generation requirements. An illustrative example of such a new AC transmission facility would be the proposed 550-MW Public Service Electric & Gas (PSEG) Cross Hudson Project. That project includes the in-terconnection of an existing 550 MW natural-gas-fired com-bined-cycle generating unit located at a New Jersey-based utility, PSEGs Bergen generating plant, with the Consoli-dated Edison substation at West 49th Street in New York City via underground 345 kV transmission conductors and associated facilities. Combinations of dedicated power-gen-erating resources and interconnection facilities such as the PSEG Cross Hudson Project may offer additional alterna-tives to adding new generation resources directly into trans-mission-constrained zones such as Zones H, I, J, and K.

However, as useful as this project could be, it is currently inactive and may not be revived.

HVDC transmission projects may also provide partial so-lutions to the loss of Indian Point Units 2 and/or 3. Such HVDC transmission projects typically require the installa-tion of an AC/DC converter station, HVDC conductors, and a DC/AC converter station. The process entails the conver-sion of alternating current to direct current (in the AC/DC converter station located near a sending substation), trans-mission of the power (typically long distances) through high-voltage direct current conductors, and finally the conversion of direct current to alternating current (in the DC/AC con-verter station) adjacent to the receiving substation. Because an HVDC line is isolated from the regular HVAC grid, it is not subject to the same reliability issues, and the power that it delivers is considered to be equivalent in reliability to that from a plant within the zone of the end point. In particular, New York City and Long Island (Zones J and K), which TABLE 3-3 Nominal Transfer Capability Between New York Regions Transmission Interface Transfer Capability (MW)

Total East 6,100 Central East 2,850 Upstate New York-Southeast New York 5,100 Cable New York City 4,700 Long Island 1,270 SOURCE: New York Independent System Operator.

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42 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER have requirements for locally produced power (80 and 98 percent, respectively), obtain the same reliability benefit from a dedicated HVDC line as they would from a local power plant. The Neptune transmission line from New Jer-sey to Long Island will provide reliability benefits as well as cheaper power when it commences operation in 2007.

The addition of a new 1,000 MW HVDC transmission facility between Marcy and Rock Tavern Substations could serve as a suitable alternative to the compensatory action of adding 800 MW of new generation in Zone J. This alterna-tive also serves to increase New Yorks statewide electric system reliability and could lower total system production costs within the greater Northeast region, including New York State. Further, an additional benefit may include a re-duction in imports of electricity from outside the Northeast region owing to the more efficient use of indigenous genera-tion located in upstate New York and PJM (Hinkle et al.,

2005).

In summary, it is clear that new transmission projects can play an important role in the ultimate energy and capacity solution relating to the potential loss of power from the In-dian Point units. It is likely that a combination of modifica-tions to the existing AC transmission system and the instal-lation of new HVDC transmission projects will provide the best complement to the addition of new generating resources and efficiency programs to solve New Yorks future elec-tricity needs.

RELIABILITY AND REACTIVE POWER Reliability Most of the power interruptions of the typical customer are brief, affecting only a small area, although even very short interruptions that disturb computers and voltage varia-tions that affect voltage-sensitive equipment can be damag-ing. Many power interruptions are due to local problems, such as an automobile accident knocking down a power dis-tribution pole or a squirrel getting inside a vulnerable piece of equipment in a substation. Outages in distribution sys-tems are outside the scope of this report, which is concerned with the bulk power system.

When the transmission system goes down, perhaps due to severe weather, earthquakes, or multiple equipment failures, entire regions can be blacked out, and recovery can be lengthy. Very large multistate disturbances such as that ex-perienced in August 2003 are rare and involve a combina-tion of many unlikely events. Reliability is measured by the frequency, duration, and magnitude of interruptions and other adverse effects on the electric supply.

The regional reliability councils formed after the 1965 Northeast blackout (New York is in the Northeast Power Coordinating Council) have tried to quantify these distur-bances by requiring a measure of reliability based on com-puting the likelihood that the demand for power cannot be met. Load is modeled as a demand for power that is weather-dependent and varies with the season, the day of the week, and even the hour of the day. The maximum load tends to occur on the hottest summer days. Statistical descriptions of the historical availability of each generator are used to com-pute the expected number of days in a 10-year period when the load could not be supplied (the loss-of-load expectation, or LOLE). The New York State Reliability Council requires that the number be less than 1 day in 10 years. Changes in the system that would increase the LOLE to more than 1 day in 10 years would not be acceptable.

It is unusual for a blackout to occur simply because a large number of generators were unexpectedly out of service (the 1965, 1977, and 2003 blackouts were much more com-plicated). Nevertheless, the LOLE is useful in determining how much extra generation a given area requires. Meeting this standard in the NYCA usually means that the available capacity (the total power of all generators able to be sched-uled to serve the load) should exceed the peak load by 18 percent.

Because power can be imported from neighboring areas, the reliability and capacity of both the transmission system and the generation equipment must be included in the analy-sis. The loss of transmission lines to other areas (notably New England, PJM, or Canada) could have serious conse-quences on a hot summer day. Relief from other control ar-eas is limited, however, as interarea transmission capacity is about 5 percent of peak load and is decreasing with time. A reliable power system has enough excess installed generat-ing capacity so that the load can be supplied even if some generators are out of service for maintenance or because of unexpected problems, and it has a transmission system that is adequate to transport the power from wherever it is gener-ated (inside or outside the control area) to the customers.

The mix of generation normally includes some inexpensive baseload generators that tend to run at a constant output around the clock and serve the minimum (base) load, along with units that respond more rapidly to changes in demand and can follow the peak. Nuclear units are operated as baseload units because they usually have the lowest variable operating costs.

An additional reliability concern is the supply of fuel for generators. The adequacy and diversity of fuel constitute an important issue in operating the system and planning new generation. Heavy reliance on a single fuel source or a single pipeline for natural gas could have serious consequences if this supply were interrupted. The competing demand for natural gas for heating in the winter must also be considered as most gas-fired power plants in New York operate on in-terruptible gas-supply contracts, and therefore most are dual-fuel units that can be switched to oil firing. On an annual basis, however, as noted in Chapter 2, dual-fuel units in New York use natural gas for about 82 percent of their annual generation.

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GENERATION AND TRANSMISSION OPTIONS 43 Reactive Power Major power system disturbances have, in one way or another, involved unstable oscillations of electrical quanti-ties. Dynamic changes in power flows, or in system fre-quency (departures from 60 hertz), or in voltage reduction are all signs of system instability. Frequency excursions take place when the balance between supply and demand for power is upset. Too much demand produces a lower fre-quency, and too much supply results in a higher frequency.

As the power system came apart in August 2003, there were islands with excess generation and islands with too little gen-eration.

There is another kind of power in alternating current sys-tems, associated with the magnetic fields produced by cur-rents flowing in transmission lines, generators, and motors.

This power is called reactive power and is measured in vars (for volt-ampere reactive).3 Reactive power represents en-ergy stored in the magnetic field and later released. Motors such as those in air conditioners and refrigerators also re-quire reactive power to function correctly.

Reactive power also is essential for the smooth operation of the transmission grid. It helps hold the voltage to desired levels. Inadequate reactive power leads to a decrease in the voltage of the system in which the shortage exists. For an interconnected system where active power is exactly in bal-ance, the frequency is constant and the same everywhere, and the system is said to be in synchronous operation. Volt-age, however, varies from location to location, depending largely on the reactive power balance. If a given load has a large reactive demand, the voltage will be lower at that point than at others. Low voltage can damage equipment and, if low enough, can cause system instability and a voltage col-lapse. There have been a few voltage collapses solely be-cause of a shortage of reactive power. It is more common that reactive power problems aggravate active power prob-lems in large power system disturbances, as was the case in the August 2003 event (U.S.-Canada Power System Outage Task Force, 2004).

Active power can be transmitted over great distances, while reactive power problems must be solved locally. Gen-erators themselves are an excellent source of reactive power but at some cost. Increasing the reactive output of a genera-tor results in a decrease in the possible active power output and, if not specifically compensated, a loss of income re-ceived for real power output. Capacitors can be a second source of reactive power by storing energy in electrostatic fields rather than electromagnetic fields. Capacitors can be fixed or variable in size. Distributed generatorsfor ex-ample, microturbines and synchronous motorscan also supply reactive power, but these units are outside the control of the system operator and cannot necessarily be counted on when needed.

Indian Point is a large supplier of reactive power to the grid in southeastern New York State, capable of providing about 1,000 megavars of reactive power. If it is shut down, that reactive power must be replaced. Insofar as replacement generation is located upstate or even farther away, it becomes even more important to ensure adequate supplies of reactive power. That could be done by installing capacitors at the Indian Point site or in the general area. Generating vars is not expensive, but it is a critical necessity that must be planned for if Indian Point is to be closed.

NYISO projects that, even with Indian Point operating, voltage constraints due to reactive power deficiencies in the Lower Hudson Valley will lower system reliability to unac-ceptable levels. Consequently, NYISO has solicited market-based and regulated backstop solutions to correct the reli-ability deficiency.4 REFERENCES DOE/EIA (Department of Energy/Energy Information Administration).

2005. Natural Gas Weekly Update. December 22. Available at http:/

/tonto.eia.doe.gov/oog/info/ngw/ngupdate.asp. Accessed December 22, 2005.

EPRI (Electric Power Research Institute). 2005. Making Billion Dollar Advanced Generation Investments in an Emissions-Limited World.

Background paper for the EPRI Summer Seminar, August 8-9, 2005, San Diego, Calif.

Hinkle, G., G. Jordan, and M. Sanford. 2005. An Assessment of Alterna-tives to Indian Point for Meeting Energy Needs. Unpublished report for the National Research Council, GE-Energy, Schenectady, N.Y.,

December 19.

NYISO (New York Independent System Operator). 2005a. Comprehensive Reliability Planning Process. October 25.

. 2005b. Comprehensive Reliability Planning Process (CRPP), Reliabil-ity Needs Assessment, and NYISO Comprehensive Reliability Planning Process, Supporting Document and Appendices for the Draft Reliability Needs Assessment. December 21.

U.S.-Canada Power System Outage Task Force. 2004. Final Report on the August 14, 2003 Blackout in the United States and Canada. April. Avail-able at https://reports.energy.gov. Accessed March 2006.

3Active power, the familiar type of power that keeps lightbulbs burning, is measured in watts. Consumers pay for active power (1,000 watts used for an hour is a kilowatt-hour) but usually not for reactive power.

4See M. Calimano, NYISO solicitation letter to S.V. Lant, R.M. Kessel, E.R. McGrath, and J. McMahon, December 22, 2005.

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44 4

Institutional Considerations and Changing Impacts The previous two chapters identified the demand-and supply-side options for replacing the generating capacity of the Indian Point Energy Centers two operating nuclear re-actors. Putting these options into action in planning and ad-ministering the New York Control Area (NYCA) electrical system must be done in the context of economic, social, and institutional impacts as well as with regard to the technologi-cal opportunities and constraints. This chapter reviews the most significant general, statewide considerations:1

Financial underpinnings of the electrical supply sys-tem (that is, how the various organizations that generate, transmit, and distribute power underwrite the necessary in-vestments to ensure reliable service) and how that relates to the evolving institutional structure in New York State; and

Environmental and other impacts that affect society.

REGULATION, FINANCE, AND RELIABILITY Financial and economic considerations will have a pro-found effect on the choice of options to replace Indian Point, the reliability of the system, and the costs of substituting generation or transmission options for the Indian Point units.

Procedures for maintaining the reliability of the New York State system are discussed mainly in Chapter 5.

The New York State Electricity Market The impact of the replaced costs of the Indian Point units if they are shut down is dictated by the evolving New York State competitive market and by the socioeconomic back-ground in the state. Indian Points replacement costs to the customer are virtually impossible to project at present, given the electricity market operation and its evolving status. The reasons are summarized in Boxes 4-1 and 4-2, on the cost of replacing Indian Point: In Theory and In Practice.

This section provides background information on the regulatory and financial environment in New York State and on how this environment shapes the incentives for investing in generation and transmission facilities. It also explains why there are growing concerns about the continued reliability of electricity supply, particularly in New York City. Appendix E, Paying for Reliability in Deregulated Markets, gives a fuller account of how the regulation of the electric utility industry in New York State has changed and the implica-tions of these changes for reliability.

In response to a number of financial problems, such as the cost of building excess generating capacity in the 1980s, the Federal Energy Regulatory Commission (FERC) sup-ported new legislation in the 1990s to facilitate increased competition in the electric power industry. Competition was introduced initially in the northeastern states and in Califor-nia, regions that had relatively high prices for electricity un-der traditional regulation. In 1999, regulators in New York State took the first major step by introducing new markets for electricity (real energy) and ancillary services, such as reserve generating capacity. At the same time, the New York Independent System Operator (NYISO) was established to run these new markets and to control the operation of all power plants in the New York Control Area. Unlike the gen-eration components of the industry, the transmission and dis-tribution components continued to be regulated by the New York Public Service Commission (NYPSC).

Appendix E explains that the current patterns of spot prices in the NYCA have changed and are now much less volatile, with fewer price spikes than when the market was first introduced in 1999. This change in price behavior has made prices more predictable, but at the same time it has reduced the financial earnings of peaking capacity (generat-ing units that are used only to meet relatively short periods of peak demand and therefore have low capacity factors) relative to those of baseload capacity. The consequences of 1Specific plant and transmission line siting issues, including costs and environmental constraints, are not discussed here, since they vary so widely throughout the state and are considered beyond the scope of the study.

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INSTITUTIONAL CONSIDERATIONS AND CHANGING IMPACTS 45 BOX 4-1 The Cost of Replacing Indian Point: In Theory gated to determine the size of the revenue requirement and the corre-sponding retail rates charged to customers.1 In a competitive market for generation, the most expensive unit needed to meet the load sets the wholesale price paid to all units that are generating in the market (prices actually vary from location to location owing to congestion on the transmission lines, but this is not an important issue for this ex-ample). When an expensive peaking unit sets the price on a hot sum-mer day, the wholesale price paid to generators is much higher than the operating costs of most units. This extra income can be used to cover the capital cost of generation.

In theory, the wholesale price in a competitive market should cover all of the operating and capital costs of generation, but, as ex-plained in this chapter and in Appendix E, Paying for Reliability in Deregulated Markets, a truly competitive market will not cover the capital cost of a peaking unit unless high prices (scarcity prices) are allowed. However, the total cost of the combined-cycle unit in this example ($75/MWh) is covered by the wholesale price ($80/MWh).

Although these results are clearly sensitive to the assumptions made, this specific example shows that it is quite possible in a competitive market to add new generating capacity without increasing the whole-sale price. In fact, the simulated market prices in some of the sce-narios presented in Chapter 5 are lower when new generating capacity is added. The reason is that the new efficient units displace some generation from existing units that are more expensive to operate, and the more efficient units set the market price more frequently.

Who does pay for the incremental cost of replacing Indian Point in this example, if customers still pay the same wholesale price as before? The main loser in this example is Entergy, because the sub-stantial annual earnings from Indian Point have now been eliminated.

Given the many complexities of determining costs, such as the effect of increases in the use of natural gas on the future price of natural gas, it is extremely difficult to measure the true cost to customers of replac-ing Indian Point. The most important complications about determin-ing this cost are discussed in Box 4-2. The main point of the present example is to show that the current wholesale price of electricity in the New York market may cover a large part of the incremental costs of replacing Indian Point. In a competitive market, the financial conse-quences for customers are likely to be smaller than the consequences would have been under traditional regulation. There is, however, an important qualification that should be made. The example here and the scenarios presented in Chapter 5 assume that new generating ca-pacity will be built in a timely way before Indian Point is retired. If Indian Point experienced an unscheduled failure and had to be taken off-line in an emergency, the wholesale price would increase substan-tially. Without Indian Point and without new capacity, more-inefficient units with higher costs would have to be used to meet load. These expensive units would set higher wholesale prices.

1In fact, traditional regulation did not apply to Indian Point Unit 3, be-cause it was owned by the New York Power Authority, and its power was sold in part outside the regulated market.

The cost of replacing Indian Point is substantial because its two operating nuclear reactors, Units 2 and 3, represent 2,000 megawatts (MW) of baseload capacity with relatively low operating costs. In ad-dition, a large capital investment of these units has already been made.

To the extent that a replacement strategy includes conventional gener-ating capacity (e.g., using natural gas as a fuel), the incremental cost of building this new capacity will include the capital costs, and in addition, the operating costs will be higher. Under traditional regula-tion, all of these incremental costs would be passed on directly to customers in New York State. Although someone has to pay for these higher costs, customers may not see major increases in their monthly bills in the new deregulated market in the state. How is this possible?

An explanation follows using a simple example of the magnitudes of the costs involved.

Let us assume that the full operating costs of Indian Point are

$20 per megawatt-hour (MWh) and that the units operate for a total of 8,000 hours0 days 0 hours 0 weeks 0 months per year. These operating costs would include the nuclear fuel, labor, and capital costs for operations and maintenance (which might require adding a cooling tower in the future), and payments into a sinking fund to cover decommissioning as well as a charge paid to the federal government to cover the cost of disposing of nuclear waste.

Since Indian Point has a capacity of 2,000 MW, the total annual cost of operations is $320 million per year (20 x 2,000 x 8,000).

The average wholesale price of electricity in New York Control Area Zone H was $80 per MWh in 2005 (when the price of natural gas was substantially higher than historical levels). Consequently, the annual revenue, if all power had been sold in the wholesale market, would be $1,280 million per year (80 x 2,000 x 8,000) and the annual earnings for Entergy Corporation (the plants owner) would be $960 million per year (1,280 - 320). The situation is more complicated in reality, because Entergy may have long-term contracts to sell some of the power at prices below the current high level in the wholesale mar-ket. Nevertheless, these contracts will have to be renewed periodi-cally, and with high prices for natural gas, Indian Point represents a very valuable source of income for Entergy.

To keep the example simple, let us assume that Indian Point is replaced completely by 2,000 MW of combined-cycle capacity using natural gas as a fuel. The operating cost of these units is $60 per MWh, and the annualized capital cost is $120 per kilowatt per year (kW/year). These units will also operate for 8,000 hours0 days 0 hours 0 weeks 0 months per year, and as a result, the capital cost prorated to the annual amount generated corresponds to $15/MWh (120,000/8,000). The total annual cost of generation is $1,200 million per year ([60 + 15] 2,000 x 8,000), and the incremental cost of replacing Indian Point is $880 million per year (1,200 - 320). That is a very large amount of money, but it could be much lower for a number of valid reasons. For example, reducing load by improving the efficiency of appliances is shown in Chapter 2 of this report to be much more cost-effective than building new generating capacity, and the transmission upgrades discussed in Chapter 3 may allow existing units in other locations to generate more power.

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46 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER BOX 4-2 The Cost of Replacing Indian Point: In Practice Although the cost of building and operating new electric gener-ating capacity to replace some or all of the 2,000 MW at the Indian Point Energy Center would be substantial, it is very difficult to deter-mine what the overall effect would be on the bills paid by customers.

The committees scenarios, presented in Chapter 5, project the basis for the wholesale market prices in different zones. Generally, these prices are higher than the prices in the base case with Indian Point operating, but in some situations they are lower. The explanation for getting lower wholesale prices is that new efficient capacity displaces some of the old inefficient capacity and sets the market price more often.

The pricing mechanism used in all of the scenarios is based on a uniform-price auction assuming that the market is competitive (i.e.,

that the offers submitted into the auction by generators are equal to the true production costs, and under this specification, it would be ex-tremely unlikely for the market price ever to be set by the low produc-tion cost of Indian Point). Assuming that the market is competitive is a reasonably close representation of how the market is actually per-forming at this time. Hence, the predicted prices in the scenarios pro-vide a consistent way to determine how wholesale prices would be affected in different situations. Higher wholesale prices would result in higher rates charged to customers unless there was an offsetting reduction in the other costs of generation.

The main complication for determining the total cost of genera-tion in the current market structure is that the wholesale price of elec-tricity is only one of the components of the total cost. It would be necessary to determine how the costs of the other components would change to get a complete accounting of the effects of replacing Indian Point. Some of these costs are set by regulators and are subject to change. Consequently, unlike modeling wholesale prices, there is no consistent structure for modeling the other costs, and it is virtually impossible to predict how they would change in different scenarios.

The best examples of the other costs of generation are (1) pay-ments for availability in the installed capacity (ICAP) market, and (2) payments for reserve capacity. In addition, the discussion of reliability in this chapter explains why the current structure of markets is still not providing sufficient incentives for new merchant projects. The impli-cation is that investors will have to be paid some form of additional premium above the revenue received from the existing markets if new capacity is going to be built. In the long run, customers will have to pay for all of the additional costs of generation as well as for pur-chases in the wholesale market.

Information on the performance of the wholesale market is readily available, but information about the other costs of generation is much more limited. Patton (2005, pp. 22-25) provides a valuable discussion of the performance of the ICAP and reserve markets; in that report, Section F, and Figure 16 in particular, shows a net revenue analysis of the annual net revenue (revenue minus production costs) in 2002-2004 for a combined-cycle turbine and a combustion turbine in different locations. For generators in New York City, the ICAP mar-ket is the primary source of net revenue for combustion turbines (roughly $140,000 per year per MW out of a total net revenue of

$160,000 per year per MW in 2004) and a major source for com-bined-cycle turbines (roughly $140,000 per year per MW out of a total net revenue of $260,000 per year per MW in 2004). The net revenue from the ancillary service markets (e.g., reserve capacity) is small for both types of turbine (roughly $10,000 per year per MW). The net revenues for generators on Long Island are similar to the levels in New York City, but for upstate generators, the net revenue from the ICAP and reserve markets is very small (roughly $25,000 per year per MW).

The discussion above is relevant for assessing the cost to cus-tomers of replacing Indian Point because it shows the importance of the location of capacity on the magnitudes of the other costs of generation. In New York City and Long Island, customers will eventu-ally have to pay the relatively high wholesale prices for all of their purchases (the annual average prices in 2005 were $83 per megawatt-hour (MWh) and $98/MWh, respectively, compared to prices ranging from $65/MWh to $72/MWh in Zones A through F upstate) and the high other costs of generation for all generating capacity in New York City and Long Island (Zones J and K). New capacity that is built in zones other than J and K will incur relatively low costs in the ICAP and reserve markets but may require a higher premium to make them fi-nancially attractive (i.e., because the net revenue from the existing markets will be low). It is beyond the scope of this study to try to determine the net effect of these offsetting factors.

The current regulatory strategy in the ICAP market is to make all generating capacity in a region eligible for capacity payments. Hence, the relatively high prices for capacity in Zones J and K are paid to all installed capacity that have offers accepted in the ICAP auctions for those zones. Nevertheless, it is probable that additional premiums will have to be paid to get new merchant capacity built.

An alternative regulatory strategy is to direct capacity payments to cover the premium for new capacity, and possibly for existing ca-pacity that operates most of the time at a minimum level but is still essential for reliability. This alternative strategy may be a less expen-sive way to maintain reliability in the long run, because making capac-ity payments to all installed capacity in the current ICAP market places no obligation on existing generators to build new capacity. Once again, there is a lot of uncertainty about how regulators will decide to deal with current concerns about reliability and what the additional costs will be above the price in the wholesale market.

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INSTITUTIONAL CONSIDERATIONS AND CHANGING IMPACTS 47 this type of change in price behavior have been discussed extensively in the regulatory literature. Competitive spot prices will provide enough income to cover the operating cost of peaking capacity but not the capital cost, and as a result, the owners of peaking capacity do not earn enough in the spot market to be financially viable.

There are various ways to provide additional income to generators, but the current projections of installed generat-ing capacity made by NYISO suggest that the market proce-dures adopted in the NYCA have not been entirely effective.

In particular, installed capacity in the New York City metro-politan area could fall below the level needed to meet indus-try standards for reliability by 2008 (NYISO, 2005). Regula-tors had not anticipated this situation only a year ago. The outlook in 2004 indicated that sufficient new generating units had been approved and were expected to be completed in the near future so that standards for reliability in the NYCA would be exceeded for another 10 years. Subsequently, many of the proposed new generating units were delayed indefi-nitely, owing to the unfavorable market conditions faced by investors.

Given the size and importance of the financial, commer-cial, and residential sectors in the New York City region, the very high cost of blackouts makes it essential to maintain a reliable supply of electricity to customers in the region. Evi-dence from other published studies demonstrates that the value of avoiding a blackout is likely to be many times the typical wholesale price of electricity (Hamachi LaCommare and Eto, 2004). In other words, customers are willing to pay a substantial amount to ensure that the supply of electricity is reliable, and the current industry standard of limiting out-ages to less than 1 day in 10 years, established by the North American Electric Reliability Council (NERC), is consistent with this high value of reliability (NERC, 2004). The possi-bility that reliability in the New York City region will fall below the industry standard by 2008 presents a challenge that regulators will have to address in the near future (NYISO, 2005).

Before new ways are considered to supplement the earn-ings of generators in the spot market, it is important to iden-tify three assumptions that have been adopted by regulators in the NYCA, which have limited the effectiveness of mar-ket forces in maintaining reliability, as explained in Appen-dix E. These assumptions, which are consistent with the NYISO planning strategy,2 are

1. That setting minimum levels of installed generating capacity is an acceptable proxy for meeting the NERC stan-dards for reliability in the NYCA,

2. That setting locational requirements for generating ca-pacity in New York City and Long Island is an acceptable way to offset the limitations of the legacy transmission sys-tem into the New York City region,3 and

3. That the political realities in the NYCA make it infea-sible to allow high price spikes in the spot market above short-run competitive levels as a way to supplement the earn-ings of generators.

By accepting the first two assumptions, regulators have reduced the problem of determining how to maintain the re-liability of supply to one of simply ensuring that require-ments for installed generating capacity in New York City and Long Island, and the reserve margin requirement for NYCA, are met. Clearly, this transformation of concerns about the reliability of supply to concerns about minimum levels of generating capacity (generation adequacy) is more likely to be economically efficient when the transmission system is relatively robust and the availability of generating capacity is the main limiting factor. This is no longer the case in the NYCA, given the structure of the legacy trans-mission system and the size and location of New York City.

Nevertheless, regulators have accepted the assumption that meeting locational requirements for generating capacity is an effective strategy for meeting the NERC reliability stan-dards. By focusing on generation adequacy, however, the current regulatory practices followed in the NYCA, using the NYISO planning models adopted in Chapter 5, estimate the required levels of generating capacity. This modeling framework tends to discount the potential value of upgrades to the transmission system as a way to improve the reliabil-ity of supply. However, alternative planning models could be adopted that, in principle, would treat generation and transmission in a more integrated way. The development of such models was beyond the scope of this analysis.

By adopting the third assumptionthat it is desirable to maintain short-run competitive spot pricesregulators have ensured that earnings for some peaking units that are needed for operating reliability will be insufficient to make them financially viable.

Two distinct ways to address the economic problem of funding sufficient capacity are under discussion. The first is to supplement the profits earned in the spot market for all generating units by providing enough additional income from another source to cover the missing capital costs.

The second is to use targeted contracts, such as Power Pur-chase Agreements (PPAs), with sufficient generating units to meet reliability standards.

Regulators in the NYCA have chosen the first approach, because they apparently consider that it is economically fair for both the owners of installed generating capacity and po-2The assumptions follow from NYISO comprehensive reliability plan-ning and the NERC reliability criteria (NYISO, 2005).

3System security planning using the so-called N-1 analysis for genera-tion and transmission failure could be applied as an alternative planning approach.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

48 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER tential investors in new capacity. In contrast, contracts with some but not all generators are inherently discriminatory and may distort market behavior. Although the basic rationale for these arguments is consistent with regulatory theory, there is still no guarantee that the approach chosen by regu-lators for maintaining reliability in the NYCA will be either effective or economically efficient.

In other electricity markets (e.g., Australia), short-term price spikes in the spot market are acceptable to regulators so long as the average spot prices are competitive. Discus-sions are under way in Texas on adopting a similar approach.

The regulatory focus in this type of market is on maintaining long-run competitive prices, rather than short-run competi-tive prices, and the effect is to make the earnings of genera-tors correspond more closely to the true costs of production, including the capital costs. In the NYCA, however, regula-tors appear to try to avoid high price spikes in the spot mar-ket. Given this restriction, one possible way to recover the missing capital costs for peaking units is through a separate market for generating capacity.

The approach just described has been proposed by regu-lators in the three northeastern power pools. At this time, NYISO is the only one of the three to fully implement such a capacity market. There is still a considerable amount of political opposition to the proposal in New England, and there is an ongoing debate about it among stakeholders in the Pennsylvania Jersey Maryland (PJM) power pool. To provide a perspective on current conditions in the NYCA, it is important to understand why there is so much controversy about the effectiveness of capacity markets as a way to pro-vide the incentives needed to initiate merchant investments in new generating capacity.

Initially, the installed capacity (ICAP) market run by NYISO was simply an auction for availability, designed to ensure that enough installed generating capacity would be available to meet the projected loads in New York City, Long Island, and the NYCA for a few months ahead. In general, this type of ICAP market does provide additional earnings for generators; these earnings may be significant for the con-tinued financial viability of some peaking units. On the one hand, for example, the existence of the ICAP market may result in some units being available instead of unavailable, and it may also delay the retirement of some units. On the other hand, the extra earnings from the ICAP market are really a bonus for other generating units, such as nuclear and hydro units, because these units would be available anyway without the ICAP market. Nevertheless, regulatory theory implies that all generators should be eligible for participa-tion in the ICAP market, and this issue is not the major source of controversy among regulators.

The main controversy about the ICAP market arises when the objectives of this market are extended to deal with the construction of new generating capacity. The following three limitations of an ICAP market in providing incentives for potential investors are explained more fully in Appendix E:

The time horizon in an ICAP market does not extend far enough into the future to meet the needs of investors.

It is unrealistic to place the primary responsibility for maintaining generation adequacy (and by assumption, sys-tem reliability) on load serving entities (LSEs).

There is no legal requirement that any of the additional earnings from an ICAP market be used to build new generat-ing capacity when and where it is needed.

The basic structure of the ICAP market in the NYCA is that regulators have placed a legal obligation on buyers (LSEs) to purchase enough generating capacity to meet their projected load plus a reserve margin before the spot market for electricity clears. (LSEs can also meet some of their own capacity requirements if these sources are certified by NYISO.) The final monthly auction in the ICAP market clears a few days before the month begins. It represents the last chance for LSEs to meet their capacity obligations with-out paying a substantial penalty.

The final monthly ICAP auction includes a specified de-mand curve that is designed to ensure that the market price of capacity is equivalent to the capital cost of a peaking unit if the total supply of capacity in the ICAP auction falls to the minimum amount needed to meet the regulated standards of generation adequacy. The market price will be higher (lower) if the total capacity offered is lower (higher) than the re-quired amount. The basic objective of the current ICAP mar-ket is to make the market price of capacity cover the missing capital cost of a peaking unit when the market is economi-cally efficient (i.e., when the total supply of capacity is equal to the amount needed for adequacy).

The financing of new generation and transmission facili-ties in the NYCA, whether it is needed to accommodate the retirement of existing facilities, the projected growth of load, or the intentional shutdown of Indian Point Units 2 and 3, must be understood in the context of the current hybrid mix of competitive markets and regulatory interventions that has resulted from the restructuring of the electric sector. Propos-als to build new generation and transmission facilities are no longer preapproved by the New York Public Service Com-mission with the implicit guarantee to investors that all pru-dent production costs and capital costs will be recovered from customers. Investors face regulatory risk due to con-cerns that current market rules may be changed in the future, as they were after the energy crisis of 2000 and 2001 in Cali-fornia, as well as competitive risk. Risk increases the finan-cial risk of an investment in new generating capacity, imply-ing that the cost of borrowing capital for investors will be substantially higher than it would be under regulation.

Market forces have been able to maintain adequate levels of generation with relatively little regulatory intervention in Australia, for example, but not in the NYCA. Appendix E explains why the successful efforts of regulators to maintain short-run standards of economic efficiency in the spot mar-ket have undermined the financial viability of generating Copyright © National Academy of Sciences. All rights reserved.

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INSTITUTIONAL CONSIDERATIONS AND CHANGING IMPACTS 49 units that are needed for reliability (i.e., units with low ca-pacity factors). This change in the pattern of spot prices has reduced the earnings of peaking units relative to baseload units and, coupled with the current uncertainty about the fu-ture prices of fossil fuels such as natural gas, has led to de-lays in the construction of new facilities already licensed in the NYCA.

The deteriorating outlook for reliability in the NYCA is best summarized by the drop in projected reserve margins for generating capacity from the forecast made in 2004 to that in 2005. A year ago as of this writing, in 2004, the re-serve margin in 2008 was expected to be over 40 percent; however, the 2005 projection for 2008 was less than the 18 percent needed to meet the NERC reliability standards.

Figure 4-1 shows the two projections of reserve margins for the summer peak load in the NYCA that were published by NYISO in 2004 and 2005. The drop in the projected re-serve margins shown in the figure was caused by delays in the construction of new generating units that had already received construction licenses. The lists of potential new generating units underlying the two projections of reserve margins in 2004 and 2005 are essentially the same, but the Proposed In-Service dates are quite different. In 2004, 2,038 MW were under construction (four units); 3,120 MW were approved (seven units); and 1,605 MW had applica-tions pending (two units), for a total of 6,763 MW. Five of the nine projects (2,430 MW) with applications approved or pending had proposed in-service dates no later than 2007.

However, although the amount of capacity under construc-tion was still 2,038 MW in 2005, none of the other nine projects had proposed in-service dates, and under current market conditions, there is no guarantee that any of these generating units will actually be built.4 The current concern about meeting the levels of genera-tion adequacy needed to maintain reliability in the NYCA coincides with two important changes in regulatory proce-dures and responsibilities. First, a new Comprehensive Reli-ability Planning Process (CRPP) was implemented by NYISO in 2005; the new forecasted reserve margins for 2005 FIGURE 4-1 Projections made by NYISO in 2004 and 2005: summer reserve margin for generating capacity in the New York Control Area.

SOURCES: Projections made in 2004 from NYISO (2004), Table V-2; those made in 2005 from NYISO (2005), Table 7.2.1.

0 10 20 30 40 50 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2004 2005 Min. Reserve Percent 4The time frame for deciding on alternatives is not known. However, NYISO is sufficiently concerned about the delays or cancellation of new generation capacity to have requested proposals for alternative solutions for addressing electricity supply, especially for the New York City area as dis-cussed in Chapter 5.

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50 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER shown in Figure 4-1 were produced for the CRPP. The sec-ond regulatory change is that the Energy Policy Act of 2005 has given FERC stronger oversight responsibilities for main-taining reliability standards for all users of the bulk power system in the United States. Under this legislation, FERC is permitted to pass these responsibilities to a single Electric Reliability Organization (ERO) that will determine explicit reliability standards and also have the authority to enforce them.

When uncertainty about the retirement dates of existing generating units in the NYCA is combined with uncertainty about whether new generating units will be built, the task of ensuring that there will be enough installed generating ca-pacity to meet reliability standards is very challenging. Nev-ertheless, reliability standards must be met because the cost of blackouts in a dense urban area like New York City is so high. Although the importance of maintaining reliability has been recognized in the implementation of the CRPP and the Energy Policy Act of 2005, it is still too early to know ex-actly how regulators will meet their new responsibilities and use their new authority. Nevertheless, it is clear that the ob-jective of meeting reliability standards is a high priority at both the state and federal levels, as it should be.

The current pessimistic outlook for maintaining reliabil-ity standards in the NYCA also poses a challenge for this committee. Although the committee is convinced that regu-lators should place the highest priority on maintaining reli-ability, the committees responsibilities do not include mak-ing specific recommendations about how this should be done. Since the current projections of installed generating capacity fall short of the minimum levels needed for genera-tion adequacy, the first step in evaluating alternatives to Indian Point is to specify a new scenario that does meet reli-ability standards with Indian Point operating. The assump-tions used to specify this scenario are discussed in detail in Chapter 5 of this report.

The Permitting Process with Article X The committee is aware that New York State will face a formidable task in constructing sufficient power plants to satisfy the continued load growth being experienced in the state and to replace old power plants that are to be retired for various reasons. Early retirement of Indian Point would add to those problems, whichever options are selected. A busi-ness-as-usual approach is unlikely to achieve the additional capacity that would be required. The siting of new major electric generating facilities would be facilitated if the State of New York reauthorized Public Service Law Article X, which expired on January 1, 2003.5 Article X had centralized the process of environmental permitting for electric power plants and provided for a firm, finite schedule for the approval or denial of environmental permits, limiting the risks of delay. This approach grew in importance with the restructuring of the electric power sec-tor. Before restructuring, the monopoly franchise utility would propose a project based on the need to meet local loads, and the appropriate regulatory body (e.g., the NYPSC) approved or denied the proposal. In this approach, additional costs imposed on the utility company by environmental regulatory requirements or delays could be (and usually were) passed on to ratepayers. Now, the costs and risks of power plant development fall to private developers, who seek to be compensated in the marketplacewhich may be intol-erant of any additional expenses due to delays or other contingencies.

While it was in force, Article X set forth a review process for consideration of applications to construct and operate electric generating facilities of 80 MW or more. An approval would result in the applicant being granted a Certificate of Environmental Compatibility and Public Need, which is re-quired before the construction of such a facility.

Most of the review under Article X is conducted by two examiners, one from the New York Department of Public Service and one from the New York Department of Environ-mental Conservation (NYDEC). Numerous opportunities for public involvement in hearings and other proceedings ex-isted, and the applicants were required to pay fees that inter-veners could use, with permission of the examiners. Munici-palities and individuals within a 5-mile radius of the proposed facilities were granted routine intervener status.

Within a year of receipt of the application, the Board on Electric Generating Siting and the Environment was required to make a decision. This board consisted of the chair of the New York Public Service Commission, the chair of the New York State Energy Research and Development Authority (NYSERDA), the commissioners of NYDEC, the New York Department of Health, and the New York Department of Economic Development, plus two public members who re-side near the proposed facility and are appointed by the governor.

For example, in 2000 the board granted the Athens Gen-erating Station a certificate (Board on Electric Generating Siting and the Environment, 2000). Topics that the board considered included the legality of the application and re-view process, regional and local aquatic impacts (including erosion control and deposition of pollutants), the visibility of the plant and stacks to the public (especially from historic sites), the visibility of the proposed cooling-tower plume, air quality, terrestrial biology, chemical storage and waste man-agement, impacts on agricultural lands, noise, traffic, land use (including wetlands mitigation), public interest concerns (including the enhancement of competition, alternative sites, electrical interconnection, and local taxes), and the status of 5For additional information, see http://www.dps.state.ny.us/articlex_

process.html. Accessed January 2006.

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INSTITUTIONAL CONSIDERATIONS AND CHANGING IMPACTS 51 required permits. During the process, many interveners par-ticipated; they and the applicant agreed to many changes in plant design, some of which were fairly expensive. Impor-tant changes included shorter stacks, the use of dry cooling, the use of state-of-the-art emissions controls, and payments to mitigate various impacts. The board also imposed several conditions on the applicant in its approval.

Since the expiration of Article X, electric generating project developers must obtain all of the appropriate local and state permits and approvals and must undergo environ-mental review subject to the State Environmental Quality Review Act (Article 8 of the Environmental Conservation Law). Project developers may also obtain a Certificate of Public Convenience and Necessity, based on the traditional approach to adding electric generating capacity. New Yorks Governor George Pataki and several state legislators have proposed new laws to replace Article X, but there is none currently in place.

Industry groups (e.g., the Business Council of New York State) have promoted a new siting law, while some advo-cacy groups (e.g., the New York Public Interest Research Group) have expressed concerns. One specific concern is about whether or not the local community must give its per-mission for a new plant. Under Article X, municipalities could participate in the process, but the final decision was made by the board.

If action is taken to reauthorize Article X, the following issues, among others, could be considered:

The addition of modifications and measures to Article Xs procedural requirements that would enable the siting board to streamline its review when interested parties, in-cluding affected communities groups, had reached a consen-sus as to the specific issues presented by an Article X application.

The appropriateness of developing specific procedures with respect to the expansion, modification, or repowering of existing major generating facilities.

In addition, the committee suggests consideration of the reauthorization of Article 6 of New Yorks energy law, for statewide energy planning, that expired on January 1, 2003.6 In addition to statutory modifications, the following admin-istrative steps might be taken:

The Energy Planning Board could meet annually to co-ordinate the development and implementation of energy-re-lated strategies and policies, receive reports from the agen-cies staffs on the compliance of major energy suppliers with its information-filing requirements, and receive summary reports on the information filed.

The information-filing regulations of the Energy Plan-ning Board could be modified to recognize new entrants into the energy marketplace and the need for pertinent energy-related information and data.

SOCIAL CONCERNS The social concerns considered here are environmental impacts, energy security, and indirect socioeconomic fac-tors, including impacts on the affected communities. The concerns can have a significant effect on what sort of facili-ties can replace Indian Point and where they can be built.

Environmental Regulation All energy technologies have environmental impacts. Re-placement technologies discussed in Chapters 2 and 3 in-clude efficiency and distributed generation,7 natural-gas-fired turbines, and, potentially, coal-fired generation (any new coal plants are likely to be upstate or out of state, with long-distance transmission). Replacing the Indian Point nuclear power generators with a different type of electricity supply may reduce some environmental effects but may in-crease others. In contrast, energy-efficient technologies re-duce the need for both capacity (megawatts) and energy (megawatt-hours) and thus tend to reduce environmental impacts (unless their manufacture, recycling, or disposal is problematic).

In New York as elsewhere in the United States, a com-plex set of regulations and permit requirements are in place to manage these effects and to ensure that they impose a minimal burden on the public and the environment. Environ-mental effects of nuclear power plants associated with plant construction, fuel production, and disposal of radioactive waste have been evaluated extensively elsewhere (e.g.,

McFarlane, 2001; NRC, 2001, on spent fuel disposal) and are outside the scope of this study. In normal operation, nuclear power plants such as those at Indian Point emit very little air pollution. Large releases of radionuclides might oc-cur as the result of an accident or attack (Farrell, 2004b), but that potential has a relatively low probability. Indian Point does have a significant impact on the Hudson River, as dis-cussed in the subsection below, on Water Use.

The most significant pollutants from natural-gas com-bined-cycle plants, the most likely fossil-fueled generation replacement for Indian Point, are nitrogen oxides, NO and NO2 (designated as NOx), and, to a much lesser extent, car-6Article 6 concerns the organization and functions of the state Energy Planning Board.

7On-grid renewable generation options were also considered, but the committee determined that they were not competitive in the timescale of the study.

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52 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER bon monoxide (CO), volatile organic compounds (VOCs),

and particulate matter (PM) (e.g., Barboza et al., 2000).

However, emissions of all of these pollutants are sufficiently low from gas turbines or can be controlled sufficiently well so that it is quite feasible to obtain air quality permits which guarantee plant operation that protects human health and the environment (U.S. EPA, 1997). Carbon dioxide emissions, currently not regulated, are discussed below.

The effect of possible replacements for the Indian Point reactors on a broader size range of particulate matter (PM10) emissions is likely to be small because of (1) permitting re-quirements that will require low emission rates and a tall stack to control local effects, and (2) emission-reduction off-set requirements that will yield a net decrease in regional emissions of PM10. For the more important emissions of the smaller particulate matter (called PM2.5), the effect on mass emissions is largely determined by SO2 and NOx emissions, which, on a regional basis, will be unaffected owing to the emissions caps imposed on the electric power sector for these pollutants.

Three important pollutants from power plants, including coal-fired units, are or will be controlled by cap-and-trade programs: NOx, sulfur dioxide (SO2), and mercury (Hg)

(U.S. Congress, 1990; Farrell, 2004a).

Both NOx and SO2 can have direct negative effects on human health, and so are criteria pollutants, with their own standards under the federal Clean Air Act. Southeastern New York (and, in fact, the entire country) has attained healthful air quality for NOx and SO2 and is classified as in attain-ment of the National Ambient Air Quality Standards (NAAQS) for these pollutants. Nitrogen oxides and SO2 con-tribute indirectly to two other criteria pollutants, ozone (O3) and particulate matter. The former is produced in the atmo-sphere through photochemical reactions of NOx and VOCs.

The latter involves nitrate and sulfate formation from oxida-tion of the two gases in the air forming condensable material as PM. Measured O3 and PM2.5 concentrations in various cities have resulted in local nonattainment of the NAAQS for these pollutants, including cities in some parts of south-eastern New York. The nonattainment designation requires the state to provide plans for achieving attainment, which in turn requires reductions in NOx and SO2 concentrations well below levels otherwise required. These requirements affect choices of power plant technology using fossil fuels.

The attainment of the NAAQS for NOx (as NO2) and SO2 has been achieved locally through the use of cleaner fuels, improved combustion technologies, and combustion by-products emitted well above ground level, to disperse and dilute remaining emissions. As with PM and CO, the regula-tory process to approve new power plants involves atmo-spheric modeling to set emissions limitations and stack heights in order to help ensure that there are no local health impacts from the expected NOx and SO2 emissions. A new power plant would also be required to offset its emissions and retire emission credits equal to 30 percent of those emissions, creating a net reduction in regional NOx and SO2 emissions.

Nitrogen oxides and SO2 contribute not only to local is-sues, but also to larger-scale (regional) environmental prob-lems of tropospheric ozone, fine particulate matter (PM2.5),

acidification of sensitive ecosystems, and (in the case of NOx) eutrophication (Regens, 1993; Chameides et al., 1994; Jaworski et al., 1997; Tucker, 1998; Solomon et al., 1999; U.S. EPA, 2000; Mauzerall and Wang, 2001; Streets et al.,

2001; Farrell and Keating, 2002; Creilson et al., 2003). In order to manage these regional problems, additional controls for NOx and SO2 are superimposed on controls designed to ensure local air quality. These regional air-quality-related problems result from aerometric phenomena that occur over several hundred kilometers and can take several days to com-plete. Therefore, projecting the impact of potential fossil-fueled replacements for Indian Point requires placing them into a context of regional changes in emissions, not simply the localized changes near new power plants or urban settings.

In the United States, SO2 and NOx emissions from large electric generators are regulated by a cap-and-trade sys-tem; this type of regulation has been proposed for Hg as well (Farrell, 2004a). Current regulations for SO2 and NOx are contained in the Clean Air Interstate Rule (CAIR), which was published in its final form in March 2005 and will be implemented fully by 2020 (U.S. EPA, 2005).8 The CAIR will lower SO2 emissions from the electric power sector across a 28-state region (including New York) by about 65 percent and NOx emissions by about 50 percent.

However, the CAIR imposes an annual cap on NOx emis-sions, while the key problem in the northeastern states is summertime ozone and fine particulate formation. Some analyses suggest that the annual cap in the CAIR may not be sufficient to maintain current summer air quality in the New York area, and that an additional, seasonal NOx control pro-gram may be required (Palmer et al., 2005).

The Clean Air Mercury Rule (CAMR) is still under re-view. Even without it, Hg emissions are expected to decline as a co-benefit of the more stringent controls on SO2 and NOx emissions.

In considering a potential replacement of the Indian Point reactors with fossil-fuel generation, the key feature of cap-and-trade systems is that emissions are limited in absolute magnitude and do not respond to changes in the amount of electricity generated or in the technologies used. While in-creased generation at an existing power plant may lead to additional emissions at that facility, such increased genera-tion would not be allowed if new emission controls are added to the plant, as is happening (and has been happening for over a decade) across the nation. Even if no new control technologies are added, under a cap-and-trade system addi-8See www.epa.gov/interstateairquality. Accessed November 2005.

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INSTITUTIONAL CONSIDERATIONS AND CHANGING IMPACTS 53 tional emissions at one plant (including a new one) must be compensated for by reduced emissions from another plant.

This trade-off would result in no net change in regional emis-sion. The SO2 and NOx cap-and-trade programs are designed to solve such regional (not local) problems. These require-ments are added to protect local air quality. Under the fed-eral Clean Air Act amendments of 1990, the air quality stan-dards that these policies are designed to achieve must protect human health with an adequate margin of safety.

Thus, if the Indian Point plants are replaced by gas-or coal-fired generators, total emissions of SO2, NOx, and Hg will not change (assuming that the CAMR or a more restric-tive cap is put in place) and should not significantly affect human health. Instead, the spatial patterns of emissions may change slightly, and the cost of controlling emissions will increase slightly.

Local air quality in the immediate vicinity of power plants is controlled separately by environmental regulations (as dis-cussed above). These regulations set limits on rates of emis-sions and require the use of tall exhaust stacks to ensure that pollutants are diluted sufficiently to avoid negative health impacts in the communities immediately surrounding the facilities under expected meteorological conditions (Davis et al., 2000; Goodfellow, 2000).

Most cap-and-trade systems, such as the one that controls SO2 emissions, include antibacksliding provisions that prevent facilities from violating local air quality regulations through the use of emissions trading. Nonetheless, because the emissions of specific sources are not directly controlled by cap-and-trade programs, concerns have been raised about the possibility of hotspots, areas of greater air pollution (or air pollution that is not lowered sufficiently) in the vicin-ity of some sources (Nash and Revesz, 2001). However, there is little evidence of hotspots having occurred in SO2 and NOx cap-and-trade programs (Farrell, 2004a; U.S. EPA, 2004). Nevertheless, local effects of emissions of toxics un-der a cap-and-trade program have been found to be a cause for concern (Chinn, 1999). Thus, it is reasonable to be con-cerned about the possibility of negative effects of Hg emis-sions if a coal-fired power plant replaces the Indian Point plants. However, the difficulty of finding an adequate site and of delivering coal in sufficient quantities to a location near New York City makes such an outcome unlikely in the short term (to 2015) examined in this study.

There is scientific consensus (with few dissenting opin-ions) that rising concentrations of greenhouse gases (GHGs) in the atmosphere have already caused perceptible changes in climate and will lead to further climate change in the fu-ture (Intergovernmental Panel on Climate Change, 2001).

The impact of climate change may be significant for water resources, agriculture, ecosystems, and the incidence of cata-strophic weather systems (Malmqvist and Rundle, 2002; Hayhoe et al., 2004). The most important anthropogenic GHG is carbon dioxide (CO2), and the most important source of CO2 is the combustion of fossil fuel.

Avoiding serious climate change impacts will require deep cuts in global CO2 emissions. Deep cuts in return will require significant changes from current practices in energy supply and demand, because fossil fuels dominate global energy use (Hoffert et al., 1998). As a non-fossil-fuel source of energy, nuclear power may grow in importance in the future. Replacement of the Indian Point Energy Center with fossil-fueled generation could increase CO2 emissions, the opposite of the direction necessary to avoid climate change.

There is currently no regulatory framework in the United States for controlling GHG emissions, but on December 20, 2005, Governor Pataki signed the Regional Greenhouse Gas Initiative (RGGI) Memorandum of Understanding, which committed New York State to proposing a cap-and-trade program to limit GHG emissions from the electric power sector starting in 2009. Six other states were part of this agreement: Connecticut, Delaware, Maine, New Hampshire, New Jersey, and Vermont. Fossil-fueled replacements for the Indian Point plant would emit CO2 and would be subject to this regulation.

Costs of Emissions from New Fossil Power Plants An upper-bound estimate of the cost of obtaining pollut-ant-emission allowances to cover annual emissions is calcu-lated assuming two technologies that could be adopted as replacements for the Indian Point units up to 2018 and per-haps beyond. These are the natural gas combined cycle (NGCC) and coal-based integrated gasification combined cycle (IGCC), with the latter serving as a proxy for advanced pulverized coal with state-of-the-art emission-control tech-nologies. The amount of energy required is assumed to be the amount produced by the two Indian Point units operating at 90 percent capacity factor for 1 year, which is about 17 million MWh. Assuming 80 percent capacity factors for the fossil-fueled plants, a total capacity of about 2,430 MW would be required.

For purposes of evaluation, nominally representative emission rate data are taken from the observed performance of Sithe Independence and Polk Stations, as given in the U.S.

Environmental Protection Agencys (EPAs) database, e-grid. Two scenarios are considered: in one, CAIR and CAMR are implemented but there is no GHG emission con-trol; the other is identical except that the RGGI baseline policy package is also implemented. Emission allowance prices for these two scenarios are taken from the September 2005 RGGI analysis (Table 4-1). The price of CO2 allow-ances in the latter scenario is $1 per ton. While this is lower than the amount estimated in other policies, including that of the European Union, it nevertheless is consistent with cur-rent projections for the Northeast. Below are considered the consequences of a range of CO2 charges, ranging from $1 per ton of CO2 removed to $25 per ton of CO2 removed.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

54 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER about $60 million per year, using the RGGI baseline price for CO2 allowances. However, many other studies have sug-gested that higher prices for CO2 allowances are likely. Hold-ing the other allowance prices constant, adjusting CO2 al-lowance prices to $10 per ton yields total annual allowance costs for NGCC of about $72 million and for IGCC of about

$210 million. At $25 per ton of CO2, these costs become about $175 million for NGCC and $450 million for IGCC.

Given the uncertainties in fuel prices, policies, and tech-nologies, it is reasonable to expect that the cost of air emis-sion allowances for fossil-fueled replacements for the Indian Point units would vary from a few million to ten million dollars per year if there is no GHG policy, and from ten million to possibly several hundred million dollars per year if a GHG policy is imposed.9 Water Use The Indian Point Energy Center is located on the eastern shore of the Hudson River and uses three intake structures to withdraw approximately 2.5 billion gallons of water per day for cooling the reactor units in once-through heat exchang-ers; the water is returned to the river somewhat warmer (NYDEC, 2003, p. 8). Under the federal Clean Water Act, discharges of heat to water bodies are considered pollution and are regulated by NYDEC. In addition, the cooling-water intake systems at Indian Point contribute to significant mor-tality of aquatic organisms in the Hudson River estuary. For this reason the cooling-water intake system is also subject to regulation under the Clean Water Act and state regulations.

These regulations require that the location, design, construc-tion, and capacity of the cooling-water intake system must reflect the best technology available for minimizing adverse environmental impacts.

TABLE 4-1 Estimated Future Emission Allowance Prices Study Description NOx ($/ton)

SO2 ($/ton)

Hg ($/lb)

CO2 ($/ton)

Energy Information Administration 50%-75% reductions in SO2, NOx, and Hg 1,108-2,825 719-1,737 21,119-85,225 N.A.

(2001, Table 4)

Palmer et al.

CAIR, CAMR, and seasonal NOx cap 1,042 0-1,347 35,760 N.A.

(2005, Table 14)

Regional Greenhouse Gas Initiative Baseline: CAIR and CAMR 1,710 1,268 21,730 N.A.

(RGGI)a Regional Greenhouse Gas Initiative

Reference:

CAIR, CAMR, constant CO2 1,713 1,267 21,670 1

emissions, 2009-2014 NOTE: N.A., not available. Abbreviations are defined in Appendix C.

aRGGI prices are based on the September 2005 analysis. See http://www.rggi.org/documents.htm. Accessed November 2005.

In 2003, NYDEC issued a draft State Pollutant Discharge Elimination System (SPDES) permit for Indian Point that required immediate and long-term steps to reduce the ad-verse impacts on the Hudson River estuary.10 The short-term steps include mandatory outage periods, reduced intake dur-ing certain periods, continued operation of fish-impingement mitigation measures, the payment of $25 million to a Hudson River Estuary Restoration Fund, and the conduct of various studies. In the long term, NYDEC staff has determined that closed-cycle cooling is the best technology available to mini-mize environmental impacts of the Indian Point facility.

However, the implementation of the very large, expensive modification is contingent on approval of the U.S. Nuclear Regulatory Commission (U.S. NRC) and extension of the U.S. NRC operating license for Indian Point and so is not yet certain.

Alternatives to Indian Point would likely also be required to use closed-cycle or dry cooling technologies that use little water. This type of cooling technology was required of the new Athens Generating Station up the Hudson River (Board on Electric Generating Siting and Environment, 2000). Small-scale generators (used for distributed genera-tion and combined heat and power) use air cooling and thus have no significant water use.

Overall, potential replacements for Indian Point would have less impact on the Hudson River than Indian Point cur-rently does. However, if Indian Point adds closed-cycle cool-ing, its impact would be reduced also.

Environmental Justice Equity and aesthetic concerns about the impacts of elec-tric power plants (and all energy infrastructure) are often called matters of environmental justice, which is typically 9Higher levels of costs would encourage energy-efficiency investments or replacements that emit less carbon, thus reducing the total cost.

10Available at http://www.dec.state.ny.us/website/dcs/eisanddp/Indian PointSPDES.pdf. Accessed November 2005.

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INSTITUTIONAL CONSIDERATIONS AND CHANGING IMPACTS 55 TABLE 4-3 Annual Costs for Allowances to Replace Indian Point Generation with CO2 Control (Regional Greenhouse Gas Initiative Reference Scenario)

Nuclear Natural Gas Coal Integrated Gasification Plant Combined-Cycle Plant Combined-Cycle Plant Capacity (MW) 2,158 2,428 2,428 Capacity factor 0.9 0.8 0.8 Generation (MWh) 17,013,672 17,013,672 17,013,672 NOx rate (lb/MWh) 0 0.134 0.719 NOx emissions (tons) 0 1,140 6,116 NOx allowance cost (cost per ton: $1,713)

$0

$1,952,676

$10,477,419 SO2 rate (lb/MWh) 0 0.025 1.55 SO2 emissions (tons) 0 213 13,186 SO2 allowance cost (cost per ton: $1,267)

$0

$269,454

$16,706,150 Hg rate (lb/GWh) 0 0

0.0397 Hg emissions (lb) 0 0

675 Hg allowance cost (cost per lb: $21,670)

$0

$14,626,993 CO2 rate (lb/MWh) 0 828 1,959 CO2 emissions (tons) 0 7,043,660 16,664,892 CO2 allowance cost (cost per ton: $1)

$0

$7,043,660

$16,664,892 Total emission allowance cost

$0

$9,265,790

$58,475,454 NOTE: Allowance prices are based on September 2005 analysis of the Regional Greenhouse Gas Initiative. See http://

www.rggi.org/documents.htm. Accessed November 2005. Abbreviations are defined in Appendix C.

TABLE 4-2 Annual Costs for Allowances to Replace Indian Point Generation, Without CO2 Control (Regional Greenhouse Gas Initiative Baseline Scenario, No CO2 Control)

Nuclear Natural Gas Coal Integrated Gasification Plant Combined-Cycle Plant Combined-Cycle Plant Capacity (MW) 2,158 2,428 2,428 Capacity factor 0.9 0.8 0.8 Generation (MWh) 17,013,672 17,013,672 17,013,672 NOx rate (lb/MWh) 0 0.134 0.719 NOx emissions (tons) 0 1,140 6,116 NOx allowance cost (cost per ton: $1,710)

$0

$1,949,256

$10,459,070 SO2 rate (lb/MWh) 0 0.025 1.55 SO2 emissions (tons) 0 213 13,186 SO2 allowance cost (cost per ton: $1,268)

$0

$269,667

$16,719,335 Hg rate (lb/GWh) 0 0

0.0397 Hg emissions (lb) 0 0

675 Hg allowance cost (cost per lb: $21,730)

$0

$14,667,493 Total emission allowance cost

$0

$2,218,923

$41,845,898 NOTE: Allowance prices are based on September 2005 analysis of the Regional Greenhouse Gas Initiative. See http://

www.rggi.org/documents.htm. Accessed November 2005. Abbreviations are defined in Appendix C.

defined as the fair treatment of all people, regardless of race or income, with respect to environmental issues. Ensuring environmental justice has been a matter of policy for the federal government for more than a decade, and in 2004 the U.S. Nuclear Regulatory Commission reaffirmed its com-mitment to this goal. In practice this means that while the NRC [Nuclear Regulatory Commission] is committed to the general goals of E.O. 12898, it will strive to meet those goals through its normal and traditional NEPA [National Environ-mental Policy Act of 1969] review process (President of the United States, 1994; U.S. NRC, 2004).

As a concept rooted in ideas of rights and fairness, not science and technology, environmental justice concerns are very different from the other types of issues discussed in this section. In addition, environmental justice concerns associ-ated with energy can include a wide array of issues, because many people find electric power plants and transmission towers ugly and undesirable to live or work near. For this Copyright © National Academy of Sciences. All rights reserved.

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56 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER reason, there are often concerns that new power plants or power lines will lower property values. By contrast, some communities might welcome a new power plant because of the jobs and tax revenues it would bring.

Everyone uses electricity, and it must be generated some-where and delivered in some way. Why should one commu-nity accept a power plant or transmission line when that fa-cility will serve another community? This problem can create tensions among communities or between residents of differ-ent states. Indian Point serves Westchester County and New York City. Once the power goes onto the grid, it is indistin-guishable from all other power sources, but Indian Point is basically a local plant for Westchester County and New York City. In fact, it is essentially the only generating plant in Westchester County. New York City is required to generate 80 percent of its power, but Westchester County currently has no local generation requirement. As noted elsewhere in this report, if Indian Point is closed, it will have to be re-placed at least in part with new generating capacity. If these are not local plants, then all of Westchester Countys power would have to be imported, impacting other communities that might object to new facilities being imposed on them.

This problem has been exacerbated by the transition from the traditional model of a regulated monopoly franchise in the electric power sector toward a model of a competitive generation market with monopoly franchise distribution utilities and a transmission system owned by various firms, but coordinated by an independent system operator. In this new framework, the traditional concepts applied to proposed power plantsincluding estimating the public interest in granting construction permits against the need for new gen-eration to meet local loadsno longer fits. Instead, plants are built to be competitive in the marketplace, as embodied in the New York State Energy Plan, which describes compe-tition as being in the public interest, as discussed earlier in this chapter.11 As discussed in Chapter 1, safety is a primary concern for many people living near Indian Point. They feel threatened by the plant and want it closed. This committee has not as-sessed the vulnerability of Indian Point. It defers to other experts to analyze whether those risks are real or negligible.

What this committee can say is that the socioeconomic, en-vironmental, and environmental justice impacts of replacing Indian Point are significant, although not universally nega-tive. The committee also notes that safety risks of the plant would not be eliminated until the spent fuel pool is emptied, which may be many years after the plant is closed. Storage of the spent nuclear fuel, presumably onsite, may involve costs that will be borne by the current owner, or by negoti-ated settlement with the state or federal authorities. Policy makers must balance the risks of continued operation against the impacts inherent in closing the plant.

Energy Security Historically, access, availability, and affordability have dominated public policy and the design of energy systems.

The costs of existing security measures have been implicitly divided between energy users, suppliers, and the govern-ment. Today, the security of energy infrastructures against deliberate attack has become a growing concern. Therefore, the context within which energy is supplied and used has evolved well past the paradigm that has led to the current physical energy infrastructure and associated institutional arrangements.

Concerns about deliberate attacks on the energy infra-structure have highlighted many critical questions to which no ready answers exist. For example: How much and what kind of security for energy infrastructure do we want and who will pay for it? Current government efforts directed at critical infrastructure protection tend to ignore this issue en-tirely, focusing on preventing attacks and protecting what-ever energy infrastructure the private sector creates. These decisions are being made implicitly for decades, favoring certain risk-creating technologies over others (Farrell, 2004b).

Many different approaches are likely to be necessary to achieve desired levels of energy-infrastructure security. Rou-tine security and emergency planning have obvious roles, and some features seem to inherently enhance system secu-rity, including decentralization, diversity, and redundancy.

Other features, such as the utilization of specific energy sources and energy-efficiency measures, seem to have mixed effects. In particular, some renewable energy technologies can be deployed more securely than can fossil-fuel and nuclear technologies; others cannot.

Socioeconomic Factors Including Indirect Costs to the Public The direct-cost projections, as exemplified in the sce-narios discussed in Chapter 5, depend on the generation choices to replace the 2,000 MW baseload of Indian Point, the location of the generation, modifications in transmission and distribution, the timing of any projected changes, and the load growth in the New York area. Each of the options considered has certain costs associated with it in addition to the direct costs of replacement capacity and environmental protection. These likely will be borne by the public, either through arrangements with the state or through changes in the electricity rates in southern New York, although the indi-rect costs do not appear directly on the customers electricity bill. At least three kinds of potential indirect, or hidden, costs are associated with replacing the power from Indian Point:

The economic value of the plant and its associated property. Entergy Corporation might have to be reimbursed if the Indian Point reactors are shut down prior to their end 11See http://www.nyserda.org/Energy_Information/energy_state_

plan.asp. Accessed January 2006.

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INSTITUTIONAL CONSIDERATIONS AND CHANGING IMPACTS 57 of licenses (including the period of extended operation if they are relicensed).

Higher natural gas costs to all users because of in-creased demand from the electric power sector. Natural gas is likely to be the main fuel for replacement generating ca-pacity, and unless new supplies are created, constraints are likely to be experienced.

Changes in employment opportunities and the tax base and the loss of local services associated with the Indian Point plant. These costs (or potential benefits, e.g., if the Indian Point plant site is converted to other economic uses) would be borne mainly by Westchester County.

The committee was unable to assess these costs, but they could be significant relative to the direct replacement costs, depending on the arrangements for the possible closure of Indian Point.

Additional sociopolitical issues to be faced by the New York communities are less tangible than are projected costs or regulation. However, there are factors that may constrain or severely limit the options for replacing Indian Point and may affect the communities in the next 20 to 30 years. These factors include the following:

Public attitudes toward siting power plants and trans-mission lines (aesthetics and the not-in-my-backyard, or NIMBY, phenomenon);

The willingness of the public to invest in energy-effi-ciency measures;

Attitudes toward advanced nuclear power plants as an option that would help maintain electric energy fuel-source diversity and minimize CO2 emissions;

Growth and development in southern New York, re-quiring major decisions on resource management and infra-structure, including energy, social services, primary and sec-ondary education, and so on; and

Attitudes of the state government regarding the regula-tion of the energy sector and its approach to permitting new facilities in the state.

Accounting for these factors will influence the choices of technological options discussed or summarized in Chapters 2 and 3 in ways that are beyond the scope of this study.

However, implicitly these factors, along with others dis-cussed in this chapter, tend to reinforce the focus on the short-term options of natural-gas-supplied generation and added transmission in southern New York State as key to a replacement strategy for Indian Point.

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127.

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Davis, W.T., A.J. Buonicore, L. Theodore, and L.H. Stander. 2000. Intro-duction: Air Pollution Control Engineering and Regulatory Aspects.

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Farrell, A.E. 2004a. Clean Air Markets. Encyclopedia of Energy, Vol.1.

C.J. Cleveland, ed. San Diego: Academic Press, pp. 331-342.

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Hayhoe, K., D. Cayan, C.B. Field, P.C. Frumhoff, E.P. Maurer, N.L. Miller, S.C. Moser, S.H. Schneider, K.N. Cahill, E.E. Cleland, L. Dale, R.

Drapek, R.M. Hanemann, L.S. Kalkstein, J. Lenihan, C.K. Lunch, R.P.

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Hoffert, M., K. Caldeira, A.K. Jain, E.F. Haites, L.D.D. Harvey, S.D. Pot-ter, M.E. Schlesinger, S.H. Schneider, R.G. Watts, T.L. Wigley, and D.J. Wuebbles. 1998. Energy Implications of Future Stabilization of Atmospheric CO2 Content. Nature 395: 881-884.

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Jaworski, N.A., R.W. Howarth, and L.J. Hetling. 1997. Atmospheric Depo-sition of Nitrogen Oxides onto the Landscape Contributes to Coastal Eutrophication in the Northeast United States. Environmental Science and Technology 31: 1995-2004.

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McFarlane, A. 2001. Interim Storage of Spent Fuel in the United States.

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58 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER NRC (National Research Council). 2001. Disposition of High-Level Waste and Spent Nuclear Fuel: The Continuing Societal and Technical Chal-lenges. Washington, D.C.: National Academy Press.

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59 5

Analysis of Options for Meeting Electrical Demand The retirement of the two operating reactors at Indian Point in the 2008-2015 time frame could have significant consequences for the reliable supply of electricity in the met-ropolitan New York City area unless appropriate replace-ments are supplied. This chapter discusses the impacts that potential replacements could have on reliability, costs, and other factors.

These replacements are analyzed in the context of the cur-rent evolution of the New York electric system (the New York Control Area, or NYCA) and the regulatory system that oversees it. Until recently, the future of the NYCA was viewed with relative complacencygrowth was modest, and more than enough generating plants had been proposed by developers to handle that growth. Subsequently, however, some of these plants have been canceled or deferred indefi-nitely. As discussed in Chapter 4, projections now show po-tential shortfalls as early as 2008, even without the retirement of Indian Point. Other projections, using less conservative assumptions, still predict that new capacity will be needed by 2010.

Replacing Indian Point would be likely to involve a port-folio of the options discussed in Chapters 2 and 3, including the following:

Energy efficiency (EE);

Demand-side management (DSM) and distributed gen-eration (DG);

Fuller utilization of existing generation and transmis-sion, and deferred plant retirements;

New generation; and

New transmission.

The committee did not model the actions and policy ini-tiatives that would be required to implement the supply and demand options considered here. The early-shutdown cases in particular would require some strong measures to be implemented immediately.

Different portfolios are possible, emphasizing different options. Exactly which ones would be implemented and where would make a big difference in how well the system would operate. In this chapter, example scenarios are adopted to illustrate options that could provide alternatives to the In-dian Point units should they be retired.

THE NYISO STARTING POINT The New York Independent System Operator (NYISO) recently completed the 2005 Reliability Needs Assessment (RNA; NYISO, 2005a) and the companion analysis Com-prehensive Reliability Planning Process (CRPP; NYISO, 2005b). Box 5-1 briefly reviews the criteria for reliability used in the analysis. The RNA includes all generation and transmission projects currently under construction in the NYCA (2,530 MW); retirements of existing capacity cur-rently announced (2,260 MW); and the projected electrical load through 2015. The NYISO process is described in more detail in Appendix F-1. Peak load and known NYCA re-sources listed by NYISO for the period under study are shown in Table 5-1.

To quantify the magnitude of the needed correction, NYISO analyzed the system adding assumed capacity where needed until adequate reliability was achieved. The Base Case in the NYISO reports is a result of analyses showing that NYCA system reliability would be determined by volt-age constraints in the system due to reactive power deficien-cies in the Lower Hudson Valley (LHV). In that situation, reliability falls below requirements by 2008, and an addi-tional 500 MW would be required then, increasing to 1,750 MW by 2010.

NYISO also projects that if essential reactive power cor-rections were made in the Lower Hudson Valley, thermal transmission constraints would then control, and less gener-ating capacity (250 MW beginning in 2009, increasing to 1,250 MW by 2010) would be required to meet NYCA reli-ability criteria. NYISO projected the scenario with thermal constraints controlling to 2015 (but not the Base Case), when Copyright © National Academy of Sciences. All rights reserved.

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60 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER 2,250 MW would be needed. All of these projections are based on Indian Point remaining in service (NYISO, 2005a).

NYISO has solicited proposed market-based or regulated solutions from participants and stakeholders in the NYCA market. The solicitations provide that Proposed solutions may take the form of large generating projects, small gen-eration projects including distributed generation, demand-side programs, transmission projects, market rule changes, operating procedure changes, and other actions and projects that meet the identified reliability needs (NYISO, 2005c).

Figure 5-1 shows projected NYCA LOLEs for the Base Case and the thermal constraint case (the top and bottom lines). It also shows two other analyses: if load increases faster than expected, and if power is constrained from flow-ing from upstate New York through New England and back to southeast New York. Both these assumptions adversely affect reliability to a significant extent compared to the ther-mal constraint case. All the analyses show that LOLE will violate the criteria limit of 0.1 in the 2008-2010 time frame.

THE COMMITTEES REFERENCE CASE The committee adopted a Reference Case (with Indian Point still operating), similar to the NYISO Sensitivity Case with thermal transmission limits controlling.1 The Reference Case includes two assumptions that differ from the NYISO case: (1) it includes constraints on the flow of power from upstate New York through New England and back to south-east New York, an assumption that NYISO did not apply in its final RNA/CRPP for the thermal sensitivity case; and (2) it used actual, though inactive, proposals for generating sta-tions for additional capacity to meet demand, rather than NYISOs standard 250 MW plants located wherever they were needed. The committee used these as illustrative ca-pacity additions to demonstrate the changes required to meet or exceed the LOLE requirements for balancing the electri-cal system. While there is no assurance that these projects will be built, presumably the developers would not have pro-ceeded as far as they did without a reasonable expectation that the sites were viable, that fuel and transmission access would be available, and that all permits would be attainable (several have been permitted under Article X).2 In addition, one generic plant was included, with 580 MW. Other op-tions could be selected along with alternative timing, but the TABLE 5-1 NYISO Base Case Peak Load and Known New York Control Area (NYCA) Resources 2008 2010 2013 2015 Peak load (MW) 33,330 34,200 35,180 35,670 Resources (MW) 39,759 39,766 39,766 39,766 Reserve margina (%)

19 16 13 12 Reserve marginb (%)

14 12 8

7 aFor the calculation of reserve margin and loss-of-load expectation (LOLE), NYISO adjusted installed NYCA generating capacity downward for contracted sale of hydropower outside the NYCA and for wind power (because wind cannot be counted on during peak demand). Resources include the adjusted NYCA generating capacity plus Special Case Re-sources (SCRs, 975 MW) and Unforced Delivery Rights (UDRs, 990 MW).

SCRs are agreements between NYISO and large electricity consumers (e.g.,

industrial companies) that will reduce load at NYISOs order. This is one of the emergency steps available to NYISO to avert outages. UDR corresponds to the two high-voltage direct current (HVDC) cables into Long Island, the Cross Sound Cable from New England (330 MW), and the Neptune Cable from New Jersey (660 MW scheduled for 2007). It is power that is expected to be available and is thus included by NYISO for planning purposes.

bReserve margin without the 1,965 MW of SCR and UDR, as plotted in Figure 4-1 in Chapter 4 of this report. Assumptions on allowable resources make a large difference in the calculated reliability.

SOURCE: NYISO (2005b, p. 39).

BOX 5-1 Reliability Criteria System operators generally use two main criteria for ensuring reliability: reserve margin and loss-of-load expectation (LOLE). Re-serve margin is simply the difference between the generating capac-ity available to serve an area and the expected peak demand divided by the peak demand. It is measured in percent. NYISO plans for the NYCA to keep a reserve margin of at least 18 percent.

LOLE is more complicated but more meaningful. It measures the predicted frequency, in days per year, that the bulk power system will not meet the expected demand for electricity in one or more zones in New York State, even if only for a short time. Equipment failures in the power system (i.e., generators and the high-voltage transmission grid together) can force part of the load on the bulk power transmission system to be involuntarily disconnected. LOLE does not include the more frequent cause of blackouts for customers that are associated with failures of the local distribution system due, for example, to fall-ing tree limbs and ice storms.

The North American Electric Reliability Council recommends a reliability standard of LOLE less than 0.1, and this standard has been adopted for the region by the Northeast Power Coordinating Council, and in turn by the New York State Reliability Council. In other words, there must be sufficient generation and transmission capability in the system that a failure to serve load somewhere in the bulk power sys-tem would be expected not more than on 1 day in 10 years. The LOLE criterion is central to the discussion of reliability in this chapter. See also Chapter 1 for a discussion of reliability.

1The committee believes that the essential corrections to reactive power would most likely be made in a timely manner, and that thermal transmis-sion constraints would ultimately dictate system reliability and thus the ad-ditional compensatory resources required.

2The committee does not endorse any of these projects, nor did it analyze the financial viability of any of them; they are simply assumed to be in the generating fleet when needed in the reliability calculation. None of them is under construction. Several of them have been, or may be, canceled, al-though other generating companies might acquire the sites and reactivate the projects.

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ANALYSIS OF OPTIONS FOR MEETING ELECTRICAL DEMAND 61 FIGURE 5-1 NYISO reliability projections. SOURCE: Derived from NYISO (2005b).

NYCA LOLE, Uncompensated 0.000 1.000 2.000 3.000 4.000 5.000 6.000 Year NYCA LOLE NYISO Base Case, Voltage Limits Control, RNA p. 5 NYISO Sensitivity Case, Thermal Limits Control (RNA SupDoc. pp. 61 and 69)

High Load - NYISO Sensitivity Case, Thermal Limits Control (RNA SupDoc. p. 70)

NYISO CRPP Alt. NE Transmission Case (v.3 pp. 61 and 69; GE Table 10, p. 33) 2008 2010 2012 2014 additions identified serve to illustrate the kinds of response envisaged for Indian Point replacement. The generating ca-pacity changes assumed (beyond the 2,530 MW of genera-tion and transmission expected to be completed before 2008) are shown in Table 5-2.

To assist the committee with the analysis, General Elec-tric International, Inc. (GE) was retained to run its propri-etary models, MARS3 and MAPS',4 of the New York State and Northeast region electric systems. The MARS model (Box 5-2) is one of the principal tools used to assess NYCA system reliability. The MAPS model allows a preliminary assessment of the impact of each option studied on NYCA system operations and economics.5 Reliability was analyzed only for 2008, 2010, 2013, and 2015, the years that the In-dian Point reactors were hypothesized to be closed.

The goal of the reliability simulations was to determine the additional resources that would be required to meet reli-ability standards. Generating capacity was added until LOLE met the requirement of 0.1, and the NYCA reserve margin reached 18 percent.6 The results of the MARS analyses are shown in Figure 5-2 in comparison with NYISOs two main cases. With the committees Reference Case assumptions, 3,300 MW are needed by 2015 to maintain reliability (LOLE < 0.1). LOLE is well below 0.1 day per year in 2008 and 2010, slightly exceeding 0.1 in both 2013 and 2015.7 Details of this analy-TABLE 5-2 Additional Generating Capacity Assumed in Reference Case Capacity NYCA Online Project (MW)

Zonea Date SCS Astoria Energy 500 J

Jan 08 Caithness 383 K

Jan 08 Long Island Wind 15b K

Jan 08 Bowline Point 750 G

Jan 10 Wawayanda 540 G

Jan 13 Generic Combined Cycle 580 H

Jan 13 Reliant Astoria I 367 J

Jan 15 Reliant Astoria II 173 J

Jan 15 Total Power 3,308 aSee Figure 1-3 in Chapter 1 of this report for a map of the New York Control Area (NYCA) zones.

bFPL Energy has proposed a 150 MW wind energy project off the south shore of Long Island. Wind is an intermittent power producer, and only a small fraction of rated capacity may be available during peak load. The committee used 15 MW for this project in its reliability analysis. NYISO did not use any of the 47 MW of existing NYCA wind capacity in its reli-ability analyses.

SOURCE: As shown in Hinkle et al. (2005).

3GEs MARS: Multi-Area Reliability Simulation. See http://www.ge power.com/prod_serv/products/utility_software/en/downloads/10320.pdf.

4GEs MAPS': Multi-Area Production Simulation. See http://www.

gepower.com/prod_serv/products/utility_software/enge_mars.htm.

5In identifying initial reliability needs, NYISO does not conduct an eco-nomic evaluation of resources needed.

6The problem is considerably more complex than this. Iterative adjust-ments of resources assumed are needed, and the parameters to which the model is sensitive also interact with one another.

7In several of the committees analyses, the rate of adding additional resources was not optimized, resulting in instances of overcompensation; projected LOLEs are thus unnecessarily low in the years prior to 2015. In further analyses, this assumption could be corrected.

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62 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER BOX 5-2 Multi-Area Reliability Simulation (MARS) Model GEs MARS simulation software is the same system reliability screening tool approved by the New York State Reliability Council (NYSRC) and used by NYISO in its CRPP/RNA studies. MARS uses Monte Carlo simulation of the electrical generation and transmission system of the New York Control Area (NYCA) interconnected with the four contiguous electrical power systems in the northeastern United States and eastern Canada.

MARS is a transportation model, sometimes referred to as a bubble and stick model, connecting generation and loads in the grid. That is, it connects the sources and sinks of power with direct-current-like flows.

sis, along with those of the scenarios below, are in Appen-dix F-2.

The different results (about 1 GW difference in resources needed by 2015) of the generally similar analyses by NYISO and the committee illustrate the sensitivity of the reliability analysisand thus the additional resources neededto dif-ferences in initial system conditions assumed. The main dif-ferences are with transmission constraints and geographic distribution of additional generating capacity.8 The commit-tee believes that these two cases approximately encompass the range of additional resources needed. Appendix F dis-cusses the differences between the analyses.

REPLACEMENT SCENARIOS With the Reference Case defined, the committee exam-ined several cases with Indian Point closing. First, it looked at simply closing Indian Point, either in 2008/2010 (Case b1), or at the end of current license in 2013/2015 (Case c1) with no measures to compensate for the 2,000 MW capacity reduction.9 As expected, the LOLE in both cases increased to unacceptable levels for these cases, as summarized in Fig-ure 5-3.

The committee then analyzed cases with additional re-placement resources, representing possible solutions that might arise out of NYISOs solicitation process to restore or maintain system reliability. The goal was to determine how much compensation would be necessary to maintain reliabil-ity within criteria. All of these cases included additional, aggressive programs to improve efficiency of electricity use and stronger demand-side measures to reduce peak demand.

For most of them, peak demand was reduced by 300 MW in 2008, 650 MW in 2010, 800 MW in 2013, and a total of 850 MW10 in 2015.

Additional supply was assumed to come from the pro-posed TransGas Energy project (1,100 MW, which was not needed in the Reference Case) in Brooklyn. Several of the Reference Case projects were accelerated as shown in Table 5-3 for Case b2 (early retirement) and Case c2 (end-of-license retirement).

The committee explored the consequences of additional scenarios, but in less detail, only looking at 2015. These in-cluded:

1. A 1,000 MW north-south high-voltage direct-current (HVDC) transmission line running from the Marcy Substa-tion (near Utica in Zone E) to Rock Tavern (in Zone G, south of the current transmission bottlenecks), assumed to be op-erational in 2012. Cases b3 and c3 represent the early retire-ment and end-of-license (EOL) retirement of the Indian Point units with this HVDC cable resource in place. The inference drawn from the results is that with such a north-south trans-mission option, using excess power upstate and from out of state, the potential generating resource needed downstate might be reduced from 1,100 MW to 300 MW.

2. Higher market penetration of energy efficiency and demand-side management, Cases b4 and c4, for early and EOL shutdown scenarios, respectively. This scenario in-cluded 1,200 MW of energy efficiency and 800 MW of DSM load-reduction measures for a net 1,950 MW reduction of peak load by 2015, mainly in the New York City area. De-mand would continue to grow, but at a low rate (390 MW growth compared with 2,340 MW without the EE/DSM measures). No additional capacity beyond the Reference Case would be necessary, as the additional EE and DSM measures would compensate for Indian Point. EE/DSM mea-sures of this magnitude would require significant, aggres-sive early attention by the New York State government and a high fraction of all electricity users.

3. Sensitivity to higher fuel prices. The systems modeled were the same as in the earlier scenarios, so reliability analy-sis was not necessary. The committee included this analysis to estimate the approximate economic impact of higher fuel prices. The price projections used in other scenarios are lower than recent prices, and it seems plausible that gas and oil prices could remain much higher.

8Other differences in initial assumptions are estimated roughly to ac-count for <200 MW of the 1 GW total.

9Note that the license for Indian Point Unit 2 expires on September 28, 2013, and that for Unit 3 on December 12, 2015. Both could still be operat-ing through the summer peak of their last year. In particular, the absence of Unit 3 would not seriously affect reliability until the summer of 2016. How-ever, because of the lack of a database for 2016, it was not possible to extend the analysis past 2015, so the reactors were assumed to close in January 2013 and 2015 in order to capture the impact on peak-demand reliability. In reality, an additional year would be available for replacement.

10Energy efficiency measures (575 MW) and demand-side management measures (300 MW) by 2015 contribute in different ways to peak reduction.

The net effect of these assumptions in the model is 850 MW reduction in peak load, not the 875 MW sum.

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ANALYSIS OF OPTIONS FOR MEETING ELECTRICAL DEMAND 63 Table 5-4 summarizes the assumed additions to resources for the various scenarios, based on achieving or exceeding the LOLE requirements. Details of the assumptions and tim-ing of additions of illustrative resources are in Appendix F-2.

RESULTS OF RELIABILITY ANALYSES Table 5-5 summarizes the reliability results of the cases run, showing the resulting LOLEs after compensation. Re-sults for the Reference Case and the main cases of early and end-of-license shutdown of Indian Point are shown graphi-cally in Figures 5-4 and 5-5, which also provide a compari-son to the NYISO Base and Sensitivity Cases. Figure 5-6 shows the projected reserve margin for Case c2 (EOL shut-down of Indian Point), allowing comparison to reserve mar-gin projections in Figure 4-1 and the impact of differing com-pensation.

If Indian Point is closed, roughly 2,000 MW of additional resources would be needed beyond that needed for the Ref-erence Case. As shown in Table 5-4, the Early-Shutdown scenario (b2) requires about 4,500 MW of additional re-sources (total new capacity plus peak-load reduction) to be available by 2010 to meet load growth, retirements of other units, and retirement of Indian Point.11 Of this amount, about 650 MW could result from improved efficiency and demand-11The data on reserve margins and Figure 5-5 show the degree to which the illustrative resource additions result in overcompensation in the early years until 2013 and 2015. The schedule for adding compensation might therefore be extended in the early years.

FIGURE 5-2 Approximate additional resources needed. SOURCE: Derived from NYISO (2005b) and Hinkle et al. (2005).

0 500 1000 1500 2000 2500 3000 3500 Year Capacity Added, MW GE Reference Case, v.2 Alt. NE Transmission Model, Table 2, p. 6 NYISO Base Case, Voltage Limits Control (RNA p. 5)

NYISO Sensitivity Case, Thermal Limits Control (RNA SupDoc. p. 70) 2008 2010 2012 2014 FIGURE 5-3 Impact on NYCA reliability loss of load (LOLE) of shutting down Indian Point without additional resources beyond the reference case. SOURCE: Derived from Hinkle et al. (2005).

0.000 0.200 0.400 0.600 0.800 1.000 1.200 1.400 1.600 Year LOLE Early Shutdown/Without, GE Case b1, p. 35 EOL Shutdown/Without, GE Case c1, p. 37 GE Reference Case, Using Alt. NE Transmission Model, GE Table 11, p. 34 2008 2010 2012 2014 Copyright © National Academy of Sciences. All rights reserved.

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64 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER TABLE 5-4 Summary of Illustrative Resources Assumed to Maintain NYCA Reliability Year 2008 2010 2013 2015 NYCA Peak Load, MW 33,330 34,200 35,180 35,670 NYCA Firm Capacity, MW 37,794 37,801 37,801 37,801 Total Resources with 975 MW SCR and 990 MW UDR, MW 39,759 39,766 39,766 39,766 NYISO Additional Capacity Required for Reliability, Cumulative. Thermal Limits Controlling, MW 0

1,250 1,750 2,250 COMMITTEE SCENARIOS Reference case, cumulative additional generating capacity assumed to meet or exceed load growth and 900 1,650 2,770 3,310 scheduled retirements, Indian Point continues in service, MW Early shutdown + compensation, Case b2, cumulative generation added above reference case, MW 540 2,180 1,640 1,100 Total Generation Added, MW 1,440 3,830 4,410 4,410 Cumulative Peak-Load Reduction by EE/DSM Measures, MW 300 650 800 850 Total Compensation for Scenario, MW 1,740 4,480 5,210 5,260 EOL shutdown + compensation, Case c2, cumulative generation added above reference case, MW 0

900 540 1,100 Total Generation Added, MW 900 2,550 3,310 4,410 Cumulative Peak-Load Reduction by EE/DSM Measures, MW 300 650 800 850 Total Compensation for Scenario, MW 1,200 3,200 4,110 5,260 ADDITIONAL SCENARIOS Compensation including 1,000 MW HVDC line, Cases b3 and c3, cumulative generation added above 300 reference case, MW Total Generation Added, MW 3,600 Cumulative Peak-Load Reduction by EE/DSM Measures, MW 850 Compensation including high EE/DSM measures, Cases b4 and c4, cumulative generation added above 0

reference case, MW Total Generation Added, MW 3,300 Cumulative Peak-Load Reduction by EE/DSM Measures, MW 2,000 SOURCE: Hinkle et al. (2005).

TABLE 5-3 Capacity Additions Assumed for Cases b2 and c2 Onlinea Capacity NYCA Case Case Project (MW)

Zone b2 c2 SCS Astoria Energy 500 J

2008 2008 Caithness 383 K

2008 2008 Long Island Wind 15b K

2008 2008 Bowline Point 750 G

2010 2010 Wawayanda 540 G

2010 2010 Generic Combined Cycle 580 H

2013 2013 Reliant Astoria I 367 J

2008 2010 Reliant Astoria II 173 J

2008 2011 TransGas Energy 1,100 J

2010 2015 Total Power 4,408 aAll additions were assumed to come online in January of the year listed.

bSee note b in Table 5-2.

SOURCE: As shown in Hinkle et al. (2005).

side management. Constructing the proposed 600 MW Cross-Hudson Cable Project, at present suspended, and ex-tending the operation of the 880 MW Poletti 1 plant through 2010, for example, would help. Another possibility would be to extend the operation of one of the Indian Point units beyond 2010, until sufficient generation capacity could be installed in the NYCA.

In Cases b3 and c3, the added north-south HVDC trans-mission line was counted as a 1,000 MW resource, but the availability of sufficient generating capacity upstate was not examined in detail. As discussed in Chapter 3, the supple-mental generation could come from a combination of sources, including existing or new generation upstate, or imports from Canada, all of which require additional analy-sis beyond the scope of this study.

This assumed HVDC line would reduce the need for new capacity in the New York City area by about 800 MW. The impact of the line on reliability would be even more substan-tial if (1) it would extend all the way into New York City (Zone J) and (2) if it would be backed by dedicated generat-Copyright © National Academy of Sciences. All rights reserved.

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ANALYSIS OF OPTIONS FOR MEETING ELECTRICAL DEMAND 65 TABLE 5-5 Results of Reliability Analyses Year 2008 2010 2013 2015 NYISO 2008 CRPP/RNA Data: Table 7.3.1 Firm Resources only NYCA Reserve Margin, %

19 16 13 11 NYCA LOLE 0.073 0.752 2.692 4.816 For Comparison: GE-Calculated NYCA LOLE with Thermal Limits Controlling and Alternate NE 0.122 0.966 3.164 5.210 Transmission Constraints NYISO Compensation Case, with Additional Capacity as in Table 5-4. Thermal Limits Controlling Estimated NYCA Reserve Margin, %

19 20 18 18 Resulting NYCA LOLE 0.073 0.068 NA NA COMMITTEE SCENARIOS Reference case NYCA Reserve Margin, %

22 21 21 21 Resulting NYCA LOLE 0.021 0.069 0.104 0.102 Early shutdown, reference case additions only, Case b1 NYCA Reserve Margin, %

20 16 16 16 Resulting NYCA LOLE 0.104 1.352 1.323 1.48 Early shutdown with compensation, Case b2 NYCA Reserve Margin, %

22 24 23 22 Resulting NYCA LOLE 0.023 0.011 0.032 0.101 EOL shutdown, reference case compensation only, Case c1 NYCA Reserve Margin, %

22 21 19 16 Resulting NYCA LOLE 0.021 0.069 0.333 1.48 EOL shutdown with compensation, Case c2 NYCA Reserve Margin, %

18 21 18 17 Resulting NYCA LOLE 0.013 0.006 0.036 0.101 ADDITIONAL SENSITIVITY ANALYSES Compensation including 1,000 MW HVDC line in 2012, Cases b3 and c3 NYCA Reserve Margin, %

19 Resulting NYCA LOLE 0.098 Compensation including high EE/DSM measures, Cases b4 and c4 NYCA Reserve Margin, %

22 Resulting NYCA LOLE

0.082 NOTE: All reserve margin and LOLE results include SCR and UDR as defined in Table 5-1. SOURCE: Hinkle et al. (2005).

ing capacity. If these two conditions could be met, the trans-mission line would then also be counted as a resource con-tributing to the locational installed capacity (LICAP) require-ment that Zone Js generation capacity be at least 80 percent of peak load. This HVDC line would then be analogous to the Neptune Cable now under construction, which will meet both criteria for Long Island and therefore contribute to Zone Ks LICAP requirement of 98 percent.

The high levels of EE and DSM in Cases b4 and c4 would be advantageous in meeting reliability criteria, while reduc-ing the additional generating resources required for load re-quirements with the retirement of the Indian Point units. Re-ducing demand growth by 1 MW would mean avoiding the need to build 1.18 MW to meet the NYCA reserve margin requirement. Even so, replacing the 2,000 MW from Indian Point would require reducing peak load by 1,700 MW by 2015, a very ambitious goal. The technical potential is there, and current programs are having considerable success, but progress comes in small increments that must be imple-mented by many people. It should be noted that the results of such programs are harder to verify than the contribution of a new generating capacity.

Corrections to reactive power are also required. The capi-tal cost of static VAR compensation (SVC) is in the range of

$50 per kilovar (kVAR), and that of a synchronous condenser about $35/kVAR (ONeill, 2004).12 Equipment to replace the reactive power that Indian Point is capable of supplying would cost on the order of $30 million to $45 million. In comparison, the capital cost of a 1,000 MW power plant is on the order of $1 billion. Since the cost of correcting reac-12ONeill is on the staff of the Federal Energy Regulatory Commission, but was expressing his own views here.

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66 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER tive power is relatively low, the committee infers that timely local corrections to reactive power would be made.

OPERATIONAL AND ECONOMIC IMPACTS The committee estimated the impact of closing Indian Point with the GE MAPS model for the scenarios that met reliability criteria in the MARS modeling. The NYISO case with thermal limits controlling in 2008 is the benchmark for comparing projected operational and economic impacts on (1) the diversity of the mix of fuels used to generate electric-ity, (2) the impact on the wholesale price of electricity, and (3) the annual variable operating cost (VOC) of producing electricity, important in the industry because it reflects the net effect of changes in both zonal generation and fuel cost (and is the fundamental variable minimized systemwide in FIGURE 5-4 Capacity assumed to meet load growth and compensate for retiring Indian Point. SOURCE: Derived from NYISO (2005b) and Hinkle et al. (2005).

Compensation Assumed vs. Time 0

1000 2000 3000 4000 5000 6000 Year Compensation Assumed, MW GE Early IP Shutdown/Comp, Case b2, Table 2, p. 6 GE EOL IP Shutdown/Comp, Case c2, Table 2, p. 6 GE Reference Case v.2 Alt. NE Transmission Model, Table 2, p. 6 NYISO Base Case, Voltage Limits Control, RNA p. 5 NYISO Sensitivity Case, Thermal Limits Control (RNA SupDoc. p. 70) 2008 2010 2012 2014 FIGURE 5-5 Loss-of-load expectation after compensation. SOURCE: Derived from NYISO (2005b) and Hinkle et al. (2005).

NYCA LOLEs after compensation 0.000 0.020 0.040 0.060 0.080 0.100 0.120 Year GE Reference Case, Using Alt. NE Transmission Model, GE Table 11, p. 34)

NYISO v.6 Base Case, after compensation, RNA p. 6 NYISO v.6 Thermal Sensitivity Case, with Compensation, RNA

p. 8 GE Early Shutdown with Compensation, Case b2, GE p. 36 GE EOL Shutdown with Compensation, Case c2 Calculated Reliability, LOLE 2008 2010 2012 2014 Copyright © National Academy of Sciences. All rights reserved.

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ANALYSIS OF OPTIONS FOR MEETING ELECTRICAL DEMAND 67 the MAPS calculations). In addition, a brief sensitivity analy-sis was conducted to help understand the impact that differ-ing fuel costs would have on the cost of electricity.

Analytical Considerations Neighboring regions (New England and part of the Penn-sylvania Jersey Maryland [PJM] control area) were included in the analysis. At the outset, the committee recognized that MAPS, itself dependent on the approximate results from the MARS model analyses, would provide mainly an approxi-mate picture of economic and cost projections into the fu-ture. Part of the MAPS model simulates the current whole-sale electricity marketplace in New York State. This market is evolving to take into account aspects of pricing and in-vestment that will differ from the present operation (see Chapter 4). Since the model cannot project such changes, confidence in the MAPS results for wholesale cost change is substantially less than in the reliability calculations of MARS.

Box 5-3 lists the main points of how the MAPS simula-tion works with MARS and the results produced by the simu-lation. Details of the modeling are contained in Appendix F-2 and the GE report (Hinkle et al., 2005).

GEs MARS and MAPS are well-accepted screening methodologies despite their many limitations. Some addi-tional caveats are necessary in considering some limitations in the models and databases used, and thus the utility of com-parisons of results for the various scenarios.

Since MAPS calculates a systemwide minimum operat-ing cost of producing electricity, which in turn is dominated by fuel costs, the fuel prices assumed dominate the economic outputs. Fuel-cost volatility presents a significant uncertainty in interpreting the MAPS results. For the basic calculations, MAPS used a reference 2008 cost of natural gas of $5.1 per million British thermal units ($5.1/MMBtu), decreasing to

$4.2/MMBtu by 2015 (both in nominal cost, or dollars-of-the-year).13 For comparison, the U.S. Department of En-ergys Energy Information Administration (DOE/EIA) re-ports that natural gas prices paid by electric power producers in New York State were in the range of $7.3 to $9.3/MMBtu in August 2005 (before the price increases resulting from the damage caused by Hurricane Katrina).

To assess the impact of higher fuel prices, a sensitivity study was made using a 2008 natural gas price of $7.8/

MMBtu (decreasing to $7.0 by 2015). Although gas prices have dropped some in recent months, the committee recom-mends focusing on this case unless increased imports of liq-uefied natural gas (LNG) are seen as likely. Clearly, more in-depth study of gas prices and their consequences is needed.

The MAPS model of the scenarios adds considerable new NYCA generation based on modern, efficient gas-fired com-bined-cycle units, which require less natural gas than simple-cycle gas turbines for the same power produced. Conse-quently, application of these units results in lower system variable operating costs. However, no comparable assump-tion is made in the MAPS database for adjacent areas. This tends to lower the impact on the wholesale price of retiring Indian Point and would tend to project reduced imports of electricity from the adjacent areas in favor of increased, lower variable cost generation in the NYCA.

FIGURE 5-6 Projected reserve margin for End-of-License (EOL) Shutdown of Indian Point with Compensation (Case c2). SOURCE:

Derived from NYISO (2005b) and Hinkle et al. (2005).

EOL Shutdown with Compensation to LOLE = 0.1 in 2015: Impact of Resource Assumptions on NYCA Reserve Margin 0

5 10 15 20 25 30 Year Adj. GE Case c2, SCRs + UDRs:

7.3.1 Basis Adj. GE Case c2 to

7.2.1 Basis

no SCR or UDR NYISO Table 7.3.1, SCR + UDR NYISO Table 7.2.1, no SCR or UDR A

NYCA Reserve Margin 2010 2008 2012 2014 13Base case data set, Quarter 1, 2005, published by Platts, a Division of McGraw-Hill Companies. See http://www.platts.com/Analytic%20 Solutions/BaseCase/index.xml. Accessed March 2006.

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68 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER In evaluating the results of the MAPS analyses, readers should understand that the assumptions made tend to under-estimate the projections on future wholesale prices of elec-tricity. Therefore, the focus should be on major trends and percentage changes rather than on the absolute value of pro-jected wholesale price of electricity. Similarly, the whole-sale price of electricity modeled does not represent the final cost to consumers. Among other things, it does not include transmission and distribution costs or all of the costs for re-covery of the cost of new capacity, either generation or trans-mission, which ultimately will, most likely, be borne by the consumer.

Fuel Diversity: Impact on NYCA Reliance on Natural Gas for Generating Electricity Diversity of fuels used in generation is a security crite-rion to avoid excessive reliance on a single fuel. Generation in urban environments with minimal pollution is another cri-terion. New York State has benefited from ample fuel diver-sity in the past, and flexibility has been maintained using many gas-fired plants with dual-fuel units that can burn oil.

For the new generating capacity assumed in this study, the committee focused on natural gas in high-efficiency com-bined-cycle units. Natural-gas-fired generators have been the dominant choice nationwide since the mid-1980s, but that may not be strategically prudent for the next decade.

Table 5-6 compares the diversity of fuels used to generate electricity in the NYCA and the Northeast region for 2005 and 2008. Gas consumption for generating electricity is ex-pected to increase 25 percent from 2005 to 2008. In addition, the regional shifts in fuel diversity are significant. There has been a recent reduction in the use of both oil and coal in the NYCA. In the Northeast region as a whole, the use of oil has declined, but the use of coal evidently is increasing. Finally, the projections for the Reference Case are about the same as for the Benchmark and are directionally correct in that the Reference Case adds about 1 GW of gas-based capacity and increases the change from 2005 by about another 2 percent.

Further detail is shown in Appendix F-2.

Table 5-7 summarizes the projected increase of NYCA reliance on natural gas for the main options scenarios con-sidered in this study. The table gives the percentage of NYCA reliance on natural gas for generating electricity and the impact of higher assumed fuel prices.

The MAPS projections show that reliance on natural gas would increase from 34 percent in 2008 to 44 percent in 2015 just to meet load growth and replace the capacity of units currently scheduled for retirements (the Reference Case). The projected reliance on natural gas increases to 53 percent by 2015 if Indian Point is shut down and capacity shortfall is compensated for principally by adding gas-fired units. Higher penetration of EE/DSM measures tends to re-duce gas requirements, but only by about 2 percentage points. One might expect that the High EE/DSM case would lie closer to the Reference Case, but the committee was not able to investigate this further. Higher natural gas price shifts generation to other fuels, but not much, according to the MAPS projections, as the reliance on natural gas decreased only by about 3 percentage points.

In sum, the compensatory actions evaluated would sig-nificantly reduce diversity in the mix of fuels used for elec-trical generation in New York State. Basing compensating BOX 5-3 Multi-Area Production Simulation (MAPS) Software Model The MAPS model assesses the operational and economic char-acteristics of the entire interconnected region. MAPS models the elec-trical system in greater detail than MARS does, and is based on an economic commitment and dispatch model, also examining the flow on each transmission line for every hour of the simulation, recogniz-ing both normal and operating reliability-related constraints. MAPS dispatches generating units in the system to meet the zonal electrical-generation requirements of a specific scenario being modeled, con-sidering any transmission constraints. MAPS then calculates the an-nual variable operating cost (AVOC) of producing electricity systemwide and iterates, adjusting the dispatch of units in the system, starting with lowest variable operating cost first, to determine the mini-mum annual regional systemwide variable operating cost. The vari-able cost of producing electricity is dominated by fuel costs, but it also includes variable operational and maintenance costs, unit start-up cost (say, going from a cold start and ramping up to full electrical output), and the variable cost of emission credits consumed, where required. MAPS does not explicitly consider fixed costs, which would include capital charges; in this work, MAPS was not used to mimic the bidding strategy for bids into the wholesale market submitted by gen-erators of electricity. Instead, pricing was equal to the variable cost of the marginal bidder, which is the theoretical limit to which economic theory drives the clearing price of a commodity in a perfectly competi-tive market.

Having established the minimum systemwide AVOC, MAPS then provides the corresponding wholesale price of electricity, airborne emissions, and the mix of fuels used in generating electricity for each pricing zone in the system.

Generation resources added to maintain reliability are inputs to the model, using MARS results as a base. MAPS does not assess the financial attractiveness of adding that capacity. It assumes that the resource is there, calculates its variable operating cost, and dis-patches it in rank order of the variable operating cost for that re-source, as capacity is aggregated to meet the then-current demand for electricity in the wholesale market.

Iterative use of both the MARS reliability simulations in con-junction with the MAPS simulations for the different scenarios thus provides a basis, with some caveats, for comparing both reliability and trends of operating and economic impacts among the illustrative scenarios posed by the committee.

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ANALYSIS OF OPTIONS FOR MEETING ELECTRICAL DEMAND 69 resources upstate on fuel other than natural gas could lessen the reliance on natural gas, but to meet NYCA reliability criteria, that option would also require additional transmis-sion capacity to bring power south of the congested Upstate New York-Southeast New York (UPNY/SENY) interface.

Greater than 50 percent reliance on gas presents a strategic issue. In addition, it is not clear where the additional gas will be coming from. New sources, such as imported liquefied natural gas, and new transmission pipelines are likely to be required. A coal plant might be completed upstate by 2016 (the first peak-demand period after the second Indian Point reactor reaches its current EOL would be in the summer of 2016), but planning would have to start soon. Otherwise, there are few supply alternatives to gas. Considerable analy-sis and planning are required to develop the optimum path forward in the common interest.

Projected Impact on the Wholesale Price of Electricity The options selected to compensate for an Indian Point shutdown would affect the operating costs for power genera-tion. This change in turn will influence the wholesale price TABLE 5-6 Benchmark of the Consumption of Natural Gas, Coal, and Oil for 2005 and 2008: Annual Fuel Consumption in Trillion Btu Benchmark CRPP 2005 Thermal Case in 2008 Reference Case in 2008 NYCA Northeast NYCA Northeast NYCA Northeast Natural gas 308 804 385 1,031 392 1,032 Oil 103 132 47 59 32 44 Coal 249 2,242 218 2,344 218 2,343 Percent change from 2005 Natural gas

25.1 28.1 27.3 28.3 Oil

-53.7

-54.8

-68.1

-66.3 Coal

-12.4 4.5

-12.5 4.5 Percent change from benchmark 2008 NYISO Base Case Natural gas

1.8 0.1 Oil

-31.1

-25.4 Coal

-0.1

0.0 SOURCE

Derived from Hinkle et al. (2005), plus additional personal communication with Gene Hinkle, December 2005.

TABLE 5-7 Projected Impact on Electrical Generation Based on Natural Gas for 2008 to 2015, with Sensitivity to Fuel Price Reference Fuel Price:

Higher Fuel Price:

NYCA Natural Gas Prices: 2008 @

$5.11/MMBtu; 2015 @ $4.24/MMBtu

$7.69/MMBtu; 2015 @ $7.03/MMBtu 2008 2010 2013 2015 2008 2010 2013 2015 Percent gas in:

2003: 20%

2005: 28%

Benchmark NYISO CRPP Thermal Case in 2008 34 Reference Case 36 38 43 44 34 Early Shutdown with Compensation, b2 40 48 53 53 38 47 49 50 EOL Shutdown with Compensation, c2 35 39 47 53 33 37 44 50 Early Shutdown with Higher EE/DSM, b4 51 EOL Shutdown with Higher EE/DSM, c4 51 SOURCE: Derived from Hinkle et al. (2005).

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70 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER of electricity. Table 5-8 gives the results of the MAPS-pro-jected impact on wholesale prices of electricity in the NYCA and New York City. It is also important to recognize that other costs of producing, transmitting, and distributing elec-tricity will ultimately be passed through, directly or indi-rectly, to the consumer.

As noted earlier, the committee has been unable to esti-mate future costs to the consumer accurately. The trends and estimated changes should be viewed as approximate. Since this is an important topic of particular importance to the con-sumer, additional investigation is required, including that into the evolving market structure in New York.14 For the Reference Case results with the higher-fuel-price assump-tion (more likely, considering the situation today), NYCA wholesale prices are projected to remain in the range of $57 to $61/MWh between 2008 and 2015.15 Zone J prices are consistently higher, ranging from $73/MWh to $66/MWh. If Indian Point is retired, MAPS calculates that wholesale prices by 2015 would be about $66/MWh in the NYCA and

$79/MWh in New York City.

For the lower fuel prices (lower by 33 percent in 2008 and by 40 percent in 2015), the yearly average wholesale price of electricity in all of the NYCA for 2008 is projected at about $46/MWh for the Benchmark 2008 NYISO Ther-mal Limits case. As in the present market, there is a strong difference among zones, as the data in Appendix F-2 show in detail. The wholesale price is in the range $51/MWh to

$53/MWh in Zones I, J, and K, but reaches $61/MWh in Zone H.

Some general observations include these:

Adding substantial efficient capacity based on low-cost gas tends to lower wholesale prices in meeting load growth TABLE 5-8 MAPS-Projected Impact on Electricity Wholesale Price 2008 2010 2013 2015 Case Area

($/MWh)

HIGHER FUEL PRICES SENSITIVITY CASES Benchmark of 2008 NYISO Thermal Case, Lower fuel cost 46.28 Reference Case in Year Noted NYCA 61 58 57 59 Zone J 73 69 66 67 Early Shutdown with Compensation, Case b2 NYCA 63 62 60 66 Zone J 77 75 71 79 End-of-License Shutdown with Compensation, Case c2 NYCA 60 53 58 66 Zone J 72 60 68 79 REFERENCE CASE NATURAL GAS PRICES Benchmark of 2008 NYISO Thermal Limits Case NYCA 46.28 Zone J 56 Reference Case in Year Noted NYCA 44 42 37 39 Zone J 51 49 42 43 Early Shutdown, Case b2 NYCA 45 44 40 43 Zone J 54 53 47 51 End-of-License Shutdown, Case c2 NYCA 43 38 38 43 Zone J 51 43 44 51 Shutdown with HVDC Line, Cases b3 and c3 NYCA 41 Zone J 47 Shutdown with High EE/DSM, Cases b4 and c4 NYCA 43 Zone J 49 SOURCE: Derived from Hinkle et al. (2005).

14Indian Point Unit 2 was out of service for some time in 2000 as the new market was emerging and before later measures were introduced to mitigate wholesale price spikes. The NYISO Market Advisor, David Patton, ana-lyzed the impact on wholesale prices due to the outage (Patton, 2001). Dur-ing off-peak months the estimated impact on statewide wholesale prices of loss of that one unit varied from 3 to 13 percent. For summer months in the eastern part of the state, the estimated impact was as much as 30 percent.

Though the market structure has changed somewhat, the impact of loss of two units could be substantial. Care should also be taken to distinguish between wholesale prices and cost to the consumer, which also includes cost of delivery to the consumer. The Westchester Public Issues Institute (2002), citing an NYPSC study, estimated that a 20 percent increase in wholesale price of electricity would translate to about a 9 percent increase in cost to the consumer.

15Wholesale prices are generally quoted in dollars per megawatt-hour ($/

MWh). To convert to cents per kilowatt-hour (¢/kWh) divide by 10. Thus,

$57/MWh is 5.7¢/kWh. Recall that these are wholesale prices. Retail prices are higher.

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ANALYSIS OF OPTIONS FOR MEETING ELECTRICAL DEMAND 71 and scheduled retirements in both the NYCA and Zone J (which always has substantially higher prices than the NYCA). One should also recall that the unoptimized cases with compensation added more low-cost generation than needed (or is likely to be built) in the early years. Such over-compensation leads to predictions of lower wholesale prices than would result from a more realistic level of construction that just maintained reliability at a LOLE of 0.1.

The early-shutdown scenario gives up a bit of that re-duction, but not much until 2010 when Indian Point Unit 2 would be shut down.

The HVDC case suggests the potential cost benefit of needing 800 MW less of new downstate capacity, by bring-ing south lower-cost electricity from upstate (assumed, ar-guably, to exist without new capacity upstate). It also should be noted that this case is not directly comparable to other cases, as the cost of the HVDC line would have to be passed through to the consumer in some manner, but not via the wholesale price market. The inference might still be that if no new generation is needed upstate specifically to supply the HVDC line, a lower wholesale price might well prevail downstate, but considerable analysis would be required to verify that.

The impact of high EE/DSM penetration has only a 2 percentage point impact on wholesale price by 2015 relative to the cases with assumed EE/DSM penetration of 875 MW.

This seems to be counterintuitive, and further evaluation is warranted, as this also relates to the overall incentive to in-vest in EE/DSM measures. In any event, it is also important to note that the ultimate cost to the consumer may be lower with EE/DSM measures, as consumers use less electricity.

An estimate of the net change in the wholesale price solely due to shutting down Indian Point, after compensating for load growth and scheduled retirements, can be obtained from GEs calculations by subtracting from the Reference Case the wholesale price estimates for the various scenarios con-sidered. For example, by 2015 with the higher fuel prices used, the increase in wholesale price might increase $7/MWh for all of the NYCA and increase $13/MWh in New York City. For the lower-fuel-cost cases, the impact for the NYCA might be $2 to $4/MWh, and double that for New York City.

However, the committee urges great caution in interpreting these numbers, since (1) the difference between two uncer-tain numbers is doubly uncertain; (2) it unrealistically takes shutting down Indian Point out of the context of the overall reliability situation facing New York today; (3) it allows the inference that shutting down Indian Points 2 GW at EOL would also be compensated for by adding additional low-cost, gas-based generation; and (4) as noted earlier, the com-mittee has low confidence in the MAPS-projected wholesale prices (based on the current locational-based marginal pric-ing wholesale market), which are believed to be too low.

Impact on the Annual Variable Cost of Producing Electricity The systemwide AVOC that MAPS minimizes depends principally on the annual generation in the systemwide re-gion under consideration and the prices of fuel there.16 Table 5-9 gives part of the output results, providing a picture of the impacts on the AVOC for the NYCA and New York City (Zone J) in 2008 and 2015 and the sensitivity to fuel prices for the limited cases run. Values listed are the percent-age changes from the Benchmark.

The data for the Reference Case in 2008 using the lower fuel prices show that AVOC initially decreases slightly, be-cause fuel prices are low and low-cost generation is being added based on high-efficiency, natural-gas-fired units. But early shutdown of Indian Point changes this result because additional gas-based generation is added, and it has a higher variable operating cost than Indian Point, the lowest-vari-able-cost producer in the generating fleetaside from hy-dropower. By 2015 the impact on AVOC is 21 percent higher for the NYCA and 40 percent higher for New York City.

Generators of electricity there have substantially higher vari-able costs to cover.

The data in Table 5-9 show large impacts on AVOCs, especially in Zone J. The key points to note include these:

1. The impact of higher fuel prices is large for the entire NYCA, and especially for Zone J, with percentage increases over the Benchmark ranging from 27 to 70 percent for 2008 and from 44 to 117 percent for 2015, with the higher per-centages applying to New York City. (Note that the higher-fuel-price assumptions correspond to a 50 percent increase of the 2008 price of natural gas.)

2. The AVOC in Zone J increases by 17 to 40 percent from 2008 to 2015, both relative to the Benchmark, for the Early Shutdown with Compensation scenario, because of the added capacity in Zone J.

3. Delaying the shutdown of Indian Point units until EOL shows a net early reduction in Zone J (up until 2015) be-cause additions to capacity come later, and in the early years the impact of the use of more efficient units dominates total additions to capacity.

4. Addition of the HVDC line into Rock Tavern (Zone G) reduces the change in Zone J, as expected, as does greater penetration of EE/DSM measures. For Zone J in 2015, the combined net impact on AVOC is reduced to the range of an 8 to 14 percent increase over the Benchmark. The impact of this magnitude warrants further detailed study.

Appendix F-2 elaborates on the differing impact on AVOC in the various pricing zones, with large percentage changes 16As noted earlier, current variability in fuel prices, with bias toward higher prices than modeled, indicates that the AVOC values from the MAPS modeling are likely to be highly uncertain.

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72 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER in some instances, as MAPS adjusts the electricity dispatch of various generating units to find the minimum systemwide cost. Changes of this magnitude may influence different gen-erators of electricity substantially and could present operat-ing and risk-management challenges, such as reliable access to fuels, and substantial shifts as new low-cost capacity is added.

Detailed results summarized in Appendix F-2 suggest an increase in AVOCs of about 10 percent for the entire North-east region from 2008 to 2015. But this raises another cau-tion to consider regarding the initial MAPS runs presented here and the complexity of the economic factors. The MAPS results suggest a significant, perhaps controversial, impact on regional AVOC beyond meeting load growth and com-pensatory actions from shutting down Indian Point. This in-ference might, however, only be an artifact of the calcula-tions because of the assumptions used in the MAPS studies.

Substantial gas-fired combined-cycle capacity with high ef-ficiency is added to the NYCA over the period in question.

This new capacity could be expected to displace more-ex-pensive generation there, even older gas-fired units having lower efficiency (after compensating for the shutdown of Indian Point). However, as just one example of complexity, no comparable assumption of adding more modern gas-fired combined-cycle capacity for the New England region went into the initial MAPS model run by GE. This approach dis-torts the likely pattern of new generating sources that would emerge.

Sensitivity to Higher Fuel Prices For the fuel-price sensitivity cases, the price assumptions used in MAPS differ in the following ways. For the assumed lower fuel prices, the natural gas price is 5 to 7 percent higher in PJM and New England than in NYISO; coal is 16 to 28 percent higher in New England than in either NYISO or PJM; residual oil and distillate have the same price in all three regions.17 For the higher-fuel-price assumptions, fuel prices are the same in all regions, except that gas is 2 percent higher and coal is 16 to 23 percent higher in New England. In addi-tion, the changes from the lower fuel prices to the higher fuel prices assume that the NYISO gas price is 50 percent higher in 2008 and 66 percent higher in 2015. The coal price is the same as in the lower set of prices; the price of residual oil rises 50 percent and 63 percent in 2008 and 2015, respec-tively; and the distillate fuel price goes up 38 percent and 35 percent in 2008 and 2015, respectively.

Since MAPS estimates the minimum systemwide AVOCs, these assumptions, in moving from the lower prices to the higher fuel prices, will tend to (1) slightly favor gas-based generation in NYISO over that in either New England or PJM, (2) favor coal-based generation in NYISO over coal-17Base case data set, Quarter 1, 2005, published by Platts, a Division of McGraw-Hill Companies. See http://www.platts.com/Analytic%20 Solutions/BaseCase/index.xml. Accessed March 2006.

TABLE 5-9 Projected Impact on Annual Variable Operating Cost Reference Fuel Prices Higher Fuel Prices 2008 NYCA Gas at 2015 NYCA Gas at 2008 NYCA Gas at 2015 NYCA Gas at

$5.11/MMBtu

$4.24/MMBtu

$7.69/MMBtu

$7.03/MMBtu NYCA Zone J NYCA Zone J NYCA Zone J NYCA Zone J Case

(%)

Reference case

-1

-2 5

-8 29 42 48 44 Early shutdown, Case b2 6

17 21 40 40 70 77 117 EOL shutdown, Case c2

-2

-3 21 40 27 40 77 117 Early shutdown, including

12 8

N-S HVDC line in 2012, Case b3 EOL shutdown, including

12 8

N-S HVDC line in 2012, Case c3 Early shutdown, including

13 14

high EE/DSM measures by 2015, Case b4 EOL shutdown, including

13 14

high EE/DSM measures by 2015, Case c4 SOURCE: Derived from Hinkle et al. (2005).

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ANALYSIS OF OPTIONS FOR MEETING ELECTRICAL DEMAND 73 based generation in New England, (3) favor coal-based gen-eration slightly more in the high-fuel cases, (4) be neutral regarding gas-based generation relative to residual oil-based generation, or (5) favor distillate-based generation, rela-tively, except that distillate fuel is always 58 to 65 percent more costly than natural gas, so distillate-based generation penetrates only slightly in the MAPS analyses.

In evaluating the results of the MAPS analyses, it should be remembered that trends and percentage changes (rather that the absolute values of the calculated wholesale price of electricity) are mainly of interest.

COMPARING THE RESULTS WITH CRITERIA Chapter 1 listed six criteria adopted by the committee.

This section compares the results of the committees sce-nario analysis with those criteria.

1. Would the combination of demand and supply options provide adequate energy to replace that provided by Indian Point?

A portfolio of additional supply and demand-reduction options can be identified to replace Indian Point, but they must be added to the capacity required to meet load growth and to offset generating plant retirements. The committee estimates that even if Indian Point is not retired, New York State will need about 1.2 to 1.7 GW in 2010, and 2.2 to 3.3 GW in 2015, from projects that are not already under con-struction. The additional 2 GW required if Indian Point were to be closed could be met by some suitable combination of new generation in the New York City area, efficiency im-provements and demand-side management, and new trans-mission capability from upstate.

Most of the approximately 5 GW that would be needed by 2015 probably would come from new generating capac-ity relying at least initially on natural gas as a fuel. Energy efficiency and demand-side management have great poten-tial, and could replace at least 800 MW of the energy pro-duced by Indian Point and possibly much more. The new north-south transmission line analyzed by the committee also could reduce the additional generating capacity needed downstate by about 800 MW. The committee notes that criti-cally required corrections to reactive power would have to be made locally in a timely manner, since losing the reactive power from Indian Point would only compound the projected deficiency in the Lower Hudson Valley identified by NYISO.

2. Would the generation and transmission system be ad-equate to deliver the energy reliably to end users?

Identifying the generation and transmission system capa-bility that must be provided to replace Indian Point is much easier than determining whether it actually would get built when needed. All these measures will take time to imple-ment, and several factors may converge to make it even more difficult. As discussed in Chapter 4, the committee questions whether the present market mechanisms are adequate to at-tract the capital investment required for the roughly 5 GW of new capacity and transmission corrections that would be needed by 2015. In addition, the lack of a state program, such as the former Article X, to expedite siting and licensing is likely to discourage new projects. A concerted, well-man-aged, and coordinated effort would be required to replace Indian Point by 2015. Replacement in the 2008-2010 time frame would be considerably more difficult, probably re-quiring extraordinary, emergency-like measures to achieve.

3. How would the new combination of demand and sup-ply options compare with Indian Point in terms of security of fuel supply for new generation?

While the details of security comparisons are beyond the scope of this study (and would depend on the exact set of options selected), it is possible that the NYCA would be vul-nerable to potential natural gas shortages. Adding several gigawatts of electrical capacity (including projects currently under construction) based mainly on natural gas supply would increase NYCA reliance on gas-based generation from 20 percent in 2003 to over 50 percent by 2015. The present gas supply and transmission capacity is inadequate to meet such future demand. In-so-far as additional gas is supplied by imported LNG, another energy security issue is introduced. Adding electrical capacity upstate based on other fuels will require additional electrical transmission capacity to serve downstate load centers, and transmission systems are inherently vulnerable to some extent. On the other hand, distributed generation has some security advantages over large generating stations. Continued vigilance at the Indian Point site for stored spent nuclear fuel will be necessary whether or not the plant is closed.

4. How would economic costs, especially to the con-sumer, compare with those for continued operation of In-dian Point?

The Indian Point power plant produces baseload electric-ity as a low-cost wholesale provider in southern New York State. While the present regulated competition wholesale market depends on many factors, the projected wholesale cost without the Indian Point units, based on analysis of vari-able operating costs only, will tend to rise. The strongest influence on wholesale costs is fuel costs. The current vola-tility of natural gas prices and the structure of the wholesale market make it difficult and uncertain to project costs in 2015. In any event, it is unlikely that replacing the low-cost producer would do anything other than raise the ultimate cost of electricity to consumers.

Investors must be attracted back to the NYCA for new projects, but providing for adequate return on new capital investment will tend to increase projected wholesale prices.

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74 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER ment in new gas transmission infrastructure, and require ex-penditure for emissions permits.

5. How would environmental emissions and other im-pacts compare with those for continued operation of In-dian Point?

Since the air emissions of New York power plants cur-rently involve emission caps already in place, new sources would have to purchase emission rights. Thus, most pollut-ants would be little changed. The main change expected would be an increase in carbon dioxide (CO2, the most im-portant greenhouse gas) from substituting fossil fuel for nuclear fuel. If the regional plans for reducing or capping CO2 emissions are implemented, local CO2 increases will likely be offset with an emissions credit market. Water qual-ity would be improved by retiring Indian Point, but much the same advantage could be achieved if the plant switched to cooling towers from the current once-through cooling.

6. What would be the impacts on local communities from closing Indian Point and replacing it with these options?

Community impacts would be mixed, depending on the choice of replacements and their locations. There would likely be potentially significant disruption in the tax base and supporting business income to Westchester and sur-rounding counties. A loss of employment of skilled workers would be associated with the plants retirement. The costs of electricity are likely to rise with changes in the electrical system infrastructure in southern New York State. Projec-tions of all of these impacts are difficult to estimate without additional information. While the committee has not studied these factors, some benefits may occur. For example, upstate communities might benefit if replacement power plants are built there. The Indian Point site could also be used for new industrial facilities that could replace the jobs and tax ben-efits of the nuclear station.

REFERENCES Hinkle, G., G. Jordan, and M. Sanford. 2005. An Assessment of Alterna-tives to Indian Point for Meeting Energy Needs. Unpublished report for the National Research Council. GE-Energy, Schenectady, N.Y., De-cember 19.

NYISO (New York Independent System Operator). 2005a. Comprehensive Reliability Planning Process (CRPP) Reliability Needs Assessment (RNA). December 21.

. 2005b. Comprehensive Reliability Planning Process Supporting Document and Appendices for the Draft Reliability Needs Assessment, NYISO, Albany, N.Y., December 21. See http://

www.nyiso.org/public/webdocs/newsroom/press_releases/2005/

crrp_supporting_rna_doc12202005.pdf. Accessed December 2005.

. 2005c. Michael Calimano, solicitation letter to S.V. Lunt, R.M. Kessel, E.R. McGrath, and J. McMahon, December 22. See http://www.

nyiso.org/public/webdocs/newsroom/press_releases/2005/rna

_solution_letter.pdf. Accessed January 2006.

ONeill, Richard. 2004. Reactive Power: Is It Real? Is It in the Ether?

Harvard Electric Policy Group, Austin, Tex. December 2.

Patton, David B. 2001. New York Market Advisor Annual Report on the New York Electric Markets for Calendar Year 2000. April.

Westchester Public Issues Institute. 2002. Closing Indian PointImplica-tions for NYC Metro Energy Supply. June.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

75 Appendixes The appendixes provide information on this project and additional details and background information for the mate-rial in the report.

Appendix A, Committee Biographical Information, includes brief biographies of all the committee members.

Appendix B, Presentations and Committee Meetings, lists all the meetings that the committee held and the pre-senters who supplied information at the public meetings.

Appendix C, Acronyms, identifies the acronyms in the report.

Appendix D, Supply Technologies, provides addi-tional details and background information on the generating and transmission options discussed in Chapter 3.

Appendix E, Paying for Reliability in Deregulated Markets, provides the information from which the first sec-tion of Chapter 4, Regulation, Finance, and Reliability, was extracted.

Appendix F, Background for the System Reliability and Cost Analysis, describes the process by which the New York Independent System Operator ensures reliability and the details of the committees analysis of future scenarios, as discussed in Chapter 5.

Appendix G, Demand-Side Measures, documents the energy-efficiency and demand-reduction technologies dis-cussed in Chapter 2.

Appendixes D, E, F, and G were prepared by individual committee members or subgroups. They are reproduced on the CD-ROM that contains the full report but are not included in the printed report owing to space limitations.

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A Committee Biographical Information 77 Lawrence T. Papay (NAE), Chair, is currently a consultant with a variety of clients in electric power and other energy areas. Previously he held positions including senior vice president for the Integrated Solutions Sector, Science Appli-cations International Corporation, and senior vice president and general manager of Bechtel Technology and Consult-ing. He also held several positions at Southern California Edison, including senior vice president, vice president, gen-eral superintendent, and director of research and develop-ment (R&D), with responsibilities for areas including bulk power generation, system planning, nuclear power, environ-mental operations, and development of the organization and plans for the companys R&D efforts. Dr. Papays profes-sional affiliations have included the Electric Power Research Institute (EPRI) Research Advisory Committee, the Atomic Industrial Forum, the U.S. Department of Energys Energy Research Advisory Board, and the Renewable Energy Insti-tute. He is a member of the National Academy of Engineer-ing and the National Science Foundations Industrial Panel on Science and Technology. His expertise and knowledge range across a wide variety of electric system technologies, from production, to transmission and distribution, utility management and systems, and end-use technologies. He re-ceived a B.S. degree in physics from Fordham University, and S.M. and Sc.D. degrees in nuclear engineering from the Massachusetts Institute of Technology (MIT).

Dan E. Arvizu is the director and chief executive of the National Renewable Energy Laboratory. He was formerly a senior vice president and chief technology officer for the Federal and Industrial Client Groups of CH2M Hill Compa-nies, Ltd., and before that, a vice president and director of the Energy and Industrial Systems Business Group. Prior to working at CH2M Hill, Dr. Arvizu worked at Sandia Na-tional Laboratoriesas director, Materials and Process Sci-ences Center; director, Advanced Energy Technology and Policy Center; and director, Technology Transfer Center. Dr.

Arvizu was also a member of the technical staff, Customer Switching Systems, Bell Telephone Laboratories. He has experience as an executive in managing a business profit and loss, and in corporate technology commercialization as well as extensive experience in materials science applications for nuclear weapons and energy systems, and in the develop-ment of renewable energy systems, including solar thermal, photovoltaic, and concentrating solar collectors. He has been recognized for excellence in the management of technology transfer and renewable energy R&D programs. In 2004, Dr.

Arvizu was appointed by President Bush to serve on the National Science Board. He received the 1996 Hispanic Engineers National Achievement Award for Executive Ex-cellence and has served on a number of advisory groups, including the Commercialization Advisory Board for the Solar II Central Receiver Pilot Plant. He served on the Na-tional Research Council (NRC) Committee on Programmatic Review of the Office of Power Technologies. He received his B.S. degree from New Mexico State University and his M.S. and Ph.D. degrees from Stanford University, all in mechanical engineering.

Jan Beyea is chief scientist, Consulting in the Public Inter-est, and is a consultant to the National Audubon Society. He consults on nuclear physics and other energy/environmental topics for numerous local, national, and international orga-nizations. He has been chief scientist and vice president, National Audubon Society, and has held positions at the Center for Energy and Environmental Studies, Princeton University, Holy Cross College, and Columbia University.

He has served as a member of numerous advisory commit-tees and panels including the National Research Council (NRC) Board on Energy and Environmental Systems; the NRC Energy Engineering Board; the NRC Committee on Alternative Energy R&D Strategies; the NRC Committee to Review DOEs Fine Particulates Research Plan; the Secre-tary of Energys Advisory Board, Task Force on Economic Modeling; and the policy committee of the Recycling Advi-sory Council. Dr. Beyea has been an advisor to various stud-Copyright © National Academy of Sciences. All rights reserved.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

78 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER ies of the U.S. Congress Office of Technology Assessment.

He has expertise in energy technologies and associated envi-ronmental and health concerns and has written numerous articles on the environment and energy. He received a B.A.

from Amherst College and a Ph.D. in physics from Colum-bia University.

Peter Bradford advises and teaches restructuring and en-ergy policy in the United States and abroad. He has been a visiting lecturer in energy policy and environmental protec-tion at Yale University and has taught utility law at the Ver-mont Law School, where he is currently teaching a course on nuclear power and public policy. He is also affiliated with the Regulatory Assistance Project, which provides assistance to state and federal regulatory commissions regarding en-ergy regulatory policy and environmental protection. Mr.

Bradford was a member of the U.S. Nuclear Regulatory Commission (1977-1982). He has served on panels advising the European Bank for Reconstruction and Development on how best to replace the remaining Chernobyl nuclear plants in Ukraine and advising the Austrian Institute for Risk Re-duction on regulatory issues associated with opening the Mochovce Nuclear Plant in Slovakia. He chaired the New York State Public Service Commission and the Maine Pub-lic Utilities Commission, and was also briefly Maines Pub-lic Advocate. Mr. Bradford has written extensively on en-ergy regulatory and energy security issues. He is a graduate of Yale University and the Yale Law School.

Marilyn A. Brown is the interim director of the Engineer-ing Science and Technology Division at the Oak Ridge Na-tional Laboratory (ORNL). During her 22 years at ORNL, Dr. Brown has researched the impacts of policies and pro-grams aimed at advancing the market entry of sustainable energy technologies and has led several energy technology and policy scenario studies. Prior to serving at ORNL, she was a tenured associate professor in the Department of Ge-ography at the University of Illinois, Urbana-Champaign, where she conducted research on the diffusion of energy in-novations. She has authored more than 140 publications and has been an expert witness in hearings before committees of both the U.S. Senate and the House of Representatives. She has received awards for her research from the American Council for an Energy-Efficient Economy, the Association of American Geographers, the Technology Transfer Soci-ety, and the Association of Women in Science. A recent study that she co-led (Scenarios for a Clean Energy Future) was the subject of two Senate hearings, has been cited in proposed federal legislation, and has had a significant role in international climate change debates. Dr. Brown serves on the boards of directors of several energy, engineering, and environmental organizations (including the Alliance to Save Energy and the American Council for an Energy Efficient Economy), and she serves on the editorial board of the Jour-nal of Technology Transfer. She is also a member of the National Commission on Energy Policy. She has a Ph.D. in geography from Ohio State University and a masters degree in resource planning from the University of Massachusetts.

She is also a certified energy manager.

Alexander E. Farrell is assistant professor in the Energy and Resources Group at the University of California, Berke-ley. He is working on characterizing environmental impacts of energy production and transformation, especially air pol-lution and greenhouse gases, and in the economic, political, and other social aspects of energy systems with reduced en-vironmental impacts. Previously, Dr. Farrell had been ad-junct assistant professor in the Department of Engineering and Public Policy at Carnegie Mellon University and execu-tive director of the Carnegie Mellon Electricity Industry Center. He had been a research fellow at the John F. Kennedy School of Government and at the Wharton Risk Manage-ment and Decision Processes Center, University of Pennsyl-vania. He also was an engineer at Air Products and Chemi-cals, Inc., and served as a nuclear submarine officer in the U.S. Navy. He has a B.S. degree in systems engineering from the U.S. Naval Academy and a Ph.D. in energy management and policy from the University of Pennsylvania.

Samuel M. Fleming is currently a consultant. His prior po-sitions include executive assistant to the executive vice president for strategic planning and technology commer-cialization of Bechtel BWXT Idaho, LLC; senior program manager in the Operations Department of Bechtel Technol-ogy and Consulting; commercial development manager and program manager for Bechtel R&Ds Cargoscan' pro-gram; manager of the Advanced Processes Department in Bechtel R&D; project operations manager for renewable energy and fuels technologies in Bechtel R&D; manager, Process Technology Department, Bechtel R&D; manager of advanced technology planning, Fluor Engineers, Inc.; and director of technology, the Badger Company, Inc. Dr.

Flemings expertise spans a wide range in advanced tech-nology and engineering development, economic evaluation of technologies, and project management. He has worked on various types of technology development, including ad-vanced fuel and gas conversion, nuclear, solar, wind, geo-thermal, drilling, biotechnology, cargo detection, supercon-ducting magnetic storage, and gas pipelines. He has a B.S.

(Pennsylvania State University), S.M. (MIT), and Sc.D.

(MIT) in chemical engineering.

George M. Hidy is principal of Envair/Aerochem. He is the retired Alabama Industries Professor of Environmental En-gineering at the University of Alabama, where he was also adjunct professor of environmental health science in the School of Public Health. From 1987 to 1994, he was techni-cal vice president of the Electric Power Research Institute, where he managed the Environmental Division and was a member of the Management Council. From 1984 to 1987, he Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX A 79 was president of the Desert Research Institute of the Univer-sity of Nevada. He has held a variety of other scientific posi-tions in universities and industry and has made significant contributions to research on the environmental impacts of energy use, including work on atmospheric diffusion and mass transfer, aerosol dynamics, and chemistry. He is the author of many articles and books on these and related top-ics. Dr. Hidy received a B.S. in chemistry and chemical en-gineering from Columbia University, an M.S.E. in chemical engineering from Princeton University, and a D.Eng. in chemical engineering from the Johns Hopkins University.

James R. Katzer (NAE) was manager of strategic planning and program analysis for ExxonMobil Research and Engi-neering Company, where he was responsible for primary technology-planning and analysis activities and for future-focused technology-planning activities. Prior to that he was vice president, technology, Mobil Oil Corporation, with pri-mary responsibilities for ensuring Mobils overall technical health, developing forward-looking technology scenarios, identifying and analyzing technology and environmental developments and trends, guiding Mobils long-term direc-tions on the basis of strategic technical drivers, and identify-ing future threats and opportunities and recommending strat-egies to deal with them. Dr. Katzer joined the Central Research Laboratory of the Mobil Oil Corporation in 1981, later becoming manager of process research and technical service and vice president of planning and finance for Mobil Research and Development Corporation. Before joining Mobil he was a professor on the chemical engineering fac-ulty at the University of Delaware and the first director of the Center for Catalytic Science and Technology there. Dr.

Katzer has more than 80 publications in technical journals, holds several patents, and co-authored and edited several books. He received a B.S. degree from Iowa State and a Ph.D. in chemical engineering from MIT.

Parker D. Mathusa is a member of the Board of DirectorsResearch Scientist, New York State Energy Re-search and Development Authority (NYSERDA). Formerly he was program director, Energy Resources, Transportation and Environmental Research Program, NYSERDA, where he was responsible for establishing research programs and policies required to develop new energy technologies and environmental mitigation measures that could contribute to New York States energy supply needs, with a focus on re-newable energy resources, advanced transportation technolo-gies, and environmental products. Dr. Mathusas previous positions include service as chief, Utility Research and De-mand Management, New York State Public Service Com-mission, in which he developed a comprehensive R&D pro-gram for electric and gas utilities, and engineering positions at Yankee Atomic Electric Company and Bechtel Corpora-tion. He has been involved in the evaluation of a number of emerging energy technologies and associated environmental mitigation measures, including fuel cells, hybrid electric ve-hicles, and photovoltaic systems, and has published numer-ous assessments of energy technologies. He has served on numerous advisory panels including federal and state advi-sory groups. He has a B.S. in physics from the State Univer-sity of New York at Albany and an M.S. in engineering man-agement from Northeastern University.

Timothy Mount is professor of applied economics and man-agement at Cornell University. His research and teaching interests include econometric modeling and policy analysis relating to the use of fuels and electricity and to their envi-ronmental consequences (acid rain, smog, and global warm-ing). Professor Mount is currently conducting research on the restructuring of markets for electricity and the implica-tions for (1) price behavior in auctions for electricity, (2) the rates charged to customers, and (3) investment decisions for maintaining system adequacy. He has spent sabbaticals at the University of New South Wales, Australia, and the Lon-don School of Economics and the University of Manchester, United Kingdom. He has a B.S. from Wye College, Univer-sity of London, and a Ph.D. from the University of Califor-nia, Berkeley.

Francis J. Murray, Jr., is an energy and environmental consultant, providing strategic policy and market-develop-ment guidance on energy and environmental issues for pri-vate sector clients. His previous positions include consultant to the Office of Assistant Secretary for Policy and Interna-tional Affairs, U.S. Department of Energy; chairman of NYSERDA, and commissioner of energy in the New York State Energy Office; deputy secretary and assistant secretary to the governor for energy and environment; and senior leg-islative counsel/legislative counsel in the New York State Office of Federal Affairs. His experience includes the devel-opment and implementation of major energy and environ-mental initiatives and programs for New York State, includ-ing the development of a comprehensive, integrated State Energy Plan that integrated state energy, environmental, and economic development policies in the early 1990s, and policy analysis for the federal government on electric reli-ability and appliance efficiency standards. He was an envi-ronmental policy fellow at the Institute of Ecosystems, Millbrook, New York (1999-2000); director, Scenic Hudson, Inc. (1994-2000); director, the Environmentors Project (Washington, D.C., 1994-2000); and founding member of the Hudson River Greenway Communities Council (1992-1996). He has a B.S.F.S. from the Georgetown University School of Foreign Service and a J.D. degree from the Georgetown University Law Center.

D. Louis Peoples is president and founder of Nyack Man-agement Company, a business consulting and turnaround firm. Formerly he was chief executive officer of Orange and Rockland Utilities in New York State. While at Orange and Copyright © National Academy of Sciences. All rights reserved.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

80 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER Rockland, he was a leader in the deregulation of electric power, serving as chairman of the New York Power Pool and of the Transition Steering Committee to form the New York Independent System Operator. Earlier, he was execu-tive vice president of Madison Gas and Electric Company; senior vice president of RCG/Hagler, Bailly, a consulting company; and vice president of Bechtel Management Con-sulting Services. Mr. Peoples has also been corporate con-troller of McGraw Edison Company, director of nuclear li-censing at Commonwealth Edison, and training manager at Vermont Yankee Nuclear Power Corporation. He served in the nuclear submarine service in the U.S. Navy. He received a B.S.M.E. from Stanford University and an M.B.A. from Harvard Business School. He is a certified public accountant and a registered professional engineer.

William F. Quinn is founder and president of Argos Utili-ties LLC. Formerly he was president of Shaw Transmission and Distribution Services, Inc., part of The Shaw Group, where he had responsibility for strategic planning, business development, and the financial viability of the transmission and distribution subsidiaries. Mr. Quinn also sits on the board of directors of Hydro Power Solutions LLC, a joint venture company owned equally by The Shaw Group and Hydro Quebec LTD of Montreal. He also managed The Shaw Groups Structured Transaction Group, where his duties in-cluded managing mergers and acquisitions teams, oversee-ing project development activities, and evaluating invest-ment options. Prior to joining The Shaw Group, Mr. Quinn was responsible for management of the Pacific Gas and Elec-tric (PG&E) National Energy Groups power-asset-develop-ment business in North America. Among other projects there, Mr. Quinn directed the 1,200 MW Athens Generating Project, New Yorks first merchant generating facility and one of the largest gas-fired power plants in the United States.

Prior to joining PG&E, he incorporated Meridian Power Corporation, where he was responsible for the marketing, development, financing, and construction of power-generat-ing projects. While at Energy Management, Inc., Mr. Quinn developed several biomass and gas-fired cogeneration projects. He also was project engineer for Badger America, Inc. He has a B.S. in mechanical engineering from the Uni-versity of Massachusetts and did graduate studies in busi-ness administration at Harvard University. He is a registered professional engineer.

Dan W. Reicher is president, New Energy Capital Corpora-tion. He served recently as executive vice president of North-ern Power Systems, the nations oldest renewable energy company. From 1997 to 2001, Mr. Reicher was Assistant Secretary of Energy for Energy Efficiency and Renewable Energy at the U.S. Department of Energy (DOE). As Assis-tant Secretary, he directed annually more than $1 billion in investments in renewable energy, distributed generation, and energy-efficiency research, development, and deployment.

Prior to that position, Mr. Reicher held other senior manage-ment posts in DOE and was also a senior attorney at the Natural Resources Defense Council. He was also co-chair of the U.S. Biomass Research and Development Board, a mem-ber of the U.S. delegation to the Climate Change Negotia-tions, and a member of the board of the government-industry Partnership for a New Generation of Vehicles. Mr. Reicher is also currently co-chair of the advisory board of the Ameri-can Council on Renewable Energy and a member of the boards of Burrill and Companys Biomaterials and Bio-processing Venture Fund, the American Council for an En-ergy Efficient Economy, and the Keystone Centers Energy Program. He has more than 20 years of experience in energy technology, policy, and finance. He holds a B.A. from Dartmouth College and a J.D. from Stanford Law School.

James S. Thorp (NAE) is the Hugh P. and Ethel C. Kelly Professor of Electrical and Computer Engineering and head of the Department of Electrical and Computer Engineering at Virginia Polytechnic Institute and State University. Previ-ously he had been the Charles N. Mellowes Professor in Engineering at Cornell University and director of the Cornell School of Electrical and Computer Engineering. He had also been a faculty intern at the American Electric Power Service Corporation; an Overseas Fellow, Churchill College, Cam-bridge University; and an Alfred P. Sloan Foundation Na-tional Scholar. Dr. Thorp is a fellow of the Institute of Elec-trical and Electronics Engineers (IEEE) and the editor of the IEEE Transactions on Power Delivery for protection sys-tems. Dr. Thorp received the 2001 Power Engineering Soci-ety Career Service award. He was a member of the Interna-tional Advisory Board of the Department of Electrical and Electronic Engineering, Hong Kong University, and a mem-ber of the Iowa State Electrical and Computer Engineering External Advisory Board. He has written more than 100 jour-nal articles and many book chapters. He obtained a B.E.E.

and Ph.D. from Cornell University.

John A. Tillinghast (NAE) is president of Tillinghast Tech-nology Interests, Inc. Early in his career from 1949 to 1979, he held a number of positions at American Electric Power (AEP) Service Corporation, including executive vice presi-dent, engineering and construction, and vice chairman of the board in charge of engineering and construction. Positions that he held subsequent to his employment at AEP include senior vice president and senior technical officer overseeing research and development of Technology Wheelabrator-Frye, Inc.; senior vice president, technology, Signal Ad-vanced Technology Group, The Signal Companies, Inc; and senior vice president, Science Applications International Corporation. His experience and knowledge span a variety of areas, including steam turbines; nuclear energy systems; magnetohydrodynamic power plants; fossil energy power plants; transmission and distribution (T&D) systems; engi-neering, construction, and operation of electric power pro-Copyright © National Academy of Sciences. All rights reserved.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

APPENDIX A 81 duction and T&D facilities; restructuring of the utility indus-try; alternative energy projects; cogeneration including small gas turbines; geothermal plants; life extension of utility fa-cilities; and power marketing. He has served on a number of National Research Council units, including as chairman of the Energy Engineering Board and as a member of the Com-mission on Engineering and Technical Systems. He is a fel-low of the American Society of Mechanical Engineers. He has a B.S. and M.S. in mechanical engineering from Colum-bia University.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

82 B

Presentations and Committee Meetings

1. COMMITTEE MEETING, THE NATIONAL ACADEMIES, WASHINGTON, D.C.

JANUARY 18-19, 2005 Congressional Expectations for the Study Beth Tritter, Office of Congresswoman Nita M. Lowey, Representative from New Yorks 18th District Department of Energy Perspectives: Indian Point Energy Alternatives Study Philip Overholt, U.S. Department of Energy Transmission Considerations for the Replacement of Indian Point Generation with Alternate Sources John Kucek, Oak Ridge National Laboratory Energy Efficiency and Renewable EnergyResource Potential in New York State: Summary of Potential Analy-sis Prepared for the New York State Energy Research and Development Authority (NYSERDA)

Lawrence Pakenas, NYSERDA, and John Plunkett, Opti-mal Energy, Inc.

Indian Point: What Could Wind Contribute?

Randall Swisher, American Wind Energy Association Natural Gas Use in Eastern New York: Can the Indian Point Nuclear Facility Be Replaced by Gas-Fired Power Generation?

Harry Vidas, Energy and Environmental Analysis, Inc.

2. COMMITTEE MEETING, CROWNE PLAZA HOTEL, WHITE PLAINS, NEW YORK MARCH 14-16, 2005 Northeast Power Coordinating Council (NPCC) Reliability Criteria, Guides, and Procedures Philip Fedora, Northeast Power Coordinating Council New York Power Generation Development Overview Bill Quinn, Argos Utilities, LLC ICF Power Market Analysis Capabilities Juanita Haydel, ICF Consulting Entergys Views Michael R. Kansler, Entergy Nuclear Northeast Building Transmission Lines Steve Mitnick, Conjunction LLC New York State Department of Public Service Howard Tarler, New York State Department of Public Service Westchester County Government Views The Honorable Andrew J. Spano, Office of the Westchester County Executive Westchester County Legislature Views The Honorable Michael B. Kaplowitz, Westchester County Board of Legislators Alternatives to Indian Point Bruce Biewald, Synapse Energy Economics, Inc; Alex Matthiessen, Riverkeeper; and Fred Zalcman, Pace Law School Energy Project New York Independent System Operator Views Garry Brown, New York Independent System Operator (NYISO)

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APPENDIX B 83

3. COMMITTEE MEETING, THE NATIONAL ACADEMIES, WASHINGTON, D.C.

MAY 31-JUNE 1, 2005 Integrated Gasification Combined Cycle (IGCC)

N.Z. Shilling, GE New York State Public Benefits Energy Efficiency Pro-grams Paul A. DeCotis, New York State Energy Research and Development Authority

4. SITE VISIT, SCHENECTADY, NEW YORK JULY 25-26, 2005

5. CLOSED COMMITTEE MEETING, THE NATIONAL ACADEMIES OCTOBER 17-18, 2005

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

84 C

Acronyms AC alternating current AMP Automatic Mitigation Procedures AVOC annual variable operating cost BWR boiling water reactor C&D constructing and demolition CAA Clean Air Act CAIR Clean Air Interstate Rule CAMR Clean Air Mercury Rule CC combined cycle CDW construction and demolition waste CHP combined heat and power CIPP Commercial and Industrial Performance Program CO carbon monoxide CO2 carbon dioxide ConEd Consolidated Edison CPU central processing unit CRPP Comprehensive Reliability Planning Process CSP curtailment service provider CT combustion turbine DC direct current DER distributed energy resource DG distributed generation DOE Department of Energy DR demand response DSM demand-side management EE energy efficiency EESP energy efficiency service provider EIA Energy Information Administration EOL end of license EPA Environmental Protection Agency ERO Electric Reliability Organization ESP electrostatic precipitator/precipitation ETP Enabling Technologies Program FERC Federal Energy Regulatory Commission FF fabric filter FGD flue-gas desulfurization FO2 No. 2 (distillate oil)

FO6 No. 6 (residual oil)

GAP Gap Analysis Program (U.S. Geological Survey)

GE General Electric International GHG greenhouse gas Hg mercury HHV higher heating value HVAC high-voltage alternating current; or heating, ventilating, air conditioning (Chapter 2 only)

HVDC high-voltage direct current IC internal combustion ICAP installed capacity ICR installed capacity requirement IGCC integrated gasification combined cycle IOU investor owned utility IP2 Indian Point Unit 2 IP3 Indian Point Unit 3 IPP independent power producer IRM installed reserve margin ISO-NE independent system operator-New England LBMP locational-based marginal pricing LBNL Lawrence Berkeley National Laboratory LCOE levelized cost of energy LED light-emitting diode LHV Lower Hudson Valley LI Long Island LICAP locational installed capacity LIPA Long Island Power Authority LNG liquefied natural gas Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX C 85 LOLE loss-of-load expectation LSE load serving entity MAAC Mid-Atlantic Area Council (reliability council)

MAPS Multi-Area Production Simulation MARS Multi-Area Reliability Simulation MDEA methyl diethanol amine MIT Massachusetts Institute of Technology MSW municipal solid waste NAAQS National Ambient Air Quality Standards NE New England NERC North American Electric Reliability Council NG natural gas NGCC natural gas combined cycle NOx nitrogen oxide NPCC Northeast Power Coordinating Council NRC National Research Council NREL National Renewable Energy Laboratory N-S north-south NYC New York City NYCA New York Control Area NYDEC New York Department of Environmental Conservation NYISO New York Independent System Operator NYMex New York Mercantile Exchange NYPA New York Power Authority NYPSC New York Public Service Commission NYSERDA New York State Energy Research and Development Authority NYSRC New York State Reliability Council O3 ozone O&M operation and maintenance PC pulverized coal PJM Pennsylvania Jersey Maryland (regional transmission organization)

PLRP Peak Load Reduction Program PM particulate matter PPA Power Purchase Agreement PSEG Public Service Electric and Gas PUC public utility commission PV photovoltaic, photovoltaics PWR pressurized water reactor REAP Residential Energy Affordability Program REPIS Renewable Plant Information System RGGI Regional Greenhouse Gas Initiative RMR Reliability-Must-Run RNA Reliability Needs Assessment ROS rest of state RPS Renewable Portfolio Standard SBC Systems Benefit Charge SCPC supercritical pulverized coal SCR Special Case Resource; selective catalytic reduction SHW solar hot water SO2 sulfur dioxide SOx sulfur oxide SPDES State Pollutant Discharge Elimination System SVC static VAR compensator TO transmission owner UCAP unforced capacity UDR Unforced Delivery Rights (transmission capacity)

UPNY-SENY Upstate New York-Southeast New York (transmission interface)

U.S. NRC U.S. Nuclear Regulatory Commission VOC volatile organic compound; variable operating cost VOLL value of lost load WESP wet electrostatic precipitator/precipitation Copyright © National Academy of Sciences. All rights reserved.

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86 D

Supply Technologies This appendix provides additional details and background information related to the 18 potential alternative supply technologies, examined in Chapter 3, Generation and Trans-mission Options. Appendix D contains the following:

Appendix D-1, Cost Estimates for Electric Generation TechnologiesTable D-1-1 summarizes estimated total costs and the later tables detail the key cost elements for each of the technologies examined by the committee.

Appendix D-2, Zonal Energy and Seasonal Capacity in New York State, 2004 and 2005Table D-2-1 provides a summary, and the remaining tables present data for sum-mer and winter capacity (MW) and energy production (GWh) by fuel and provide other data on the New York Con-trol Area (NYCA).

Appendix D-3, Energy Generated in 2003 from Natu-ral Gas Units in Zones H Through KThis appendix con-tains tabular data on power generation from natural gas in the New York City area in 2003 and 2004, indicating the oil products used in the overall production of electricity from gas turbines in the New York City area.

Appendix D-4, Proposed Pipeline Projects in the Northeast of the United StatesA map of the northeastern states shows proposed natural gas pipelines.

Appendix D-5, Coal TechnologiesCommittee member James R. Katzer presents a discussion of the coal-based technologies that the committee considered and evalu-ated with respect to operating costs, including the technol-ogy (integrated gasification, combined cycle [IGCC]) that will be most appropriate for the capture of carbon dioxide.

The appendix explores the issue of emissions control for coal plants.

Appendix D-6, Generation TechnologiesWind and BiomassDan Arvizu of the Department of Energys Na-tional Renewable Energy Laboratory (NREL) summarizes an analysis performed by NREL to evaluate the potential of wind energy and biomass resources as sources of electricity for the New York City region. Issues associated with the expanding use of wind in New York State are discussed.

Appendix D-7, Distributed Photovoltaics to Offset De-mand for ElectricityDan Arvizu summarizes an NREL analysis that evaluated the potential of distributed photovol-taics (PV) for the New York City region. Also included are a summary of New York States current policies related to PV technology and an accelerated PV-deployment scenario for New York State through 2020.

References Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX D 87 APPENDIX D-1 COST ESTIMATES FOR ELECTRIC GENERATION TECHNOLOGIES Parker Mathusa and Erin Hogan1 1Parker Mathusa is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs. Erin Hogan is with the New York State Energy Research and Development Authority.

TABLE D-1-1 Summary Cost Estimates: Total Cost of Electricity (in 2003 U.S. dollars per kilowatt-hour) for Generating Technologies Examined by the Committee Costs Estimated by:

University Technology EIAa of Chicagob MITc Municipal solid waste landfill gas 0.0352 Scrubbed coal, new (pulverized) 0.0382 0.0357 0.0447 Fluidized-bed coal 0.0358 Pulverized coal, supercritical 0.0376 Integrated coal gasification combined cycle (IGCC) 0.0400 0.0346 Advanced nuclear 0.0422 0.0433 0.0711 Advanced gas combined cycle 0.0412 0.0354 0.0416 Conventional gas combined cycle 0.0435 Wind 100 MW 0.0566 Advanced combustion turbine 0.0532 IGCC with carbon sequestration 0.0595 Wind 50 MW 0.0598 Conventional combustion turbine 0.0582 Advanced combined cycle with carbon sequestration 0.0641 Biomass 0.0721 Distributed generation, base 0.0501 Distributed generation, peak 0.0452 Wind 10 MW 0.0991 Photovoltaic 0.2545 Solar thermal 0.3028 NOTE: EIA: Energy Information Administration; MIT: Massachusetts Institute of Technology.

Data exclude regional multipliers for capital, variable operation and maintenance (O&M), and fixed O&M. New York costs would be higher. Data exclude delivery costs. Data reflect fuel prices that are New York State-specific; see Table D-1-7. Costs reflect units of different sizes; while some technolo-gies have lower costs than others, the total capacity of the lower-cost generation technology may be limitedfor example, a 500-MW municipal solid waste landfill gas project is unlikely. MIT calcula-tions assumed a 10-year term; consequently, estimated costs are higher.

aFor EIA data, see Table D-1-3 in this appendix, column Total Cost of Energy ($/kWh). Annual Energy Outlook 2005, Basis of Assumptions, Table 38. The 0.6 rule was applied to the wind 10 MW and 100 MW units using 50 MW as the base reference. Solar thermal costs exclude the 10 percent investment tax credit.

bFor University of Chicago data, see Tables D-1-5 and D-1-6 in this appendix.

cFor MIT data, see Table D-1-2 in this appendix.

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88 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER TABLE D-1-2 Cost Components for Electricity Generation Technologies Capital Costs O&M Costs Fuel Costs Cost of Electricity Without Source

($/kWh)

Regional Multipliers ($/kWh)

Natural Gas Combined Cycle Chicago Report

$0.0088

$0.0030

$0.0236

$0.0354 MIT (moderate gas $)

NR NR NR

$0.0416 EIA (Advance CC)

$0.0083

$0.0031

$0.0298

$0.0412 Natural Gas Aeroderivative Turbine Chicago Report/MIT NR NR NR NR EIA (Advanced CT)

$0.0056

$0.0040

$0.0406

$0.0501 Pulverized Coal Steam Chicago Report

$0.0167

$0.0077

$0.0113

$0.0357 MIT NR NR NR

$0.0447 EIA (scrubbed coal new)

$0.0209

$0.0069

$0.0122

$0.0382 Pulverized Coal Supercritical Chicago Report

$0.0179

$0.0085

$0.0113

$0.0376 MIT/EIA NR NR NR NR Fluidized-Bed Coal Chicago Report

$0.0179

$0.0059

$0.0120

$0.0358 MIT NR NR NR NR EIA (scrubbed coal new)

$0.0181

$0.0071

$0.0130

$0.0382 Integrated Coal Gasification Combined Cycle Chicago Report

$0.0199

$0.0052

$0.0094

$0.0346 MIT NR NR NR NR EIA

$0.0209

$0.0069

$0.0122

$0.0400 Biomass Chicago Report/MIT NR NR NR NR EIA

$0.0284

$0.0094

$0.0219

$0.0598 Municipal Solid Waste Chicago Report/MIT NR NR NR NR EIA

$0.0223

$0.0128

$0.0000

$0.0352 Wind 10 MW Chicago Report/MIT NR NR NR NR EIA

$0.0896

$0.0095

$0.0000

$0.0991 Wind 50 MW Chicago Report/MIT NR NR NR NR EIA

$0.0471

$0.0095

$0.0000

$0.0566 Wind 100 MW Chicago Report/MIT NR NR NR NR EIA

$0.0357

$0.0095

$0.0000

$0.0452 NREL w/o Tax Credit

$0.037 to $0.057

$0.003 to 0.009

$0.0000

$0.04 to $0.06 NREL w Tax Credit

$0.022 to $0.047

$0.003 to 0.009

$0.0000

$0.025 to $0.05 Offshore Wind 500 MW NREL

$0.045 or more

$0.0150

$0.0000

$0.06 or more Solar Chicago Report/MIT NR NR NR NR EIA

$0.2646

$0.0382

$0.0000

$0.3028 Photovoltaic Chicago Report/MIT NR NR NR NR EIA

$0.2496

$0.0049

$0.0000

$0.2545 NREL-Current (2004) Low

$0.20

$0.03

$0.00

$0.23 NREL-Current (2004) High

$0.32

$0.06

$0.00

$0.38 NREL-Projected (2015) Low

$0.11

$0.01

$0.00

$0.12 NREL-Projected (2015) High

$0.18

$0.02

$0.00

$0.20 New Next-Generation Nuclear Chicago Report

$0.0238

$0.0152

$0.0042

$0.0433 MIT NR NR NR

$0.0711 EIA

$0.0292

$0.0081

$0.0050

$0.0422 NOTE: Abbreviations are defined in Appendix C. EIA and Chicago report capital costs are overnight costs only. Delivery costs are not included. Capital costs assumed 100 percent debt with a 20-year term at 10 percent. MIT report assumed a 10-year term; consequently costs are higher. All costs are in 2003 U.S.

dollars. Adjustment to fuel costs may change relative cost of electricity. NREL wind costs noted that Canadian wind/hydro would add $0.002/kWh to $0.006/

kWh to the cost of pure wind alone.

SOURCES: Energy Information Administration, 2005, Assumptions to the Annual Energy Outlook 2005; MIT study on the future of nuclear power, An Interdisciplinary MIT Study, 2003; University of Chicago study, The Economic Future of Nuclear Power, August 2004.

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89 TABLE D-1-3a Energy Information Administration National Average Cost Estimates (2003 dollars)

Total Costa Capacity Financing (20 year term at 10%/year)

Annual Capital Operating Fuel Total Cost Delivery Assumed Hours Overnight Costs Capital Annual Cost Cost Costs Costs of Electricity Cost Capacity Capacity Operated w/Contingencies Cost Payment Payment Plant Typeb (million $)

($/kWh)

($/kWh)c (MW)

Factor per Year

($/kW)a,b (million $)

(million $)

($/kWh)

MSW Landfill Gas 8.3 0.0223 0.0128 0.0000 0.0352 0.0852 30 0.90 7884 1,500 45.0 5.3 0.0223 Scrubbed Coal New 180.8 0.0181 0.0071 0.0130 0.0382 0.0882 600 0.90 7884 1,213 727.8 85.5 0.0181 Integrated Coal Gasification 173.5 0.0209 0.0069 0.0122 0.0400 0.0900 550 0.90 7884 1,402 771.1 90.6 0.0209 Combined Cycle (IGCC)

Advanced Nuclear 332.8 0.0292 0.0081 0.0050 0.0422 0.0922 1,000 0.90 7884 1,957 1,957.0 229.9 0.0292 Advanced Gas Combined Cycle 130.1 0.0083 0.0031 0.0298 0.0412 0.0912 400 0.90 7884 558 223.2 26.2 0.0083 Conventional Gas 85.7 0.0084 0.0032 0.0318 0.0435 0.0935 250 0.90 7884 567 141.8 16.7 0.0084 Combined Cycle Wind 100 MWd 12.8 0.0357 0.0095 0.0000 0.0452 0.0952 100 0.32 2829 859 85.9 10.1 0.0357 Advanced Combustion 90.9 0.0056 0.0040 0.0406 0.0501 0.1001 230 0.90 7884 374 86.0 10.1 0.0056 Turbine IGCC with Carbon Sequestration 159.4 0.0299 0.0090 0.0143 0.0532 0.1032 380 0.90 7884 2,006 762.3 89.5 0.0299 Wind 50 MW 8.0 0.0471 0.0095 0.0000 0.0566 0.1066 50 0.32 2829 1,134 56.7 6.7 0.0471 Conventional Combustion 73.4 0.0059 0.0045 0.0478 0.0582 0.1082 160 0.90 7884 395 63.2 7.4 0.0059 Turbine Advanced CC with Carbon 187.6 0.0166 0.0048 0.0381 0.0595 0.1095 400 0.90 7884 1,114 445.6 52.3 0.0166 Sequestration Biomass 34.8 0.0284 0.0094 0.0219 0.0598 0.1098 80 0.83 7271 1,757 140.6 16.5 0.0284 Distributed Generation Base 1.0 0.0120 0.0081 0.0440 0.0641 0.1141 2

0.90 7884 807 1.6 0.2 0.0120 Distributed Generation Peak 0.6 0.0145 0.0081 0.0495 0.0721 0.1221 1

0.90 7884 970 1.0 0.1 0.0145 Wind 10 MWd 2.8 0.0896 0.0095 0.0000 0.0991 0.1491 10 0.32 2829 2,159 21.6 2.5 0.0896 Photovoltaic 2.7 0.2496 0.0049 0.0000 0.2545 0.3045 5

0.24 2102 4,467 22.3 2.6 0.2496 Solar Thermale 39.8 0.2646 0.0382 0.0000 0.3028 0.3528 100 0.15 1314 2,960 296.0 34.8 0.2646 aExcludes regional multipliers.

bAnnual Energy Outlook 2005, Basis of Assumptions Table 38, DOE (2005).

cAssumed $0.05/kWh delivery cost excluding line losses.

dApplied the 0.6 rule using 50 MW as the base reference.

eCapital costs are without the 10 percent investment tax credit.

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90 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER TABLE D-1-3b Energy Information Administration National Average Cost Estimates (2003 dollars)

Variable O&M Fixed O&M Fuel Cost Annual Fuel Heat Fuel Annual O&M Cost Rate Cost Fuel Cost Plant Typea

($/kWh)a (million $)

($/kW)a

($/kWh)

(million $)

($/mmBtu)b (Btu/kWh)a ($/kWh)

(million $/yr)

MSW Landfill Gas 0.0000 2.4 101.07 0.0128 3.0 0.00 13,648 0.0000 0

Scrubbed Coal New 0.0041 19.2 24.36 0.0031 14.6 1.47 8,844 0.0130 61.5 Integrated Coal Gasification Combined 0.0026 11.2 34.21 0.0043 18.8 1.47 8,309 0.0122 53.0 Cycle (IGCC)

Advanced Nuclear 0.0004 3.5 60.06 0.0076 60.1 10,400 0.0050 39.4 Advanced Gas Combined Cycle 0.0018 5.6 10.35 0.0013 4.1 4.42 6,752 0.0298 94.1 Conventional Gas Combined Cycle 0.0018 3.6 11.04 0.0014 2.8 4.42 7,196 0.0318 62.7 Wind 100 MWc 0.0000 0

26.81 0.0095 2.7 0.00 10,280 0.0000 0

Advanced Combustion Turbine 0.0028 5.1 9.31 0.0012 2.1 4.42 9,183 0.0406 73.6 IGCC with Carbon Sequestration 0.0039 11.8 40.26 0.0051 15.3 1.47 9,713 0.0143 42.8 Wind 50 MW 0.0000 0

26.81 0.0095 1.3 0.00 10,280 0.0000 0

Conventional Combustion Turbine 0.0032 4.0 10.72 0.0014 1.7 4.42 10,817 0.0478 60.3 Advanced CC with Carbon 0.0026 8.2 17.60 0.0022 7.0 4.42 8,613 0.0381 120.1 Sequestration Biomass 0.0030 1.7 47.18 0.0065 3.8 2.46 8,911 0.0219 12.8 Distributed Generation Base 0.0063 0.1 14.18 0.0018 0.03 4.42 9,950 0.0440 0.7 Distributed Generation Peak 0.0063 0

14.18 0.0018 0.01 4.42 11,200 0.0495 0.4 Wind 10 MWc 0.0000 0

26.81 0.0095 0.3 0.00 10,280 0.0000 0

Photovoltaic 0.0000 0

10.34 0.0049 0.05 0.00 10,280 0.0000 0

Solar Thermald 0.0000 0

50.23 0.0382 5.0 0.00 10,280 0.0000 0

aAnnual Energy Outlook 2005, Basis of Assumptions Table 38, DOE (2005).

bFuel prices are New York-specific.

cApplied the 0.6 rule using 50 MW as the base reference.

dCapital costs are without the 10 percent investment tax credit.

Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs http://www.nap.edu/catalog/11666.html

91 TABLE D-1-4a Energy Information Administration Regional Cost Estimates (2003 dollars)

Total Costa Capacity Financing (20-year term at 10%/year)

Annual Capital Operating Fuel Total Cost Delivery Hours Overnight Capital Annual Cost Cost Costs Costs of Electricity Cost Capacity Capacity Operated Costs Cost Payment Payment Plant Typeb

($ million)

($/kWh)

($/kWh)c (MW)

Factor per Year

($/kW)a,b

($ million)

($/kWh)

MSW Landfill Gas 11.1 0.0340 0.0128 0.0000 0.0468 0.0968 30 0.90 7884 2,280 68.4 8.0 0.0340 Scrubbed Coal New 225.3 0.0275 0.0071 0.0130 0.0476 0.0976 600 0.90 7884 1,844 1,106.2 129.0 0.0275 Integrated Coal Gasification Combined 220.6 0.0317 0.0069 0.0122 0.0509 0.1009 550 0.90 7884 2,131 1,172.1 137.7 0.0317 Cycle (IGCC)

Distributed Generation Base 0.5 0.0257 0.0034 0.0000 0.0291 0.0791 2

0.90 7884 1,724 3.5 0.4 0.0257 Distributed Generation Peak 0.3 0.0339 0.0034 0.0000 0.0373 0.0873 1

0.90 7884 2,274 2.3 0.3 0.0339 Advanced Gas Combined Cycle 143.7 0.0126 0.0031 0.0298 0.0456 0.0956 400 0.90 7884 848 339.3 39.8 0.0126 Wind 10 MWd 1.3 0.0376 0.0095 0.0000 0.0471 0.0971 10 0.32 2829 905 9.1 1.1 0.0376 Conventional Gas Combined Cycle 94.4 0.0128 0.0032 0.0318 0.0479 0.0979 250 0.90 7884 862 215.5 25.3 0.0128 Advanced Nuclear 452.3 0.0443 0.0081 0.0050 0.0574 0.1074 1,000 0.90 7884 2,975 2,974.6 349.4 0.0443 Advanced Combustion Turbine 111.1 0.0089 0.0045 0.0478 0.0613 0.1113 230 0.90 7884 600 138.1 16.2 0.0089 IGCC with Carbon Sequestration 205.9 0.0454 0.0090 0.0143 0.0687 0.1187 380 0.90 7884 3,049 1,158.7 136.1 0.0454 Wind 100 MWd 19.9 0.0236 0.0061 0.0406 0.0703 0.1203 100 0.32 2829 568 56.8 6.7 0.0236 Advanced CC with Carbon Sequestration 221.9 0.0183 0.0081 0.0440 0.0704 0.1204 400 0.90 7884 1,227 490.7 57.6 0.0183 Conventional Combustion Turbine 89.1 0.0398 0.0089 0.0219 0.0707 0.1207 160 0.90 7884 2,671 427.3 50.2 0.0398 Biomass 47.4 0.0238 0.0083 0.0495 0.0816 0.1316 80 0.83 7271 1,474 118.0 13.9 0.0238 Wind 50 MW 16.6 0.0703 0.0088 0.0381 0.1172 0.1672 50 0.32 2829 1,693 84.7 9.9 0.0703 Photovoltaic 4.0 0.3793 0.0049 0.0000 0.3843 0.4343 5

0.24 2102 6,790 33.9 4.0 0.3793 Solar Thermale 57.9 0.4022 0.0382 0.0000 0.4404 0.4904 100 0.15 1314 4,499 449.9 52.8 0.4022 aIncludes a regional multiplier for capital costs only to account for higher construction costs in New York. The regional multiplier of 1.52 based on Regional Greenhouse Gas Initiative modeling assumptions. An additional regional multiplier for the variable and fixed O&M would be needed to reflect the higher costs in New York.

bAnnual Energy Outlook 2005, Basis of Assumptions Table 38, DOE (2005).

cAssumed $0.05/kWh delivery cost excluding line losses.

dApplied the 0.6 rule using 50 MW as the base reference.

eCapital costs shown are before the 10 percent investment tax credit is applied.

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92 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER TABLE D-1-4b Energy Information Administration Regional Cost Estimates (2003 dollars)

Variable O&M Fixed O&M Fuel Cost Annual Annual O&M Fuel Cost Heat Rate Fuel Cost Fuel Cost Plant Typea

($/kWh)a (million $)

($/kW)a

($/kWh)

(million $)

($/mmBtu)b (Btu/kWh)a ($/kWh)

(million $/yr)

MSW Landfill Gas 0.0000 2.4 101.07 0.0128 3,032,100 0.00 13,648 0.0000 0

Scrubbed Coal New 0.0041 19.2 24.36 0.0031 14,616,000 1.47 8,844 0.0130 61.6 Integrated Coal Gasification 0.0026 11.2 34.21 0.0043 18,815,500 1.47 8,309 0.0122 53.0 Combined Cycle (IGCC)

Distributed Generation Base 0.0000 0

26.81 0.0034 53,620 0.00 10,280 0.0000 0

Distributed Generation Peak 0.0000 0

26.81 0.0034 26,810 0.00 10,280 0.0000 0

Advanced Gas Combined Cycle 0.0018 5.6 10.35 0.0013 4,140,000 4.42 6,752 0.0298 94.1 Wind 10 MWc 0.0000 0

26.81 0.0095 268,100 0.00 10,280 0.0000 0

Conventional Gas Combined Cycle 0.0018 3.6 11.04 0.0014 2,760,000 4.42 7,196 0.0318 62.7 Advanced Nuclear 0.0004 3.5 60.06 0.0076 60,060,000 0.00 10,400 0.0050 39.4 Advanced Combustion Turbine 0.0032 5.7 10.72 0.0014 2,465,600 4.42 10,817 0.0478 86.7 IGCC with Carbon Sequestration 0.0039 11.8 40.26 0.0051 15,298,800 1.47 9,713 0.0143 42.8 Wind 100 MWc 0.0028 0.8 9.31 0.0033 931,000 4.42 9,183 0.0406 11.5 Advanced CC with Carbon 0.0063 19.9 14.18 0.0018 5,672,000 4.42 9,950 0.0440 138.7 Sequestration Conventional Combustion Turbine 0.0030 3.7 47.18 0.0060 7,548,800 2.46 8,911 0.0219 27.7 Biomass 0.0063 3.7 14.18 0.0020 1,134,400 4.42 11,200 0.0495 28.8 Wind 50 MW 0.0026 0.4 17.60 0.0062 880,000 4.42 8,613 0.0381 5.4 Photovoltaic 0.0000 0

10.34 0.0049 51,700 0.00 10,280 0.00 0

Solar Thermald 0.0000 0

50.23 0.0382 5,023,000 0.00 10,280 0.00 0

aAnnual Energy Outlook 2005, Basis of Assumptions Table 38, DOE (2005).

bFuel prices are New York-specific.

cApplied the 0.6 rule using 50 MW as the base reference.

dCapital costs shown are before the 10 percent investment tax credit is applied.

TABLE D-1-5 University of Chicago National Average Cost Estimates (2003 dollars)

Total Costa Capacity Annual Capital Operating Fuel Total Cost Delivery Assumed Assumed Hours Cost Cost Costs Costs of Electricity Cost Capacity Capacity Capacity Operated Plant Type

($/yr)

($/kWh)

($/kWh)b (MW)

(kW)

Factor per Year Integrated Coal Gasification 136,251,949 0.0199 0.0052 0.0094 0.0346 0.0846 500 500,000 0.90 7,884 Combined Cycle Natural Gas Combined Cycle 139,350,109 0.0088 0.0030 0.0236 0.0354 0.0854 500 500,000 0.90 7,884 Pulverized Coal Steam 140,577,240 0.0167 0.0077 0.0113 0.0357 0.0857 500 500,000 0.90 7,884 Fluid Bed Coal 141,076,995 0.0179 0.0059 0.0120 0.0358 0.0858 500 500,000 0.90 7,884 Pulverized Coal Supercritical 148,369,695 0.0179 0.0085 0.0113 0.0376 0.0876 500 500,000 0.90 7,884 Nuclear Advanced Boiler Water 341,200,360 0.0238 0.0152 0.0042 0.0433 0.0933 1,000 1,000,000 0.90 7,884 Reactor Financing Total O&M Fuel Cost Capital Annual Costs Capital Term Interest Payment Payment Fuel Cost Fuel Cost Plant Type

($/kW)a Cost ($)

(yr)

(%)

($/yr)

($/kWh)

($/yr)

($/kWh)

($/yr)

Integrated Coal Gasification 1,338 669,000,000 20 10 78,580,489 0.0199 0.0052 20,458,980 0.0094 37,212,480 Combined Cycle Natural Gas Combined Cycle 590 295,000,000 20 10 34,650,589 0.0088 0.0030 11,668,320 0.0236 93,031,200 Pulverized Coal Steam 1,119 559,500,000 20 10 65,718,660 0.0167 0.0077 30,471,660 0.0113 44,386,920 Fluid Bed Coal 1,200 600,000,000 20 10 70,475,775 0.0179 0.0059 23,139,540 0.0120 47,461,680 Pulverized Coal Supercritical 1,200 600,000,000 20 10 70,475,775 0.0179 0.0085 33,507,000 0.0113 44,386,920 Nuclear Advanced Boiler Water 1,600 1,600,000,000 20 10 187,935,400 0.0238 0.0152 120,073,320 0.0042 33,191,640 Reactor aExcludes regional multipliers.

bAssumes $0.05/kWh delivery cost, excluding line losses.

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APPENDIX D 93 TABLE D-1-7 New York City Fuel Prices ($/MMBtu)

Fuel 2004 Prices 2004 Prices in 2003$

Coal 1% S

$1.50

$1.47 Natural gas

$4.50

$4.42 Municipal solid waste (MSW)

-$2.50

-$2.46 Biomass

$2.50

$2.46 NOTE: Fuel prices are New York-specific and were provided by the New York State Energy Research and Development Authority. The negative price for MSW is from avoidance of otherwise necessary disposal fees.

TABLE D-1-6 University of Chicago Regional Cost Estimates for the New York Control Area (2003 dollars)

Total Costa Capacity Annual Capital Operating Fuel Total Cost Delivery Assumed Assumed Hours Cost Cost Costs Costs of Electricity Cost Capacity Capacity Capacity Operated Plant Type

($/yr)

($/kWh)

($/kWh)b (MW)

(kW)

Factor per Year Natural Gas Combined Cycle 157,368,416 0.0134 0.0030 0.0236 0.0399 0.0899 500 500,000 0.90 7,884 Pulverized Coal Steam 174,750,943 0.0253 0.0077 0.0113 0.0443 0.0943 500 500,000 0.90 7,884 Integrated Coal Gasification 177,113,803 0.0303 0.0052 0.0094 0.0449 0.0949 500 500,000 0.90 7,884 Combined Cycle Fluid Bed Coal 177,724,398 0.0272 0.0059 0.0120 0.0451 0.0951 500 500,000 0.90 7,884 Pulverized Coal Supercritical 185,017,098 0.0272 0.0085 0.0113 0.0469 0.0969 500 500,000 0.90 7,884 Nuclear Advanced Boiler 438,926,767 0.0362 0.0152 0.0042 0.0557 0.1057 1,000 1,000,000 0.90 7,884 Water Reactor Financing Total O&M Fuel Cost Capital Annual Costs Capital Term Interest Payment Payment Fuel Cost Fuel Cost Plant Type

($/kW)a Cost ($)

(yr)

(%)

($/yr)

($/kWh)

($/yr)

($/kWh)

($/yr)

Natural Gas Combined Cycle 897 448,400,000 20 10 52,668,896 0.0134 0.0030 11,668,320 0.0236 93,031,200 Pulverized Coal Steam 1,701 850,440,000 20 10 99,892,363 0.0253 0.0077 30,471,660 0.0113 44,386,920 Integrated Coal Gasification 2,034 1,016,880,000 20 10 119,442,343 0.0303 0.0052 20,458,980 0.0094 37,212,480 Combined Cycle Fluid Bed Coal 1,824 912,000,000 20 10 107,123,178 0.0272 0.0059 23,139,540 0.0120 47,461,680 Pulverized Coal Supercritical 1,824 912,000,000 20 10 107,123,178 0.0272 0.0085 33,507,000 0.0113 44,386,920 Nuclear Advanced Boiler 2,432 2,432,000,000 20 10 285,661,807 0.0362 0.0152 120,073,320 0.0042 33,191,640 Water Reactor aIncludes a regional multiplier for capital costs only to account for higher construction costs in New York. The regional multiplier of 1.52 based on Regional Greenhouse Gas Initiative modeling assumptions. An additional regional multiplier for the variable and fixed O&M would be needed to reflect the higher costs in New York.

bAssumed $0.05/kWh delivery cost excluding line losses.

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94 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER APPENDIX D-2 ZONAL ENERGY AND SEASONAL CAPACITY IN NEW YORK STATE, 2004 AND 2005 Parker Mathusa and Erin Hogan1 TABLE D-2-1 Summary of Summer and Winter Capacity, Energy Production, and Energy Requirements in the New York Control Area, by Zone Summer Capacity Winter Capacity Energy Energy Requirements Energy Production/

(MW)

(GWh)

Demand Index Zonea 2004 2005 2004 2005 2004 2005 2004 2005 2004 2005 A

5,216 5,083

-2.55 5,314 5,212

-1.93 26,963 32,080 18.98 15,942 16,106 1.03 1.69 1.99 17.77 B

950 950

-0.07 971 972 0.05 5,738 6,258 9.07 9,719 9,911 1.98 0.59 0.63 6.95 C

6,651 6,617

-0.51 6,859 6,884 0.36 29,821 27,263

-8.58 16,794 16,830 0.21 1.78 1.62

-8.77 D

1,268 1,262

-0.50 1,182 1,277 8.08 8,505 9,153 7.62 5,912 5,782

-2.20 1.44 1.58 10.04 E

886 871

-1.74 947 946

-0.11 3,165 1,404

-55.63 6,950 7,044 1.35 0.46 0.20

-56.22 F

3,608 3,111

-13.78 3,720 3,535

-4.97 7,726 8,508 10.12 11,115 11,161 0.41 0.70 0.76 9.67 G

3,501 3,421

-2.28 3,575 3,512

-1.77 9,327 9,213

-1.22 10,452 10,640 1.80 0.89 0.87

-2.96 H

2,079 2,069

-0.46 2,102 2,100

-0.06 16,297 16,638 2.10 2,219 2,276 2.57 7.34 7.31

-0.46 I

3.5 2.9

-17.24 3

3

-3.25 4

8 107.93 6,121 6,184 1.03 0.00 0.00 105.81 J

8,894 8,981 0.99 9,455 9,705 2.65 20,352 21,821 7.22 50,829 52,073 2.45 0.40 0.42 4.66 K

5,054 5,180 2.48 5,375 5,509 2.49 15,565 14,822

-4.78 21,960 22,203 1.11 0.71 0.67

-5.82 Statewide 38,111 37,548

-1.48 39,504 39,655 0.38 143,463 147,169 2.58 158,014 160,210 1.39 0.91 0.92 1.18 aThe New York Control Areas load zones are A, West; B, Genesee; C, Central; D, North; E, Mohawk Valley; F, Capital; G, Hudson Valley; H, Millwood; I, Dunwoodie; J, New York City; and K, Long Island.

SOURCE: NYISO (2005).

1Parker Mathusa is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs. Erin Hogan is with the New York State Energy Research and Development Authority.

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95 TABLE D-2-2 Summer Zonal Capacity, by Fuel, 2004 and 2005 Total Dual-Fuel Summer Capacity (MW)

Single-Fuel Summer Capacity (MW)

Zonal Winter Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (MW)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

2004 5,216 201 1,988 309.4 1

5 2,672 39 0.03 2005 5,083 193 1,902 307.8 1

5 2,636 38 0.03

-2.55%

-3.84%

-4.35%

-0.51%

0.00%

3.85%

-1.34%

-4.06%

0.00%

B 2004 950 240 132 14 2

58 498 6.7 2005 950 238 133 14 2

57 499 6.7

-0.07%

-0.83%

0.99%

0.00%

-1.62%

0.20%

0.00%

C 2004 6,651 1,043 678 442 8

1,667 17 122 34 2,611 30 2005 6,617 1,038 677 432 8

1,649 17 122 33 2,610 30

-0.51%

-0.42%

-0.19%

-2.13%

0.00%

-1.06%

-0.51%

0.60%

-2.07%

-0.04%

0.00%

D 2004 1,268 320.9 2

927 18 2005 1,262 320.6 2

922 18

-0.50%

-0.09%

0.00%

-0.64%

-0.55%

E 2004 886 52 333 471 20 9.9 2005 871 52 329 460 20 9.9

-1.74%

0.00%

-1.44%

-2.30%

1.00%

0.00%

F 2004 3,608 405 356 1,363 1,470 13 0.5 0

2005 3,111 398 1,227 2

1,472 12 0.5 0

-13.78%

-1.78%

-10.01%

0.18%

-12.3%

0.00%

G 2004 3,501 17 2,525 92 727 5

15.6 6

105 9

0 2005 3,421 16 2,446 91 728 5

15.6 6

105 8

0

-2.28%

-3.53%

-3.13%

-1.95%

0.15%

0.00%

0.67%

-4.65%

0.00%

H 2004 2,079 47 52 1,981 2005 2,069 47 52 1,971

-0.46%

0.00%

0.97%

-0.50%

I 2004 3

3 0.48 0.2 2005 3

0.2 2

0.48

-17.24%

-21.4%

0.00%

J 2004 8,894 285 5,253 1,181 1,321 669 186 2005 8,981 513 5,181 1,186 1,318 667 117 0.99%

80.18%

-1.37%

0.42%

-0.20%

-0.31%

-36.99%

K 2004 5,054 567 2,420 805 1,126 6

18 114 2005 5,180 579 2,442 920 1,113 5

121 2.48%

2.26%

0.88%

14.39%

-1.17%

-9.09%

6.43%

NYCA 2004 38,111 2,516 10,555 1,273 0

727 2,958 5,026 1,871 1,667 0

202 36 5,827 18 260 5,090 39 47 2005 37,548 2,737 10,069 1,276 0

728 2,869 4,988 1,856 1,649 0

133 37 5,777 0

264 5,080 39 47

-1.48%

8.78%

-4.60%

0.24%

0.15%

-3.03%

-0.76%

-0.82%

-1.06%

-34.13%

4.28%

-0.86%

-97.4%

1.25%

-0.20%

0.26%

0.00%

NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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96 TABLE D-2-3 Winter Zonal Capacity, by Fuel, 2004 and 2005 Total Dual-Fuel Summer Capacity (MW)

Single-Fuel Summer Capacity (MW)

Zonal Winter Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (MW)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

2004 5,314 215 2,039 342.8 1

6 2,672 40 0.03 2005 5,212 217 1,937 337.4 1

6 2,674 40 0.03

-1.93%

1.07%

-5.01%

-1.56%

0.00%

-1.79%

0.07%

1.77%

0.00%

B 2004 971 250 141 16 2

58 498 6.7 2005 972 245 143 18 2

58 499 6.7 0.05%

-2.00%

1.92%

12.50%

0.00%

0.21%

0.14%

0.00%

C 2004 6,859 1,184 675 482 8

1,675 18 125 33 2,630 30 2005 6,884 1,191 673 489 8

1,689 17 123 33 2,629 30 0.36%

0.62%

-0.16%

1.49%

0.00%

0.83%

-1.44%

-1.6%

0.68%

-0.03%

0.00%

D 2004 1,182 330.7 2

831 18 2005 1,277 331.2 2

927 18 8.08%

0.15%

0.00%

11.4%

-0.6%

E 2004 947 52 373 492 20 9.4 2005 946 53 365 497 20 11.1

-0.11%

2.89%

-2.28%

0.85%

0.50%

18.2%

F 2004 3,720 444 383 1,392 1,487 13 0.5 0.02 2005 3,535 458 1,545 2

1,517 12 0.5 0.02

-4.97%

3.08%

11.00%

2.07%

-12.03%

0.00%

G 2004 3,575 23 2,565 111 730 5

22.4 6

104 8

0 2005 3,512 22 2,504 112 731 5

17.7 6

105 8

0

-1.77%

-2.61%

-2.37%

1.54%

0.12%

0.00%

-22%

0.00%

0.86%

-4.76%

0.00%

H 2004 2,102 64 51 1,987 2005 2,100 64 52 1,985

-0.06%

0.00%

1.96%

-0.11%

I 2004 3

2 0.48 0.2 2005 3

0.2 2

0.48

-3.25%

-4.2%

0.00%

J 2004 9,455 324 5,280 1,436 1,385 833 197 2005 9,705 580 5,256 1,463 1,394 876 137 2.65%

79.00%

-0.45%

1.82%

0.67%

5.18%

-31%

K 2004 5,375 665 2,312 906 1,374 6

112 2005 5,509 674 2,355 980 1,382 6

112 2.49%

1.29%

1.84%

8.24%

0.59%

0.00%

-0.18%

NYCA 2004 39,504 2,855 10,540 1,547 0

730 3,015 5,352 2,302 1,675 0

220 37 5,772 0

257 5,115 39 46 2005 39,655 3,142 10,115 1,575 0

731 2,909 5,586 2,355 1,689 0

155 39 5,903 0

257 5,113 39 48 0.38%

10.06%

-4.03%

1.80%

0.12%

-3.54%

4.37%

2.31%

0.83%

-30%

4.09%

2.26%

0.00%

-0.19%

-0.04%

0.00%

3.68%

NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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97 TABLE D-2-4 Annual Energy Production, by Fuel, 2004 and 2005 Dual-Fuel Summer Capacity (GWh)

Single-Fuel Summer Capacity (GWh)

Total Zonal Natural Jet Energy NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (GWh)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

2004 26,963 1,249 12,531 507.0 51 12,355 270 2005 32,080 1,214 12,775 484.1 45 17,316 245 18.98%

-2.75%

1.94%

-4.52%

-11.02%

40.15%

-8.96%

B 2004 5,738 1,423 201 1

17 216 3,863 15.6 2005 6,258 1,545 134 1

16 239 4,308 14.3 9.07%

8.60% -33.27%

-56.42%

-2.19%

10.46%

11.51%

-8.3%

C 2004 29,821 2,664 4,600 261 395 118 653 228 20,833 69 2005 27,263 1,854 3,967 243 407 144 276 236 20,057 79

-8.58%

-30.4%

-13.78%

-6.82%

2.99%

22.12%

-57.77%

3.64% -3.72%

14.1%

D 2004 8,505 1989.9 6,417 98 2005 9,153 1938.1 7,108 107 7.62%

-2.60%

10.77%

9.03%

E 2004 3,165 340 221 2,491 94 18.8 2005 1,404 420 148 714 104 19.4

-55.6%

23.39% -33.25%

-71.34%

10.4%

2.72%

F 2004 7,726 3,024 102 1,019 3,491 91 2005 8,508 3,021 2,958 14 2,129 77 10.12%

-0.08%

190.25%

-39.%

-15.09%

G 2004 9,327 135 4,447 8

4,312 2.4 381 43 2005 9,213 136 4,833 1

3,830 0.2 363 49

-1.22%

1.10%

8.70%

-81.9%

-11.%

-90.%

-4.68%

14.44%

H 2004 16,297 382 15,915 2005 16,638 378 16,260 2.10%

-1.02%

2.17%

I 2004 4

4 2005 8

8 107.9%

107.93%

J 2004 20,352 2,094 12,249 418 5,466 107 19 2005 21,821 3,295 12,750 554 5,060 119 43 7.22%

57.37%

4.08%

32.71%

-7.44%

12.09%

132.%

K 2004 15,565 2,009 10,507 1,474 664 19 892 2005 14,822 2,020 10,099 1,421 369 16 897

-4.78%

0.52%

-3.89%

-3.58%

-44.49%

-16.75%

0.64%

NYCA 2004 143463 11,175 27,305 425 0

4,312 18,895 11,140 772 395 0

21 205 26,008 0

1,905 40,610 192 103 2005 147169 11,541 27,990 556 0

3,830 18,706 12,386 489 407 0

43 236 28,153 0

1,883 40,626 211 112 2.58%

3.28%

2.51%

30.60%

-11.%

-1.00%

11.19%

-36.70% 2.99%

106.%

15.13%

8.25%

-1.13%

0.04%

9.71%

8.63%

NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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98 Table D-2-5 Summary of New York Control Area Generation Facilities Energy Production by Fuel Type as of January 1, 2005 Dual-Fuel Energy (GWh)

Single-Fuel Energy (GWh)

Total Zonal Natural Jet Energy NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (GWh)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

32,080 1,214 12,775 484.1 45 17,316 245 B

6,258 1,545 134 1

16 239 4,308 14 C

27,263 1,854 3,967 243 407 144 276 236 20,057 79 D

9,153 1,938.1 7,108 107 E

1,404 420 148 714 104 19 F

8,508 3,021 309 2,958 14 2,129 77 G

9,213 136 4,833 1

3,830 0.2 363 49 H

16,638 378 16,260 I

8 8

J 21,821 3,295 12,750 554 5,060 119 43 K

14,822 2,020 10,099 1,421 369 16 0

897 NYCA 147,169 11,541 27,990 556 0

3,830 18,706 12,386 489 407 0

43 236 28,153 0

1,883 40,626 211 112 Dual-Fuel Energy (%)

Single-Fuel Energy (%)

Total Zonal Natural Jet Energy NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone

(%)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

21.8 3.8 39.8 1.5 0.1 54.0 0.8 B

4.3 24.7 2.1 0.0 0.3 3.8 68.8 0.2 C

18.5 6.8 14.5 0.9 1.5 0.5 1.0 0.9 73.6 0.3 D

6.2 21.2 77.7 1.2 E

1.0 29.9 10.5 50.8 7.4 1.4 F

5.8 35.5 3.6 34.8 0.2 25.0 0.9 G

6.3 1.5 52.5 0.0 41.6 0.0 3.9 0.5 H

11.3 2.3 97.7 I

0.01 100.0 J

14.8 15.1 58.4 2.5 23.2 0.5 0.2 K

10.1 13.6 68.1 9.6 2.5 0.1 0.0 6.1 NYCA 100.0 7.8 19.0 0.4 0.0 2.6 12.7 8.4 0.3 0.3 0.0 0.0 0.2 19.1 0.0 1.3 27.6 0.1 0.1 NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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99 TABLE D-2-6 Summary of New York Control Area Generation Facilities Winter Capacity, by Fuel Type, as of January 1, 2005 Total Dual-Fuel Winter Capacity (MW)

Single-Fuel Winter Capacity (MW)

Zonal Winter Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (MW)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

5,212 217 1,937 337.4 1

6 2,674 40 0

B 972 245 143 18 2

58 499 6.7 C

6,884 1,191 673 489 8

1,689 17 123 33 2,629 30 D

1,277 331.2 2

927 18 E

946 53 365 497 20 11.1 F

3,535 458 1,545 2

1,517 12 0.5 0

G 3,512 22 2,504 112 731 5

17.7 6

105 8

0 H

2,100 64 52 1,985 I

3 0

2 0

J 9,705 580 5,256 1,463 1,394 876 137 K

5,509 674 2,355 980 1,382 6

112 NYCA 39,655 3,142 10,115 1,575 0

731 2,909 5,586 2,355 1,689 0

155 39 5,903 0

257 5,113 39 48 Total Dual-Fuel Winter Capacity (%)

Single-Fuel Winter Capacity (%)

Zonal Winter Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone

(%)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

13.1 4.2 37.2 6.5 0.0 0.1 51.3 0.8 0.0 B

2.5 25.2 14.7 1.9 0.2 6.0 51.3 0.7 C

17.4 17.3 9.8 7.1 0.1 24.5 0.3 1.8 0.5 38.2 0.4 D

3.2 25.9 0.1 72.5 1.4 E

2.4 5.6 38.6 52.5 2.1 1.2 F

8.9 13.0 43.7 0.0 42.9 0.3 0.0 0.0 G

8.9 0.6 71.3 3.2 20.8 0.1 0.5 0.2 3.0 0.2 0.0 H

5.3 3.0 2.5 94.5 I

0.01 6.7 77.2 16.1 J

24.5 6.0 54.2 15.1 14.4 9.0 1.4 K

13.9 12.2 42.7 17.8 25.1 0.1 2.0 State 100.0 7.9 25.5 4.0 0.0 1.8 7.3 14.1 5.9 4.3 0.0 0.4 0.1 14.9 0.0 0.6 12.9 0.1 0.1 Total NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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100 TABLE D-2-7 Summary of New York Control Area Generation Facilities Summer Capacity, by Fuel Type, as of January 1, 2005 Total Dual-Fuel Summer Capacity (MW)

Single-Fuel Summer Capacity (MW)

Zonal Summer Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (MW)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

5,083 193 1,902 307.8 1

5 2,636 38 0.03 B

950 238 133 14 2

57 499 6.7 C

6,617 1,038 677 432 8

1,649 17 122 33 2,610 30 D

1,262 320.6 2

922 18 E

871 52 329 460 20 9.9 F

3,111 398 1,227 2

1,472 12 0.5 0

G 3,421 16 2,446 91 728 5

15.6 6

105 8

0 H

2,069 47 52 1,971 I

3 0

2 0

J 8,981 513 5,181 1,186 1,318 667 117 K

5,180 579 2,442 920 1,113 5

121 NYCA 37,548 2,737 10,069 1,276 0

728 2,869 4,988 1,856 1,649 0

133 37 5,777 0

264 5,080 39 47 Total Dual-Fuel Summer Capacity (%)

Single-Fuel Summer Capacity (%)

Zonal Summer Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone

(%)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

13.5 3.8 37.4 6.1 0.0 0.1 51.9 0.7 0.0 B

2.5 25.1 14.0 1.5 0.2 6.0 52.5 0.7 C

17.6 15.7 10.2 6.5 0.1 24.9 0.3 1.8 0.5 39.4 0.5 D

3.4 25.4 0.1 73.0 1.4 E

2.3 6.0 37.7 52.8 2.3 1.1 F

8.3 12.8 39.4 0.1 47.3 0.4 0.0 0.0 G

9.1 0.5 71.5 2.6 21.3 0.1 0.5 0.2 3.1 0.2 0.0 H

5.5 2.2 2.5 95.2 I

0.01 6.9 76.4 16.7 J

23.9 5.7 57.7 13.2 14.7 7.4 1.3 K

13.8 11.2 47.1 17.8 21.5 0.1 2.3 NYCA 100.0 7.3 26.8 3.4 0.0 1.9 7.6 13.3 4.9 4.4 0.0 0.4 0.1 15.4 0.0 0.7 13.5 0.1 0.1 NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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101 TABLE D-2-8 Summary of New York Control Area Generation Facilities Energy, by Fuel Type, as of January 1, 2004 Dual-Fuel Energy (GWh)

Single-Fuel Energy (GWh)

Total Zonal Natural Jet Energy NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (GWh)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

26,963 1,249 12,531 507 51 12,355 270 B

5,738 1,423 201 1

17 216 3,863 16 C

29,821 2,664 4,600 261 395 118 653 228 20,833 69 D

8,505 1989.9 6,417 98 E

3,165 340 221 2,491 94 19 F

7,726 3,024 102 1,019 3,491 91 G

9,327 135 4,447 8

4,312 2

381 43 H

16,297 382 15,915 I

4 4

J 20,352 2,094 12,249 418 5,466 107 19 K

15,565 2,009 10,507 1,474 664 19 892 NYCA 143,463 11,175 27,305 425 0

4,312 18,895 11,140 772 395 0

21 205 26,008 0

1,905 40,610 192 103 Dual-Fuel Energy (%)

Single-Fuel Energy (%)

Total Zonal Natural Jet Energy NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone

(%)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

18.8 4.6 46.5 1.9 0.2 45.8 1.0 B

4.0 24.8 3.5 0.0 0.3 3.8 67.3 0.3 C

20.8 8.9 15.4 0.9 1.3 0.4 2.2 0.8 69.9 0.2 D

5.9 23.4 75.4 1.2 E

2.2 10.7 7.0 78.7 3.0 0.6 F

5.4 39.1 1.3 13.2 45.2 1.2 G

6.5 1.4 47.7 0.1 46.2 0.0 4.1 0.5 H

11.4 2.3 97.7 I

0.0 100.0 J

14.2 10.3 60.2 2.1 26.9 0.5 0.1 K

10.8 12.9 67.5 9.5 4.3 0.1 5.7 NYCA 100.0 7.8 19.0 0.3 0.0 3.0 13.2 7.8 0.5 0.3 0.0 0.0 0.1 18.1 0.0 1.3 28.3 0.1 0.1 NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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102 TABLE D-2-9 Summary of New York Control Area Generation Facilities Winter Capacity, by Fuel Type, as of January 1, 2004 Total Dual-Fuel Winter Capacity (MW)

Single-Fuel Winter Capacity (MW)

Zonal Winter Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (MW)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

5,314 215 2,039 342.8 1

6 2,672 40 0

B 971 250 141 16 2

58 498 6.7 C

6,859 1,184 675 482 8

1,675 18 125 33 2,630 30 D

1,182 330.7 2

831 18 E

947 52 373 492 20 9.4 F

3,720 444 383 1,392 1,487 13 0.5 0

G 3,575 23 2,565 111 730 5

22.4 6

104 8

0 H

2,102 64 51 1,987 I

3 2

0 0

J 9,455 324 5,280 1,436 1,385 833 197 K

5,375 665 2,312 906 1,374 6

112 NYCA 39,504 2,855 10,540 1,547 0

730 3,015 5,352 2,302 1,675 0

220 37 5,772 0

257 5,115 39 46 Total Dual-Fuel Winter Capacity (%)

Single-Fuel Winter Capacity (%)

Zonal Winter Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone

(%)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

13.5 4.0 38.4 6.4 0.0 0.1 50.3 0.7 0.0 B

2.5 25.7 14.5 1.6 0.2 5.9 51.3 0.7 C

17.4 17.3 9.8 7.0 0.1 24.4 0.3 1.8 0.5 38.3 0.4 D

3.0 28.0 0.1 70.3 1.5 E

2.4 5.5 39.4 52.0 2.1 1.0 F

9.4 11.9 10.3 37.4 40.0 0.4 0.0 0.0 G

9.0 0.6 71.8 3.1 20.4 0.1 0.6 0.2 2.9 0.2 0.0 H

5.3 3.0 2.4 94.5 I

0.01 77.9 15.6 6.5 J

23.9 3.4 55.8 15.2 14.6 8.8 2.1 K

13.6 12.4 43.0 16.8 25.6 0.1 2.1 NYCA 100.0 7.2 26.7 3.9 0.0 1.8 7.6 13.5 5.8 4.2 0.0 0.6 0.1 14.6 0.0 0.7 12.9 0.1 0.1 NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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103 TABLE D-2-10 Summary of New York Control Area Generation Facilities Summer Capacity, by Fuel Type, as of January 1, 2004 Total Dual-Fuel Summer Capacity (MW)

Single-Fuel Summer Capacity (MW)

Zonal Summer Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone (MW)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

5,216 201 1,988 309.4 1

5 2,672 39 0.03 B

950 240 132 14 2

58 498 6.7 C

6,651 1,043 678 442 8

1,667 17 122 34 2,611 30 D

1,268 320.9 2

927 18 E

886 52 333 471 20 9.9 F

3,608 405 356 1,363 1,470 13 0.5 0

G 3,501 17 2,525 92 727 5

15.6 6

105 9

0 H

2,079 47 52 1,981 I

3 3

0 0

J 8,894 285 5,253 1,181 1,321 669 186 K

5,054 567 2,420 805 1,126 6

18 114 NYCA 38,111 2,516 10,555 1,273 0

727 2,958 5,026 1,871 1,667 0

202 36 5,827 18 260 5,090 39 47 Total Dual-Fuel Summer Capacity (%)

Single-Fuel Summer Capacity (%)

Zonal Summer Natural Jet Capacity NG/

NG/

Coal Gas No. 2 No. 6 Fuel Kerosene Methane Water Other Refuse Uranium Wood Wind Zone

(%)

FO2 FO6 KER JF BIT BIT NG FO2 FO6 JF KER MTE WAT OT REF UR WD WND A

13.7 3.8 38.1 5.9 0.0 0.1 51.2 0.8 0.0 B

2.5 25.3 13.9 1.5 0.2 6.1 52.4 0.7 C

17.5 15.7 10.2 6.6 0.1 25.1 0.3 1.8 0.5 39.3 0.5 D

3.3 25.3 0.1 73.1 1.4 E

2.3 5.9 37.6 53.1 2.3 1.1 F

9.5 11.2 9.9 37.8 40.7 0.4 0.0 0.0 G

9.2 0.5 72.1 2.6 20.8 0.1 0.4 0.2 3.0 0.2 0.0 H

5.5 2.2 2.5 95.3 I

0.01 80.5 13.8 5.7 J

23.3 3.2 59.1 13.3 14.9 7.5 2.1 K

13.3 11.2 47.9 15.9 22.3 0.1 0.4 2.2 NYCA 100.0 6.6 27.7 3.3 0.0 1.9 7.8 13.2 4.9 4.4 0.0 0.5 0.1 15.3 0.0 0.7 13.4 0.1 0.1 NOTE: See Table D-2-1, footnote a, for zone names. For definitions of acronyms in Dual-Fuel column heads, see Single-Fuel column heads.

SOURCE: NYISO (2005).

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104 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER APPENDIX D-3 ENERGY GENERATED IN 2003 FROM NATURAL GAS UNITS IN ZONES H THROUGH K Parker Mathusa and Erin Hogan1 TABLE D-3-3 Estimated Natural Gas (NG) Consumption of a 2,000 MW Combined-Cycle Unit with a 95 Percent Capacity Factor Estimated NG Estimated NG Estimated Daily Percent of Estimated Consumed Consumed Consumption Total GWh Capacity Estimated GWh Heat Rate (million Btu (thousand cubic (billion cubic Fuel Type Produced in 2003 Using NG Generated with NG (Btu/kWh) per year) feet per year) feet per day)

NG 16,644 100 16,644 7,000 116,508,000 113,666 0.31 TABLE D-3-2 Natural Gas Consumption for Electricity in Zones H Through K, 2004 Estimated NG Estimated NG Estimated Daily Percent of Estimated Consumed Consumed Consumption Total GWh Capacity Estimated GWh Heat Rate (million Btu (thousand cubic (billion cubic Fuel Type Produced in 2003 Using NG Generated with NG (Btu/kWh) per year) feet per year) feet per day)

NG/FO2 5,315 80 4,252 10,500 44,646,000 43,557 0.12 NG/FO6 22,849 80 18,279 9,500 173,652,400 169,417 0.46 NG/KER 554 80 443 14,500 6,426,400 6,270 0.02 NG 6,481 100 6,481 8,500 55,088,500 53,745 0.15 Total 35,199 29,455 279,813,300 272,989 0.75 NOTE: See Table D-2-1, footnote a, for zone names. NG, natural gas; FO2, No. 2; FO6, No. 6; KER, kerosen SOURCE: NYISO (2005).

TABLE D-3-1 Natural Gas Consumption for Electricity in Zones H Through K, 2003 Estimated NG Estimated NG Estimated Daily Percent of Estimated Consumed Consumed Consumption Total GWh Capacity Estimated GWh Heat Rate (million Btu (thousand cubic (billion cubic Fuel Type Produced in 2003 Using NG Generated with NG (Btu/kWh) per year) feet per year) feet per day)

NG/FO2 4,103 80 3,282 10,500 34,465,200 33,625 0.09 NG/FO6 22,756 80 18,205 9,500 172,945,600 168,727 0.46 NG/KER 418 80 334 14,500 4,848,800 4,731 0.01 NG 6,940 100 6,940 8,500 58,990,000 57,551 0.16 Total 34,217 28,762 271,249,600 264,634 0.73 NOTE: See Table D-2-1, footnote a, for zone names. NG, natural gas; FO2, No. 2; FO6, No. 6; KER, kerosene.

SOURCE: NYISO (2005).

1Parker Mathusa is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs. Erin Hogan is with the New York State Energy Research and Development Authority.

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APPENDIX D 105 APPENDIX D-4 PROPOSED PIPELINE PROJECTS IN THE NORTHEAST OF THE UNITED STATES FIGURE D-4-1 Proposed Northeast pipeline projects. SOURCE: Northeast Gas Association. Available at http://www.northeastgas.org/pdf/

pipe_enhance1105.pdf. Accessed February 2006. Reproduced with the permission of the Northeast Gas Association.

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106 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER APPENDIX D-5 COAL TECHNOLOGIES James R. Katzer1 Coal was used to produce 51 percent of the electricity generated in the United States in 2004. Domestic coal re-serves are far greater than those of oil or natural gas, and costs for using coal to generate electricity are much lower than for oil and natural gas. Thus, coal promises to continue its position as the primary fuel for power generation for the foreseeable future. Pennsylvania, West Virginia, and other states have large resources of coal that could be delivered to New York relatively inexpensively.

Coal can contain high concentrations of ash and substan-tial amounts of sulfur, in addition to other toxic elements. It thus has the potential for high emissions, but appropriate control technology can reduce these emissions to a very low level.

Large coal-fired power plants are expensive to build and require substantial infrastructure for the delivery and storage of coal and the removal of ash and other captured pollutants.

A much larger area is required for a coal plant than for a natural gas combined-cycle (NGCC) plant. Thus, coal plants require careful site selection and design. Even then, their impact on the environment and local communities can be greater than that of nuclear plants.

Pulverized coal combustion is the primary technology used to generate electricity from coal. Flue-gas-treatment technology to control emissions on new coal plants is very effective in reducing criteria emissions to very low levels.

Plant generating efficiency can range from about 35 percent to as high as 43 percent for ultrasupercritical steam technology.

Fluidized-bed technology is another approach to coal combustion which, compared with pulverized coal combus-tion, offers much broader operating flexibility with respect to coal type. It also allows the combustion of a range of other materials mixed with the coal, such as the co-firing of biom-ass, wood wastes, and so on. Efficiency and emissions con-trol are similar to that of pulverized coal.

Integrated gasification combined cycle (IGCC) involves gasification of coal to produce synthesis gas, cleaning the syngas, and then burning it in a combustion turbine. The power generation block for an IGCC plant is similar to that of an NGCC plant. The syngas-burning combustion turbine is connected to a generator; the steam raised from cooling the turbine exhaust powers a steam turbine. Typical generat-ing efficiency is about 39 percent. The technology is com-mercial, but issues of operability and availability need fur-ther resolution. With IGCC, emissions including mercury and other toxics can be extremely low (unlike the case of pulverized coal with current technology), because the gases are all fully contained at high pressure. Coal ash from the IGCC process is fused and exits as a much less-leachable solid than fly ash. IGCC also allows for co-firing with biom-ass. Gasification provides for the most effective route to the capture of carbon dioxide for sequestration, and IGCC is projected to produce the lowest-cost power from any tech-nology with carbon dioxide capture.

Whereas coal-fired power plants produce the lowest-cost power (without carbon dioxide capture), the requirements for large sites and extensive infrastructure limit the potential for the New York City area. In addition, air emissions and other environmental and community issues are likely to cre-ate considerable opposition to them in heavily populated ar-eas. High capital costs and uncertainty of success in con-struction are likely to discourage investors. Nevertheless, the potential, particularly of the advanced IGCC technology, is so great that coal should be considered an option, at least for New Yorks upstate regions. The remainder of Appendix D-5 explores emissions control, probably the most conten-tious issue for coal plants.

Emissions Control for Pulverized Coal (PC)

Combustion Units Typical flue-gas-cleaning configurations for coal-fired power plants are shown in Figure D-5-1. U.S. emissions data are typically given in terms of energy inputfor example, pounds per million British thermal units (Btu)and are thus independent of generating efficiency. This does not drive generating efficiency, as would an emissions limit based on output, such as pounds per megawatt (electric)-hour (MWe-h). Emissions below are presented in milligrams per cubic meter (mg/Nm3). The pulverized coal (PC) emissions are typically for supercritical PC units that are operating at about 39 percent (higher heating value [HHV]). Those for IGCC are for a unit that has 38 to 40 percent efficiency (HHV).

Low -NOx Burners SCR FF and/or ESP FGD Low -NOx Burners SCR FF and/or Cold ESP FGD WESP FIGURE D-5-1 Emissions control options for coal-fired genera-tion. NOTE: NOx: oxides of nitrogen; SCR: selective catalytic re-duction; FF: fabric filter; ESP: electrostatic precipitation; FGD:

flue-gas desulfurization; WESP: wet ESP.

1James R. Katzer is a member of the Committee on Alternatives to In-dian Point for Meeting Energy Needs and a former manager of strategic planning and program analysis at ExxonMobil Corporation.

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APPENDIX D 107 Figure D-5-2 shows how emissions of SOx and NOx are likely to continue to decline for many years, despite growing electricity generation. Figure D-5-3 compares the emissions potential for various technologies. Table D-5-1 lists the cost of electricity with various levels of emissions control.

Particulate Control Particulate control is typically accomplished with elec-trostatic precipitators (ESPs) or fabric filters. ESPs or fabric filters are installed on all U.S. PC units and routinely achieve

>99 percent particulate removal. Greater particulate control is possible with enhanced performance units or with the ad-dition of wet ESP (WESP) after flue-gas desulfurization (FGD) (Oskarsson et al., 1997), as illustrated in the second set of technologies in Figure D-5-1. The addition of wet ESP is beginning to become standard U.S. practice for new units to control condensable particulate matter (PM) and should achieve emissions levels less than 5 mg/Nm3 at 6 percent O2.

Typical emissions for modern, efficient, U.S. PC units are 15 to 20 mg/Nm3. New units in Japan are achieving 5 mg/

Nm3 (PowerClean, 2004). Level of control is affected by coal type, sulfur content, and ash properties.

SOx Control Partial flue-gas desulfurization is accomplished by dry injection of limestone into the ductwork just behind the air preheater for 50-70 percent removal, with recovery of the solids in the ESP. Wet flue-gas desulfurization (wet lime scrubbing) can achieve 95 percent SOx removal without ad-ditives and 99+ percent SOx removal with additives (Os-karrson et al., 1997; Emissions Performance of PC Units, personal communication from ALSTOM, Windsor, Con-necticut, 2005). Wet flue-gas desulfurization has the great-est share of the market in the United States, is well proven, and is commercially established. Typical U.S. commercial performance is 150 to 170 mg/Nm3 at 6 percent O2,2 because this is what their permits require. Recently permitted units have much lower limits, and still lower emissions levels can FIGURE D-5-2 Past and projected U.S. emissions from fossil power generation, 1965 to 2030.

0 5

10 15 20 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030 Year Million Tons 0

500 1,000 1,500 2,000 2,500 3,000 3,500 Billion kWh SO2 NOx Electricity Generation Projected with CAIR Projected 2005 Clean Air Interstate Rule and Mercury Rule Caps for 2015:

SO2 = 2.5 million tons; NOx = 1.3 million tons; mercury = 15 tons.

2When input-based standards such as lb/MMBtu are compared, the re-spective degree of dilution of the flue gas needs to be specified in terms of flue-gas O2 concentration. All values here are given for 6 percent O2 which is the international standard; boiler emission standards in the United States are typically given for 3 percent O2.

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108 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER be expected as permit levels are further reduced. The tech-nology has not reached its limit of control. The best PC units in the United States burning high-sulfur bituminous coal are achieving demonstrated performance of less than 0.04 lb SO2/MMBtu or 40 mg/Nm3 (Emissions Performance of PC Units, personal communication from ALSTOM, Windsor, Connecticut, 2005); those in Japan operate below 75 mg/

Nm3. The wet sludge from the FGD unit must be disposed of safely.

NOx Control Low-NOx combustion technologies, which are very low cost, are always used and give up to a 50 percent reduction TABLE D-5-1 Electricity Cost from Coal with Emissions Controls Cost of Electricity Level of Emissions Control (cents/kWe-h)

PC generation without SOx or NOx controls, but with ESP for particulates 4.08 Todays PC unit with SOx and NOx controls 4.75 2015 PC unit, tighter SOx, NOx, and mercury 4.97 FIGURE D-5-3 Types of power plants.

0.41 0.15 0.06 0.31 0.17 0.15 0.01 0.002 0.027 0.02 0.015 0.01 0.08 0.02 0.015 0.053 0.01 0.01 0

0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 Traditional PC Retrofit Older PCs w/Scrubbers and SCR (using low-S Coal)

Advanced PC/SCPC/CFB IGCC w/MDEA Absorber IGCC w/Selexol and SCR NGCC w/SCR Type of Power Plant lb/MMBtu NOx SO2 PM10 from noncontrolled combustion. The most effective, but also the most expensive, technology is selective catalytic reduc-tion (SCR), which can achieve >90 percent NOx reduction over inlet concentration. Selective noncatalytic reduction falls between these two in effectiveness and cost. Today, SCR is the technology of choice to meet very low NOx lev-els. Typical U.S. commercial emissions control performance is 65 to 90 mg/Nm3. The best PC units in the United States are achieving demonstrated performance of 0.03 lb NOx/

MMBtu or 30 mg/Nm3 on sub-bituminous coal and 60 mg/

Nm3 on bituminous coal. The Parish plant, burning Powder River Basin coal, is achieving 0.03 lb/MMBtu, which is 30 mg/Nm3. The best PC units in Japan are achieving 30 to 50 mg/Nm3 at 6 percent O2.

Mercury Control Mercury in the flue gas is in the elemental and oxidized forms, both in the vapor and as mercury that has reacted with the fly ash. This third form of emissions is removed with the fly ash, resulting in 10 to 30 percent removal for bituminous coals, but less than 10 percent for sub-bituminous coals and lignite. The oxidized form is effectively removed by wet FGD scrubbing, resulting in 40-60 percent removal for bitu-minous coals and less than 30-40 percent removal for sub-bituminous coals and lignite. For low-sulfur sub-bituminous coals and particularly lignite, most of the mercury is in the elemental form, which is not removed by wet FGD scrub-Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX D 109 bing. SCR for NOx control can convert up to 60 percent of the elemental mercury to the oxidized form, which is re-moved by FGD (EPA, 2005). Additional mercury removal can be achieved with activated carbon injection and an added fiber filter to collect the carbon. This technique can achieve 85-95 percent removal of the mercury. Commercial short-duration tests with powdered, activated carbon injection have shown removal rates around 90 percent for bituminous coals but lower for sub-bituminous coals (EPA, 2005). Research and development are currently evaluating improved technol-ogy that could reduce costs and improve effectiveness. The general consensus in the industry is that improved technol-ogy will change this picture significantly within the next few years.

Emissions Control for Integrated Gasification Combined-Cycle Technology IGCC has inherent advantages for emissions control be-cause the cleanup occurs in the syngas, which is contained at high pressure, and contaminants have high partial pressures.

Thus, removal can be more effective and economical than cleaning up large volumes of low-pressure flue gas.

Particulate Control The coal ash is primarily converted to a fused slag, which is about 50 percent less in volume and is less leachable than fly ash; as such, it can be more easily disposed of safely.

Particulate emissions from existing IGCC units vary from 1 to 8 lb/MWe-h. Most of these emissions come from the cool-ing towers and not from the turbine exhaust and as such are probably characteristic of any generating unit with large cooling towers. This means that particulate emissions in the stack gas are below about 1 mg/Nm3.

SOx Control Commercial processes such as MDEA and Selexol can remove more than 99 percent of the sulfur so that the syngas has a concentration of sulfur compounds that is less than 5 parts per million by volume (ppmv). The Rectisol process, which is more expensive, can reduce the SOx concentration to less than 0.1 ppmv (Korens, 2002). SO2 emissions of 0.15 lb/MWe-h, or 5.7 mg/Nm3 (2 ppm) have been demonstrated at the ELCOGAS plant in Puertollano, Spain (Thompson, 2005), and at the new IGCC plant in Japan. Recovered sulfur can be converted to elemental sulfur or sulfuric acid.

NOx Control NOx emissions from IGCC are similar to those from a natural-gas-fired combined-cycle plant. Dilution of syngas with nitrogen and water is used to reduce flame temperature and to lower NOx formation to below 15 ppm. Further reduc-tion to single-digit levels is achievable with SCR. NOx emis-sions of 4.2 mg/Nm3 (2 ppm) NOx (at 15 percent O2) have been demonstrated commercially in the new IGCC unit in Japan.

Mercury Control Commercial technology for mercury removal in carbon beds is available. For natural gas processing 99.9 percent removal has been demonstrated, as has 95 percent removal from syngas (Parsons, 2002). Mercury and other toxics that are also co-captured in carbon beds produce a very small volume of material, which must be handled as a hazardous waste. Carbon capture will likely inhibit re-release into the environment.

Water Usage PC and IGCC technologies both use significant quantities of water, and treatment and recycling are increasingly im-portant issues. IGCC uses 20 to 50 percent less water than do PC plants. Wastewater treatment technology has been dem-onstrated for both technologies. Proven water treatment tech-nology is available to handle the water effluents from each technology.

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110 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER APPENDIX D-6 GENERATION TECHNOLOGIESWIND AND BIOMASS Dan Arvizu1 This paper summarizes an analysis performed by NREL under my direction and supervision to evaluate the potential of wind energy and biomass resources to generate electricity to meet the future energy needs in the area currently sup-plied by the Indian Point Nuclear Power Plant near New York City. This analysis discusses the potential for three sources of wind energy and several sources of biomass, and the underlying assumptions and issues related to the projec-tions of potential.

Some important observations include the following:

The technical potentials (market size constrained only by the ability of technology to meet customer need and not by economics or other considerations) for both wind and bio-mass are very substantial, on the order of 9-10 GW in the Indian Point service area.

The achievable potentials for both are significantly less than the technical potential, on the order of 3 GW in 2014, but still substantial enough to replace the Indian Point capac-ity by that time.

Wind systems can be placed in the Hudson Valley right now, and, to a small extent, in the rural areas (northeast) of Long Island, within 10 miles of a transmission corridor.

Offshore wind could meet most of the Indian Point load by 2014. Canadian wind and hydro are reasonable options to explore in the meantime.

Biomass in the form of municipal solid waste could provide half of the Indian Point capacity in 2014.

Studies should continue to resolve wind-related issues such as transmission, dispatchability, siting and permitting, and biomass-related issues such as public perception, im-proved technology costs, and tipping fees.

Table D-6-1 summarizes quantitatively the potential impact of wind and biomass resources on the Indian Point service area, both in terms of technical potential and achievable potential.

Wind Contribution Much relevant work has been done recently and is cur-rently underway regarding wind power in New York. This analysis will outline broad issues and deployment options that could be considered as part of the electrical energy and capacity replacement, with reference to the recent work.

In addition to being renewable, wind power has charac-teristics that are different than conventional, dispatchable re-sources. First, the fuel source is controlled by nature, re-sulting in variable power output that is not controlled by the utility schedulers and dispatchers. This has two main impli-cations to consider: (1) the capacity credit in the long term and the reliability value of wind to meet peak demand, and (2) the impact of wind variability on grid operations in the short term resulting from increased regulation, load follow-ing, and unit commitment burdens on other generators.

Second, the fuel cannot be transported. The wind tur-bines must be located in areas of good wind resource, which may or may not have access to existing transmission lines.

Therefore, any comprehensive look at wind power potential must factor in questions such as:

Proximity of wind resources to the existing grid,

Available transmission capacity on existing lines (tem-poral profiles can be important),

Potential for upgrading capacity of existing lines and existing corridors, and

Costs and siting issues for any necessary new transmis-sion connections.

The analysis below broadly discusses three wind-based options, including issues of resource, cost, reliability, and transmission (deliverability). The purpose is to broadly de-scribe what is known, what the quantitative potentials may be, and what remaining issues could be examined to further define the potential.

Option 1: Land-Base, In-State Wind Development Resources

There is adequate raw and developable wind resource in the state to generate the energy equivalent of Indian Point, over and above current state RPS needs.

In the future, increased hub heights, low wind speed turbine developments, and better wind resource information will likely expand the resource estimate.

Site-specific permitting issues may remain, and could be impacted by local and state policy.

Costs

Generally, land-based bus bar wind costs are in the 3-7¢/kWh range (not including the federal 10-year 1.8¢/kWh Production Tax Credit, which currently applies to projects online by 12/31/05).

Costs are expected to continue to decline incrementally due to increased efficiency, taller towers, and manufacturing volume. (However, it should be noted that near-term costs have increased slightly due to the euro exchange rate, cost of steel, and other temporary factors.)

1Dan Arvizu is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs and the director and chief executive of the National Renewable Energy Laboratory.

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APPENDIX D 111

Further examination of the details of the GE/

NYSERDA wind integration and the Regional Greenhouse Gas Initiative work would likely yield specific site-based cost/supply curves.

Additional grid operating costs have been found to be in the 0.2-0.5 ¢/kWh range for a variety of U.S. utilities and up to 20 percent penetration by nameplate.

Operating costs were considered in the GE/NYSERDA study, but these additional costs were not reported separately from total costs. Little regulation impact and no impact on reserve requirements were found. Scheduling impacts were identified, and improvements in forecasting could bring costs down.

Specific operational costs for higher wind generation scenarios are unknown, but the study framework and meth-ods exist.

For the GE 3,300-MW wind scenario, the increase in system costs was projected to range between $582 million and $762 million for renewable projects. It is expected to be offset by approximately $362 million in wholesale energy cost reductions as New York reduces its reliance upon fos-sil fuels.

Transmission

The GE study examined load-flow impacts of a 3,300-MW wind generation scenario for RPS compliance and found no significant upgrade needs.

Grid stability was found to be generally enhanced by the installation of new turbine technology incorporating power electronics and fault ride-through capability.

Much of the land-based resource is located upstate, on the wrong side of the bottlenecks near Indian Point.

Likely, significant upstate wind additions for Indian Point replacement would require some grid reinforcement.

Specific needs are speculative, but the study methods and data are known.

Generally, transmission costs, including new lines, are an order of magnitude lower than generation costs.

Transmission permitting and construction times are in the 10-year time frame. Wind plants can come online in 1-3 years total. Grid operators in TX and CA are examining in-novative solutions to this mismatch.

Due to resource variability, the potential exists for av-erage line utilization factors to be low on lines serving pri-marily wind generation.

Temporal line loading profiles could be examined to determine if increased wind energy could flow on existing lines with limited curtailment during critical times.

Reliability

Effective load carrying capability studies in the GE/

NYSERDA study show low values, averaging 10 percent, therefore a land-based wind-only replacement of the peak load capability of Indian Point is not feasible.

Other opportunities could be examined to complement the energy-dominated value of wind with other generators, including:

Hydro: In-state resources of around 4.5 GW have an average utilization factor of around 50 percent, indicating a water-limited resource. If other flow regulations (environ-mental, recreation, etc.) allow, water could be retained for peak demand needs as a result of wind energy meeting off-peak and shoulder needs.

Simple cycle fast ramp generators: Simulations show an economic advantage for new, low-capital-cost gas gen-eration run for very minimal peak hours in conjunction with wind as an optimum solution (saving expensive gas, but get-ting reliability benefit). These super peakers can also be located optimally on the transmission system.

Other electric storage systems could potentially help:

pumped hydro, and compressed air being the most economi-cal. Longer term, a transition to plug-in hybrid vehicles could TABLE D-6-1 Estimate of Potential Impact of Renewable Generation Technologies on Indian Point Service Area Today 2009 2014 Wind and Capacity Generation Capacity Generation Capacity Generation Biomass Potential (MW)

(GWh)

(MW)

(GWh)

(MW)

(GWh)

Tehnical Wind onshore 2,294 5,310 2,294 5,310 2,294 5,310 Wind offshore 5,200 17,082 5,200 17,082 5,200 17,082 Biomass 1,502 10,560 1,502 10,560 2,233 15,680 Subtotal 8,996 32,952 8,996 32,952 9,727 38,072 Achievable Wind onshore 0

0 229 531 459 1,062 Wind offshore 0

0 300 986 1,800 5,913 Biomass 234 1,640 386 2,705 1,137 7,968 Subtotal 234 1,640 915 4,222 3,396 14,943 SOURCE: NYSERDA (2003).

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112 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER expand wind electricity markets and also provide grid stor-age support.

Option 2: Offshore Wind Development Resources

Shallow water resources (up to 20 m depth) exceed 5 GW potential for class 5 and above for Long Island. Deeper water resources (20-40 m depth) off Long Island exceed 40 GW potential.

Permitting issues for federal waters (>3 miles) are in flux, but the Long Island Power Authority is currently nego-tiating with a developer for a 160-MW development within the state water boundaries.

Visual and other concerns seem to be much less off Long Island than those associated with the Cape Wind project in Massachusetts.

Technologies for deeper water are under development, including deep water floating and tethered concepts. Great amounts of resources exist in these waters.

Costs

Off-shore capital cost estimates begin at $1,500/kW (roughly 50 percent more than on-shore) and go up. Euro-pean experience is relevant up to about 30 m depth. Higher, steadier wind speeds increase energy production, but O&M costs are generally higher. Current levelized cost is around 6¢/kWh at best.

Costs are expected to decline significantly, perhaps to less than 4¢ in shallow water, in the next decade.

Grid-operating cost additions would be expected to be similar to on-shore, with the possible caution that limited data from Horns Rev in Europe shows some higher ramp rates than on-shore.

Transmission

Off-shore is generally envisioned as being deployed near load centers. Some on-shore reinforcement may be needed, and an off-shore cable is needed. However, costs should be lower and siting difficulties should be minimal compared to on-shore transmission expansion.

The Long-Island off shore resource is on the load side of the transmission bottlenecks around Indian Point, further alleviating transmission concerns.

Reliability

The GE study found an effective load carrying capabil-ity (capacity factor) of 30 percent for Long Island off-shore resources. This is promising compared to on-shore.

Further study of great lakes resources would be neces-sary to quantify possible diversity benefits of multiple off-shore locations.

All the generator synergistic and storage options dis-cussed in on-shore could apply here, but needs might be a factor of three less per MW of wind.

Option 3: Imported Canadian Wind, Firmed with Canadian Hydro Resources

Canadian wind and hydro resources appear vast; fur-ther examination is needed.

Hydro Quebec imports some energy into New York already, and is willing to look at more, including wind/hydro blends.

There is some reluctance to promote additional large Canadian hydro for U.S. demand due to environmental and native population concerns.

Costs

Wind power costs should be similar to the U.S. land-based resources.

Operating cost additions from hydro are not well char-acterized, but should be minimal.

Bonneville Power in the United States has offered a shaping and firming product for wind that delivers a schedulable, flat block of equivalent wind power for an ad-ditional 0.6¢/kWh. Recent discussions indicate this price is well over actual cost and the price may drop as the utility gets more experience with the service.

Canadian hydro seems to be much less constrained by other river criteria than in the United States, so costs of vari-ability mitigation would be expected to be much lower.

Transmission

Studies of the capability of existing lines for importing additional power from Canada should be available, but were not researched.

At 2-GW levels, DC options become advantageous for new long lines. This could be considered for direct connec-tion to and near-equivalent replacement of Indian Point.

Hydro firming could essentially base-load the wind and levelize the transmission line loading at near full capacity.

Reliability

Hydro firming will essentially turn the wind into a base-load resource with equivalent reliability to Indian Point.

Options for shaping the energy to fit the full peaking and load following needs could also be examined, with some incremental impact on transmission due to lower average loading factors and/or higher line capacity needs.

Quantitative Estimates for Wind Estimates of wind resources in New York electric zones G, H, I, J, and K are presented in Table D-6-2. These zones are south of the major transmission bottlenecks from up-state New York generation to the New York City load.

Therefore, adding wind generation in these zones is not likely to require significant upgrade or additional transmis-sion line construction. This analysis used a high-resolution Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX D 113 wind map produced for NYSERDA by AWS Truewind in 2000. Higher-resolution data should now be available, and the analysis should be repeated.

As noted above, GE Energy and AWS Truewind Solu-tions have recently completed a look at integrating 3,300 MW of additional wind spread around the New York grid, finding no need for significant transmission upgrades or re-liability issues. In selecting locations for the 3,300 MW, GE identified 10 GW of likely wind locations. Much of that wind generation was postulated in upstate areas. For comparison purposes, the last column in Table D-6-2 shows how much of the 10 GW scenario is in each of the generation zones in question.

The numbers presented in Table D-6-2 assume 5 MW per square kilometer of windy land. Values are net after sub-tracting environmental exclusions defined as all national Park Service, Fish and Wildlife, other specially designated federal lands such as wilderness areas, monuments, etc., all highly protected as determined by land stewardship data from the Gap Analysis Program (GAP) of the U.S. Geologi-cal Survey, and half of the second highest GAP land stew-ardship category, remaining U.S. Forest Service, and De-partment of Defense land. No other land use exclusions were subtracted.

As shown, there is some potential for wind in the imme-diate vicinity of Indian Point. Most of the wind potential in Zone G is close to existing transmission corridors. However, Zones H, I, and J are some of the least windy areas of the state. Long Island shows significant onshore and offshore wind resource potential. Note again that offshore wind power peak times show a much better match to peak electric load demand as measured by Effective Load Carrying Capability (reliability-based capacity credit) than on-shore resources.

The operational, reliability, and transmission impacts of wind as a potential part of Indian Point replacement is best examined with detailed grid simulation. This will provide much better data on least cost solutions that may incorporate significant amounts of wind outside the zones tabulated in Table D-6-2.

Wind-Related Policy Options

On a $/MWh basis, wind is likely to be a low-cost, in-state option in 2007-2015, so broad state economic subsidy policy drivers may not be necessary.

It is likely that near-to mid-term worldwide markets for wind hardware will be supply limited. Manufacturing incentives may help build up supply capability, and help state economic development as well.

Wind is primarily an energy, not capacity source, so that system reliability issues are important. The GE tools called MARS (Multi-Area Reliability Simulator) and MAPS (Multi-Area Production Simulator) are a good framework for the grid issues to be examined. GE could examine sce-narios that include reliability synergies of possible benefit to wind, including:

In-state hydro dispatch modifications Canadian hydro contract modifications to provide additional ancillary services (indications are they have dis-patch flexibility)

Options for additional Canadian hydro (it appears current Day Ahead and Real Time Hydro Quebec imports are bounded at about 1,500 MW, so additional transmission may be needed)

TABLE D-6-2 Quantitative Estimates of Wind Potential in Indian Point Zones Zone Complete Wind Resource, Resource Within 10 Miles Postulated Possible Development After Environmental Exclusions; of Existing Transmission; (out of 10 GW total) in GE NYSERDA Power Class 3, 4, 5, and above Power Class 3, 4, 5, and above Renewable Portfolio Standard Study Zone G 528, 129, 90 MW 436, 110, 84 MW 154 MW Zone H 0, 0, 0 0, 0, 0 0

Zone I 0, 0, 0 0, 0, 0 0

Zone J 0, 0, 0 0, 0, 0 0

Zone K 2,116, 431, 73 MW (onshore)a 1,482, 177, 5 MW (onshore) 600 MW NOTE: The wind resource potential is essentially constant with time, so the numbers can be used over the complete 2007-2015 study time frame. Between-turbine spacing to prevent excessive induced downwind turbulence is normally computed as a multiple of rotor diameter. In this assessment we have assumed a turbine density of 5 MW per square kilometer, independent of turbine size. Energy output per unit of nameplate capacity is expected to increase slightly over the time period due to incremental improvement in machine efficiency and higher average wind speeds resulting from increasing tower height. Because of increased energy delivery, there may be a corresponding incremental increase in reliability (capacity credit) values.

aOver 5,200 MW of offshore class 5 and better wind is located in water less than 20 m deep.

bOffshore within state 3 mile limit.

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114 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER Examination of competitive market structures that would motivate other resources to provide additional ancil-lary service levels Examination of transportation market modifications (plug hybrids and hydrogen) that would decrease the need for grid ancillary services imposed by wind

Grid-level issues like transmission and operational is-sues for increased wind deployment should continue to be examined, through public funded mechanisms like NYSERDA or through allowing NYISO or others to recover appropriate costs from ratepayers.

Siting and permitting issues for both land-based and off-shore wind plants should be addressed, including proac-tive examination of potential wildlife issues.

Transmission costs are not large adders to generation costs. It is almost always cheaper to build transmission to a better wind resource than to use lower-class, closer wind.

Transmission planning, siting, cost recovery, and construc-tion issues need to be examined to reduce uncertainty and shorten the in-service timelines, if new transmission is nec-essary to serve wind.

Biomass Contribution Primary Source There have been extensive studies of the renewable bio-mass potential in New York. Information summarized in this analysis has been gleaned from the NYSERDA report En-ergy Efficiency and Renewable Energy Resource Develop-ment Potential in New York StateFinal Report, dated Au-gust 2003. (Prepared by Optimal Energy Inc., ACEEE, Vermont Energy Investment Corporation, and Christine T.

Donovan Associates.)

Geographical Basis The zones of interest in the NYSERDA report are G, H, I, J, and K. Since biomass is generally assigned on a county basis, the relevant counties are (again working northwest to southeast): Delaware, Ulster, Green, Columbia, Sullivan, Dutchess, Orange, Putnam, Rockland, Westchester (location of Indian Point), Richmond, Nassau, and Suffolk. The report also has time horizons of 2007, 2012, and 2022.

Background on Biomass Availability The regions other than Delaware, Sullivan, and Ulster are increasingly heavily populated as one goes from NW to SE.

Thus six of the existing 10 waste-to-energy facilities are in this region. These six already generate 68 percent of the total 2.15 TWh generated in 2000. The regions net capacity is 156 MW.

Urban residues are a huge resource, but are not viewed as clean from the NY-RPS definition. Public acceptance is low and to comply with federal, state, and local regulations, the cost of the facilities has reached over 8,000 $/kW.2 Thus even with a tipping fee, there is presently a lower-cost alter-native in burial of the wastes out of state.

The report assumes continuing use of mass burn technol-ogy. For the regions defined above, the capacity would be unchanged until 2012 when the report proposes 76 MW ad-ditional located in NYC. By 2022 a further 166 MW would be added, also in NYC.

Cleaner biomass resources include: mill residues (from primary and secondary wood processing); silviculture resi-dues; site and land conversion residues; wood harvest; yard trimmings; construction and demolition (C&D) wood; pal-lets; agricultural residues; bio-energy crops; animal and avian manure, and wastewater methane.

Supply curve: Ideally the availability of these resources could be combined with the potential technologies to derive a supply curveGWh vs cost. The current data is not ad-equate to do this at the regional scale. Statewide the sum of these resources amounts to 0.24 quad in 2003, and 0.4 quad in 2022, with the increase primarily due to a large energy crop contribution. In the regions identified for the Hudson Valley to Long Island, the resource base is primarily urban residues (ranging from MSW to C&D wood) in the time-frame to 2012. After 2012 additional energy crop biomass could be developed. For this region the assumption is that the 2012 availability would about 0.015 quad. Upstate New York has a far higher potential due to forest and agricul-tural potentials.

Table D-1-3 assumes two biomass pricesbiomass (e.g wood chips from forestry operations) at $2.50/106 Btu, and MSW at -$2.50/106 Btu. The negative cost reflects a tipping fee. A reasonable blended price for the urban residue gen-eration in the zones considered would be $1.00/106 Btu (2002). More detailed study would be needed to arrive at a more precise estimate of the proportions of material with a significant tipping fee, and those for which transportation would be a larger factor.

Technical potential: Applying these resources to the load zones G, J, and K, the 2003 technical potential would be 203 MW generating 1.423 TWh (capacity factor is 7,000 h/y, heat rate 10,500 Btu/kWh, i.e., 32 percent efficient). The technical potential in 2022 would be 295 MW, with the main part of the growth being in the Hudson Valley (zone G).

Technologies There are three technologies in the NYSERDA report:

CHP, co-fire, and gasification. Assumptions in the report are 2While the report quotes $8,000/kW, a modern mass burn facility of 2,000 tons per day mass capacity would have a rated capacity of 80 MW, the maximum allowed by law, and would cost about $150,000 to $200,000 per ton of daily capacity. These industry-recognized data (unpublished) give a maximum estimated cost of $5,000 per kW.

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APPENDIX D 115 for CHP to grow statewide, mainly in the pulp and paper sector. However, in the regions of interest, there would be a zero contribution of CHP.

Co-fire would be possible in the Hudson Valley. How-ever, this is not an incremental generation of net power as the biomass displaces coal in an existing facility. Approxi-mately 100 MW of the potential 203 MW would be in co-firing in the report.

Gasification in the study would be applied to low-cost construction and demolition debris more or less at the point of generation in NYC (zone J) with approximately 100 MW capacity.

Conclusion from the 2003 Report The near-term potential in the region is about 200 MW with an 80 percent annual capacity factor. With attention to energy crops in the Hudson Valley this could increase to 300 MW. A further increment could come from the urban resi-due stream but would require a change in technology to over-come public resistance and very high investment cost barriers.

Economics: Assuming that gasification was to be used for all biopower applications (i.e., no CHP or co-firing con-tribution), the economic parameters assumed include an in-vestment level (2002) of $1,700/kW, and a fuel cost of about

$1/GJ. This fuel cost is a blended price from very low cost C&D material to some forest residues at $2.50/GJ. The pro-posed technology is based on an IC engine technology with a medium-heating-value gasifier system. The scale would be in the range of 20-40 MW with a heat rate of 35 percent (9,000 Btu kWh-1). The fleet of gasification IC engine units would be between 5 and 12 depending on size. Modularity is assumed as well as a series production of units to achieve the investment cost proposed.

Cost per kWh: Using the same financial assumptions as in Appendix D-1 above, the busbar cost before distribution would be $0.045/kWh.

An Alternative View Table D-6-3 contains both technical potential data and an estimate of achievable potential that exceeds the values pro-posed on the basis of the Energy Efficiency and Renewable Energy Resource Development Potential in New York StateFinal Report, dated August 2003. Similar cost and performance of the biomass-to-electric technologies are as-sumed in the report and Table D-6-3, such that the technical potential is the same. The differences in achievable potential result from valid differences in optimism about economics, technology, and non-monetary barriers.

The New York State report was constrained by an eco-nomic assumption framework for a period up to about 2001.

This is essentially a business-as-usual framework that did not assume the loss of the nuclear capacity, nor the recent rapid changes in fossil energy prices (coal, oil, and gas), nor the more aggressive renewable energy framework of state RPS and increased federal and state incentives. Thus, for MSW/CDW shown in Table D-6-3, the difference between 398 MW in 2022 in the report, and the achievable potential TABLE D-6-3 Biomass Potential Applicable to Indian Point Today 2009 20014 Potential Capacity Capacity Generation Capacity Generation (MW)

(MW)

(TWh)

(MW)

(TWh)

Achievable MSW/CDW 233.8 365 2.56 1,096 7.68 Biogas (Sewage) 20 0.14 41 0.32 Total biomass 386 2.72 1,137 8.00 Technical MSW/CDW 1,461 10.24 2,192 15.36 Biogas 41 0.32 41 0.32 Total biomass 1,502 10.56 2,233 15.68 NOTE: Counties in region: Bronx, Kings, New York, Queens, Richmond, Columbia, Delaware, Dutchess, Greene, Nassau, Orange, Putnam, Rockland, Suffolk, Sullivan, Ulster, Westchester. Population dataNew York State Data Center, http://www.nylovebiz.com/nysdc/data_economic.asp (Aug 10, 2005). MSW per capita generationnational average from Biocycle, Apr 2004, v45, n4, p22 (1.31 ton/per capita/annum);

this number includes C&D wood. Biogas = 1 ft/per capita/day@640 Btu/ft3 Roberts and Hagen, UC Davis, 1978. Existing Capacity, Renewable Electric Plant Information System, NREL, 2002 data. Assumption for solid feeds: 80% capacity factor, 20% efficiency in 2009, 30% efficiency in 2014. Assumption for biogas:

35% efficiency, 80% capacity factor. Did not factor in population growth for this version. Existing genera-tion is for 2004, estimated from EIA Form 906.

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116 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER of 1,096 MW for 2014, represents the difference between a very conservative forecast and one in which many of the nonmonetary barriers, and some of the cost barriers, are reduced.

The disparity can only be resolved by a more substantial analysis in which there is a regionwide supply curve for bio-mass electricity generation at specific locations based on GIS supply and demand analysis.

Supporting Discussion for Biomass Potential Table Technical Potential The amount of capacity or power which is possible by using a technology or practice in all applications in which it could technically be adopted, without consideration of its costs.

Assumptions Counties in regionThe counties are Bronx, Kings, New York, Queens, Richmond, Columbia, Delaware, Dutchess, Greene, Nassau, Orange, Putnam, Rockland, Suffolk, Sullivan, Ulster, Westchester

1. Population Data: 2004 estimate from the New York State Data Center (http://www.nylovebiz.com/nysdc/data_

economic.asp, August 10, 2005). Population growth was not factored into the 2009 and 2014 estimates, but can be in fu-ture updates.

2. 1.31 tons MSW per capita per year. This was the na-tional average generation from Biocycle, Apr 2004, v45, n4, p22 (individual states not given). The number may include construction and demolition wood. Since then the actual Biocycle survey (The State of Garbage in America, Biocycle, January 2004) was obtained. The New York esti-mate is 1.29 tons/per capita/year. Since the value is close the original estimate was not corrected.

3. The existing capacity estimate was taken from the Re-newable Electric Plant Information System (REPIS), NREL, 2002 data. The data are on a state and regional basis. Exist-ing biogas generation (primarily landfill gas) was not in-cluded.

4. Existing generation was taken from the EIA Form 906/

920 using 2004 data (http://www.eia.doe.gov/cneaf/electric-ity/page/eia906_920.html, August 10, 2005). Form 906 gives capacity and generation information for all power plants in the United States. Form 906 was not used for capacity since not all data entries include a reported capacity.

5. Assumed basis is higher heating value.

6. Biomass potential was based on Oak Ridge National Laboratory, Biomass Feedstock Availability in the United States, State Level Data, 1999.

7. Sewage biogas was estimated using 1 ft3/per capita/

per day with a heat content of 640 Btu/day based on an old reference: E.B. Roberts and R.M. Hagen, Guidelines for the Estimation of Total Energy Requirements of Municipal Wastewater Treatment Alternatives, a report to the Califor-nia State Water Control Board, University of California at Davis, 1977.

8. MSW heating value (5,000) Btu/lb (dry) was taken from W.R. Niessen, C.H. Marks, and R.E. Sommerlad, 1996, Evaluation of Gasification and Novel Thermal Pro-cesses for the Treatment of Municipal Solid Waste, 196 pp.,

NREL Report No. TP-430-21612. Values used for wood and agriculture residues/energy crops were 8,000 and 7,500 Btu/

lb dry, respectively.

9. Efficiency and capacity assumptions a.

Biogas35 percent efficiency (IC engine), 80 per-cent capacity factor

b. Solid feeds

i. 20 percent efficiency (mass burn or stoker grate),

80 percent capacity factor from R.L. Bain, W.P. Amos, M. Downing, and R.L. Perlack, 2003, Biopower Technical Assessment: State of the Industry and the Technology, NREL Report No. TP-510-33123, Jan., Golden, CO.

ii. 30 percent efficiency (gasification), 80 percent capacity factor from W.R. Niessen, C.H. Marks, and R.E.

Sommerlad, 1996, Evaluation of Gasification and Novel Thermal Processes for the Treatment of Municipal Solid Waste, 196 pp., NREL Report No. TP-430-21612.

Calculation Procedure

1. Biomass

a. Generation estimated by multiplying resource by heating value, converting to kW thermal, and multiplying by assumed efficiency to obtain kWh electric

b. The capacity factor was used to estimate capacity:

MWh divided by hours per year divided by capacity factor.

2. MSW/CDW and Biogas

a. Generation estimated by multiplying population estimate (both regional and state) by per capita genera-tion, multiplying by heating value, converting to kWh ther-mal, and multiplying by assumed efficiency to obtain kWh electric.

b. The capacity factor was used to estimate capacity:

MWh divided by hours per year divided by capacity factor.

Market Potential

1. Technical Potential

a. Assumes 100 percent utilization of estimated feed-stock.

b. In 2009, the assumption is that the process will be mass burn or stoker grate for solid feeds.

c. In 2014, the assumption is that the process will be gasification for solid feeds.

d. IC engines at constant efficiency assumed for biogas.

e. Although co-firing is by far the least expensive op-tion for electricity generation, it does not increase capacity, i.e., considered fuel substitution and was not included.

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APPENDIX D 117

a. For Biomass and MSW/CDW

i. An RPS and a Section 45 tax credit are assumed as market intervention factors.

ii. A Section 45 type credit (value not estimated) is extended to CHP systems heat production to encourage maximum process efficiency.

iii. A 25 percent penetration is assumed in 2009.

iv. With the use of higher efficiency, lower emis-sions, and lower-cost gasification technologies the penetra-tion rate is increased to 50 percent in 2014.

v. For energy crops a low penetration is assumed, 5 percent in 2009 and 10 percent in 2014. The value is greater that zero to recognize the progress made in dedicated crops (willow) by projects such as the Salix project.

b. Since biogas (sewage) is already being generated, and because the generation of electricity should give lower emissions than flaring, a high penetration should occur. Fifty percent is assumed in 2009, and 100 percent in 2014.

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118 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER APPENDIX D-7 DISTRIBUTED PHOTOVOLTAICS TO OFFSET DEMAND FOR ELECTRICITY Dan Arvizu1 This appendix summarizes an analysis performed by NREL under my direction and supervision to evaluate the potential of distributed photovoltaics (PV) to offset the fu-ture electricity generation and capacity needs in the area cur-rently supplied by the Indian Point Nuclear Power Plant near New York City. This analysis provides an overview of PV markets, an analysis of the potential for PV to help replace the electricity capacity and generation from the Indian Point nuclear power station in New York State, a summary of New Yorks current policies related to PV technology, and an ac-celerated PV deployment scenario for New York through 2020.

Some important observations include:

The technical potential for rooftop PV in New York is very largeon the order of 35-40 GW statewide and 18-20 GW in the Hudson Valley, NYC, and Long Island control areas. Reaching this potential will require time to scale up the market infrastructure and production capacity for PV.

Given that PV is a distributed generation technology it competes against retail, not wholesale, electricity rates.

Given that PV is a distributed generation technology and that its production profile is highly coincident with peak demand it can contribute significantly to grid stability, reli-ability, and security. Thus, from a planning perspective PV should be valued at a rate higher than the average retail rate.

The cost of PV-generated electricity is expected to de-cline considerably over the next decade, falling from a cur-rent cost of 20-40 cents/kWh to a projected cost of 10-20 cents/kWh by 2015.

Given that Indian Point is a ~2 GW base load plant, operating roughly 95 percent of the time, it would be very difficult for PV alone to replace all of the generation from Indian Point during the next 5-10 years.

By pursuing a strategy that would combine PV with other technologies, such as efficiency, wind, hydro, and stor-age, PV should be able to replace 15-20 percent of the gen-eration of Indian Point and 80-90 percent of the capacity of Indian Point during peak periods by 2020.

Under an aggressive but plausible accelerated PV deploy-ment scenario, roughly 50 MW of PV systems could be in-stalled in New York by 2009 (generating roughly 80 GWh of electricity), and 470 MW of PV systems could be installed in New York by 2014 (generating 700 GWh of electricity)

(see Table D-7-1). This level of PV installations in 2014 could offset about 30 percent of Indian Points capacity dur-ing peak periods and about 4 percent of Indian Points an-nual electricity output. In addition, under the accelerated sce-nario about 1 GW of PV systems could be installed in New York by 2016, generating 1,500 GWh of electricity (offset-ting about 40-50 percent of Indian Points capacity during peak periods and 9 percent of Indian Points annual electric-ity output). Realizing this accelerated scenario would require making a clear long-term commitment, in terms of both poli-cies and resources, to expanding New Yorks existing PV programs. Perhaps more importantly such an initiative would establish a self-sustaining PV market in New York, resulting in an additional 1 GW of PV being installed in New York by 2020, generating 3,000 GWh of electricity (offsetting about 80-90 percent of Indian Points capacity during peak periods and 18 percent of Indian Points annual electricity output) without any public subsidies between 2016 and 2020.

Key PV Markets During the past decade the global PV market has been experiencing explosive growth. For example, during the past 5 years (1999-2004), the average annual growth rate of the global PV industry has been 42 percent. As shown in Figure D-7-1, the fastest growing PV market segments during this period were the grid-connected residential and grid-connected commercial segments. Such rapid growth has cre-ated tremendous excitement about PV technology around the world on the part of governments (EC, 2004), industry (SEIA, 2004; NEDO, 2004; EPIA, 2004), and the invest-ment community (CLSA, 2004). As shown in Figure D-7-1, during 2004 the global PV industry passed the 1 GW mark in annual installations. At this point in time the global PV industry is truly beginning to move into large-scale production.

The rapid growth in the global PV market during the past decade, shown in Figure D-7-1, was driven largely by gov-ernment subsidy programs, in particular in Japan, Germany, and a few states within the United States (including Califor-nia and New York). Over the coming decades, as costs con-1Dan Arvizu is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs and the director and chief executive of the National Renewable Energy Laboratory.

TABLE D-7-1 Estimated Distributed Photovoltaics in the Indian Point Service Area in the Accelerated Deployment Scenario 2005 2009 2014 2016 2020 Installed PV capacity (MW) 2 56 470 1,000 2,000 Generation offset by PV(GWh) 3 84 700 1,500 3,000 SOURCE: Derived from NYSERDA (2003).

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APPENDIX D 119 tinue to decline and subsidies are phased out, industry ana-lysts expect that the distributed grid-connected residential and grid-connected commercial markets will continue to expand rapidly and will become self-sustaining. Thus the grid-connected residential and commercial markets have emerged as key markets for developing and expanding the use of PV technology and are the logical place for New York State to focus its market development efforts over the next decade.

Technical Potential and Value of PV in New York State The technical potential for grid-connected residential and commercial PV in New York State is very largeestimates of the rooftop technical potential in 2025 are on the order of 35-40 GW (NYSERDA, 2003; Navigant, 2004). If one con-siders only the Hudson Valley, NYC, and Long Island con-trol areas, then the rooftop technical potential is on the order of 18-20 GW (NYSERDA 2003; Navigant 2004). This tech-nical potential is enough to generate 27,000 GWh of elec-tricity per year compared to the 16,700 GWh currently pro-duced at Indian Point Units 1 and 2.

Expanding the market toward this technical potential, however, will require time to develop both the market infra-structure and production capacity for PV. As noted above, global PV production exceeded 1 GW in 2004. Given that Indian Points capacity is ~2 GW with a capacity factor of

~95 percent, and that PV in New York State has a capacity factor of ~17 percent, replacing the equivalent of Indian Points generation with PV alone would require an installed PV capacity of >10 GW in New York State. Thus it would be unrealistic to expect New York State to be able to fully replace the generation from Indian Point with PV alone dur-ing the next 5 to 10 years.

In thinking about the potential contribution PV could make towards replacing Indian Point, it is important to em-phasis the technologys best attributes, i.e., PV can provide high-value peak-time power in a distributed fashion and with zero environmental emissions. The ability to install PV in a distributed fashion combined with its production profile en-able PV to contribute significantly to grid stability, reliabil-ity, and security (Perez et al., 2004b). Thus it would make sense to pursue a strategy that combines PV with energy conservation, other generation technologies (such as hydro and wind), and storage (e.g., a combination of pumped stor-age, compressed air energy storage, a variety of end-use stor-age technologies, etc.). Such a strategy would be designed to draw on the strengths of each of its components. For ex-ample, using hydro as a buffer for PV might be an attractive option. While major hydro facilities within New York State, such as Niagara Falls and Robert Moses (7 GW total), have limited buffers, it might be possible to use PV in combina-tion with imported Canadian hydro. This strategy would uti-lize PV generation combined with a limited amount of local energy storage to displace expensive on-peak demand, i.e.,

when transmission is likely to be constrained and the market 0

200 400 600 800 1,000 1,200 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 Year Annual Installation (MW)

GridCommercial GridResidential GridUtility Remote Habitation Remote Industrial Consumer Power Consumer Indoor Note: 1999--2004 average annual growth rate was 42%

FIGURE D-7-1 Global PV market evolution by market segment, 1985 to 2004. SOURCE: Strategies Unlimited (2005).

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120 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER clearing price is high, and to import Canadian hydro to meet off-peak demand, i.e., when transmission is available and the market clearing price is low.

With such a strategy PV might be able to realistically replace 15-20 percent of the generation of Indian Point and 80-90 percent of the capacity of Indian Point during peak periods by 2020 (the strategy as a whole would replace a much larger fraction of the generation from Indian Point).

This strategy could be implemented starting in relatively small increments, installing 10s of MW during the first couple of years and increasing installations to about 200 MW per year by 2015, resulting in a total installed PV capacity of

~2 GW by 2020 (as illustrated in the accelerated PV deploy-ment scenario discussed below). Such a goal could probably be achieved through a declining subsidy program that would enable the PV industry and market infrastructure to grow in New York State and enable regulators and policymakers to learn about how PV interacts with the grid in a controlled fashion.

Overview of PV Current and Projected Cost Through 2015 An overview of the current and projected cost through 2015 for PV technology is shown in Table D-7-2. As dis-cussed above the two key markets for PV are assumed to be distributed residential systems and distributed commercial systems; thus the high/low ranges are based on current and projected costs in these two market segments. As shown in the table, the current levelized cost of energy is roughly 20-40 cents/kWh, and the projected levelized cost of energy in 2015 is roughly 10-20 cents/kWh.

It is important to note that the costs shown in Table D 2 are to the end user, i.e., they should be compared to retail rather than wholesale electricity rates. In addition, since the production from PV is highly coincident with peak demand in New York,2 a strong argument can be made for valuing PV in a planning context at a rate higher than the average retail rate in New York. For example, Perez et al. (2004a) used the average NYISO day ahead hourly wholesale price of electricity data in the NYC metro area and Long Island regions during 2002 to estimate the solar-weighted whole-sale price, i.e., weighted by PV output. Using this detailed data they concluded that combining PV with a limited amount of load management (to enable PV to claim a ca-pacity value close to 100 percent) would have increased the value (i.e., the systemwide cost savings) of residential PV during 2002 from 15 cents/kWh (the average retail rate) to 21.3 cents/kWh in NYC and from 12 cents/kWh (the aver-age retail rate) to 20.3 cents/kWh on Long Island. As shown in Table D-7-2, if PV system owners could capture this value through interconnection rules, rate structures, etc.,

then PV technology could become a rapidly expanding and self-sustaining industry in New York State during the next decade.

TABLE D-7-2 Current and Projected Distributed PV Cost (2005 dollars)

Current (2004)

Projected (2015)

Low High Low High Capital cost ($/W) 6 8

3.5 4.5 O&M cost (¢/kWh) 3 6

1 2

DC-AC conversion efficiency (%)

93 91 95 95 Fuel cost (¢/kWh) n.a.

Levelized cost of electricity (¢/kWh) 23 38 12 20 Availability 17% CF, i.e., daylight hours only (without storage).

Reliability Very reliable, can help reduce stress on grid.

Environmental considerations Clean, quiet, and easy to site.

Site retrofit potential Limited: Requires ~100 sq. ft/kW could install ~50 MW using ~50% of the Indian Point site.

Other issues Very large technical potential, but will require time to penetrate market/develop market infrastructure.

NOTE: LCOE calculation assumes system is financed over the 30-year life of system. Low estimates are based on a commercial system with 17 percent capacity factor, 10 percent federal investment tax credit, federal accelerated depreciation, and 7 percent real (after tax) discount rate. High estimates are based on a residential system with 17 percent capacity factor and 4 percent real (after tax) interest rate. O&M costs are dominated by inverter replacement cost.

Current inverters lifetimes are 5-7 years, with expected lifetimes rising to 10-15 years over the next decade.

SOURCE: Based on data and projections in DOE (2004), Margolis and Wood (2004), and SEIA (2004).

2Letendre et al. (2003) analyzed data on the day ahead hourly wholesale price of electricity from NYISO from the summer of 2002, combined with satellite-derived solar resource data, and found that the average PV avail-ability for all 32 peak power price days in the summer of 2002 was 79 percent. In other words, on average in the NYISO control area, distributed PV systems would have been operating at roughly 80 percent of their ideal output during the days when power prices spiked above 20 cents/kWh in the wholesale market.

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APPENDIX D 121 Current Policies for PV in New York. New York has a fairly aggressive set of policies aimed at encouraging the adoption of PV technology. A detailed list of existing poli-cies is provided in Table D-7-3. As shown in the table, New York has put in place a combination of tax exemptions and credits, loan subsidies, rebates (administered by LIPA and NYSERDA), and standard interconnection and net metering rules. Only New Jersey has created a more comprehensive set of incentives for residents and businesses to install PV in the Northeast.

As shown in Table D-7-3, New York has an existing re-bate or buy-down program. The main program, adminis-tered by NYSERDA, is called New York Energy $mart and includes customers with all the major IOUs. New York En-ergy $mart provides customers who purchase and install PV systems with a $4/W rebate. This incentive in combination with state tax credits and exemptions has resulted in the in-stallation of over 1.5 MW as of summer 2005. The program currently has $12 million allocated to its PV incentive pro-gram, of which about $6.5 million has been reserved as in-staller/customer incentives. The remaining funding should take the program through 2006.

LIPA, the public utility serving Long Island, also has an existing PV incentive program called the Solar Pioneer Pro-gram. LIPA launched the Solar Pioneer Program in 1999 and offered customers a substantial rebate. The rebates bud-get is tied into LIPAs 5-year Clean Energy Initiative with a funding level totaling $37 million annually (covering mul-tiple technologies). The Clean Energy Initiative is expected to receive funding through 2008. To date, 511 rebates have been disbursed for PV systems totaling more than 2.63 MW installed on Long Island. LIPAs rebate is currently set at $4/W.

While the existing rebate programs are functioning well and expect to be fully subscribed this year, what is missing in New York is a clear long-term commitment of resources at the scale required to grow the PV industry in New York rapidly. Given New Yorks relatively high electricity pricesthe average residential electricity price in New York was 14.3 cents/kWh in 2003 (EIA, 2005)and reasonably good solar resources, with a long-term commitment of suffi-cient resources New York should be able to accelerate the growth of PV substantially over the next decade.

An Accelerated PV Deployment Scenario for New York.

The fact that the existing buy-down programs are well sub-scribed indicates that they are buying down the price of PV systems into a range that makes them economically attrac-tive to consumers. Given that current installed system prices are about $8/W in New York, with a $4/W buy-down, the final cost to the consumer is about $4/W. If financed over the life of the system (30 years) at a 6 percent interest rate

(~4 percent real interest rate after tax benefits) the levelized cost of energy from such a PV system would be about 13.5 cents/kWh. With an average residential electricity price above 14 cents/kWh in New York, combined with attractive net metering rules, it is not surprising that this investment would look reasonable to many consumers.

While such an investment might look attractive to con-sumers, it is of little value if consumers cannot find repu-table installers. Here is where having a clear long-term policy commitment plays a critical role. Setting up a new business (getting certified, training staff, etc.) requires a substantial investment of resources. Entrepreneurs need to believe they will be able to recoup this investment over time. Policy un-certainty, in this context, creates a substantial barrier to building a viable local PV distribution, installation, and maintenance industry.

This accelerated scenario is modeled on the successful Japanese program that provided a declining subsidy to resi-dential PV systems over the past decade, expanding residen-tial PV installations in Japan from roughly 2 MW in 1994 to 800 MW in 2004 (Ikki, 2005). The history of the Japanese residential PV subsidy program during the past decade has provided proof that making such a long-term commitment to building the market infrastructure for PV can result in a self-sustaining industry. The average price of residential PV sys-tems installed in Japan in 2004 was $6.2/W, i.e., about 25 TABLE D-7-3 Current PV-Related Policies in New York State Incentivea Description Sales tax exemption (R) 100% sales tax exemption Property tax exemption (C, I, R, A) 15-year tax exemption for all solar improvements Personal tax credit (R) 25% tax credit for PV (<10 kW) and SHW, capped at $5,000 State loan program (C, I, R, A, G)

$20,000-$1 million loan for 10 years at 4-6.5% below the lender rate for PV and SHW State rebate program (C, I, R, A, G)

$4-$4.50/W (<50 kW) up to 60% of total installed costs; IOU customers only Municipal utility rebate program (C, R, G)

$4-$5/W (<10kW); LIPA customers only Interconnection standards (C, I, R, A)

Standard agreement for PV requires additional insurance and an external disconnect; up to 2 MW max.

Net metering standards (R, A)

All utilities must credit customer monthly at the retail rate for PV systems under 10 kW aC = commercial; R = residential; I = industrial; A = agricultural; G = government. Incentive data available at <DSIRE.org 08/2005>.

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122 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER

A declining subsidy is implemented, set at 50 percent in 2006, declining linearly to 25 percent in 2011, and 0 per-cent in 2016. The combination of a declining subsidy and declining costs maintains an installed system cost to con-sumers below $4/W throughout the scenario.

A clear long-term commitment to growing the PV in-dustry in New York is put in place. The combination of a declining subsidy, declining system costs and rising installa-tions creates a peak program cost of $74 million in 2012.

Achieving the high growth rates envisioned during the 2006-2015 period will require investing additional resources (on the order of $10 million per year) in programs aimed at helping entrepreneurs establish PV businesses and boosting public awareness of PV in New York.

Additional detail for this scenario is shown in Table D 4. This scenario envisions creating a self-sustaining PV mar-ket in New York by 2016. Under this scenario about 1 GW of PV systems would be installed in New York by 2016.

Achieving this goal would require a total public investment of roughly $500 million (undiscounted) between 2006 and 2015. An additional 1 GW of PV would be installed in New York by 2020 without any public subsidies beyond 2015.

0 1

2 3

4 5

6 7

8 9

10 2005 2007 2009 2011 2013 2015 2017 2019 Year 0

500 1,000 1,500 2,000 2,500 Cumulative Installation (MW)

Installed Cost (Left)

Cumulative Installation (Right)

Installed System Cost ($/W)

FIGURE D-7-2 An accelerated PV market development path for New York (all estimates are 2005 dollars).

percent lower than in New York. This cost differential is a reflection of the difference between a well-functioning and emerging market for PV systems. PV modules and inverters are commodities whose prices are largely driven by interna-tional markets; however, labor and balance of system costs (which typically account for 30-40 percent of total system cost) are driven by local policies and market development.

Figure D-7-2 shows an accelerated market development path for New York. This scenario is not a model result, but an estimate of what New York could achieve under the fol-lowing assumptions:

The cost projection is in line with what the DOE Solar Energy Technology Program and the U.S. PV industry be-lieve will be achieved over the next 10-15 years in the United States (DOE, 2004; SEIA, 2004)in other words, it is an aggressive but plausible projection.

The average annual growth rate was set in 5-year inter-vals as follows: 55 percent between 2006 and 2010, 40 per-cent between 2011 and 2015, and 5 percent between 2016 and 2020. These rates are below the rates achieved in the Japanese program.

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APPENDIX D 123 TABLE D-7-4 Accelerated PV Deployment Scenario for New York (2005 dollars)

Annual Growth Cumulative Installed Buydown Effective Annual State Installed System Installations Rate Installations System Cost Rate Buydown Investment Cost to Consumer Year (MW)

(%)

(MW)

($/W)

(%)

($/W)

(million)

($/W) 2005-actual 2.0 NA 4.2 8.14 52 4.23 8.47 3.91 2006 6.0 55 10.2 7.50 50 3.75 22.50 3.75 2007 9.3 55 19.5 7.00 45 3.15 29.30 3.85 2008 14.4 55 33.9 6.50 40 2.60 37.48 3.90 2009 22.3 55 56.3 6.00 35 2.10 46.92 3.90 2010 34.6 55 90.9 5.50 30 1.65 57.14 3.85 2011 53.7 40 144.6 5.20 25 1.30 69.78 3.90 2012 75.2 40 219.7 4.90 20 0.98 73.65 3.92 2013 105.2 40 324.9 4.60 15 0.69 72.60 3.91 2014 147.3 40 472.2 4.30 10 0.43 63.34 3.87 2015 206.2 40 678.4 4.00 5

0.20 41.24 3.80 2016 288.7 5

967.1 3.80 0

0.00 0.00 3.80 2017 303.1 5

1,270.3 3.60 0

0.00 0.00 3.60 2018 318.3 5

1,588.6 3.40 0

0.00 0.00 3.40 2019 334.2 5

1,922.8 3.20 0

0.00 0.00 3.20 2020 350.9 5

2,273.7 3.00 0

0.00 0.00 3.00 References CLSA (Credit Lyonnais Securities Asia). 2004. Sun Screen: Investment Opportunities in Solar Power. CLSA Asia-Pacific Markets. Available at www.clsa.com.

DOE (Department of Energy). 2004. Solar Energy Technologies Program, Multi-Year Technical Plan 2003-2007 and Beyond. Office of Energy Efficiency and Renewable Energy, U.S. Department of Energy, Wash-ington, D.C. Report DOE/GO-102004-1775.

DOE. 2005. Annual Energy Outlook 2005, Table 38. Energy Information Administration. Washington, D.C.

EC (European Commission). 2004. PV Status Report 2004: Research, So-lar Cell Production and Market Implementation of Photovoltaics. Euro-pean Commission, Directorate General Joint Research Centre, Renew-able Energies Unit, Ispra, Italy. Report EUR 21390 EN.

EIA (Energy Information Administration). 2005. Electric Power Monthly.

Energy Information Administration, U.S. Department of Energy, Wash-ington, DC. (January).

EPA (Environmental Protection Agency). 2005. Control of Mercury Emis-sions from Coal Fired Electric Utility Boilers: An Update. Air Pollution Prevention and Control, U.S. EPA: Research Triangle Park, N.C.

EPIA (European Photovoltaic Industry Association). 2004. EPIA Roadmap.

European Photovoltaic Industry Association, Brussels. Available at www.epia.org.

Ikki, Osamu. 2005. PV Activities in Japan. RTS Corporation, Tokyo, Japan (May).

Korens, N. 2002. Process Screening Analysis of Alternative Gas Treating and Sulfur Removal for Gasification. DOE/NETL: Pittsburgh.

Letendre, Steven, et al. 2003. Solar And Power Markets: Peak Power Prices and PV Availability for the Summer of 2002. Paper presented at ASES 2003, Austin, Tex., June.

Margolis, Robert M., and Frances Wood. 2004. The Role for Solar in the Long-Term Outlook of Electric Power Generation in the U.S. Paper presented at the IAEE North American Conference in Washington, D.C.,

July 8-10.

Navigant Consulting. 2004. PV Grid Connected Market Potential in 2010 Under a Cost Breakthrough Scenario. Report to the Energy Founda-tion. Available at www.navigantconsulting.com.

NEDO (New Energy and Industrial Technology Development Organiza-tion). 2004. PV Roadmap Toward 2030 (Japanese PV Industry Roadmap). New Energy and Industrial Technology Development Orga-nization. Available at www.nedo.go.jp.

NYISO (New York Independent System Operator). 2005. 2004 Interim Review of Resource Adequacy Covering the New York Control Area for the Years 2004-2006. January 24.

NYSERDA (New York State Energy Research and Development Author-ity). 2003. Energy Efficiency and Renewable Energy Resource De-velopment Potential in New York State. New York State Energy Re-search and Development Authority, Albany, New York. Available at www.nyserda.org.

Oskarsson, K., Anders Berglund, Rolf Deling, Ulrika Snellman, Olle Stenback, and Jack Fritz. 1997. A Planners Guide for Selecting Clean-Coal Technologies for Power Plants. World Bank Technical Paper No.

387. Washington, D.C.: World Bank.

Parsons. 2002. The Cost of Mercury Removal in an IGCC Plant, P.I.a.T.

Group, Editor.

Perez, Richard, et al. 2004a. Quantifying Residential PV Economics in the USPayback vs Cash Flow Determination of Fair Energy Value. So-lar Energy 77: 363-366.

Perez, Richard, et al. 2004b. Solar Energy Security. REFocus (July/

August): 24-29.

PowerClean, T.N. 2004. Fossil Fuel Power Generation State-of-the-Art, P.T. Network, Editor. University of Ulster: Coleraine, UK, pp. 9-10.

SEIA (Solar Energy Industries Association). 2004. Our Solar Power Fu-ture: The U.S. Photovoltaic Industry Roadmap Through 2030 and Be-yond. Solar Energy Industries Association, Washington, D.C.

Strategies Unlimited. 2005. Personal Communication with Paula Mints, Senior Photovoltaic Analyst, Strategies Unlimited, Mountain View, California. February.

Thompson, J., 2005. Integrated Gasification Combined Cycle (IGCC)

Environmental Performance, in Platts IGCC Symposium. 2005: Pitts-burgh.

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124 E

Paying for Reliability in Deregulated Markets Timothy Mount1 THE CHANGING REGULATORY STRUCTURE IN NEW YORK STATE The problems faced by investors in the process of financ-ing new power plants and transmission lines have changed over time depending on the regulatory structure and the eco-nomic climate, and these factors will probably continue to change in the future. Prior to the restructuring of electricity markets, under the system of regulated monopolies, inves-tor-owned utility companies were given a guaranteed rate of return, with a potential penalty if their investments were found to be imprudent. Once an expansion plan had been approved by a state public utility commission (PUC), it was relatively straightforward for investors to finance the capac-ity expansions, even for a capital-intensive project such as a nuclear plant, because the financial risk of an investment was relatively low under regulation. A key factor in deter-mining how many plants were to be built was the utilitys forecast of future load and the acceptance of this forecast by the PUC. If the utilities forecasts of demand were consis-tently biased in the same direction, utilities could be caught with a deficit of capacity, as happened after World War II, or a surplus of capacity, as happened in the late 1980s.

The rate of growth of demand was consistently high after the post-war shortages, and the total demand doubled every 10 years in the United States until the early 1970s. After the oil embargo in 1973, the growth of demand was and has continued to be much lower than historical levels. Electric-ity demand grew at a 7.3 percent annual rate from 1960 to 1973, but slowed to 2.5 percent a year from 1973 to 1985 (Geddes, 1992). The utility industry was relatively slow to recognize and adopt lower forecasts of demand, and there was an extended public debate about how much the in-dustrys forecasts of demand should be lowered in response to higher prices (Nelson and Peck, 1985). An additional ra-tionalization for building nuclear power plants after the oil embargo was to substitute a domestic source of energy for imported oil. As a result, ambitious construction plans for nuclear power plants were continued in spite of growing evi-dence that the growth of demand would be lower than ex-pected and that these projects would eventually lead to an excess of installed generating capacity (Schuler, 2001).2 Since the industrys forecasts of demand had been ap-proved by PUCs, consumers still had to pay for much of the excess capacity when installed capacity got ahead of demand (Zadlo et al., 1996).3 As a result, there was considerable soul-searching by regulators and criticism by the public about what had gone wrong with the regulatory process. Increases in prices led to further decreases in demand below projec-tions (Zadlo et al., 1996). When the excess capacity and the high cost of new nuclear facilities (Potts, 2002)4 became apparent in the 1980s, many PUCs held prudency hearings (Geddes, 1992), and in some high-profile cases, such as those involving Nine Mile Point Unit 2, near Oswego, New York, and Seabrook Nuclear Power Plant in New Hampshire, stockholders were denied the full recovery of capital (Adams, 2005). In total, $19 billion of the accumulated costs of constructing new generating capacity was disallowed ac-cording to one estimate (Lyon and Mayo, 2000). Although

$19 billion was a small amount compared with the total book 1Timothy Mount is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs and professor of applied economics and management at Cornell University.

2... customers in New York were burdened over the past twenty years to pay for reserve margins as high as forty percent because of incorrect load forecasts (Schuler, 2001, p. 80).

3Changes in the market, such as the oil embargo, resulted in lower growth in peak demand than had been projected. The result was the con-struction of excess capacity through the late 1980s (Zadlo et al., 1996).

4Considerable debate exists as to why these cost overruns occurred. Some blame undue safety regulation of nuclear plants; some blame utilities for delaying completion of facilities to avoid having so much installed capacity that they would trigger prudency hearings; some blame the many different nuclear designs that permeated the U.S. market.

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APPENDIX E 125 value of installed generating capacity, it was still large enough to send a message of dissatisfaction to investors.

Since only a fraction of the total cost of building excess gen-erating capacity was charged to stockholders, ratepayers were also adversely affected by paying higher rates; the pri-mary cause of the problem was a failure by the industry and regulators to predict future levels of demand accurately.

The memory of excess generating capacity and unrealis-tic demand forecasts was part of the rationale for utility re-structuring, based on the perception that the investment de-cisions made by regulated utilities were often economically inefficient (Rebellon, 2002). Regulated monopolies were thought by many people to imply high rates for customers owing to overbuilding. It was also thought that more com-petition would lower costs, encourage innovation, and at-tract new investment (Rebellon, 2002; Anderson, 2004; Higley, 2000; Potts, 2002).5,6 In addition, investment deci-sions in deregulated markets would be decentralized, and as a result, the responsibilities of regulators for selecting a par-ticular forecast of demand and authorizing an expansion plan would be substantially reduced.7 Supporters of deregulation argued that market forces could be relied on to ensure that there would be enough installed generating capacity to meet the growth of demand.

Although it was not recognized at the time, the changing economic circumstances in the 1980s had already led most utilities to reduce their level of capital investment. Some analysts attributed the cause of this reduced investment to the hammer of the prudency reviews and the resulting regulatory disallowances (Geddes, 1992).8 Other analysts, however, concluded that the primary cause was the exist-ence of excess generating capacity and the economic incen-tives to shift away from expensive nuclear power plants to less expensive natural gas turbines (Lyon and Mayo, 2000).

In the latter half of the 1970s, high oil prices, restrictions on the use of natural gas by utilities, and increasing environ-mental concerns about the adverse effects of air pollution were among the major reasons that utilities in New York State embraced nuclear power as an alternative to fossil-fuel sources of electricity. When high oil prices and cost over-runs for constructing nuclear power plants drove electric rates steadily higher, the New York legislature responded by enacting a law in 1980 that required utilities to buy power from independent power producers (IPPs) for 6¢/kWh. Un-fortunately, this law was enacted just before the price of oil dropped, and after additional supplies of natural gas became available after the oil industry was deregulated. Conse-quently, the actual cost of generating electricity from natural gas turbines, including the capital cost, was well below 6¢/kWh. Nevertheless, forecasters did not anticipate these changes in 1980, and therefore they expected higher prices for oil and natural gas in the 1980s.

The assumption underlying the six-cent law was that rising oil prices and the high construction costs of nuclear power plants would soon make 6¢/kWh a bargain for the buyers. In fact the opposite happened. Falling fuel prices, technological advances, and successful energy-efficiency investments created a surplus of generation that kept the cost of electricity well below 6¢/kWh, and the six-cent law cre-ated a substantial subsidy for IPPs and became a source of controversy for the public. The six-cent law was reinter-preted in 1987 to require an IPP to accept 6¢/kWh until such time as the front-end subsidy was paid back to customers, but projections indicated that wholesale prices of electricity would be so low that repayment would never occur. The overall outcome of the six-cent law was that thousands of megawatts of new contracts were made to buy electricity from IPPs at above-market prices. Most of this new capacity was built upstate, because construction costs were lower there than they were in the New York City region. The high cost of these contracts resulted in higher rates for customers.

In the 1990s, regulators decided that the best strategy was to allow utilities to buy out the IPP contracts and treat the cost of doing this as a lump-sum loss.

Combining the effects of the high construction costs of the new nuclear power plants, the impact of the six-cent law, and the high property taxes in Long Island and New York City, electricity prices in New York State remained among the highest in the country, even though the amount of gen-eration from oil-fired sources diminished to relative insig-nificance. Large customers in New York Stateas in Cali-fornia and other high-cost statesbecame interested in self-generation and retail access as ways to bypass paying the high rates for electricity and, in some cases, as ways to shift production and jobs to regions with lower electricity prices. In 1994, California became the first state to announce the intention of permitting retail customers to choose their power suppliers. New York State announced its own plan for retail access one year later. This plan started by persuad-5The primary rationale for electricity restructuring in most countries has been to reap welfare gains by supplanting regulation with competition where it is viable (Anderson, 2004).

6Calls by large industries for utility deregulation found a ready chorus in academics, analysts, and politicians who believed that competition could produce lower prices, better service, and more innovation than government regulation. The free-marketeers pointed at other industries that had been deregulated during the 1980s, such as airlines and telecommunications, claiming that deregulation helped lower the cost of airplane tickets and long-distance telephone rates (Public Citizen disputes many of these claims; deregulation helped lower prices for some, but others have seen price in-creases and reduced service). The free-market proponents argued that since deregulation worked for the airlines and telecommunications (which Public Citizen disputes), why not the electric power industry? (Higley, 2000).

7Recent history has created a tremendous disincentive to risk the eco-nomic future of the industry on forecasting the right energy production technology and building the correct amount of it to serve future demand (Zadlo et al., 1996).

8The lesson of that experience was not lost on electric utility managers.

They now fear that the cost of large (and efficient) new generating capacity might not be recovered through the regulatory process. New capacity might be disallowed from the rate base although its costs were justified and pru-dently incurred (Geddes, 1992).

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126 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER ing the utilities to sell their generating capacity to merchant generators prior to the establishment of a new deregulated wholesale market for electricity in 1999.

The perceived failure of the traditional regulatory com-pact that occurred in many countries in the 1970s and 1980s was the primary motivating factor for deregulating the electric utility industry. This restructuring took place around the world beginning in the 1980s and accelerated in the 1990s (Anderson, 2004), and it generally involved unbundling as-sets (i.e., separating the ownership) for the generation, trans-mission, and distribution segments of the supply system.

Customers were no longer restricted to buying electricity from a single utility. In the United States, As of April 2004, twenty four states and the District of Columbia had enacted legislation or issued regulatory orders to permit retail access to competitive electricity suppliers; more recently, however, seven of these states delayed or suspended their plans for retail access, largely in response to the turmoil in Californias market (Anderson, 2004).

In 1999, when the new wholesale market for electricity started to operate in New York State, the price of natural gas happened to be low. Entrepreneurs saw an opportunity to make money by building efficient combined-cycle turbines that would undercut the costs of older fossil-fuel power plants. Merchant facilities were built without guarantees of a regulatory rate of return, and these projects were still able to get financing from financial institutions. Given the econom-ics of the time, merchant plants were expected to earn for investors higher rates of return than the traditional regulated rates. Figure E-1 shows the dramatic increase in the con-struction of new generating capacity in North America that started in 2000. It looked at that time as though market forces would ensure that the amount of new generating capacity being built would be enough to keep up with the forecasted growth of demand (and the retirement of older power plants).

However, during the early 2000s, the underlying eco-nomic conditions changed. As a result, many merchant projects for natural gas turbines ended up in financial trouble that persists today. By 2003, cancellations of planned facili-ties accelerated (Horton, 2002), leading to concerns about capacity shortages in the near future (see Figure E-1). New York State is not the only region of the country that is facing the possibility of capacity shortages. All three of the north-eastern control areas (New York, New England, and the mid-Atlantic control area known as Pennsylvania Jersey Mary-land [PJM]) are now struggling to create effective investment incentives for building new generating capacity. Some policy makers are calling for major changes in the current path of deregulation and less dependence on the merchant develop-ment paradigm (Adams, 2005).

Once again, the failure to forecast key economic vari-ables accurately (in this case the prices of natural gas and electricity) has contributed to the financial problems faced by many owners of natural gas turbines. This time, however, the financial consequences of unprofitable merchant projects will be borne by the stockholders rather than by the ratepayers. Higher prices for natural gas in 2005, coupled with relatively low prices for electricity, have led to delays in the construction of new generating capacity in New York State. These delays have arisen in spite of the establishment of a new form of locational installed capacity (LICAP) auc-tion, run by the New York Independent System Operator (NYISO). The major objectives for establishing this new LICAP auction were to supplement the income of generators FIGURE E-1 North American additions in historical perspective. The current boom is modest relative to what happened in the 1970s.

SOURCE: Logan (2002).

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APPENDIX E 127 when shortages of generating capacity are likely to occur, and to provide sufficient incentives to delay the retirement of existing generating capacity and to build new generating capacity.

Today, even with higher natural gas prices, natural gas turbines are still the preferred type of traditional generating capacity for providing an alternative to the nuclear units at New Yorks Indian Point Energy Center. Although many utilities in the country are now planning to use coal instead of natural gas in new power plants, building a typical coal plant in the New York City region is unlikely to meet state environmental standards and unlikely to get widespread sup-port from the public. Clearly, a nuclear power plant in this region is not a viable alternative.

To summarize, until a year ago most policy makers in New York State believed that market forces could be relied on to build enough new generating capacity to meet future levels of demand. Unfortunately, this level of optimism about market forces is no longer realistic under the present economic conditions. The increased uncertainty that now exists about the financial viability of building new generat-ing capacity in New York State, particularly in the New York City region, makes the task of finding alternatives to Indian Point much more challenging for this Committee on Alter-natives to Indian Point for Meeting Energy Needs. For ex-ample, the current projection made by NYISO of the reserve margin for capacity in New York State falls below the 18 percent level needed to maintain reliability standards by 2008 (NYISO, 2005a). This type of problem is occurring in other parts of the nation, and the North American Electric Reli-ability Council (NERC) has lowered the forecasts of installed generating capacity in the nation every year since 2002. The current projected summer capacity margin (summer capac-ity margin = installed capacity - summer peak load) is below 15 percent for the nation in 2008 and continues to decline to 10 percent by 2014, the last year forecasted (NERC, 2005, Fig. 7, p. 18).

The growing concerns about how to maintain the reliabil-ity of the electric supply system in New York State and the nation coincide with major changes in the regulatory struc-ture of the industry. In particular, the Energy Policy Act of 2005 was signed into law in August 2005, giving greater authority over reliability to the Federal Energy Regulatory Commission (FERC). Prior to the enactment of this legisla-tion, FERC was primarily an economic regulator of the wholesale transactions and tariffs on the bulk power system.

The main implications of the Energy Policy Act of 2005 are to give FERC the authority to enforce reliability standards by imposing penalties on end users if the standards are vio-lated. In addition, a new organization, the Electric Reliabil-ity Organization (ERO), will be given the authority to estab-lish these reliability standards. At this time, it is not clear exactly how this new authority will be implemented by FERC. Nevertheless, these mandatory changes show that maintaining reliability is a major priority of federal policy makers, but state regulators will still have the main responsi-bility for determining how the new standards will be imple-mented (i.e., determining how much generating capacity is needed to meet the standard).

The sections below provide a more detailed explanation of the following questions: how regulators determine the amount of generating capacity needed to meet reliability standards, why the current regulatory practices have failed to ensure that future levels of generating capacity will be sufficient to meet these standards, and what can be done, given current circumstances, to meet future levels of demand and maintain the reliability of supply.

DETERMINING AND IMPLEMENTING THE RELIABILITY STANDARDS In an electric supply system, the performance of the net-work and the level of reliability are shared by all users of the network. Reliability has the characteristics of a public good (e.g., all customers benefit from the level of reliability without consuming it). In contrast, real energy is a pri-vate good because the real energy used by one customer is no longer available to other customers. Markets can work well for private goods but tend to undersupply public goods, such as reliability (and oversupply public bads such as pollution). The reason this happens is that customers are gen-erally unwilling to pay their fair share of a public good be-cause it is possible to rely on others to provide it (i.e., they are free riders). Some form of regulatory intervention is needed to make a market for a public good or a public bad socially efficient.

If a public good or a public bad has a simple quantitative measure that can be assigned to individual entities in a mar-ket, it is feasible to internalize the benefit or the cost in a modified market. For example, the emissions of sulfur and nitrogen oxides from a fossil-fuel generator can be measured.

Requiring every generator to purchase allowances for the quantities emitted makes pollution another production cost.

Regulators determine a cap on the total number of allow-ances issued in a region, and this cap effectively limits the level of pollution. Independent (decentralized) decisions by individual generators in the market determine the pattern of emissions and the types of control mechanisms that are eco-nomically efficient. For example, the choice between pur-chasing low-sulfur coal and installing a scrubber is left to market forces in a cap-and-trade market for emission al-lowances. Unfortunately, when dealing with the reliability of an electric supply system, it is impractical to measure and assign reliability to individual entities on the network in the same way that emissions can be assigned to individual gen-erators. This is particularly true for transmission lines that are needed to maintain supply when equipment failures oc-cur. NERC uses the following two concepts to evaluate the reliability of the bulk electric supply system (NERC, 2005,

p. 10):

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128 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER

1. AdequacyThe ability of the electric system to sup-ply the aggregate electrical demand and energy require-ments of customers at all times, taking into account sched-uled and reasonably expected unscheduled outages of system elements.

2. Operating ReliabilityThe ability of the electric sys-tem to withstand sudden disturbances such as electric short circuits or unanticipated failure of system elements.

The desired level of reliability on a network should be specified by a regulatory agency, and under the Energy Policy Act of 2005, FERC will be responsible for enforcing a set of standards for reliability that are established by the ERO. State regulators will continue to be responsible for interpreting the standards to determine how they should be implemented. Before passage of the Energy Policy Act of 2005, the NERC standard of 1 day in 10 years for the loss-of-load expectation (LOLE) was generally accepted by regu-lators as the appropriate standard for the reliability of the bulk transmission system (i.e., this does not include outages of the local distribution systems caused, for example, by fall-ing tree limbs and ice storms). Nevertheless, it is still very difficult to allocate the responsibilities for maintaining this standard to individual owners of generating and transmis-sion facilities because of the interdependencies that exist among components of a network. This fundamental problem has not stopped regulators from trying to do it.

The basic approach used by state regulators is to assume that setting reserve margins for generating capacity (i.e., set-ting a standard for generation adequacy) is an effective proxy for meeting the NERC reliability standard. This new proxy for reliability can now be viewed as the sum of its parts, like emissions from generators, and the task of main-taining reliability can be turned over to market forces once the regulators have set a reserve margin. In practice, it has been difficult, without regulatory intervention, to maintain a given standard for generation adequacy in many deregulated markets, particularly in the three deregulated markets in the Northeast. The underlying reasons for this difficulty are ex-plained in the following sections. The main implication for this study is that even if Indian Point continues to operate at full capacity, there will still be problems with maintaining the reliability of supply that should be addressed immedi-ately by regulators. Ignoring these problems would make it much more difficult to find viable ways to replace the gener-ating capacity at Indian Point and maintain the reliability of supply in the New York City region.

Generation adequacy is clearly a necessary condition for the operating reliability of supply, but it is not a sufficient condition. Treating generation adequacy as the central issue for reliability downplays the importance of transmission ser-vices and distributed energy resources (DERs) for maintain-ing the reliability of supply. This issue has been discussed in the NERC (2005) report Long-Term Reliability Assessment.

The executive summary of that report (NERC, 2005, p. 5) states:

Transmission Systems Will Be Operated at or Near Lim-its More Frequently. North American transmission systems are expected to meet reliability requirements in the near term.

However, as customer demand increases and transmission systems experience increased power transfers, portions of these systems will be operated at or near their reliability limits more of the time. Under these conditions, coincident failures of generating units, transmission lines, or transform-ers, while improbable, can degrade bulk electric system reliability.

This general conclusion reflects the complicated state of the electric utility industry in North America at this point in time when different regions are in different stages of deregulating the industry. Deregulation implies moving away from the use of a relatively centralized planning pro-cess to determine the investments needed in generation and transmission in order to meet reliability standards in a given region and moving toward a more decentralized decision process and a greater reliance on market forces. However, there is a lot of uncertainty in the deregulated markets about the best way to maintain system reliability and provide the right incentives to get new generation and transmission built when and where it is needed. For example, in the New York City region, two out of three recent proposals for new mer-chant transmission lines have failed to secure financing. In addition, there is a considerable amount of ongoing uncer-tainty about whether or not some existing generating units will be retired and whether proposed new generating units will actually be built. Most of these decisions have been or will be determined by the financial conditions faced by the owners and the investors and their expectations about the profitability of future sales of electricity in the spot market.

Three issues relating to reliability are discussed in the following three sections. The next section explains why the amount of generating capacity needed to meet adequacy standards in New York City is relatively large. The section after that shows why the profitability of this capacity from earnings in the spot market is low and therefore why addi-tional sources of income for generators are needed to main-tain operating reliability. The section on Filling the Finan-cial Gap discusses alternative ways of providing additional income for generators. The final section explains the poten-tial limitations of the current approach adopted in New York State and the pressing need to find a more effective way to finance new generation and transmission capacity.

GENERATING CAPACITY FOR MEETING ADEQUACY STANDARDS IN NEW YORK CITY New York Citys large size, commercial importance, and unique dependence on electricity for transportation implies Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX E 129 that unscheduled outages in New York City cause substan-tial financial losses for electricity customers. As a result, maintaining a high level of reliability for the city has always been, correctly, a major priority for system planners and regulators. This basic objective has not changed in the new deregulated market, but the financial consequences of main-taining reliability are no longer as straightforward as they were when electric utilities were fully regulated. Although financial problems of this type occur in all deregulated mar-kets, the chosen approaches to solving the problems vary substantially from one region to another. Regulators in New York State have adopted a relatively innovative but untested way to address the problem. This approach is discussed in more detail in the following section.

The problem of maintaining reliability in New York City is exacerbated by the structure of the legacy transmission system. Since the geographic region supported by the New York Power Pool under regulation corresponded almost ex-actly with New York State, the supply of electricity to New York City was designed to depend heavily on transmission lines from the north through the Hudson Valley. Transmis-sion links to adjoining power pools in the west/south and east (i.e., PJM and New England) were and continue to be relatively weak. Furthermore, the location of Long Island as an appendage to New York City adds to the concentration of load in the southeastern corner of the New York Control Area (NYCA). If the legacy transmission system had been developed at the regional level rather than at the state level, it is probable that the transmission links between New York City and New Jersey, for example, would be considerably stronger than they are now.

The overall implication of the size and location of New York City in the NYCA is that NYISO has supplemented the standard reliability criterion used by the New York State Reliability Council (NYSRC) to conform to the NERC stan-dard for reliability. The Introduction to the current annual report by NYSRC summarizes the councils responsibilities as follows (NYSRC, 2005, p. 1):

Section 3.03 of the New York State Reliability Council (NYSRC) Agreement states that the NYSRC shall establish the annual statewide Installed Capacity Requirements (ICR) for the New York Control Area (NYCA) consistent with North American Electric Reliability Council (NERC) and Northeast Power Coordinating Council (NPCC) standards.

This report describes an engineering study conducted by the NYSRC for establishing the NYCA required installed re-serve margin (IRM) for the period of May 2005 through April 2006 (Year 2005) in compliance with the NYSRC Agreement. The ICR relates to the IRM through the follow-ing equation:

ICR = (1 + IRM% / 100) x Forecasted NYCA Peak Load NYISO will implement the statewide ICR as determined by NYSRCin accordance with the NYSRC Reliability Rules and the NYISO Installed Capacity manual. NYISO translates the required IRM to an unforced capacity (UCAP) basis, in accordance with a 2001 NYISO filing to FERC.

In the same report (NYSRC, 2005, p. 3), the reliability criterion is defined as follows:

The acceptable LOLE reliability level used for establishing NYCA Installed Reserve Margin (IRM) requirements is dic-tated by the NYSRC Reliability Rules, wherein Rule A-R1 (Statewide Installed Reserve Margin Requirements) states:

The NYSRC shall establish the IRM requirement for the NYCA such that the probability (or risk) of disconnecting any firm load due to resource deficiencies shall be, on av-erage, not more than once in ten years. Compliance with this criterion shall be evaluated probabilistically, such that the loss of load expectation (LOLE) of disconnecting firm load due to resource deficiencies shall be, on average, no more than 0.1 day per year. This evaluation shall make due allow-ance for demand uncertainty, scheduled outages and de-ratings, forced outages and deratings, assistance over in-terconnections with neighboring control areas, NYS Transmission System transfer capability, and capacity and/

or load relief from available operating procedures.

The underlying analysis of reliability in the NYSRC re-port (NYSRC, 2005, p. 2) is based on:

a probabilistic approach for determining the NYCA IRM requirements. This technique calculates the probabilities of generating unit outages, in conjunction with load and trans-mission representations, to determine the days per year of expected capacity shortages. The General Electric Multi-Area Reliability Simulation (MARS) is the primary analyti-cal tool used for this probabilistic analysis. This program includes detailed load, generation, and transmission repre-sentation for eleven NYCA Zonesplus four external Con-trol Areas (Outside World Areas) directly interconnected to the NYCA. MARS calculates Loss of Load Expectation (LOLE, expressed in days per year), to provide a consistent measure of system reliability.

The overall implication of the NYSRC report is to set the statewide IRM for 2005 to 2006 at 17.6 percent (NYSRC, 2005, p. 2). However, this criterion is found to be sensitive to the levels of installed generating capacity in New York City and Long Island, and as a result, NYISO does a supple-mentary analysis to determine the locational installed capac-ity (ICAP) requirements for these two regions, using the General Electric Multi-Area Reliability Simulation (MARS) model. Figure E-2 shows that the locational ICAP require-ments are very stringent, particularly for Long Island, and it is not practical to meet the NERC standard for LOLE if the ICAP for Long Island falls below 97 percent of the peak load (NYISO, 2005a, p.8). The required levels of ICAP proposed by NYISO for 2005/2006 are 80 percent of peak load for New York City and 99 percent of peak load for Long Island (NYISO, 2005b, p. 10). These requirements are supplements to the NYSRC requirement of 118 percent of peak load for Copyright © National Academy of Sciences. All rights reserved.

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130 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER the NYCA, and the capacity implications are summarized in Table E-1 (NYISO, 2005b, pp. 6 and 10).

The capacity requirements in Table E-1 are relatively stringent and imply that 38 percent of the total NYCA gener-ating capacity must be located in New York City and Long Island. However, most of the inexpensive sources of genera-tion in the NYCA (hydro, nuclear, and coal), are located upstate. The existing generating units in New York City and Long Island are relatively expensive to operate because they use oil or natural gas as a fuel. As a result, an economically efficient dispatch of generators in the NYCA loads the trans-mission capacity from upstate to New York City to the maxi-mum allowed, and the capacity factors of the generating units in New York City and Long Island are relatively low. This implies that it may be difficult to maintain the desired level of reliability (i.e., locational ICAP) because the profitabil-ity of sales in the spot market is relatively low for many generating units in New York City and Long Island. The low profitability of these generating units is a major cause of the current uncertainty that exists about the timing of retirements and of new construction of generating units in New York City and Long Island. The issue of profitability of generat-ing units in the New York City and Long Island regions is discussed in more detail in the next section.

THE HIGH COST OF RELIABILITY IN NEW YORK CITY AND LONG ISLAND Effect of the Capacity Factor of Peaking Units on Cost The standard rule for defining an economically efficient (competitive) market is that the market price paid by buyers to sellers should be equal to the highest marginal production cost. In a deregulated market for electricity, the competitive price is equal to the short-run marginal cost of production, defined as (the fuel cost plus the operating and maintenance cost) of the most expensive generating unit that is dispatched to meet the load in a region (under regulation, this measure corresponds to the system lambda for a merit order dispatch).

In reality, most final customers in a deregulated market still pay a fixed price based on a regulated tariff rather than the spot price of electricity in the wholesale market. Generators, FIGURE E-2 Locational installed capacity requirements for Long Island and New York City for 2005-2006. SOURCE: NYSRC (2005).

TABLE E-1 Locational ICAP Requirements and Installed Capacity for NYCA in 2005-2006 Forecasted Required Peak Load Locational ICAP Locational ICAP Actual ICAP Actual ICAP Ratio of Actual Locality (MW)

(% of peak)

(MW)

(% of peak)

ICAP to Required New York City 11,315 80 9,052 9,887 87 1.09 Long Island 5,231 99 5,179 5,318 102 1.03 New York Control Area 31,692 118 37,715 39,647 125 1.05 SOURCE: Derived from NYISO (2005b).

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APPENDIX E 131 on the other hand, are paid the spot price (or they are paid through forward contracts that reflect the expectations that traders had about future spot prices when the contracts were executed). Hence, an efficient market price covers the pro-duction costs of all units that are dispatched, but additional income to cover capital costs is only earned when the market price is higher than the marginal production cost of a gener-ating unit. Generators that are only needed to meet peak loads on hot summer days are dispatched for relatively few hours in a year (i.e., they have very low capacity factors), and the ability of these units to earn sufficient income to cover capital costs is highly dependent on how often high prices above their production costs actually occur.

To understand how the capacity factor of a peaking unit affects the cost, define the average total cost as (production cost plus annualized capital cost)/megawatt-hour (MWh) generated. This definition measures the long-run marginal production cost conditional on the number of megawatt-hours generated. The average total cost is highly sensitive to the number of hours that a peaking unit is dispatched, and this relationship is illustrated in the following simple ex-ample. The production cost for a representative peaking unit is $60/MWh and the annualized capital cost is $85/kW.9 Using these component costs of generation, the average total cost can be written:

Average total cost = (60 + 85,000/number of hours dispatched)$/MWh In Figure E-3, the average total costs for this representa-tive peaking unit are shown in terms of the number of days that the unit is dispatched, assuming that it generates for 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months on each one of these days. The costs are shown for a range of 1 to 100 days, and the latter corresponds roughly to being dispatched every day during the summer (equivalent to an annual capacity factor of only 18 percent). The average total costs in Figure E-3 decrease rapidly from over $5,000/

MWh for 1 day to $113/MWh for 100 days. However, this latter cost would still be nearly twice as high as the competi-tive market price ($60/MWh) if this unit was the marginal generator. For peaking units, there is a fundamental incon-sistency between the ability of generators to earn a fair rate of return on capital and the existence of economically effi-cient prices in the spot market. This problem is not new.

There are extensive discussions in the regulatory literature about the financial implications of real-time pricing using the system lambda from a merit order dispatch to set the price.

Regulators have followed two very different approaches for dealing with this financial predicament in a deregulated market. One is to focus on the standard goal of short-run economic efficiency in the spot market and to provide some source of supplementary income for generators (the approach advocated in the northeastern states of the United States).

The second is to allow high prices to occur (above the mar-ginal production cost) and to focus on long-run economic efficiency by keeping the overall average spot price com-petitive (the approach followed in Australia and proposed in Texas). In the latter case, the basic rationale is that a few high spot prices will provide sufficient financial incentives to maintain generation adequacy. Experience in the Austra-lian market suggests that this rationale is correct, and aver-age spot prices in Australia are low even though price spikes up to a cap of A$10,000/MWh (US$7,500/MWh) can and do occur (NEMMCO, 2005). In contrast, most deregulated mar-kets in the United States set a price cap of $1,000/MWh in the spot market and have introduced ways to mitigate high spot prices, such as the Automatic Mitigation Procedures (AMP) used in the NYCA (NYISO, 2005c).

Before describing the changing behavior of spot prices in the NYCA, the question of whether or not high spot prices are economically justifiable should be addressed. Since most spot prices in the NYCA are well below $100/MWh and the highest marginal production cost for any generating unit is almost certainly less than $200/MWh, is it reasonable to al-low prices to go above $5,000/MWh (the total cost of pro-duction from peaking capacity that is used for only 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months per year, corresponding to 1 day per year in Figure E-3)?

The answer is yes, because the value of lost load (VOLL) when an unscheduled outage occurs is very high, particu-larly for a large urban complex like New York City. A recent study published by the Lawrence Berkeley National Labora-tory (LBNL, 2004) concludes that the total cost of interrup-tions in electricity supply is $80 billion/year for the nation (LBNL, 2004, pp. xi-xii), and 72 percent of this total is borne by the commercial sector (plus 26 percent by the industrial sector and only 2 percent by the residential sector). The fre-quency of interruptions is found to be the most important determinant of the cost, because the cost of an interruption increases proportionally much less than the length of an in-terruption, and the cost of relatively short interruptions of only a few minutes is substantial.

The cost estimates in the LBNL (2004) report were de-veloped from an earlier report on customer outage costs (Lawton et al., 2003), prepared for the U.S. Department of Energys (DOEs) Office of Electric Transmission and Dis-tribution. The results in the DOE report are based on a num-ber of surveys of the outage costs for individual customers.

For large commercial and industrial customers in different economic sectors, the average costs are reported for 1-hour outages in dollars per peak kilowatt (Lawton et al., 2003, Table 3-3, p. 13). These average costs range from negligible for the construction sector to $168/kW ($168,000/MWh for 9These costs correspond to the values used by David Patton, market monitor for NYISO from Potomac Economics, in recent discussions among regulators and system operators about the adequacy of generation capacity in the NYCA.

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132 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER a 1-hour outage) for the finance, insurance, and real estate sector, and the average cost for all sectors is $20/kW

($20,000/MWh for a 1-hour outage). Although there is much variability in the reported costs of an unscheduled outage, the overall conclusion is that the VOLL is much higher than

$5,000/MWh, particularly for the finance, insurance, and real estate sector in New York City. It is interesting to note that the current NERC reliability standard of 1 day in 10 years corresponds to a VOLL of $33,333/MWh (5,000 x 16/2.4, based on the costs shown in Figure E-2), and this value is at the low end of the range of estimated values of VOLL in the DOE report.

The high level of the VOLL does not imply that all loads are equally valuable. Some types of load, such as water pumps and refrigerators, can be cut for short periods of time and cause minimal costs for customers. There are many real-istic opportunities for customers to reduce load willingly when prices are high, and the main obstacles to realizing this are the lack of adequate metering and the fact that most cus-tomers still pay fixed regulated prices. Clearly, a truly effi-cient market would include price-responsive load, smart appliances, and a wide range of distributed energy resources on microgrids. Nevertheless, the VOLL is still a valid mea-sure for an unscheduled outage, and as a result, having gen-erating units available to meet unexpected contingencies is economically justifiable, even if these units are only dis-patched for a few hours each year. The real problem for regu-lators is how to pay for these generating units with low ca-pacity factors that are needed primarily to maintain operat-ing reliability. This question is discussed in more detail in the next section, following a description of the behavior of spot prices in the NYCA after deregulation.

Spot Prices in the New York Control Area After Deregulation Figure E-4 shows the daily spot prices in New York City after the market was first deregulated in the fall of 1999. The prices in Figure E-4 represent the zonal price for New York City in the balancing (real-time) market at 2:00 p.m. each day. During the first summer after deregulation, a number of price spikes occurred. This type of price behavior provided sufficient financial incentives for investors to initiate the li-censing process for a number of new generating units. How-ever, the summer of 2000 was exactly when the deregulated market in California became dysfunctional, leading even-tually to an intervention in the California market by FERC in the fall. The response of regulators and politicians in the Northeast was to adopt measures to ensure that the problems experienced in California were not repeated in their own re-gions. High prices above the marginal production cost were treated as evidence of the exploitation of market power by FIGURE E-3 Average total cost of production (in dollars per megawatt-hour generated) for a representative peaking unit.

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APPENDIX E 133 generators. (This is strictly correct in an economic sense given the standard textbook definition of a competitive mar-ket.) For example, the NYISO set a low price cap of $1,000/

MWh and eventually introduced Automatic Mitigation Pro-cedures that made it harder for generators to justify submit-ting high offers above their true production costs into the spot market.

The presence of AMP, together with additional new gen-erating capacity, more participation by loads, and other fac-tors have resulted in fewer price spikes occurring after the summers of 2000 and 2001. This is clearly evident in Figure E-4, and the current price behavior in the spot market will probably continue. Although high price volatility is perfectly acceptable in Australia, it is highly unlikely that politicians in the Northeast, unlike Texas, will tolerate price spikes even if they actually result in lower average prices and better op-erating reliability. For the NYCA, this situation implies that many generating units needed for operating reliability in New York City and Long Island will not earn enough in-come above production costs to cover their capital costs.

Given the current behavior of spot prices, additional finan-cial incentives from other sources will be needed to maintain generation adequacy in the NYCA.

Concerns about maintaining generation adequacy are not limited to New York City or the NYCA. This problem is widespread. For example, the NERC report Long-Term Reli-ability Assessment (NERC, 2005, Fig. 7, p. 16) shows that the projected reserve margins published in 2001 for the na-tion were substantially higher than they had been a year ear-lier. However, the delays and cancellations in the construc-tion of new generating units have resulted in lower projections published in the 2004 report that are actually lower than the corresponding low values in the 2000 report.

The projections of summer capacity margins for 2005 are even lower, and fall below 15 percent by 2008 (NERC, 2005, Fig. 7, p. 18).

The changing behavior of spot prices experienced by gen-erators in New York City since the deregulated wholesale market began is illustrated by the three average price-dura-tion curves shown in Figure E-5. The three curves are de-rived from the hourly zonal spot prices in New York City from May to April for 2000-2001, 2002-2003, and 2004-2005, corresponding to the standard time periods used by the NYSRC to determine the annual installed capacity require-ments for the NYCA. The two curves for 2002-2003 and 2004-2005 are almost identical and consistently below the Date FIGURE E-4 Daily zonal spot prices ($/MWh), January 2000 to July 2005, for New York City in the balancing (real-time) market at 2:00 p.m. on the first day of each month shown. SOURCE: Derived from NYISO hourly spot prices, www.nyiso.com; accessed November 2005.

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134 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER curve for 2000-2001 over the truncated range of hours shown in Figure E-5. An important additional point is that the effect of suppressing price spikes after 2000-2001 did not lower the annual average spot price. The annual average spot prices are $57.47/MWh, $59.81/MWh, and $67.96/MWh for 2000-2001, 2002-2003, and 2004-2005, respectively. The lowest average price occurred in 2000-2001, and the average price-duration curve for 2000-2001 eventually crosses the other two curves if the horizontal axis is extended beyond 1,000 hours0 days 0 hours 0 weeks 0 months . For example, comparing 2000-2001 and 2004-2005, the two curves cross at 3,042 hours4.861111e-4 days 0.0117 hours 6.944444e-5 weeks 1.5981e-5 months (equivalent to a capacity factor of 35 percent), and for higher capacity factors, the prices are eventually $10/MWh lower in 2000-2001 than they are in 2004-2005. Although there is no guarantee that the relationship between average prices and price spikes will behave this way, there is also no reason to assume that higher or more frequent price spikes must lead to higher average prices.

Each average price-duration curve in Figure E-5 is com-puted by ranking the hourly spot prices from highest to low-est, and for any given number of hours N (the horizontal axis), the corresponding price in dollars per megawatt-hour (vertical axis) measures the average spot price for the N hours with the highest prices. In other words, this average price is the average revenue received by a generator from a generat-ing unit in New York City if it was dispatched for the N hours with the highest spot prices in a year (note that this definition of a duration curve is not the same as the one used to derive a load duration curve, because the latter is simply a ranking of the hourly loads and it does not measure the average load for the N hours with the highest loads). For a generator in New York City, each average price-duration curve in Figure E-5 represents the average revenue curve that corresponds to the average total cost curve shown in Figure E-3.

It is clear from a comparison of Figures E-3 and E-5 that the shape of the average price-duration curve in 2000-2001 is much closer than the other two curves are to the shape of the average total cost curve in Figure E-2, particularly when the number of hours is close to zero. (Note that the horizon-tal axis in Figure E-2 corresponds to a range of 16 to 1,600 hours0.00694 days 0.167 hours 9.920635e-4 weeks 2.283e-4 months .) The basic reason for the change after 2000-2001 is that price spikes were higher and more frequent in 2000-2001. For generators in New York City, the revenues re-ceived from sales in the spot market in 2000-2001 were far more consistent with their average total costs than they have Hours FIGURE E-5 Average price-duration curves in the balancing market for May-April in New York City (in dollars per megawatt-hour) for 2000-2001, 2002-2003, and 2004-2005. SOURCE: Derived from NYISO hourly spot prices, www.nyiso.com; accessed November 2005.

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APPENDIX E 135 been in more recent years, when fewer price spikes occurred.

To get more insight into the conclusions of this section, it is helpful to look at the annual capacity factors of the major generating units in New York City and Long Island. This information is presented in Table E-2, using 2004 data from the NYISO (2004) and covers roughly half of the generating capacity required in New York City and Long Island to meet reliability standards (see Table E-1).

The power plants shown in Table E-2 all have generating units with a total capacity greater than 80 MW, and most of the remaining generating units in New York City and Long Island are small turbines of various types that use natural gas or distillate oil as a fuel. Only 4 of the 13 power plants in Table E-2 have capacity factors above 50 percent. The two plants with the highest capacity factors (more than 85 per-cent) are relatively new combined-cycle generators (No. 8 and No. 10), the next highest (No. 11) is a relatively new cogeneration unit with a capacity factor of 74 percent, and the fourth highest (No. 5), with a capacity factor of 55 per-cent, is the only traditional steam turbine among the four.

With one exception (No. 6), the other power plants in Table E-2 are relatively old steam turbines, and their capacity fac-tors range from 9 percent to 41 percent. The low capacity factors of these plants confirm the fact that the production costs of traditional steam turbines that use natural gas or residual oil are substantially higher than the costs of the combined-cycle units (and purchases from upstate).

Since a large number of the installed generating units in New York City and Long Island are relatively old units, with high production costs and low capacity factors, there is a legitimate concern about the continued financial viability of these generating units and whether some of them will be retired in the near future. This concern has been exacerbated by the changes in the behavior of spot prices shown in Fig-ure E-5. Comparing the average price-duration curves in 2004-2005 and 2000-2001, the average price paid to gener-ating units with high capacity factors (>>66 percent) in-creased by roughly $10/MWh. In contrast, the average price paid to generating units with low capacity factors (<<33 per-cent) fell dramatically, but these units (or their replacements) are still essential for maintaining the operational reliability of supply in New York City and Long Island. Nevertheless, the VOLL is very high (probably more than 100 times the average spot price), and it is still economically rational from the perspective of society as a whole to maintain a high level of operational reliability and to meet the NERC standards of limiting outages to less than 1 day in 10 years.

The underlying economic problem is that the spot prices in a strictly competitive market are not high enough to cover the total cost of the generating units with low capacity fac-tors that are essential for maintaining operating reliability.

In other words, the current financial incentives in a competi-tive market are insufficient to keep installed generating units with high production costs active in the market or to attract investors to build new generating units to replace them. Al-though current spot prices in 2004-2005 are probably closer to competitive levels than they were in 2000-2001, the text-book definition of a competitive market simply ignores the reliability of supply as an issue. The discussion in the next section explains how regulators have addressed this funda-mental inconsistency between the market signals from a competitive spot market and the legitimate objective of TABLE E-2 The Capacity Factors in 2003 of Major Generating Units in New York City and Long Island Unit and Summer Generation Capacity Name Zone Fuel Typea Capacity (MW)

(GWh)

Factor (%)b

1. Ravenswood ST 01-03 LI ST FO6/NG 1,765 4,751 31

2. Barrett ST 01-02 LI ST NG/FO6 390 1,336 39

3. Far Rockaway ST 04 LI ST NG/FO6 107 264 28

4. Glenwood ST 04-05 LI ST NG 238 545 26

5. Northport 1-4 LI ST NG/FO6 1,539 7,507 55

6. Wading River 1-3 LI GT/FO2 245 306 14

7. Port Jefferson 3-4 LI ST FO6/NG 385 1,399 41

8. Flynn LI CC NG/FO2 136 1,069 89

9. East River 6-7 NYC ST FO6/NG 304 543 20

10. Brooklyn Navy Yard NYC CC NG/FO2 262 1,983 86

11. Cogen Tech-Linden NYC GT/NG 661 4,286 74

12. Poletti 1 NYC ST FO6/NG 882 2,629 34

13. Arthur Kill ST 2-3 NYC ST NG/FO6 860 675 9

aST, steam turbine; CC, combined-cycle turbine; GT, combustion turbine; NG, natural gas; FO6, residual oil; FO2, distillate oil.

bCapacity factor = 100 x generation/(365.25 x 24 x summer capacity/1,000).

SOURCE: Derived from NYISO (2004a), Table III-2).

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136 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER maintaining operating reliability. In this discussion, it is im-portant to distinguish the differences in the financial needs of the existing generating capacity with high production costs and low capacity factors from the needs of new generating capacity, such as combined-cycle units, with high capacity factors. Both types of capacity can contribute to maintaining operating reliability, but their financial needs are not the same, and it is unlikely that a single strategy will be the best solution for solving both problems.

FILLING THE FINANCIAL GAP TO MEET RELIABILITY STANDARDS Before discussing the alternative ways of supplementing the earnings of generators from the spot market for electric-ity, it is important to reiterate the three major regulatory as-sumptions that underlie the need for additional income to maintain operating reliability in the NYCA. First, setting a level of generation adequacy for the NYCA is an acceptable proxy for meeting the NERC standards for reliability (see the section on Determining and Implementing the Reliabil-ity Standards above). Second, given the limitations of the legacy transmission system, the locational requirements for generation capacity in New York City and Long Island de-termined by the NYISO are also acceptable proxies for meet-ing the NERC standards (see the section above titled Gen-erating Capacity). Third, the political realities in the NYCA make it infeasible to adopt the Australian solution of allow-ing high price spikes in the spot market above short-run com-petitive prices (see the preceding section). By accepting these assumptions, the very real complications of determining how to plan for and maintain the reliability of supply have been reduced by the regulators to simply ensuring that require-ments for generating capacity in New York City, Long Is-land, and the NYCA are met.

Clearly, this transformation of concerns about the reli-ability of supply to concerns about generation adequacy is more likely to be an economically efficient solution when the transmission system is relatively robust and the avail-ability of generating capacity is the main limiting factor. This is no longer the case in the NYCA given the structure of the legacy transmission system and the size and location of New York City. Nevertheless, regulators have accepted the as-sumption that meeting capacity requirements in New York City, Long Island, and the NYCA is an effective strategy for meeting the NERC reliability standards. By focusing on gen-eration adequacy, it is likely that the current regulatory prac-tices followed in the NYCA, and the models used to deter-mine the required levels of reserve margins for generating capacity, overlook the potential value of upgrades to the transmission system as a way to improve reliability.

By adopting the three assumptions stated above about re-liability, state regulators have limited their primary concerns about the performance of the deregulated market to the dual objectives of maintaining (1) generation adequacy and (2) short-run competitive spot prices. Consequently, it is inevi-table that the earnings from some generating units needed for operating reliability will be insufficient to make them financially viable. There are two distinctly different ways of addressing this problem. The first is to correct the prices in the spot market for all generating units by providing addi-tional income from another source to cover the missing capital costs. The second is to use targeted contracts, such as Power Purchase Agreements (PPAs), to meet reliability stan-dards with some but not all generating units. Regulators in New York State have chosen the first approach. Their basic rationale is that this strategy is consistent with regulatory theory and is economically fair both for the owners of in-stalled generating capacity and for potential investors in new capacity. In contrast, contracts with some but not all genera-tors are inherently discriminatory and may distort market behavior in an adverse way. These arguments are basically correct using standard textbook economics, but this fact still does not guarantee that the approach chosen by state regula-tors for maintaining reliability in the NYCA will be either effective or economically efficient. The characteristics of a market for electricity are not typical because, unlike storage alternatives for most commodities, the ways of storing elec-tricity economically are very limited. As a result, the benefi-cial effects of having an inventory to cover shortages in the spot market are also very limited in electricity markets, and in general, the amount of generation must balance the level of load at all times.

Oren (2003) has given a persuasive account of the eco-nomic rationale for adopting the strategy chosen by regula-tors for the NYCA, and his justification is consistent with the analyses of real-time pricing in the regulatory literature.

Short-run competitive spot prices imply that only the pro-duction costs of peaking units will be covered in the spot market. Consequently, the cost of capital for a peaking unit should be added to the competitive spot price for all genera-tors to get the correct price (long-run marginal cost of pro-duction). A straightforward solution to this problem is to include an expensive source of energy with no capital costs in the portfolio of supply options. The obvious choice is to treat shedding load as a source of energy that is valued at the VOLL. Since the VOLL is very high, this strategy is equiva-lent to the Australian solution of allowing high price spikes.

Joskow and Tirole (2003) have made the same argument as Oren (2003) in their analysis of how to make deregulated markets work better with fewer nonmarket interventions by regulators. They conclude that the current form of deregu-lated market will not lead to merchant investment in new generating capacity because (1) price caps are too low, and (2) most retail customers do not respond to high spot prices because they are still paying fixed regulated rates instead of the real-time spot prices.

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APPENDIX E 137 ceptable, one approach is to cover the missing capital costs for peaking units in a separate market for generating capac-ity. This is the approach that has been proposed by regula-tors in the three northeastern power pools. At this time, the NYISO is the only one of the three to fully implement this type of capacity market. There is still a considerable amount of political opposition to the proposal in New England, and there is an ongoing debate about it among stakeholders in PJM. It is important to understand why there is so much controversy about the effectiveness of a capacity market as a way of providing the incentives needed to initiate merchant investment in new generating capacity.

Initially, the ICAP auction run by the NYISO was simply a market for availability, designed to ensure that enough in-stalled generating capacity would be available to meet the projected loads in New York City, Long Island, and the NYCA. (It should be noted that the Australian market does not have markets for either capacity or reserves because the financial consequences for generators of missing a price spike are so severe if their units are unavailable.) In general, an ICAP auction does provide an additional source of rev-enue for generators that may be significant for the continued financial viability of some installed generating units with low capacity factors. For example, the existence of the ICAP auction may result in some units being available instead of unavailable, and it may also delay the retirement of some units. However, this extra revenue from the ICAP auction is really a bonus for other generating units, such as nuclear and hydro units, because they would be available anyway with-out the ICAP auction. Nevertheless, regulatory theory im-plies that all installed capacity should be eligible for partici-pation in the auction, and this issue is not a major source of controversy among regulators. The controversy arises when the objectives of the ICAP auction are extended to deal with the investment needed for new generating capacity.

There are three major issues of contention about the ef-fectiveness of extending the ICAP auction to new capacity.

The first is the difficulty of increasing the time horizon far enough into the future to meet the needs of investors. The second is whether it is appropriate to pass the responsibility for maintaining generation adequacy on to load serving enti-ties (LSEs), and, most importantly, the third is how to ensure that enough revenue is provided in the ICAP auction to make investment in new capacity financially attractive. These is-sues are discussed after the following description of how regulators expect the augmented capacity market to work in the NYCA.

The economic justification underlying the current struc-ture of the capacity market in the NYCA was established by Reeder (2002), and a detailed description of this market is given in Chapter 5 of the NYISO Installed Capacity Manual (NYISO, 2004a). The basic structure of the market is that buyers (LSEs) submit bids to buy and generators sub-mit offers to sell into a two-sided auction for generating ca-pacity over a 6-month summer or winter period (a capabil-ity period). There is no guarantee in this type of auction that the quantity of capacity purchased will be sufficient to meet reliability standards, but regulators have imposed an obliga-tion on the LSEs to purchase enough capacity to meet their load plus a reserve margin before the spot market for energy clears. This can be done through secondary trading in auc-tions for capacity over 1-month periods (i.e., making it pos-sible to divide a 6-month strip into its 1-month components) or by bilateral contracts made over the counter between an LSE and a generator. LSEs can also meet some of their own capacity requirements if these sources are certified by the NYISO. The final monthly auction is the spot market for capacity that clears a few days before the month begins. The spot ICAP auction represents the last chance for LSEs to meet their capacity obligations without paying a penalty.

Initially, the ICAP auction in the NYCA was only de-signed to deal with the availability of generating capacity for a few months ahead. In contrast, an investor in a new gener-ating unit probably needs to have a forward contract for en-ergy for at least 10 years to get adequate financing. Hence, the first issue of contention about ICAP auctions is how to extend the auction farther into the future. Although regula-tors recognized this issue as an important objective, a major limitation is that LSEs are generally reluctant to commit to long-term contracts. The basic concern of LSEs is that it is difficult, given the regulatory push toward retail competi-tion, for an individual LSE to predict how many customers it will have in the future, and therefore, how much capacity it needs to purchase. The compromise between the needs of LSEs and generators is to extend the ICAP auction from 1 to 3 years into the future. For an investor, the new auction does provide more information about the likely future levels of income from the capacity market, but a decision to build a new generating unit will still depend on getting a forward contract for a longer time period. Given the relatively short time horizon for contracts in the ICAP auction (and in exist-ing forward markets for electricity, such as the New York Mercantile Exchange [NYMEx]), long-term bilateral con-tracts (i.e., PPAs) will still be needed to get new generating capacity built. Basically, it is unrealistic to expect ICAP auc-tions to solve the problem of the long time horizon needed for an investment in new generating capacity.

The second issue of contention is the current regulatory strategy of placing the responsibility for maintaining gen-eration adequacy on LSEs. Since generation adequacy in a region is specified in terms of the projected load, the public-good characteristics of reliability are converted implicitly to a criterion based on a private good. Markets and decentral-ized decision making can work well for private goods, and as a result, regulators have decided to leave the responsibil-ity for determining how to meet reliability standards, such as generation adequacy, to market forces. This decentralization is similar to the cap-and-trade strategy used in a market for Copyright © National Academy of Sciences. All rights reserved.

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138 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER emissions. Regulators set the standards for generation ad-equacy for each LSE, but the decisions about how to meet these standards are left to the market. LSEs have to purchase enough capacity from generators, or provide it themselves, to meet their capacity obligations.

When levels of installed capacity are low relative to load, it will be harder for LSEs to find generators that are able to contract with them. Consequently, the price of purchasing capacity from generators will increase and may be very high indeed for an LSE that is short of capacity close to real time.

Although an LSE is not obligated to have full capacity cov-erage until the final spot ICAP auction, it may be very risky to wait until the last minute to purchase the capacity needed to meet its capacity obligations. A retailer caught in this pre-dicament might be tempted to drop customers rather than pay the high price required to get full capacity coverage. In this situation, an incumbent utility that still has the regula-tory obligation of meeting load would be required to pick up the discarded customers and pay the high price for additional capacity. However, if there really is insufficient installed capacity to meet generation adequacy in the near future, it is unlikely that there would be enough time to build new ca-pacity. Under the Energy Policy Act of 2005, NYISO would have to shed some load when capacity shortages occur to avoid paying penalties enforced by FERC. In other words, the market signals would come too late to ensure that ad-equacy standards were met without shedding load. This is a very serious deficiency of the ICAP auction, but regulators have anticipated this problem and introduced a demand curve into the capacity auction to address it.

The demand curve is designed to address the third issue of contention and to ensure that the revenue from the ICAP auction is sufficient to make a timely investment in new gen-erating capacity financially viable. The proposed solution originates with the basic deficiency of a competitive market identified in the regulatory literature. The bids of LSEs in the spot ICAP auction are replaced by a specified demand curve (set by regulators). The spot ICAP auction is not like the balancing market for energy because it includes all exist-ing contracts on the supply side of the auction. For each lo-cation, the demand curve is calibrated to the total capacity requirement for that location, and it ensures that the market price of capacity is equivalent to the capital cost of a peaking unit when the total supply of capacity falls to the amount needed for adequacy. The market price will be higher (lower) if the total capacity offered is lower (higher) than the re-quired amount. There are additional features of the NYCA auction, such as how capacity is measured and whether the demand curve should have a kink in it, but the overall objec-tive is clear. The market price of capacity in the spot ICAP auction should be equivalent to the capital cost of a peaking unit when the market is economically efficient (i.e., the total supply of capacity in the spot ICAP auction is just equal to the capacity needed for adequacy).

Incorporating a demand curve into the spot ICAP auction still does not solve the basic financial problem faced by an investor looking for a long-term contract. To address this problem, the parameters of the demand curves are set for the next 3 years. Even though the actual ICAP auctions are con-ducted a few months ahead in the same way as before, inves-tors now know that the future ICAP auctions, up to 3 years ahead, will converge to the specified demand curves. In fact, the information provided by the modified ICAP auction is more valuable than this because the economic rationale for setting the demand curve is known. As long as the total ca-pacity supplied in each spot ICAP auction is close to the capacity required for adequacy, a prospective investor will be able to recover the annualized capital cost of a peaking unit from the ICAP auction.

The main weakness of this argument is that it is difficult for anyone to predict future levels of available capacity because some of the capacity requirements may be self-supplied by LSEs and the retirement dates of generating units are considered to be private information in a deregulated market. The overall result of these uncertainties is that the projected levels of future reserve margins published annu-ally by NYISO in Power Trends (NYISO, 2005d) and Load and Capacity Data (NYISO, 2004) are no longer as accurate as they were under traditional regulation. An investor cannot take the NYISO predictions at face value. Even if the exact specifications of the demand curve in the modified ICAP auction are known, there is still a substantial amount of un-certainty about the future market price of capacity due to the uncertainty about future levels of installed capacity. Al-though the demand curve does provide more security about the future revenue stream from a capacity market (by reduc-ing the price volatility and mitigating the boom-or-bust cycles that typically occur in an ICAP auction), there is still a lot of risk for investment decisions. For any investor, hav-ing a demand curve in the spot ICAP auction does not pro-vide an effective substitute for having a long-term PPA. The demand curve may be an effective way of keeping some gen-erating units with low capacity factors in the energy market, but it is unlikely to be an effective way of getting new gener-ating units built when and where they are needed.

A more pragmatic criticism of the ICAP auction is that the higher payments to generators for capacity do not place any obligations on the generators to build new capacity.

When the spot prices are consistent with short-run competi-tive behavior, generators do need to earn additional income to initiate an investment in new capacity. However, paying this extra income to all generators for installed capacity in the ICAP auction is expensive, and it still does not guarantee that generation adequacy will be maintained. The obvious solution proposed by most critics of ICAP auctions is to is-sue PPAs when projected future levels of capacity fall short of the required standards. If this were done, there would be contracts to build capacity when and where it was needed, but it might be necessary to pay the investors a substantial premium above the expected income that could be earned in Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX E 139 the energy, reserve, and capacity markets. Issuing a PPA in this way no longer would be a decentralized decision based on market forces. Some regulatory authority must make the initial decision about the size and location of the PPAs. Once this has been done, the responsibility for implementing and paying for the PPAs can be allocated to the LSEs. In es-sence, the locational-capacity obligations set by regulators for LSEs in the existing ICAP market would be supple-mented by obligations for acquiring new capacity when pro-jected levels of installed capacity do not meet the levels of generation adequacy needed to maintain reliability.

Critics of the critics of ICAP auctions argue that issuing PPAs would put the market on a slippery slope back to regu-lation. When a premium is paid in a PPA, it is equivalent to putting a financial squeeze on the owners of installed capac-ity. As a result, some generating units may be retired prema-turely, increasing the need for new capacity or some form of PPA to keep installed capacity in the market. In other words, once decisions about building new capacity were central-ized, many generators would want to get special deals. To avoid an undermining of the implicit fairness of the ICAP auction, it would be necessary for regulators to set rules for determining (1) when to issue PPAs for new capacity and (2) which installed generating units would be eligible for a PPA.

For example, the rules could require initiating PPAs (1) for new capacity when the reserve margin forecasted by the NYISO fell below a specified amount on a specified future date, and (2) for installed capacity when the capacity factor of a unit fell below a specified level and the unit was still needed for reliability. Contracts of this type for Reliability-Must-Run (RMR) units are common in the industry now, and the only real change required would be to specify an explicit set of rules for how and when new PPA or RMR contracts would be authorized by the regulators.

The uncertainty that exists about how reliability standards will be maintained in deregulated markets has contributed to a substantial level of regulatory risk faced by investors.

Regulatory risk implies that high rates of return on capital will be required for merchant investments in deregulated markets if there is a lack of clarity about existing rules and the possibility of future rule changes. This situation consti-tutes a major impediment to investment in new capacity that was not present when the rate of return was guaranteed un-der regulation. For an investor in the NYISO market, having a PPA would be a good substitute for a regulated rate of return if the possibility of a default was minimal. Since the time horizon in the ICAP auction is too short to commit to building new capacity, an investor will still want to have a PPA with some credit-worthy buyer. However, an inherent characteristic of transferring the responsibility for genera-tion adequacy from regulators to decentralized decisions by LSEs would be to require that investors contract with LSEs.

The reluctance of most LSEs in the New York Control Area to make long-term contracts is justifiable and reflects the real uncertainty that they face about future market condi-tions. Hence, the risk premium for making a PPA with an LSE will be substantial and the resulting cost of capital will be high. Under these conditions, a large part of the regula-tory risk is caused by the uncertainty that exists about how defaults will be treated if, for example, a retailer holding a PPA files for bankruptcy.

One way to reduce the regulatory risk of a PPA between an investor and an LSE is to have the contract backed by regulators. This situation is, however, essentially equivalent to having the PPA initiated by the regulators in the first place.

To avoid getting too much capacity built, a PPA would have to be certified as necessary for generation adequacy. The decision about how much new capacity should be built would no longer be left to decentralized market forces. The overall conclusion is that the NYISO ICAP auction does not provide a secure enough source of extra income far enough into the future to meet the needs of investors. In addition, it places no obligations on generators to spend the extra income on build-ing new capacity. The threat that LSEs will have to pay pen-alties if they fall short of their capacity obligations is un-likely to be effective. As long as spot prices remain at short-run competitive levels in the electricity market, it will be difficult and expensive to get LSEs to bear the financial risk of building new capacity without some form of regula-tory backing. The evidence presented in the next section about how standards of generation adequacy are being met in the NYCA suggests that this conclusion is correct. Most of the existing proposals to build new generating units were initiated when price spikes occurred in the energy market (2000-2001), and many of these projects have been post-poned now that electricity prices are more competitive.

CURRENT PROSPECTS FOR MAINTAINING GENERATION ADEQUACY IN THE NEW YORK CONTROL AREA The financing of new generation and transmission facili-ties in the NYCAregardless of whether it is needed to ac-commodate the retirement of existing facilities, the projected growth of load, or the intentional shutdown of Indian Point Units 2 and 3 before the end of their current licensesmust be understood within a broad context associated with the current hybrid mix of competitive markets and regulatory interventions. Under this mix, projects to build new genera-tion and transmission facilities are no longer preapproved by the New York Public Service Commission (NYPSC), nor is there an implicit guarantee to investors that all prudent pro-duction costs and capital costs will be recovered from cus-tomers. Although market forces have been able to maintain levels of generation adequacy with relatively little regula-tory intervention in Australia, for example, this is not the case in the NYCA.

The previous section above explains why the successful efforts of regulators to ensure that the spot prices of electric-ity meet short-run standards of economic efficiency have un-Copyright © National Academy of Sciences. All rights reserved.

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140 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER dermined the financial viability of generating units that are needed for reliability but have low capacity factors. This policy has made the current shape of the price-duration curve much flatter than it was in 2000-2001 (see Figure E-5), and as a result, has reduced the earnings of generating units with low capacity factors (peaking units) relative to units with high capacity factors (baseload units). The flattening of the price-duration curve, coupled with the current uncertainty about the future prices of fossil fuels such as natural gas, has led to delays in the construction of new generating facilities that have already received licenses to build in the NYCA.

Fortunately, the deteriorating outlook for attaining the re-quired levels of generation adequacy for meeting the NERC standards for reliability in the NYCA after 2008 has been recognized in the new Comprehensive Reliability Planning Process (CRPP). This planning process was initiated in 2005, and there is still enough time for regulators to find solutions for meeting reliability standards in the NYCA. However, at this particular time, potential solutions are still being dis-cussed, and no specific solution has been chosen. This situ-ation makes the task of this committee more difficult be-cause it is necessary to propose a realistic plan for building new generating facilities to meet reliability standards before the alternatives to Indian Point can be evaluated. A detailed discussion of the scenarios specified by the committee and the corresponding results are presented in Chapter 5 of this report.

The change in the outlook for meeting reliability stan-dards in the NYCA is best summarized by the drop in pro-jected reserve margins for generating capacity from the fore-cast made in 2004 to that in 2005, shown in Figure E-6. In NYISOs 2004 report, the reserve margin in 2008 was ex-pected to be over 40 percent, but in the 2005 report, the cur-rent projection for 2008 is less than the 18 percent needed to meet the NERC reliability standards.

The drop in the projected reserve margins shown in Fig-ure E-6 was caused by delays in the construction of new generating units that had already received construction li-censes. The lists of new generating units that correspond to the two projections of reserve margins in Figure E-6 are shown in Tables E-3 and E-4 for 2004 and 2005, respec-tively. The two lists are essentially the same, but the Pro-posed In-Service dates are quite different. In 2004 (Table E-3), 2,038 MW were under construction; 3,120 MW were FIGURE E-6 Projections made in 2004 and 2005 of the summer reserve margin for generating capacity in the New York Control Area.

SOURCE: Projections made in 2004 from Table V-2, Load and Capacity Schedule in NYISO (2004b); those made in 2005 from Table 7.1, Load and Capacity Table, in NYISO (2005d).

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APPENDIX E 141 TABLE E-3 New Generating Units Proposed for the NYCA in 2004 SOURCE: NYISO (2004b).

approved; and 1,605 MW had applications pending, for a total of 6,763 MW. In 2005 (Table E-4), the amount of ca-pacity under construction was still 2,038 MW, but none of the other nine projects had proposed in-service dates. In 2004, five of the nine projects had proposed in-service dates no later than 2007, and the dates for the other four units were uncertain. The important implication is that it is no longer realistic under current economic conditions to assume that a generating unit will be built after regulators have approved a license for construction. This was typically not the case un-der regulation.

The importance of reliability has also been recognized in the Energy Policy Act of 2005, and the major effect of this legislation is to give FERC the overall authority to enforce reliability standards throughout the Eastern and Western In-ter-Connections. Although it is still too early to know how this new authority will be implemented by FERC, it is clear that the threat of paying penalties will be a tangible reason for regulators in New York State to make sure that reliability standards are met. In addition, if the required levels of gen-eration adequacy are not maintained, the possibility that some load will have to be shed to maintain adequate capac-ity margins will be unpopular with politicians and the pub-lic. Hence, it is highly likely that state regulators will deal with the current problem of inadequate generating capacity in the NYCA.

When the uncertainty about the retirement dates of exist-ing generating units is combined with the uncertainty about whether new generating units will be built, the task faced by state regulators, ensuring that there is enough installed gen-erating capacity to meet FERCs reliability standards, is very challenging. Nevertheless, reliability standards must be met because, as explained in the section on The High Cost of Reliability, above, the cost of blackouts in a dense urban area like New York City is very high. (The value of lost load is over $10,000/MWh compared with typical spot prices of less than $100/MWh.) It is also clear that the regulatory prac-tices in the NYCA existing prior to the CRPP and the Energy Policy Act of 2005 were not entirely satisfactory. During public meetings held by this committee, it was unclear what responsibilities the different regulatory organizations had for ensuring that reliability standards in the NYCA are met. Both the New York Public Service Commission and the Northeast Power Coordinating Council (NPCC) are required to con-firm that NYISOs plan for meeting projected levels of load will meet reliability standards. However, the main problem identified by the Indian Point committee was that there were no standard procedures for determining how deficiencies in a plan would be corrected. According to Michael Forte, Chief Engineer for Planning at Consolidated Edison, addressing the committee, Reliability trumps economics, and in his view a transmission provider such as Consolidated Edison Copyright © National Academy of Sciences. All rights reserved.

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142 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER must focus on reliability. However, Howard Tarler (NYPSC) stated that load serving entities and energy service compa-nies are responsible for maintaining the levels of generating adequacy needed for reliability. Until the lower projections of capacity margins were published in the CRPP report in September 2005, it seems that most state regulators believed that the existing regulatory practices were working well and that reliability standards would continue to be met.

Merchant generation and transmission projects are diffi-cult to finance under current economic conditions. Accord-ing to the chairman of the NYPSC, Merchant transmission projects are currently experiencing financing difficulties due to uncertainty about cost recovery by non-utility providers (Flynn, 2005). Carl Seligson, a Wall Street financier, made the same point in his presentation of March 15, 2005, to the committee when referring to his three Rs rule: Risk Re-quires Return! He also stated that a better way to finance utility projects is to follow the practices currently used in Iowa State.10 Under this scheme, regulators and investors agree in advance of the construction on an explicit set of rules for recovering costs from each new project. This is a transparent process that reduces the financial risk for inves-tors and lowers capital costs. The process is consistent with issuing a Power Purchase Agreement for a new generating facility that has regulatory backing, and could include per-formance-based rates of return. In contrast, there is a percep-tion among some investors that state regulators in the NYCA may change the rules for a standard PPA that is initiated as a TABLE E-4 New Generating Units Proposed for the NYCA in 2005 SOURCE: NYISO (2005d).

10All these comments were made at the committees second meeting, March 14-16, 2005.

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APPENDIX E 143 bilateral contract, and in particular, may try to recover prof-its from incumbent utilities holding a PPA for a successful contract but provide no compensation for losses. To the extent that this perception is correct, the possible asymmetry in the treatment of profits and losses increases the regulatory risk faced by investors.

In summary, getting sufficient financing for the capital-intensive investments in a new generation or transmission facilities needed to maintain the reliability of supply in the NYCA requires state regulators to address the following issues:

Long-term PPAs and other contracts need a projected revenue-stream that will cover the production costs and sup-port the recovery of the initial capital cost with a reasonable rate of return.

A regulatory commitment is needed to establish and abide by explicit rules governing long-term PPAs and other contracts.

Credit-worthy counterparties are needed for investors initiating long-term PPAs and other contracts to build new facilities, or as an alternative, some regulatory backup to deal with defaults on contracts.

Increased regulatory consistency is needed for expedit-ing the siting and licensing of new facilities at the state and local level. (Note that the Article X law, which facilitated this process, expired in 2002. A variation of the Article X law was introduced in the New York State Legislature in 2005 but was never enacted.)

More emphasis is needed on the importance of upgrad-ing transmission facilities (current regulatory practices and the models used for analysis treat generation adequacy as the main issue for maintaining reliability and do not address transmission adequacy effectively).

Appropriate roles should be established for the New York Power Authority and the Long Island Power Authority to determine the best way for these authorities to help main-tain reliability standards. (These two public authorities con-trol substantial amounts of generation and transmission ca-pacity in New York City and Long Island. In the past, these authorities have been used to intervene in the market by, for example, installing 500 MW of peaking capacity in New York City. These types of decisions are not part of the stan-dard planning process in the NYCA, and as a result, they create an additional source of regulatory risk for investors.)

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144 F

Background for the System Reliability and Cost Analysis Samuel M. Fleming1 1Samuel M. Fleming is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs.

This appendix contains the following:

Appendix F-1, The NYISO Approach, and

Appendix F-2, Notes on the MARS-MAPS Simula-tions.

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APPENDIX F 145 APPENDIX F-1 THE NYISO APPROACH The Comprehensive Reliability Planning Process (CRPP) recently completed by NYISO represents a major advance in planning. It is a stakeholder process, described along with its criteria, organization, and approval process in the Reliability Needs Assessment (RNA) Support Document (NYISO, 2005, pp. 1-6). Below are the main points of the CRPP relat-ing to this committees charge:

The reliability of the electrical generation and trans-mission system in the New York Control Area (NYCA) would be inadequate beginning in 2009 if, as is the case his-torically, thermally constrained transmission limits control transmission.1 The reliability criterion of loss-of-load expec-tation (LOLE) for the NYCA reaches 0.160 by 2009, and thus exceeds the New York State Reliability Council (NYSRC) criterion of LOLE of 0.1 or less.

The projected inadequate reliability by 2009 is a conse-quence of the factors listed below, in spite of new resources of about 2,890 megawatts (MW) coming online between 2005 and 2007 (including the 660 MW Neptune high-volt-age direct current (HVDC) cable from the Pennsylvania-Jer-sey-Maryland (PJM) Independent System Operator into Long Island). These compounding factors are as follows:

Projected load growth in southeastern New York State; Increased electrical demand over the past decade of 5,000 MW in southeastern New York, only one-fourth of which was matched by net additions to generating capacity or load reduction downstate; Scheduled retirements by early 2008 of about 2,250 MW of generating capacity and changes in neighboring power systems; and, consequently Greater past reliance and higher projected reliance on a complex and aging transmission system.

The states transmission system is increasingly charac-terized by congestion, especially during summer peak loads, at the Upstate New York-Southeast New York (UPNY/

SENY) transmission interface, where power generated in northern and western New York state is transmitted toward the high-load centers in southeastern New York, especially New York City, Long Island, and, increasingly, Westchester County (NYCA Zones J, K, and I, respectively)and by the complexity of the transmission system within New York City. Consideration of transmission transfer constraints, par-ticularly at the UPNY/SENY interface (just north of Pleas-ant Valley, New York), is thus a key aspect of considering the projected reliability of the alternating current (AC) trans-mission system.

The New York Power Authoritys (NYPAs) Poletti Unit 1 (Zone J, 885 MW) represents 39 percent, and Lovett Units 3, 4, and 5 (Zone G, 431 MW) represent 19 percent of the scheduled retirements of generating capacity by early 2008. Thus Poletti 1 and the Lovett Stations units together total 1,315 MW and represent 58 percent of the scheduled retirements by mid-2008.

Addition of a corrective resourcean additional 250 MW of generating capacity in New York City (Zone J), be-yond NYISOs Initial Base Casewould be needed by 2009 to meet the NYCA LOLE criterion of 0.1. The additional generating capacity needed downstate increases to 1,250 MW by 2010 and to 1,500 MW by 2011.

Reactive power deficiencies in the Lower Hudson Val-ley (LHV) mean, however, that voltage-constraint limits2 in the transmission system, if not corrected, would control the reliability situation, rather than thermal transmission con-straints. In this situation, the projected NYCA LOLE reaches 0.395 by 2008 and 2.43 by 2010. The impact if voltage con-straints were to controland if only adding more generation capacity were to be considered would therefore be that an additional 500 MW of generating capacity would be needed in New York City (Zone J) by 2008, increasing to 1,750 MW downstate in Zones I through K by 2010 (unless an addi-tional 1,500 MW were added in Zone J alone by 2010) (see NYISO, 2005).

The retirements of Lovett Station Units 2, 3, and 4 and Poletti Unit 1 by early 2008 therefore also result in the need in 2008 for a resource to correct reactive power, some 335 megavars (Mvar) of static VAR compensation (SVC) at Ramapo Substation (southern Zone G). By 2010, some 1,000 Mvar of SVC capacity would be needed downstate, 500 Mvar at Ramapo and 500 Mvar at Sprain Brook (southern Zone I). The inadequate NYCA system reliability beginning in 2008 or 2009 exists without the additional consideration of the hypothetical retirement of Units 2 and 3 of the Indian Point Energy Center that presently supply 2,138 MW of power and about 1,000 Mvar of reactive power downstate.

A brief scenario analysis describes the impact on NYCA system reliability of the hypothetical early retirement of the Indian Point Units 2 and 3 in 2008 and 2010, respec-tively. In this early-retirement scenario, the LOLE for the 1Thermal limits relate to avoidance of overheating the transmission lines, a condition causing the lines to sag, and in some instances to touch vegeta-tion, causing outages.

2Voltage drop in the AC system must be tightly limited to maintain fre-quency and synchronous operation and to avoid physical damage both to generating equipment and equipment served as load.

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146 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER NYCA in 2010 is projected to be 3.5 days per year, which is 35 times higher than the NYSRC requirement.3 The final NYISO Reliability Needs Assessment report was issued December 21, 2005; the solicitation for market-based solutions was issued December 22, 2005, along with criteria for evaluating the viability of proposed market-based solutions. Responses were due February 15, 2006. Proposed solutions are to be evaluated, and decisions will result in issuance of the final NYISO Comprehensive Reliability Plan in July 2006.

Because of the complexity of the generation and trans-mission system in New York State and its interconnected regions, a reliability analysis is quite elaborate. It is thus important to appreciate the issues addressed, as well as the logic and sequence of the approach to the problem. To an-ticipate some of the considerations and results discussed be-low, one should also recognize that while the regions in the Northeast are electrically interconnected, the inter-region power-transfer capability is, at present, about 5 percent of the peak electrical loads of the region. Thus, the ability of surrounding regions to supply power to the NYCA under emergency conditions, while quite important, is still rather limited.

The main elements of the NYISO (2005) study addressed the adequacy of the system to provide reliable power re-sources, requiring both enough generating capacity and the capability to transmit the power to the load centers. Adequate generation (or additional capacity required, if needed) was addressed first, and then possible limitations of the transmis-sion system that were identified.

First, the NYCA LOLEs up to 2010, for the first 5 years of an (NYISO) Initial Base Case, are calculated, assuming no transmission system transfer limitations within the NYCA system. This Free Flow Transmission case indicates only whether the projected installed generating capacity would be sufficient to satisfy the projected load demand. Next a recalculation is made of the LOLE for the NYCA when the transmission limits internal to the NYCA are imposed. This calculation indicates whether the projected NYCA transmis-sion system in the Initial Base Case is adequate to deliver the projected electricity generation to the various load zones within the NYCA. (Generally, power flows west to east in upstate New York, then southeast to New York City and Long Island.)

If the simulated system failed to meet the LOLE criterion of 0.1 day per year for the NYCA, additional combined-cycle generation units with 250 MW capacity were assumed to be added until the LOLE criteria were satisfied. Gener-ally, these natural-gas-fired units were assumed to be added to the zone(s) having too high an LOLE. This calculation showed a minimum additional generating capacity needed to meet the New York State reliability criteria.

A simplified transmission screening study was then car-ried out. The NYISO then performed a power-flow analysis, focusing only on the voltage and thermal performance of the bulk power transmission system as well as performing a lim-ited transfer analysis of some 16 New York power system interfaces. The objective of this part of the screening analy-sis was to identify the regions or corridors requiring any sig-nificant transmission-system upgrades in order to meet sys-tem reliability criteria. In particular, the goal was to determine which transmission reinforcement areas could provide the most system performance benefit, over the broadest range of possible system future conditions. Mul-tiple scenarios representing different possible system condi-tions (e.g., generation, load, transmission variations) were evaluated.4 To account for the effects of short circuits, a fault duty study was then performed using the ASPEN design code to determine the impact of the 2013 maximum generation sce-nario on local circuit breakers.5 Following the analysis of the Initial Base Case, scenarios were simulated using test cases that combine variations in installed generation, load fore-casts, transmission system transfer capabilities, and avail-able assistance from neighboring systems. These scenarios were simulated to determine their impact on the reliability of the NYCA system and hence the adequacy of the transmis-sion system.

The Initial Base Case and sensitivity analyses performed by NYISO also include the addition of illustrative and hypo-thetical compensatory resources, zone by zone, that might be used to correct projected capacity deficits in each zone of the system and/or to make up for inadequate transmission line capacity or transmission transfer limits at the intertie points. Also included is a screening-level, macro system 4From NYISO (2005), p. 35. A comprehensive transmission reliability analysis is far more complex, as discussed in the Draft Report. Such com-prehensive reliability analysis considers many more factors, and can in-clude dynamic (time-dependent) simulations. For very complex systems therefore, such comprehensive dynamic transmission analysis requires mas-sive computing power and computer run times, and thus is considered too expensive for initial screening studies. NYISO notes that some far more sophisticated dynamic analyses may be performed annually, while others may be performed only as specific circumstances arise.

5From NYISO (2005), pp. 37-38.

3NYISO identified additional system planning issues. These include (1)

Wind and Renewable Additions to Meet Renewable Portfolio Standards; (2) Environmental Compliance Issues Including NYS Acid Deposition Re-duction Program, the Clean Water Act Cooling Water Intake Best Avail-able Technology, new Source Review, Clean Air Interstate Rule (CAIR),

Clean Air Mercury Rule, Regional Greenhouse Gas Initiative (RGGI), Re-gional Haze Rule; (3) Generation Expansion; (4) Retirement of Existing Generation; (5) Transmission Owner Plans; (6) Fuel Availability/Diversity; (7) Impact of New Technologies; (8) Load Forecast Uncertainty; and (9)

Neighboring System Plans.

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APPENDIX F 147 view that identifies undesirable or unacceptable conditions identified from the modeling and tentative corrective actions.

One such example identified early during the NYISO screening study is large region-to-region flows of electricity, out of upstate New York to New England, with loopback flows of power back to deficit zones in New York, notably the high-load zones of southeastern New York, especially (but not limited to) New York City (Zone J) and Long Island (Zone K). Essentially, the large power loop flow could be corrected by adjusting the transmission transfer limits across the various transmission interties within the NYCA. An as-sumption of Alternate Transmission Constraints at the in-terties within the NYCA by NYISO for its study resulted in a proposed, Modified Transmission System Topology within the NYCA.

This summary of the NYISO approach to the in-state sys-tem analysis provided the framework for the committees study, using the same reliability model. The NYISO results are in NYISO (2005).

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148 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER APPENDIX F-2 NOTES ON THE MARS-MAPS SIMULATIONS The committee sought and received in September 2005 substantial then-current draft information from NYISO. The committee also contracted with General Electric Interna-tional (GE) to run the Multi-Area Reliability Simulation (MARS) program. This model simulates, using a transporta-tion model and Monte Carlo simulation, the electrical gen-eration and transmission system of the New York Control Area (NYCA), interconnected with the four contiguous elec-trical power systems in the northeastern United States and eastern Canada.

The MARS software is the same system reliability screen-ing tool approved by the New York State Reliability Council and used by NYISO in its Comprehensive Reliability Plan-ning Process (CRPP) and Reliability Needs Assessment (RNA) studies (NYISO, 2005). The databases used by GE and NYISO for the MARS analysis differed, however, in that the NYISO database contains commercially proprietary data. Other differences are discussed in Chapter 5.

Projecting Impacts on NYCA System Operation and Economics In addition to the MARS analyses for system reliability, GE used its Multi-Area Production Simulation (MAPS) pro-gram to examine the impacts of the several scenarios on NYCA systemwide operations and economics, as well as the impacts on a portion of the interconnected regional power systems (specifically, part of the PJM system and the Inde-pendent System Operator-New England [ISO-NE] system).

Below are main points of how the MAPS simulation works with MARS, and the results produced by this simulation.

MAPS operates in conjunction with MARS to assess, for systems where MARS projects that reliability criteria are met, the operational and economic characteristics of the en-tire interconnected system. MARS is a transportation model, commonly referred to as a bubble and stick model, connecting generation and loads in the gridthat is, con-necting with direct-current (DC)-like flows the sources and sinks of power. The MAPS software, however, models the electrical system in greater detail, examining the flow on each transmission line for every hour of the simulation, rec-ognizing both normal and security-related transmission con-straints.

MAPS adjusts the operation of each generating unit in the system to meet the electrical generation requirements of the specific scenario being modeled, also considering the trans-mission constraints noted. MAPS calculates the annual vari-able operating cost (VOC) of producing electricity system-wide, and iterates, adjusting the operation of each unit in the system, to determine the minimum annual VOC systemwide.

The variable cost of producing electricity is dominated by fuel costs, but it also includes variable operation and mainte-nance (O&M) costs, unit start-up costs (say, going from a cold start and ramping up to full electrical output), and the variable cost of emission credits consumed, where required.1 Having established the minimum systemwide annual VOC, MAPS then provides for the Northeast Region, the NYCA, and each pricing (load) zone in New York (see Fig-ure 1-3 in Chapter 1), the corresponding wholesale price of electricity, airborne emissions, and the mix of fuels used in generating electricity. Iterative use of the MARS reliability simulations in conjunction with MAPS for the different sce-narios thus provides a preliminary basis for comparing both reliability and trends of economic impacts among the illus-trative scenarios posed by the committee.

Note that the scenario analyses reported here are an early stage of analysis for hypothetical options. Additional analy-sis, using more sophisticated analytical tools, would be re-quired to develop an optimized, defensible plan for Indian Point replacement options. Such an analysis was beyond the scope of the committees charge.

NOTE: In this Appendix F-2 only, the NYISO Initial Base Case corre-sponds to Base Case in the draft NYISO Reliability Needs Assessment dated October 10, 2005. It assumes thermal transmission constraints con-trol, and it employed the Alternate New England Transmission Con-straints on the assumption that substantial loop flow of power into New England, then back into New York south of the Upstate New York/South-east New York (UPNY/SENY) interface would be limited. The issue of what transmission constraints are appropriate has been appealed to the Fed-eral Energy Regulatory Commission and the New York State Reliability Council by upstate power generators. The committees studies assumed the use of the Alt. NE Transmission Constraints, but the committee obvi-ously takes no position on the merit of the appeals before the regulatory commissions. The NYISO Base Case assumed in its Final Report dated December 21, 2005, corresponds to voltage constraints controlling, and leads to the requirement to correct reactive power in the Lower Hudson Valley.

1Some perspective on how the variable cost of operation relates to the total cost of production of electricity is provided by comparing the contri-bution of variable and fixed costs of operation. These vary for different kinds of units. A modern, high-efficiency, gas-fired combined-cycle unit having a heat rate as low as 6,700 Btu/kWh has a Battery Limits Capital Cost as low as $525/kW installed. The corresponding Non-Fuel Operating Cost is typically $3.30/MWh (Hinkle et al., 2005). Numbers reported later for the variable costs of operationdue mainly to the cost of fuelare of the order of $20/MWh. Therefore, in this instance, variable costs represent roughly 85 percent of total operating cost. In New York City, both fuel and capital costs of construction can be markedly higher than in other markets.

Project-by-project analysis is required, in any event, which is obviously very closely-held competitive information.

Finally, note with respect to the recovery of the capital cost of new addi-tions to capacity, that NYISO also runs the installed capacity market (ICAP) in New York that is designed to allow generators of electricity to recover part of their capital costs. Consideration is also being given currently to establishing a capacity market in New York, as a further evolution of deregulating electricity markets.

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APPENDIX F 149 Perspectives on MARS and MAPS Simulations Since MAPS minimizes the projected systemwide oper-ating cost of producing electricity, which in turn tends to be dominated by fuel costs, the fuel prices assumed dominate the economic outputs from this model. Consistent with past practice, GE incorporated current data from Platts,2 which provided a reference 2008 cost of natural gas of $5.1/million Btu (MBtu), decreasing to $4.2/MBtu by 2015 (both in dol-lars-of-the-year, projected future value).

To assess the impact of higher fuel prices, a brief sensi-tivity study was made, using a 2008 natural gas price of $7.8/

MBtu (decreasing to $7.0 by 2015). In comparison, the En-ergy Information Administration (EIA) of the U.S. Depart-ment of Energy reports natural gas prices to electric power consumers in New York rising from $6 to $7 in 2004 to $7.3 to $9.3/thousand cubic feet (1,000 cubic feet of natural gas is almost exactly equivalent to 1 million Btu) through August 2005 (DOE, 2005). The price of natural gas in NYISO is already higher than the high-fuel-price scenario in this case, even before the recent additional gas price volatility intro-duced by Hurricane Katrina. As noted in the report, the De-cember 21, 2005, spot price of natural gas at Henry Hub (the central point for natural gas futures trading in the United States) was $13.55/MBtu, with a New York City gate pre-mium of $1.11/MBtu (prices have subsequently dropped considerably). The consequences of high gas prices and vola-tility in the projections have been explored, but the results on cost are believed to be highly uncertain.

In evaluating the results of the MAPS analyses, it is rec-ommended that readers should (1) appreciate that price as-sumptions for natural gas are low in comparison with present NYISO prices, even for the high-fuel-price cases; (2) look for trends and percentage changes (rather than the absolute values of, say, wholesale price of electricity); and (3) keep in mind the relative changes in prices of fuels and the tenden-cies noted above that are inherent in the assumptions made for the higher-fuel-price sensitivity cases.

The NYISO Initial Base Case The generating units incorporated in the NYISO database used for the modeling were used to develop a baseline case that included the present generation and transmission sys-tem, allowing over the next 10 years for known scheduled retirements of generating capacity, and adding the firmly committed generation and transmission additions and up-grades that are projected to occur throughout the study pe-riod. The source for the data for the existing system was the MARS database maintained by NYISO staff for use in deter-mining the annual installed reserve margin (IRM). The elec-trical load and generation capacity were updated through the 2005-2015 study period based on data from the 2005 load and capacity data report issued by NYISO. Similar reports for the neighboring systems were referenced for updating the data in those regions (NYISO, 2005, p. 35).

For the NYISO (2005) reliability analysis, the NYISO planning staff adopted a somewhat conservative approach, in that only those additions to capacity or transmission were included that (simply stated here) are presently in service, are under construction, or have been certified and are under contract with a credit-worthy entity. For the NYISO Initial Base Case, this translates to the resources that include the following:

Six new generation projects adding 2,228 MW of new capacity.

Scheduled retirements of 2,363 MW of generating capacity.3

Twenty-two other proposed generation projects total-ing some 6,765 MW of proposed capacity are listed in the report. These proposed projects are at various earlier stages of project formation, and thus do not meet the NYISO crite-ria for inclusion in its Initial Base Case.

Eleven additions to transmission capacity are included, all rather small with the exception of the Neptune transmis-sion project, connecting the PJM Control Area to Long Is-land with a DC line of 600 MW capacity. Transmission op-erator (TO) projects on non-bulk power facilities are included.

The resources also include the existing fleet of generating units in the NYCA and parts of three contiguous areas in the Northeast region. The Initial Base Case for the NYISO is shown in Table F-2-1.

For the committees analyses, the units scheduled for re-tirement that are included in the NYISO Initial Base Case are removed from the database at an appropriate time, and additional generating units are added through time to meet the requirements of each scenario being modeled. Thus, sev-eral points should be kept in mind in reviewing results pro-duced by the various MAPS analyses, particularly in the late years of the 10-year study period. First, the presently-known capacity retirements are accounted for, consistent with those in the NYISO Initial Base Case, the last of which is in 2008.

But as discussed in Chapter 3 of the present report and noted by NYISO, some older units in the present generating fleet may be impacted in the future by new environmental regula-tions. Thus, some of the existing units may require future addition of emissions-control equipment, or face curtailment of operations, or may even be retired.

2Base case data set, Quarter 1, 2005, published by Platts, a Division of McGraw-Hill Companies. See http://www.platts.com/Analytic%20 Solutions/BaseCase/index.xml. Accessed November 2005.

3Retirements in the Initial Base Case do not include either Indian Point Unit 2 or Unit 3, but these possibilities are treated briefly in scenario analy-ses, subsequent to the NYISO Initial Base Case.

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150 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER TABLE F-2-1 NYISO Initial Base Case Capacity Details Adopted for the MARS Analysis SOURCE: NYISO (2005).

In-service Status CRPS ATBA ATRA CATR CRPS-15 Dates Summer Winter (**)

2010 2010 2010 2010 2015 I. Generation A. Additions ConEd-East River Repowering I/S 298 I/S X

X X

NYPA-Poletti Expansion 2006/01 500 UC X

X X

SCS Energy-Astoria Energy 2006/04 500 UC X

X X

PSEG-Bethlehem 2005/07 770 828 UC X

X X

Calpine-Bethpage 3 2005/05 79.9 UC X

X X

Pinelawn-Pinelawn Power 1 2005/05 79.9 UC X

X X

ANP-Brookhaven Enery Center 2009/Q2 560 X

X X

SCS Energy-Astoria Energy 2007/Q2 500 X

X X

NYC Energy-Kent Ave 2

007/06 79.9 X

X X

LMA-Lockport II 2007/Q2 79.9 X

X X

Calpine-JFK Expansion 2006/06 45 X

X X

Reliant-Repowering Phases 1 2010/Q2 535.8 593.7 X

X Reliant-Repowering Phases 2 2011/Q3 535.8 593.7 X

X SEI-Bowline Point 3 (Mirant) 2008/Q2 750 X

X Bay Energy 2007/06 79.9 X

X Entergy-Indian Point 2 Uprate I/S 1078 I/S X

X X

Entergy-Indian Point 3 Uprate I/S 1080 I/S X

X X

Fortistar-VP 2007/Q2 79.9 X

X Fortistar-VAN 2007/Q2 79.9 X

X KeySpan-Spagnoli Rd CC 2008-09 250 X

X Chautauqua Windpower 2006/11 50 X

X Besicorp-Empire State Newsprint 2007/Q2 603 660 X

X Flat Rock Windpower 2005/12 198 X

X Flat Rock Windpower 2006/12 123.75 X

X Calpine-Wawayanda 2008/Q2 500 X

X Global Winds-Prattsburgh 2006/10 75 X

X ECOGEN-Prattsburgh Wind Farm 2006/07 79 X

X Constellation-Ginna Plant Uprate 2006/11 610 X

X PSEG Cross Hudson Project 2008 550 X

X Liberty Radial Interconnection to NYC 2007/05 400 X

X B. Retirements NYPA-Poletti 1 2008/02 885.3 885.7 X

X X

RG&E-Russell 2007/12 238 245 X

X X

ConEd-Waterside 6,8,9 2005/07 167.2 167.8 X

X X

PSEG-Albany 2005/02 312.3 364.6 X

X X

NRG-Huntley 63,64 2005/11 60.6 96.8 X

X X

NRG-Huntley 65,66 2006/11 166.8 170 X

X X

Mirant-Lovett 5 2007/06 188.5 189.7 X

X X

Mirant-Lovett 3,4 2008/06 242.5 244 X

X X

Astoria 2 2010/Q2 175.3 181.3 X

X Astoria 3 2011/Q3 361 372.4 X

X Hudson Ave. 10 2004/10 65 X

X X

II. Transmission A. Additions PSEG-Bergen (new)-W. 49th St.345kV Cable 2008 X

X AE Neptune PJM -LI DC Line (600 MW) 2007 UC X

X X

X LIPA-Duffy Convrtr Sta-Newbridge Rd. 345kV 2007/S UC X

X X

X LIPA-Newbridge Rd. 345kV-138kV (2-Xfmrs) 2007/S UC X

X X

X LIPA-E. Garden City-Newbridge Rd. 138kV 2007/S UC X

X X

X LIPA-Ruland Rd.-Newbridge Rd. 138kV 2007/S UC X

X X

X Rochester Transmission-Sta. 80 & various 2008/F UC X

X X

Liberty Radial Interconnection to NYC-230kV 2007 X

X ConEd-Dunwoodie-Sherman Crk 138kV 2005/W X

X X

LIPA-Riverhead-Canal(new) 138kV Operation 2005/S UC X

X X

LIPA-E. Garden City-Supr.Condr. Sub. 138kV 2006/S UC X

X X

LIPA-Northprt-Norwalk Hrbr. 138kV Replcmnt(2) 2006/S UC X

X X

ConEd-Mott Havn-Dunwoodie 345kV Rec.(2) 2007/S X

X X

ConEd-Mott Havn-Rainey 345kV Rec. (2) 2007/S X

X X

ConEd-Sherman Crk 345kV-138kV (2-Xfmrs) 2007/S X

X X

ConEd-Sprin Brk-Sherman Crk 345kV 2007/S X

X X

LIPA-Holtsville GT-Brentwood 138kV (2) 2007/S UC X

X X

LIPA-Brentwood-Pilgram 138kV Operation 2007/S UC X

X X

LIPA-Sterling-Off Shore Wind Farm 138kV 2008/S O&R-Ramapo-Tallman 138kV Rec.

2007/S X

X X

O&R-Tallman-Burns 138kV 2007/S X

X X

LIPA-Riverhead-Canal 138kV 2010/S X

X X

CHG&E-Hurley Ave-Saugerties 115kV 2011/W CHG&E-Pleasant Valley-Knapps Corners 115kV 2011/W CHG&E-Saugerties-North Catskill 115kV 2012/W Besicorp-Reynolds Rd. 345kV 2007/S X

X Spagnoli Rd.-Ruland Rd. 138kV 2008/S X

X Rev. #4 - 5/31/05 CRPS: Comprehensive Reliability Planning Study UC: Under construction ATBA: Annual Transmission Baseline Assessment I/S: In-Service ATRA: Annual Transmission Reliability Assessment CATR: Comprehensive Area Transmission Review Notes

(**)

If Winter ratings are not available, the NYISO will use the summer ratings by default.

9.00 1.00 16.40 11.11 17.70 12.25 4.60 8.00 3.24 6.08 4.08 N/A 10.00 12.40 16.40 0.38 11.00 9.99 9.10 N/A 0.62 7.80 65.00 1.70 N/A 4.00 Proposed Projects for Inclusion in Study Base Cases - Load Flow MW Capacity Miles 7.50 Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX F 151 No detailed attempt was made to optimize the schedule of illustrative additions to capacity to meet load growth and compensate for scheduled capacity retirements. GE and the committee recognize that in some of the scenarios posed, the LOLE projections are lower than required. This means that the illustrative capacity requirements are assumed to be online earlier than needed. In turn this means that the sched-ule for additions of new capacity could likely be relaxed somewhat through optimization studies beyond the scope of this committees charge.

Given the scope of the present study, no attempt was made to adjust the MARS and MAPS databases to account for uncertainty in future changes. Such hypothetical consider-ations could be modeled and included in another analysis, of course, but the effort required to do so is great, and well beyond the scope of this study. (See footnote 4 in Appendix F-1 and footnote to Table F-2-2.)

As a consequence, the older generating units in the NYCA that are not presently scheduled for retirement remain in the MAPS database and are considered operable-as-is today in scenarios running through 2015. An obvious caveat in inter-preting MAPS results for the 2013-2015 timeframe is that this assumption may not be accurate; and if it is not, some caution should be used in interpreting the MAPS results for TABLE F-2-2 Electricity Generation Load and Capacity Representing NYISO Initial Base Case NOTE:

NYCA Reserve Margin in this table does not include either Special Case Resources (975 MW of callable demand under NYISO Emergency Operating procedures) or Unforced Delivery Rights (UDR, corresponding to two HVDC cables, the Cross Sound Cable (330 MW), and the Neptune Cable (660 MW) in and beyond 2007.

The 2006 NYISO Load and Capacity Report (2006 Gold Book) was issued on May 3, 2006, and is available at https://www.nyiso.com/public/webdocs/

services/planning/planning_data_reference_documents/2006_goldbook_public.pdf. Accessed March 2006.

The 2006 document shows that peak load rojections are higher than above (+3 percent for 2008). NYISO notes proposed net additions to resources of 2,244 MW by 2008 with which the present reserve margin requirement of 18 percent would be met through 2010. (Note that 900 MW of these 2,244 MW are upstate, and 160 MW of that is wind, so the impact on projected NYCA LOLE is less obvious.)

SOURCE: NYISO (2005).

Category 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Steam Turbine (Oil) 1649 1649 1649 1649 1649 1649 1649 1649 1649 1649 164 Steam Turbine (Oil & Gas) 9074 9074 9074 8120 8120 8120 8120 8120 8120 8120 812 Steam Turbine (Gas) 1067 1067 1067 1067 1067 1067 1067 1067 1067 1067 106 Steam Turbine (Coal) 3597 3597 3242 2830 2830 2830 2830 2830 2830 2830 283 Steam Turbine (Wood) 39 39 39 39 39 39 39 39 39 39 3

Steam Turbine (Refuse) 264 264 264 264 264 264 264 264 264 264 26 Steam (PWR Nuclear) 2544 2544 2639 2639 2639 2639 2639 2639 2639 2639 263 Steam (BWR Nuclear) 2610 2610 2610 2610 2610 2610 2610 2610 2610 2610 261 Pumped Storage Hydro 1409 1409 1409 1409 1409 1409 1409 1409 1409 1409 140 Internal Combustion 119 119 119 119 119 119 119 119 119 119 11 Conventional Hydro 4488 4488 4488 4488 4488 4488 4488 4488 4488 4488 448 Combined Cycle 7041 8041 8041 8041 8041 8041 8041 8041 8041 8041 804 Jet Engine (Oil) 527 527 527 527 527 527 527 527 527 527 52 Jet Engine (Gas & Oil) 173 173 173 173 173 173 173 173 173 173 17 Combustion Turbine (Oil) 1414 1414 1414 1414 1414 1414 1414 1414 1414 1414 141 Combustion Turbine (Oil & Gas) 1428 1428 1428 1428 1428 1428 1428 1428 1428 1428 142 Combustion Turbine (Gas) 1284 1284 1284 1284 1284 1284 1284 1284 1284 1284 128 Wind 47 47 47 47 47 47 47 47 47 47 4

Other 1

1 1

1 UDR 330 330 990 990 990 990 990 990 990 990 99 Non UDR 2755 2755 2755 2755 2755 2755 2755 2755 2755 2755 275 Special Case Resources 975 975 975 975 975 975 975 975 975 975 97 Demand Response Programs 269 269 269 269 269 269 269 269 269 269 26 NYCA Demand 31960 32400 32840 33330 33770 34200 34580 34900 35180 35420 3567 Required Capability 37395 37915 38434 39012 39531 40039 40487 40865 41195 41478 4177 Total NYCA Capability 38772 39772 39512 38146 38146 38146 38146 38146 38146 38146 3814 Reserve Margin 21%

23%

20%

14%

13%

12%

10%

9%

8%

7%

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152 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER the late years. Also, a detailed model of all Northeast re-gional generating and transmission capacity does not now exist and is a goal of a regional planning task force. Provid-ing the capability to project to 2015 would be an added chal-lenge if the regional capacity were to be examined.

The scenarios considered in this study add considerable new NYCA generation based on modern gas-fired com-bined-cycle units that have a low heat rate, thus require less natural gas per megawatt-hour (MWh) produced, and conse-quently result in lower operating costs. However, no assump-tion is made in the MAPS database used regarding compa-rable addition of more fuel-efficient units in adjacent areas in the Northeast region. So, it is assumed implicitly that the generating fleet in the adjacent areas continues to use less fuel-efficient generation well into the future. Thus, even for less efficient gas-fired units, gas consumption is higher per megawatt-hour produced, with a corresponding higher cost of production. Consequently, the new low-cost generation assumed for the NYCA could displace higher-cost genera-tion in other areas. This might tend to lower the price-in-crease impact of retiring Indian Point, and could reduce im-ports of electricity from the adjacent areas in favor of increased generation in the NYCA. If so, the total annual variable cost of generation would increase in the NYCA, since total generation in the NYCA increases. Similarly, the generator fuel mix could be influenced, in both the NYCA and the adjacent region.

As discussed in Chapter 2, the load growth in New York State over the past 11 years has been south of the UPNY/

SENY transmission interface (located north of Pleasant Val-ley). Further, since 2001, the Lower Hudson Valley (LHV Zones G, H, and I) has experienced the fastest rate of growth, and is projected to experience a high rate of growth (2.38 percent per year) for the period 2004-2015. Load growth in New York City and Long Island is projected to grow sub-stantially more slowly than in the past 10 years, 1.19 percent for New York City (down from 2.61 percent over the past 10 years), and 1.62 percent in Long Island (down from 3.27 percent growth over the past 10 years). Furthermore, greater reliance on the electrical transmission system is reflected in the fact that from 1994 through the summer of 2005, load growth in southeastern New York State has been about 5,400 MW, while capacity additions there (1,550 MW) and de-mand reduction (270 MW) sum to only 1,820 MW over the same period. Additions to capacity or load reduction there-fore have been only 34 percent of peak-load growth over the last 11 years. These changes evidently have been accounted for in the analysis, but they create an uncertainty in the sys-tem requirements for future years.

Throughout this study, the committee used Alternative New England Transmission Transfer Limits developed by NYISO (2005). Consequently the committees projections of resources needed to correct reliability to meet the LOLE standard of 0.1 are slightly higher than NYISOs, perhaps by 200 MW.4 Readers therefore should bear in mind that, while com-parisons among various illustrative scenarios assumed by the committee are judged to be qualitatively valid, the precise magnitude and timing of compensatory resources required are hypothetical. In addition, the data in graphs and tabula-tions in the report and this appendix should be considered in terms of two significant figures, and it should be recalled that the timing of additions to capacity is not optimized.

Given the exploratory nature of the analysis, it is recom-mended that readers focus on comparative trends, not on absolute values of price projections.

Perspective on Reactive Power The use of the thermal-constraint transmission model is, roughly to first order, equivalent to assuming that reactive power corrections would be made in a timely manner in the Lower Hudson Valley. If not, the voltage-constraint model of NYISO would require greater additions to generating ca-pacityor a correspondingly higher aggregate mix of addi-tional generating capacity, additions to transmission ca-pacity, and/or energy-efficiency and demand-reduction measures.

In the committees opinion, the essential local corrections to reactive poweron the order of 2,000 Mvar in the Lower Hudson Valleywould most likely be made in a timely manner. Corrections to reactive power are less costly than additions to generation, are often installable at existing sub-stations, and require less lead time because of lower me-chanical complexity and ease of permitting. If carried out, the committee expects that correction of the reactive power shortfall would drive the system back toward a situation in which thermal transfer limits control transmission. The com-mittee therefore focused on situations where thermal trans-mission transfer limits limit system reliability, recognizing that local corrections to reactive power flow also must be made, as NYISO has determined.

The committee did not assess the specifics of the need for corrections to reactive power, but this obviously would be required, particularly in light of the analyses reflected in the NYISO (2005) report. The committee also did not analyze in any detail the cost of corrections to reactive power. There are a number of ways to make such corrections, important technical advances have been made in recent years, and such corrections are presently being made within the NYCA and New York City. ONeill (2004) provided a recent briefing 4The committee saw no need to make the analyses agree perfectly, rec-ognizing they are preliminary. Much refinement and additional analysis will be required to fully understand the implications of retiring Indian Point.

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APPENDIX F 153 on some aspects of reactive power in which the capital cost of a static VAR compensator (SVC) or a Statcom is stated to be in the range of $50/kvar, and that of a synchronous con-denser is about $35/kvar. All three of these devices have fast dynamic response. So as a rough order of magnitude, the capital cost of a 1,000 Mvar correction at $50/kvar would be about $50 million. In comparison, capital cost of a 1,000 MW power plant, at a cost of order $1,000 per kW installed, is on the order of $1 billion. So as a rough rule of thumb, the cost of correcting 1 Mvar of reactive power is about 5 per-cent or so of the cost of replacing 1 MW of real power.

It might be possible to use the existing generators at In-dian Point Units 2 and 3 as synchronous condensers after retiring the nuclear reactors. As synchronous condensers (see Gerstenkorn, 2004, p. 271), the generators could add reac-tive power (but not real power) to the transmission system.

However, there might be no significant advantage to doing so, as the capital cost of a synchronous condenser is about

$35/kvar ONeill (2004). Replacing the 1,000 Mvar of reac-tive power supplied by Indian Point Units 2 and 3 with a new synchronous condenser in the area would cost only about

$35 million.

Preliminary Screening Analysis The committees initial reliability analysis was intended to scope the amount of compensation that would be neces-sary to replace Indian Point. It is included here (but not in the final GE report to the committee or in Chapter 5) to illustrate how the committee reached its final scenarios. The capacity resource compensation hypothesized in the committees pre-liminary screening case included 150 MW of additional en-ergy-efficiency and demand-reduction measures by 2007, added 3,510 MW by 2010, and a total 3,740 MW of new capacity, energy-efficiency, and demand-reduction measures by 2015. As noted, these illustrative capacity additions were limited to proposed generation projects that were not mature enough from a permitting or financing standpoint to meet the NYISO (2005) criteria for inclusion in its Initial Base Case assessment. The committee adjusted the timing of ad-ditions somewhat arbitrarily to meet 2010 or 2015 objec-tives. The additions are illustrative only of capacity that would be required, and no suggestion is made or implied that the projects or their timing constitute financially feasible, practical options, or that other projects would not be reacti-vated, or others proposed later.

In sum, the committees screening analysis showed first that, with the additional compensatory resource capacity as-sumed, the early-retirement scenario still resulted in an NYCA LOLE of 0.103 in 2010, increasing to 0.585 by 2013.

For retirement at the end of current licenses, the NYCA LOLE slightly exceeded the required 0.1 beginning in 2013 as Indian Point Unit 2 is shut down and reached 1.39 in 2015, when Indian Point Unit 3 is shut down. Thus, the additional capacity compensation assumed in the screening case analy-sis would not alone accommodate either the early shutdown or an end-of-license shutdown of Indian Point Units 2 and 3.

The analysis then continued with the Reference Case and following scenarios, as given in Table F-2-9 and following and discussed in Chapter 5.

Tabulated Results of MARS Calculations Tables F-2-3 through F-2-23 are a compendium of the results from the GE MARS modeling of the various sce-narios examined during this study. The tables provide suffi-cient numerical detail to provide insight into the changes by geographic region, and the compensatory resources intro-duced, given each of the scenarios adopted by the commit-tee. The comparisons generally should be made relative to the Reference Case assumed by the committee as a baseline for meeting LOLE requirements, meeting load growth and scheduled retirements of capacity (without retiring Indian Point).

TABLE F-2-3 NYISO Initial Base CaseQualifying Additions to Capacity (MW)

Rest of Yearly Zone Zone Zone Zone Zone State Total Year Qualifying Additions to Capacity (Zone, MW)

G H

I J

K (ROS)

(MW) 2005 ConEd East River Repowering (J, 298, in service);

798 160 770 1,728 Astoria Energy (J, 500); Calpine Bethpage 3 (K, 79.9); Pinelawn Power I (K, 79.9); PSEG Bethlehem (ROS, 770) 2006 NYPA Poletti Expansion (J, 500) 500 500 2007 Neptune HVDC Cable (PJM to K, 600) 600 600 2009 0

2010 0

Totals 0

0 0

1,298 760 770 2,828 NOTE: New York Control Area load zones as shown in Figure 1-3. Neptune Cable is reported later at 660 MW. Abbreviations are defined in Appendix C.

SOURCE: Derived from NYISO (2005).

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154 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER TABLE F-2-4 Committees Screening StudyEarly Shutdown with Assumed Compensation from Planned NYCA Projects and Added Energy-Efficiency and Demand-Side-Management Measures (MW)

Statewide Yearly Cumulative Additions Cumulative Year Qualifying Additions to Capacity Zone Zone Zone Zone Zone Rest of EE and DSM

Total, Beyond NYISO Additions (Zone, MW)

G H

I J

K State Measures MW Initial Base Case from 2005 2005 ConEd East River Repowering 798 160 770 1,728 (J, 298, in service); Astoria Energy (J, 500); Calpine Bethpage 3 (K, 79.9);

Pinelawn Power I (K, 79.9);

PSEG Bethlehem (ROS, 770) 2006 NYPA Poletti Expansion 500 500 (J, 500) 2007 Neptune HVDC Cable (PJM to 600 150 750 150 2,978 K, 600) 2008 Reliant Astoria Repowering I 1,040 533 150 1,723 1,873 4,701 (J, 367); Reliant Astoria Repowering II (J, 173); SCS Astoria Energy II (J, 500);

LIPA Caithness CC (K, 383);

LIPA LI Sound Wind (K, 150);

EE (100); DSM (50) 2009 0

1,873 4,701 2010 Calpine Wawayanda (G, 540);

1,290 350 1,640 3,513 6,341 Mirant Bowline Point 3 (G, 750); EE (250);

DSM (100) 2011 0

3,513 6,341 2012 0

3,513 6,341 2013 EE (75); DSM (75) 150 150 3,663 6,491 2014 0

3,663 6,491 2015 EE (50); DSM (25) 125 125 3,788 6616 Totals 1,290 0

0 2,338 1,293 770 925 6,616 3,788 6,616 NOTE: New York Control Area load zones as shown in Figure 1-3. Abbreviations are defined in Appendix C.

SOURCE: Hinkle et al., personal communication, September 2005.

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APPENDIX F 155 TABLE F-2-5 Committees Screening StudyEnd-of-License Shutdown with Assumed Compensation from Planned NYCA Projects and Added Energy-Efficiency and Demand-Side-Management Measures (MW)

Statewide Yearly Cumulative Additions Cumulative Year Qualifying Additions to Capacity Zone Zone Zone Zone Zone Rest of EE and DSM

Total, Beyond NYISO Additions (Zone, MW)

G H

I J

K State Measures MW Initial Base Case from 2005 2005 ConEd East River Repowering 798 160 770 1,728 (J, 298, in service); Astoria Energy (J, 500); Calpine Bethpage 3 (K, 79.9); Pinelawn Power I (K, 79.9); PSEG Bethlehem (ROS, 770) 2006 NYPA Poletti Expansion (J, 500) 500 500 2007 Neptune HVDC Cable 600 150 750 150 2,978 (PJM to K, 600) 2008 SCS Astoria Energy II (J, 500);

500 533 150 1,183 1,333 4,161 LIPA Caithness CC (K, 383);

LIPA LI Sound Wind (K, 150);

EE (100); DSM (50) 2009 0

1,333 4,161 2010 Astoria Repowering I (J, 367);

1,290 367 350 2,007 3,340 6,168 Calpine Wawayanda (G, 540);

Mirant Bowline Point 3 (G, 750);

EE (250); DSM (100) 2011 Astoria Repowering II (J, 173) 173 173 3,513 6,341 2012 0

3,513 6,341 2013 EE (75); DSM (75) 150 150 3,663 6,491 2014 0

3,663 6,491 2015 EE (50); DSM (25) 75 75 3,738 6,566 Totals 1,290 0

0 2,338 1,293 770 875 6,566 3,738 6,566 NOTE: New York Control Area load zones as shown in Figure 1-3. Abbreviations are defined in Appendix C.

SOURCE: Hinkle et al., personal communication, September 2005.

TABLE F-2-6 NYISO Initial Base Case with Alternate New England Transmission Constraints Projected NYCA Reliability Loss-of-Load Expectation (LOLE) and Reserve Margin LOLE Results NYISO Initial Base Case 2008 2010 2013 2015 ZONE A 0

0 0

0 ZONE B 0

0 0

0 ZONE C 0

0 0

0 ZONE D 0

0 0

0 ZONE E 0

0 0

0 ZONE F 0

0 0.001 0.002 ZONE G 0.001 0.017 0.103 0.291 ZONE H 0.001 0.008 0.017 0.018 ZONE I 0.058 0.617 2.464 4.401 ZONE J 0.095 0.785 2.618 4.473 ZONE K 0.051 0.418 1.888 3.526 NYCA 0.122 0.966 3.164 5.21 NYCA Capacity @ Peak Unit of Measure 37,039 37,039 37,039 37,039 NYCA Peak Load Unit of Measure 33,330 34,200 35,180 35,671 Special Case Resources (SCRs) Unit of Measure 975 975 975 975 NYCA Reserve Margin (%)

14%

11%

8%

7%

NOTE: New York Control Area load zones as shown in Figure 1-3. LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. Abbreviations are defined in Appendix C.

SOURCE: Hinkle et al., personal communication, September 2005.

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156 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER TABLE F-2-7 Committees Screening Study: Impact on Reliability and Reserve Margins of Shutting Down Indian Point Without Adding Compensatory Resources: Comparison of the NYISO Initial Base Case with Early-Shutdown and End-of-Current-License Shutdown Cases NYISO Initial Base Case, Using Early Shutdown: IP2 Shutdown End-of-License Shutdown:

Alternate New England 1/1/08, IP3 Shutdown 1/1/10; IP2 Shutdown 1/1/13, IP3 Transmission Constraints No Compensatory Resources Shutdown 1/1/15; No (Draft v.2 RNA Report)

Added Compensatory Resources Added Predicted Reliability (LOLE)

Predicted Reliability (LOLE)

Predicted Reliability (LOLE) 2008 2010 2013 2015 2008 2010 2013 2015 2008 2010 2013 2015 Zone A 0

0 0

0 Zone B 0

0 0

0 Zone C 0

0 0

0 Zone D 0

0 0

0 Zone E 0

0 0

Zone F 0

0 0.001 0.002 0

0 0.002 0.002 0

0 0.002 0.002 Zone G Hudson Valley 0.001 0.017 0.103 0.291 0.003 0.302 0.876 1.967 0.001 0.017 0.339 1.967 Zone H Millwood 0.001 0.008 0.017 0.018 0.035 5.568 8.913 10.77 0.001 0.008 0.377 10.77 Zone I Dunwoodie 0.058 0.617 2.464 4.401 0.323 5.956 9.582 11.554 0.058 0.617 5.914 11.554 Zone J New York City 0.095 0.785 2.618 4.473 0.292 4.927 7.701 9.742 0.095 0.785 5.071 9.742 Zone K Long Island 0.051 0.418 1.888 3.526 0.226 5.456 8.344 10.528 0.051 0.418 4.595 10.528 NYCA 0.122 0.966 3.164 5.21 0.4 6.338 10.074 12.061 0.122 0.966 6.444 12.061 NYCA Capacity @ Peak Unit of Measure 37,039 37,039 37,039 37,039 36,077 36,086 35,086 35,086 37,039 37,039 36,077 35,086 NYCA Peak Load Unit of Measure 33,330 34,200 35,180 35,671 33,330 34,200 35,180 35,671 33,330 34,200 35,180 35,671 Special Case Resources (SCRs) Unit of 975 975 975 975 975 975 975 975 975 975 975 975 Measure NYCA Reserve Margin (%)

14%

11%

8%

7%

11%

8%

3%

1%

14%

11%

5%

1%

NOTE: IP2, Indian Point Unit 2; IP3, Indian Point Unit 3; see Appendix C for definitions of abbreviations. LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs.

SOURCE: Hinkle et al., personal communication, September 2005.

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APPENDIX F 157 TABLE F-2-8 Committees Screening Study: Impact on Reliability and Reserve Margins of Shutting Down Indian Point and Adding Compensatory Resources from Announced Projects, Beyond NYISO Initial Base Case (Table F-2-3):

Comparison of Early Shutdown and End-of-Current-License Shutdown Early Shutdown With Compensatory Resources End-of-License Shutdown With Compensatory Added: IP2 Shutdown 1/1/08, IP3 Shutdown Resources Added: IP2 Shutdown 1/1/13, IP3 1/1/10 Shutdown 1/1/15 Predicted Reliability (LOLE)

Predicted Reliability (LOLE) 2008 2010 2013 2015 2008 2010 2013 2015 Zone A 0

0 0

0 Zone B 0

0 0

0 Zone C 0

0 0

0 Zone D 0

0 0

0 Zone E 0

0 0

Zone F 0

0 0

0 Zone G Hudson Valley 0.001 0

0.002 0.004 0

0 0

0.004 Zone H Millwood 0.005 0.082 0.477 1.192 0

0 0.019 1.192 Zone I Dunwoodie 0.019 0.091 0.533 1.269 0.007 0.002 0.082 1.269 Zone J New York City 0.011 0.053 0.297 0.724 0.009 0.002 0.057 0.724 Zone K Long Island 0.01 0.032 0.267 0.649 0.003 0.001 0.051 0.649 NYCA 0.023 0.103 0.585 1.393 0.013 0.003 0.106 1.393 NYCA Capacity @ Peak Unit of Measure 37,650 37,949 37,949 37,949 38,034 39,729 38,940 37,949 NYCA Peak Load Unit of Measure 33,039 33,568 34,402 34,820 33,039 33,568 34,402 34,820 Special Case Resources (SCRs) 975 975 975 975 975 975 975 975 NYCA Reserve Margin (%)

17%

16%

13%

12%

18%

21%

16%

12%

NOTE: IP2, Indian Point Unit 2; IP3, Indian Point Unit 3; see Appendix C for definitions of abbreviations. LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs.

SOURCE: Hinkle et al., personal communication, September 2005.

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158 TABLE F-2-9 Reference Case: Illustrative Additional Resources Beyond the NYISO Initial Base Case to Meet Load Growth and Scheduled Retirements and Ensure Reliability Criteria Are Met, and Including Reliability Results If Indian Point Is Closed Without Further Compensation Cumulative LOLE for Early LOLE for EOL Yearly Additions Shutdown (2008, Shutdown (2013, Year Reference Case Generating Above CRPP, 2010), No Further 2015), No Further Illustrative Additions Zone Zone Zone Zone Zone Rest of Capacity Initial Base NYCA LOLE, Compensation, Compensation, (Zone, MW)

G, MW H, MW I, MW J, MW K, MW State (ROS)

Added Case (MW)

Reference Case Case b1 Case c1 2008 SCS Astoria Energy (J, 500);

500 398 898 898 0.021 0.104 0.021 Caithness (K, 383); Long Island Wind (K, 150 MW) 2009 0

898 2010 Bowline Point (G, 750) 750 750 1,648 0.069 1.352 0.069 2011 0

1,648 2012 0

1,648 2013 Wawayanda (G, 540); Generic 540 580 1,120 2,768 0.104 1.323 0.333 Combined Cycle (H, 580) 2014 0

2,768 2015 Reliant Astoria Repower I (J, 367);

540 540 3,308 0.102 1.480 1.480 Reliant Astoria Repower II (J, 173)

Totals, 2008-2015 1,290 580 0

1,040 398 0

3,308 3,308 NOTE: Wind is credited with 10 percent availability, or 15 MW. NYISO did not include wind in reliability analyses. The Neptune Cable (2007, K, 600 MW) is carried elsewhere in the GE analysis as a UDR.

Its capacity has been upgraded to 660 MW in the final NYISO RNA. Also GE uses UDRs in calculating LOLE, but reported Reserve Margins are calculated using generating capacity and SDRs (975 MW) only. For defintions of zones, see Table F-2-7. Abbreviations are defined in Appendix C.

SOURCE: Hinkle et al. (2005).

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159 TABLE F-2-10 Early Shutdown of Indian Point with Compensatory Resources, Case b2 Capacity Cumulative Cumulative Above Peak Resources, Rest of Total

CRPP, Energy Demand Side Demand Capacity +

NYCA LOLE Capacity Additions Zone Zone Zone Zone Zone State for year, Initial Base Efficiency, Management, Reduction, Load Reduction, After Year (Zone, MW)

G, MW H, MW I, MW J, MW K, MW (ROS)

MW Case, MW MW MW MW MW Compensation 2007 100 50 2008 Reference Case plus Reliant 1,040 398 1,438 1,438 100 50 291 1,729 0.023 Astoria Repower I&II (J, 540) 2009 0

1,438 2010 Bowline (G, 750); Wawayanda 1,290 1,100 2,390 3,828 250 100 632 4,460 0.011 (G, 540); Transgas Energy (J, 1100) 2011 0

3,828 2012 0

3,828 2013 Generic Combined Cycle 580 580 4,408 75 75 778 5,186 0.032 (H, 580) 2014 0

4,408 2015 0

4,408 50 25 850 5,258 0.101 Totals 1,290 580 0

2,140 398 0

4,408 575 300 NOTE: For definitions of zones, see Table F-2-7. Abbreviations are defined in Appendix C.

NYCA Demand, MW SOURCE: Hinkle et al. (2005).

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160 TABLE F-2-11 End-of-Current-License Shutdown of Indian Point with Compensatory Resources, Case c2 Capacity Cumulative Cumulative Above Peak Resources, Rest of Total

CRPP, Energy Demand Side Demand Capacity +

NYCA LOLE Capacity Additions Zone Zone Zone Zone Zone State for year, Initial Base Efficiency, Management, Reduction, Load Reduction, After Year (Zone, MW)

G, MW H, MW I, MW J, MW K, MW (ROS)

MW Case, MW MW MW MW MW Compensation 2007 100 50 2008 Same as Reference Case 500 398 898 898 100 50 291 1,189 0.013 2009 898 898 2010 Reliant Astoria Repower I 1,290 367 1,657 2,555 250 100 632 3,187 0.006 (J, 367); Bowline (G, 750);

Wawayanda (G, 540) 2011 Reliant Astoria Repower II 173 173 2,728 2,728 (J, 173) 2012 0

2,728 2,728 2013 Generic Combined Cycle 580 580 3,308 75 75 778 4,086 0.036 (H, 580) 2014 0

3,308 3,308 2015 Transgas Energy (J, 1100) 1,100 1,100 4,408 50 25 851 5,259 0.101 Totals 1,290 580 0

2,140 398 0

4,408 375 200 851 5,259 NOTE: For definitions of zones, see Table F-2-7. Abbreviations are defined in Appendix C.

NYCA demand same as Table F-2-10.

SOURCE: Hinkle et al. (2005).

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161 TABLE F-2-12 Early Shutdown of Indian Point with High-Voltage Direct Current (HVDC) Cable, Case b3 Capacity Cumulative Cumulative Above Peak Resources, Rest of Yearly

CRPP, Energy Demand Side Demand Capacity +

NYCA LOLE Capacity Additions Zone Zone Zone Zone Zone State

Total, Initial Base Efficiency, Management, Reduction, Load Reduction, After Year (Zone, MW)

G, MW H, MW I, MW J, MW K, MW (ROS)

MW Case, MW MW MW MW MW Compensation 2007 100 50 2008 Reference plus Reliant Astoria Repower (J, 540) 1,040 398 1,438 1,438 100 50 291 1,729 2009 0

1,438 2010 Bowline Point (G, 750),

1,290 300 1,590 3,028 250 100 632 3,660 Wawayanda (G, 540),

Transgas Energy (J, 300) 2011 0

3,028 2012 1000 MW HVDC Line, 1,000 1,000 4,028 Zone E to G 2013 Generic Combined Cycle 580 580 4,608 75 75 778 5,386 (H, 580) 2014 0

4,608 2015 0

4,608 50 25 850 5,458 0.098 Totals 2,290 580 0

1,340 398 0

4,608 575 300 NOTE: For definitions of zones, see Table F-2-7. Abbreviations are defined in Appendix C.

SOURCE: Hinkle et al. (2005).

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162 TABLE F-2-13 End-of-Current-License Shutdown of Indian Point with Compensatory Resources Including 1,000 MW HVDC Transmission Lines, Case c3 Capacity Cumulative Above Cumulative Resources, Yearly

CRPP, Energy Demand Side Peak Load Capacity +

NYCA LOLE Capacity Additions Zone Zone Zone Zone Zone

Total, Initial Base Efficiency, Management, Reduction, Load Reduction, After Year (Zone, MW)

G, MW H, MW I, MW J, MW K, MW ROS MW Case, MW MW MW MW MW Compensation 2007 100 50 2008 Same as Reference Case 500 398 898 898 100 50 291 1,189 2009 0

0 2010 Reliant Astoria Repower I 1,290 367 1,657 1,657 250 100 632 2,289 (J, 367); Bowline Point (G, 750); Wawayanda (G, 540) 2011 Reliant Astoria Repower II 173 173 1,830 (J, 173) 2012 1000 MW HVDC Line, 1,000 1,000 2,830 Zone E to Zone G 2013 Generic Combined Cycle 580 580 3,410 75 75 778 4,188 (H, 580) 2014 0

3,410 2015 Transgas Energy (J, 300) 300 300 3,710 50 25 850 4,560 0.098 Totals 2,290 580 0

840 0

0 3,710 375 200 NOTE: For definitions of zones, see Table F-2-7. Abbreviations are defined in Appendix C.

SOURCE: Hinkle et al. (2005).

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163 TABLE F-2-14 Early Shutdown of Indian Point with Higher Efficiency and Demand-Side Management, Case b4 Cumulative Capacity Peak Load Cumulative Above Reduction Resources, Yearly

CRPP, Energy Demand Side Due to Capacity +

NYCA LOLE Capacity Additions Zone Zone Zone Zone Zone

Total, Initial Base Efficiency, Management, EE/DSM, Load Reduction, After Year (Zone, MW)

G, MW H, MW I, MW J, MW K, MW ROS MW Case, MW MW MW MW MW Compensation 2007 2008 Reference Case plus Reliant 1,040 398 1,438 1,438

Astoria Repower I&II (J, 540) 2009 0

1,438

2010 Bowline Point (G, 750);

1,290 1,290 2,728

Wayawanda (G, 540) 2011 0

2,728

2012 0

2,728

2013 Generic Combined Cycle 580 580 3,308

(H, 580) 2014 0

3,308

2015 0

3,308 1,200 800 0.082 Totals 1,290 580 0

1,040 398 0

3,308 1,200 800 1,951 5,259 NOTE: For definitions of zones, see Table F-2-7. Abbreviations are defined in Appendix C.

NYCA Demand, MW SOURCE: Hinkle et al. (2005).

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164 TABLE F-2-15 End-of-Current-License Shutdown of Indian Point with Higher Efficiency and Demand-Side Management, Case c4 Cumulative Capacity Peak Load Cumulative Above Reduction Resources, Rest of Yearly

CRPP, Energy Demand Side Due to Capacity +

NYCA LOLE Capacity Additions Zone Zone Zone Zone Zone State

Total, Initial Base Efficiency, Management, EE/DSM, Load Reduction, After Year (Zone, MW)

G, MW H, MW I, MW J, MW K, MW (ROS)

MW Case, MW MW MW MW MW Compensation 2007 2008 Same as Reference Case 500 398 898 898 898 2009 0

898 2010 Reliant Astoria Repower I 1,290 367 1,657 2,555 2,555 (J, 367); Bowline Point (G, 750); Wayawanda (G, 540) 2011 Reliant Astoria Repower II 173 173 2,728 (J, 173) 2012 0

2,728 2013 Generic Combined Cycle 580 580 3,308 3,308 (H, 580) 2014 0

3,308 2015 0

3,308 1,200 800 1,951 5,259 0.082 Totals 1,290 580 0

1,040 398 0

3,308 1,200 800 1,951 5,259 NOTE: For definitions of zones, see Table F-2-7. Abbreviations are defined in Appendix C.

NYCA Demand, MW SOURCE: Hinkle et al. (2005).

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APPENDIX F 165 TABLE F-2-16 Early Shutdown Without Compensatory Resources Beyond the Reference CaseImpact on NYCA Reliability (Loss-of-Load Expectation) and Reserve Margin, Case b1 Loss-of-Load Expectation Zone 2008 2010 2013 2015 A

0.000 0.000 0.000 0.000 B

0.000 0.000 0.000 0.000 C

0.000 0.000 0.000 0.000 D

0.000 0.000 0.000 0.000 E

0.000 0.000 0.000 0.000 F

0.000 0.000 0.000 0.000 G

0.002 0.012 0.001 0.008 H

0.013 1.132 1.030 1.217 I

0.083 1.232 1.163 1.325 J

0.071 0.968 1.043 0.974 K

0.041 0.366 0.525 0.820 NYCA 0.104 1.352 1.323 1.480 NYCA Capacity @ Peak Unit 37,110 36,869 37,994 38,534 NYCA Peak-Load Unit 33,330 34,200 35,180 35,671 Special Case Resources (SCRs) 975 975 975 975 NYCA Reserve Margin (%)

14%

11%

NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appen-dix B.

SOURCE: Hinkle et al. (2005).

TABLE F-2-17 End-of-Current-License Shutdown Without Compensatory Resources Beyond the Reference CaseImpact on NYCA Reliability (Loss-of-Load Expectation) and Reserve Margin, Case c1 Loss-of-Load Expectation Zone 2008 2010 2013 2015 A

0.000 0.000 0.000 0.000 B

0.000 0.000 0.000 0.000 C

0.000 0.000 0.000 0.000 D

0.000 0.000 0.000 0.000 E

0.000 0.000 0.000 0.000 F

0.000 0.000 0.000 0.000 G

0.000 0.000 0.000 0.008 H

0.000 0.002 0.039 1.217 I

0.012 0.031 0.217 1.325 J

0.016 0.056 0.354 0.974 K

0.006 0.016 0.124 0.082 NYCA 0.021 0.069 0.333 1.480 NYCA Capacity @ Peak Unit 38,072 38,822 38,985 38,534 NYCA Peak-Load Unit 33,330 34,200 35,180 35,671 Special Case Resources (SCRs) 975 975 975 975 NYCA Reserve Margin (%)

17%

16%

14%

11%

NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appen-dix B.

SOURCE: Hinkle et al. (2005).

TABLE F-2-19 Early Shutdown with Additional Compensatory ResourcesImpact on NYCA Reliability and Reserve Margin, Case b2 Loss-of-Load Expectation Zone 2008 2010 2013 2015 A

0.000 0.000 0.000 0.000 B

0.000 0.000 0.000 0.000 C

0.000 0.000 0.000 0.000 D

0.000 0.000 0.000 0.000 E

0.000 0.000 0.000 0.000 F

0.000 0.000 0.000 0.000 G

0.001 0.000 0.000 0.001 H

0.004 0.009 0.020 0.070 I

0.018 0.009 0.024 0.082 J

0.012 0.004 0.011 0.031 K

0.010 0.005 0.022 0.069 NYCA 0.023 0.011 0.032 0.101 NYCA Capacity @ Peak Units 37,650 39,049 39,629 39,629 NYCA Peak-Load Units 33,039 33,568 34,402 34,820 Special Case Resources (SCRs) 975 975 975 975 NYCA Reserve Margin (%)

17%

19%

18%

17%

NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appen-dix B.

SOURCE: Hinkle et al. (2005).

TABLE F-2-18 Committees Reference CaseImpact on NYCA Reliability (Loss-of-Load Expectation) and Reserve Margin Loss-of-Load Expectation Zone 2008 2010 2013 2015 A

0.000 0.000 0.000 0.000 B

0.000 0.000 0.000 0.000 C

0.000 0.000 0.000 0.000 D

0.000 0.000 0.000 0.000 E

0.000 0.000 0.000 0.000 F

0.000 0.000 0.000 0.000 G

0.000 0.000 0.000 0.000 H

0.000 0.002 0.001 0.002 I

0.012 0.031 0.021 0.033 J

0.016 0.056 0.087 0.067 K

0.006 0.016 0.027 0.051 NYCA 0.021 0.069 0.104 0.102 NYCA Capacity @ Peak Units 38,072 38,822 39,947 40,487 NYCA Peak-Load Units 33,330 34,200 35,180 35,671 Special Case Resources (SCRs) 975 975 975 975 NYCA Reserve Margin (%)

17%

16%

NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appen-dix B.

SOURCE: Hinkle et al. (2005).

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166 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER TABLE F-2-21 Additional Compensatory Resources, Including 1,000 MW North-South HVDC Transmission LineImpact on NYCA Reliability and Reserve Margin, Cases b3 and c3 Case b3 Case c3 Zone 2015 2015 A

0.000 0.000 B

0.000 0.000 C

0.000 0.000 D

0.000 0.000 E

0.000 0.000 F

0.000 0.000 G

0.000 0.000 H

0.066 0.066 I

0.084 0.084 J

0.047 0.047 K

0.059 0.059 NYCA 0.098 0.098 NYCA Capacity @ Peak Units 38,829 38,829 NYCA Peak-Load Units 34,820 34,820 Special Case Resources (SCRs) 975 975 NYCA Reserve Margin (%)

14%

NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appen-dix B.

SOURCE: Hinkle et al. (2005).

TABLE F-2-22 Additional Compensatory Resources, Including Higher Energy Efficiency and Demand-Side-Management PenetrationImpact on NYCA Reliability and Reserve Margin, Cases b4 and c4 Case b4 Case c4 Zone 2015 2015 A

0.000 0.000 B

0.000 0.000 C

0.000 0.000 D

0.000 0.000 E

0.000 0.000 F

0.000 0.000 G

0.000 0.000 H

0.061 0.061 I

0.072 0.072 J

0.040 0.040 K

0.038 0.038 NYCA 0.082 0.082 NYCA Capacity @ Peak Units 38,529 38,529 NYCA Peak-Load Units 33,719 33,719 Special Case Resources (SCRs) 975 975 NYCA Reserve Margin (%)

17%

NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appen-dix B.

SOURCE: Hinkle et al. (2005).

TABLE F-2-20 End-of-Current-License Shutdown with Additional Compensatory ResourcesImpact on NYCA Reliability and Reserve Margin, Case c2 Loss-of-Load Expectation Zone 2008 2010 2013 2015 A

0.000 0.000 0.000 0.000 B

0.000 0.000 0.000 0.000 C

0.000 0.000 0.000 0.000 D

0.000 0.000 0.000 0.000 E

0.000 0.000 0.000 0.000 F

0.000 0.000 0.000 0.000 G

0.000 0.000 0.000 0.001 H

0.000 0.000 0.007 0.070 I

0.006 0.001 0.023 0.082 J

0.009 0.004 0.020 0.031 K

0.003 0.001 0.019 0.069 NYCA 0.013 0.006 0.036 0.101 NYCA Capacity @ Peak Units 38,072 39,729 39,520 39,629 NYCA Peak-Load Units 33,039 33,568 34,402 34,820 Special Case Resources (SCRs) 975 975 975 975 NYCA Reserve Margin (%)

18%

21%

18%

17%

NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appen-dix B.

SOURCE: Hinkle et al. (2005).

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APPENDIX F 167 TABLE F-2-23 Projected Impact on the Annual Variable Cost of Operation for the Northeast Region, NYCA, and Zones H Through K: All Scenarios, 2008 2105, Including Percentage Change from Benchmark of 2008 NYISO Initial Base Case Annual Cost of Operation Change from 2008 NYISO Initial Base Case 2008 2010 2013 2015 2008 2010 2013 2015

($ millions)

(%)

Benchmark of 2008 NYISO Initial Base Case 3 Pool 13,169 NYISO 3,129 Zone H 97 Zone I 0

Zone J 1,094 Zone K 327 Reference Case 3 Pool 13,098 13,269 13,193 14,363

-0.5 0.8 0.2 9.1 NYISO 3,091 3,121 3,056 3,271

-1.2

-0.2

-2.3 4.5 Zone H 97 97 221 224 0.4 0.3 128.2 131.1 Zone I 0

0 0

0 Zone J 1,072 994 877 1,008

-2.1

-9.1

-19.8

-7.9 Zone K 344 308 274 286 5.1

-5.7

-16.3

-12.5 Early Shutdown with Compensation, Case b2 3 Pool 13,323 13,685 13,578 14,780 1.2 3.9 3.1 12.2 NYISO 3,301 3,668 3,523 3,783 5.5 17.2 12.6 20.9 Zone H 49 1

131 138

-49.8

-99.2 34.7 41.8 Zone I 0

0 0

0 Zone J 1,282 1,490 1,383 1,526 17.2 36.2 26.4 39.5 Zone K 367 368 333 368 12.2 12.4 1.8 12.6 End-of-License Shutdown with Compensation, Case c2 3 Pool 13,054 13,138 13,330 14,780

-0.9

-0.2 1.2 12.2 NYISO 3,058 3,069 3,177 3,783

-2.3

-1.9 1.5 20.9 Zone H 97 97 175 138 0.4 0.3 80.8 41.8 Zone I 0

0 0

0 Zone J 1,057 928 1,012 1,526

-3.4

-15.2

-7.5 39.5 Zone K 331 254 285 368 1.2

-22.4

-12.9 12.6 Higher Fuel PricesReference Case 3 Pool 16,000 16,125 16,749 18,379 21.5 22.5 27.2 39.6 NYISO 4,039 4,045 4,358 4,636 29.1 29.3 39.3 48.2 Zone H 97 97 292 299 0.4 0.4 201.3 208.0 Zone I 0

0 0

0 Zone J 1,552 1,402 1,388 1,570 41.8 28.1 26.9 43.6 Zone K 495 459 447 464 51.3 40.4 36.8 41.9 Higher Fuel PricesEarly Shutdown with Compensation 3 Pool 16,366 16,796 17,405 19,132 24.3 27.5 32.2 45.3 NYISO 4,377 4,881 5,096 5,522 39.9 56.0 62.9 76.5 Zone H 49 1

208 221

-49.8

-99.2 114.6 128.1 Zone I 0

0 0

0 Zone J 1,858 2,090 2,107 2,374 69.9 91.0 92.6 117.0 Zone K 556 560 536 644 70.0 71.3 64.0 96.8 Higher Fuel PricesEnd-of-License Shutdown with Compensation 3 Pool 15,934 15,929 17,007 19,132 21.0 21.0 29.1 45.3 NYISO 3,986 3,950 4,598 5,522 27.4 26.2 47.0 76.5 Zone H 97 97 253 221 0.4 0.3 160.7 128.1 Zone I 0

0 0

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168 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER Early Shutdown with Compensation and HVDC Line, Case b3 3 Pool 13,506 14,701 2.6 11.6 NYISO 3,279 3,500 4.8 11.9 Zone H 129 134 33.1 38.6 Zone I 0

0 Zone J 1,080 1,186

-1.3 8.4 Zone K 285 320

-12.8

-2.2 EOL Shutdown with Compensation and HVDC Line, Case c3 3 Pool 13,284 14,701 0.9 11.6 NYISO 3,085 3,500

-1.4 11.9 Zone H 173 134 78.5 38.6 Zone I 0

0 Zone J 919 1,186

-16.0 8.4 Zone K 245 320

-8,341.2

-815.3 Early Shutdown with Compensation and High EE/DSM, Case b4 3 Pool 14,650 11.2 NYISO 3,527 12.7 Zone H 135 39.1 Zone I 0

Zone J 1,242 13.5 Zone K 346 5.7 EOL Shutdown with Compensation, High EE/DSM, Case c4 3 Pool 14,650 11.2 NYISO 3,527 12.7 Zone H 135 39.1 Zone I 0

Zone J 1,242 13.5 Zone K 346 5.7 NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs.

For zones see Table F-2-7. Abbeviations are defined in Appendix C.

SOURCE: Hinkle et al. (2005).

TABLE F-2-23 Continued Annual Cost of Operation Change from 2008 NYISO Initial Base Case 2008 2010 2013 2015 2008 2010 2013 2015

($ millions)

(%)

REFERENCES DOE (U.S. Department of Energy). 2005. Annual Energy Outlook 2005, Table 38. Energy Information Administration. Washington, D.C.

Forte, Michael (Chief Engineer for Planning, Consolidated Edison). 2005.

Presentation to the committee at its meeting in White Plains, N.Y. April 15.

Gerstenkorn, D. 2004. Synchronous Condenser: An Idea Whose Time Has Come. In G.C. Casazza and J.A Loehr, eds., The Evolution of Electric Power Transmission Under Deregulation: Selected Readings. IEEE.

Hinkle, Gene, G. Jordan and M. Sanford, 2005. Report to National Re-search Council for An Assessment of Alternatives to Indian Point for Meeting Energy Needs. GE Energy, December 27.

NYISO (New York Independent System Operator). 2005. Comprehensive Reliability Planning Process Supporting Document and Appendices for the Reliability Needs Assessment. NYISO, Albany, N.Y., December 21.

ONeill, Richard. 2004. Reactive Power: Is it Real? Is It in the Ether?

Paper presented at the Harvard Electric Policy Group, Austin, Tex.,

December 2.

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169 G

Demand-Side Measures Marilyn A. Brown, Benjamin Sovacool, and Dan E. Arvizu1 1Marilyn Brown and Dan Arvizu are members of the Committee on Al-ternatives to Indian Point for Meeting Energy Needs. Benjamin Sovacool works at the Oak Ridge National Laboratory.

As indicated in Chapter 2, Demand-Side Options, this appendix provides the following additional detail and analy-sis for the estimates presented in the chapter:

Appendix G-1, Demand Reduction, provides data de-rived from the New York State Energy Research and Devel-opment Authority detailing estimates of the economic po-tential for energy-efficiency improvements that would exist by 2007 and 2012 in the residential and commercial sectors of New York City.

Appendix G-2, Estimating the Potential for Energy-Efficiency Improvements, presents details of the committees estimation of the peak-load reduction in the New York City area (Zones I, J, and K) that might realisti-cally be achieved as a result of energy-efficiency programs in the Indian Point region.

Appendix G-3, Estimating Demand-Response Poten-tial, provides details of the committees estimation of the potential for demand-response programs to reduce peak de-mand in the Indian Point service area (in Zones I, J, and K) in 2007, 2010, and 2015.

Appendix G-4, Estimating Photovoltaics for Demand Reduction, presents the analysis for the acceler-ated photovoltaic-deployment scenario, with estimates of potential peak reduction from photovoltaics in Zones I, J, and K in 2007 through 2015, developed by the committee.

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170 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER APPENDIX G-1 DEMAND REDUCTION TABLE G-1-1 Economic Potential: Annual Savings (in megawatt-hours) for Top Eight Residential Energy-Efficiency MeasuresZones J and K, 2007, 2012, and 2022 2007 2012 2022 Efficiency Measure Zone J Zone K Zone J Zone K Zone J Zone K Lighting 2,083,081 821,158 2,089,911 955,793 2,297,042 1,028,361 Cooling 523,366 202,089 912,427 296,673 1,199,762 442,591 Refrigerators 349,524 165,740 377,069 189,277 469,231 218,900 Miscellaneous 317,716 169,928 397,554 205,743 633,512 255,231 Space heating 171,485 74,367 290,730 138,846 651,694 333,681 Clothes-washer 128,123 74,235 183,615 125,475 134,807 235,273 TV/VCR/DVD 105,257 71,704 153,722 140,497 121,512 180,230 Domestic hot water 47,094 102,239 55,831 194,869 457,237 311,805 Totals 3,725,646 1,681,460 4,460,859 2,247,173 5,964,797 3,006,072 NOTE: The New York Control Area (NYCA) load zones included in this table cover New York City (Zone J) and Long Island outside of New York City (Zone K).

SOURCE: Derived from NYSERDA (2003).

TABLE G-1-2 Economic Potential: Annual Savings (in megawatt-hours) for Top Ten Commercial Energy-Efficiency MeasuresExisting Construction End Use in Zones J and K, 2007-2022 2007 2012 2022 Efficiency Measure Zone J Zone K Zone J Zone K Zone J Zone K Indoor lighting 7,396,778 1,736,231 7,643,626 1,794,289 7,699,480 1,804,833 Refrigeration 1,045,015 407,791 1,140,030 444,683 744,863 277,418 Cooling 1,220,411 294,229 1,910,358 453,369 2,371,650 553,868 Ventilation 1,019,079 277,889 1,104, 055 300,936 797,558 220,475 Office equipment 726,058 129,756 686,076 123,367 536,384 102,478 Whole building 682,825 166,806 679,940 165,681 688,005 168,508 Water heating 232,167 77,654 241,367 80,571 162,341 53,874 Outdoor lighting 115,695 56,946 115,695 56,946 111,633 53,334 Miscellaneous 71,615 246,008 103,122 353,370 91,129 282,595 Space heating 56,975 16,605 88,164 25,528 124,217 35,795 Total 12,566,628 3,409,916 13,712,433 3,798,741 13,327,258 3,553,178 NOTE: The New York Control Area (NYCA) load zones included in this table cover New York City (Zone J) and Long Island outside of New York City (Zone K).

SOURCE: Derived from NYSERDA (2003).

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APPENDIX G 171 APPENDIX G-2 ESTIMATING THE POTENTIAL FOR ENERGY-EFFICIENCY IMPROVEMENTS Appendix G-2 presents the committees analytical pro-cess for determining potential for efficiency improvements in the New York City area (Zones I, J, and K). It also reviews the results of several other studies of energy such potential.

Statewide data were available for this potential (NYSERDA, 2003), but those data are not at the level of detail that allows judgments about the subregion addressed here. Thus, the starting point was an estimate for New York City that was derived from state data (Plunkett and Gupta, 2004). That analysis determined that New York City (Zone J) could benefit from a maximum achievable potential for improvement of 502 MW for 2007, at an avoided levelized cost of 3.3 cents per kWh (¢/kWh).

Using data on the economic potential for the residential sector and the commercial-buildings energy efficiency (in MWh) from NYSERDA (2003), it can be estimated that Zone K has 0.451 of the maximum achievable potential of Zone J. Therefore, the Zone K potential would be 226 MW.

Assuming the southern part of Westchester County (Zone I) has half the maximum achievable potential of Zone K, its potential in 2007 would be 113 MW. Thus, the maximum achievable potential across all three zones would be 842 MW by 2007.

The data for residential and commercial economic poten-tial in the appendix in NYSERDAs 2003 report includes estimates for Zones J and K for 2007, 2012, and 2022. Plot-ting these estimates, one can interpolate the missing years of 2008, 2010, 2013, and 2015. Assuming a linear relation-ship, the maximum achievable potential for Zone J, starting with 502 MW in 2007, would be 529 MW in 2008, 563 MW in 2010, 624 MW in 2013, and 658 MW in 2015 (as shown in Table 2-4 of this report).

Assuming the same relationship between Zone J and Zone K (Zone K is 0.451 the size of Zone J), the potential for Zone K would be 239 MW in 2008, 253 MW in 2010, 281 MW in 2013, and 297 MW in 2015. Assuming that Zone I is half the size of Zone K, the potential for Zone I would be 119 MW in 2008, 127 MW in 2010, 140 MW in 2013, and 148 MW in 2015 (see Table 2-4).

Corroboration by Other City, Utility, State, and National Studies A preponderance of evidence from multiple studiesun-dertaken with differing scales of analysis, sponsors, types of efficiency measures, time periods, and methods of evalua-tiondemonstrates that there is an immense amount of cost-effective potential for energy-efficiency improvements. The following subsections describe some of the best practices from around the United States.

Urban Initiatives In Sacramento, California, the Sacramento Municipal Utility District Residential Peak Corps Program was imple-mented in early 1979 to demonstrate the effectiveness of demand-side management in anticipation of the retirement of the Rancho Seco Nuclear Plant. The Peak Corps Program was intended to address summer peaking for cooling, when temperatures often climb above 100°F. The implementation of the program was aimed at the residential sector and em-phasized only dual-relay alternating current (AC) cycles (which cycle the central air conditioners participating in the program 10 to 16 days per summer for durations up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ). Participating consumers could then save $20 per month off their electricity bill. The Peak Corps Program was promoted in two ways: (1) through direct mail, radio, and print advertising and (2) by Sacramento Municipal Utility District Rule 15, which requires that all new homes with central air conditioners participate in the program. As of 1994, the program cost approximately $3 million per year, involved 96,130 customers, and displaced a total of 12.1 MW of peak capacity (Sacramento Municipal Utility District, 1994).

A City of Toledo, Ohio, Municipal Energy Management Program implemented a three-phase plan to (1) retrofit light-ing and ballast systems in buildings, (2) extensively retrofit 30 energy-intensive buildings, and (3) force energy efficient technologies in the construction of 20 new city buildings.

These three phases alone (at a cost of $9.2 million) have saved $23 million since 1986 and displaced over 380 MWh per year (Ohio Department of Development, 2004).

Similarly, the School District of Philadelphiathe fifth largest in the country and home to 258 schools spread over 282 buildingsspends $32 million annually on energy. To conserve electricity, the school district implemented a re-markable efficiency program in 1983 that cost nothing. The program focused on no-cost measures, such as end-user hab-its like turning lights off and turning the heat down, and then used the savings to invest in capital improvements such as lighting retrofits, better controls, and weatherization. For the 1993-1994 school year, the school district saved over 15.8 GWh at an avoided cost of $8.5 million, representing a 25 percent reduction in the districts energy costs and making monies available for investment in other efficiency measures (School District of Philadelphia, 1995).

Perhaps the best-known city-level efficiency program is Seattle City Lights Electric and Multi-family Program, which targeted low-income residences for weatherization and ran for a very long time, from 1981 to 1997. During that time, the program weatherized 15,109 low-income houses (or a participation rate of almost 40 percent) by mandating Copyright © National Academy of Sciences. All rights reserved.

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172 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER more efficient ceilings, under-floors, heating ducts, water heaters, and insulation. From 1991 to 1997, the program pro-vided an annual energy saving of around 2,644 MWh (or peak capacity savings of 4.53 MW) at a cost of $2.75 million (or $607/kW for peak reduction) (Seattle City Light, 1992).

Utility Initiatives Moving to the slightly larger scale of analysis, a Southern California Edison Low Income Lighting Program for resi-dences provided compact fluorescent lighting to low-income houses. Under the program, the utility pays for the full cost of lamps and pays community organizations to implement the program. Started in 1986, by 1991 it had saved over 3 MW of capacity at a cost of only $4.2 million (or $1,400/kW for peak reduction) (Southern California Edison, 1992).

The Utilities Small Commercial and Industrial Program of New England Electricity System targeted consumers with power needs under 50 kW. The programaimed at improv-ing lighting, heating, ventilation, and air-condition (HVAC),

and water-heating systemsprovides the full cost for the implementation of these technologies. Started in 1990, the program saves an average of 18 MWh per year (or a peak-capacity savings of 7.98 MW during the summer) at a cost of

$9.1 million (or $1,140/kW for peak reduction) (New En-gland Electricity System, 1992).

Analogously, Northeast Utilities Lighting Catalog Pro-gram provides energy-efficient lighting through a utility-run catalog at below wholesale cost. The program simply devel-oped a small catalog of 38 efficient lighting technologies and circulated it to residential consumers, who can then or-der through a toll free number. Over 100,000 catalogs were ordered in the first 6 months, and the program has so far saved over 8.24 GWh at a low cost of $1.7 million.

A 2005 report of the Regulatory Assistance Project evalu-ated the New England regions 2002 efficiency program in-vestments and savings. The report concluded that utilities in New England spent $241 million of system benefit funds on efficiency to save 10,036 GWh assuming a cost of 2.5¢/kWh (Sedano and Murray, 2005).

A 1993 Boston Edison energy-efficiency program aimed at commercial and industrial energy users has attempted to conserve electricity among consumers with needs greater than 150 kW. Targeting a wide battery of technologies commercial and industrial lighting, HVAC, motors, refrig-eration, industrial processes, and energy-management sys-temsBoston Edisons program provided rebates after confirmed retrofittings and distributed quarterly checks to noninstitutional customers. An independent evaluation by Cambridge Systematics, Inc., found that the program saved 22,027 MWh, or 6.35 MW of capacity, during 1992 and 1993 at a cost of roughly $14 million (or $2,200/kW of capacity avoided) (Boston Edison Company, 1994).

A 2005 study conducted by the Northwest Power and Conservation Council (NPCC) calls on utilities to invest ap-proximately $1.4 billion in 42 energy-efficiency technolo-gies (including commercial lighting, boilers, HVAC systems, water heaters, and refrigerators). The Council argues that these measures could reduce electricity costs by over $2 bil-lion between 2005 and 2009. The study also found that simple efficiency measures could displace 700 MW of power by 2009 (at $2,000/kW of capacity avoided) and 2,500 MW by 2025 (at $56/kW of capacity avoided) (Northwest Power and Conservation Council, 2005).

State Initiatives A 2002 report on energy-efficiency potential in Califor-nia suggested that immense potential remains for the instal-lation of compact fluorescent lighting systems, new variable-speed-drive chillers, energy-management control systems, industrial compression systems, and the like throughout Cali-fornia (Rufo and Coito, 2002). The study concluded that the economic potential for energy-efficiency measures was ap-proximately 10,000 MW for peak-demand savings. It also found that programmable efficiency savings could reach 5,900 MW if funding for existing efficiency programs in California were tripled. These findings are tentatively sup-ported by another study, sponsored by the California Energy Commission (2003), which found that implementing effi-ciency measures in technologies such as air conditioning, clothes washing, lighting, pool pumps, and refrigerators could achieve a reduction of at least an additional 1,700 MW of peak electricity demand, with energy savings of 6,000 GWh of electricity and 100 million therms of natural gas by 2008.

Finally, a 2003 study sponsored by the Natural Resources Defense Council and the Silicon Valley Manufacturing Group concluded that investments in energy-efficiency made after the 2001 power crisis in California displaced more than 1,000 MW of anticipated capacity. The same study empha-sized that, over the next decade, California could realisti-cally and cost-effectively reduce its electricity needs by 5,900 MW, or the equivalent of $12 billion in savings. In other words, California residents and businesses have dem-onstrated some of the best possible ways to protect the economy and the environment through energy-efficiency programs (Bachrach et al., 2003, p. iv).

A 2004 report of the New Jersey Board of Public Utilities estimated that nine energy-efficiency programs (residential HVAC reimbursements, residential construction standards, residential ENERGY STAR standards, appliance cycling, a residential low-income program, refrigerator turn-in, com-mercial construction standards, the retrofitting of schools, and combined heat and power tax incentives) have cost the state $41 million per year but have saved 108,583 MWh annually.

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APPENDIX G 173 (1998) estimates that from 1991 to 1997, Vermont electric utilities spent $75 million on efficiency measures to reduce electricity use by 249 GWh (or 4.7 percent), and have dis-placed peak demand of 56 MW at the low utility cost of 2.4

¢/kWh (discounted over the lifetime of the installed mea-sures). That represents $1,350/kW of peak capacity reduc-tion. The findings of the study are backed by another 2003 Vermont Department of Public Service evaluation of state-wide residential and commercial energy-efficiency mea-sures. The 2003 study found that product efficiency stan-dards, state building codes, and energy-efficiency program offerings through system benefit funds had saved the state 48,494 MWh from March 2000 to March 2002.

A similar study, undertaken by the North Carolina En-ergy Policy Council (2004), surveyed the impacts of the State Energy Offices energy savings using an energy economic model. The study analyzed the 2002 savings in energy effi-ciency of five measurespublic education, demonstration projects, research and development on efficient technolo-gies, grants for equipment installation, and low-interest re-volving loansand concluded that these programs will save 862 GWh between 2001 and 2010, the equivalent annual savings of 105 GWh.

In Oregon, the Energy Trust of Oregon (2003) analyzed more than 154 energy-efficiency technologies in the resi-dential, commercial, industrial, and agricultural sectors. The study estimated total savings of 7 million MW from 2003-2013. Over 70 percent of this potential is concentrated in commercial and residential sectors, with the largest gains coming from more energy-efficient computers and elec-tronics, light-emitting diode (LED) lights, and wastewater treatment. For example, the study found that 162 MW could be saved from the use of more efficient computers and electronics.

Perhaps one of the most innovative techniques for achiev-ing energy efficiency comes from new legislative require-ments enacted in Texas. Texas is the first state to promulgate energy-efficiency portfolio standards for its distribution utili-ties, thereby mandating reductions in load growth. In 1999, the Texas legislature restructured the states electric utility industry and in the same bill required that its distribution utilities meet 10 percent of its projected load growth through a portfolio of energy-efficiency programs. The projects are self-selected based on Standard Offer and Market Transfor-mation programs approved by the Public Utility Commis-sion. In the deregulated sector of Texas, which is about 70 percent of total load, the distribution/wires companies can choose to implement Standard Offer contracts with an en-ergy-efficiency service provider (EESP). The EESP receives a standard payment based on the amount of energy and peak demand savings attributed to end-use customer sites where the measures are implemented. The Standard Offer or incen-tive payment is 50 percent of the avoided cost (for the next gas-fired power plant and associated energy costs) for resi-dential and 35 percent of the avoided cost for commercial energy-efficiency measures. Funds for achieving the energy-efficiency goal will be included in each service areas trans-mission and distribution rates (Public Utility Commission of Texas, 2000a, 2000b).

National Initiatives Findings comparable to those described above exist even at the national level. Researchers from five national lab-oratories conducted a study, entitled Scenarios for a Clean Energy Future that assessed how energy-efficient and clean-energy technologies could address key energy and environ-mental challenges facing the United States. A particular fo-cus of this study was the energy, environmental, and economic impacts of different public policies and programs.

Hundreds of technologies and approximately 50 policies were analyzed. The study concluded that policies exist that can significantly reduce inefficiencies in energy production and end-use systems at essentially no net cost to the U.S.

economy. The most advanced scenario found that policies implemented in 2000 could bring U.S. electricity consump-tion back to 1990 levels by the year 2010. The study also concluded that, over time, energy bill savings in these sce-narios can pay for the investments needed to achieve the reported reductions in energy use (Brown et al., 2001).

A national assessment of state initiatives (Prindle et al.,

2003) sponsored by the American Council for an Energy-Efficient Economy estimated the annual energy savings for seven different types of efficiency policy categories: ap-pliance and equipment standards, building energy codes, combined heat and power, facility management, tax incen-tives, transportation, and utility programs. The report con-cluded that an average size state could save almost 400 tril-lion British thermal units annually in the year 2020 through aggressive implementation of energy efficiency policies (Prindle et al., 2003, p. v). The largest two areas of potential, after transportation, were the combined heat and power cat-egory and utility programs like systems benefit funds and energy efficiency portfolio standards.

A rigorous analysis of state energy-efficiency programs undertaken by the Oak Ridge National Laboratory (Schweitzer and Tonn, 2005) attempted to quantify the na-tionwide energy and cost savings associated with a variety of state efficiency activities performed during 2002 under the State Energy Program. The study focused on 18 project areas, including retrofits, energy audits, codes and standards, loans and grants, and tax credits. The responding states and territories spent more than $540 million on these energy-efficiency programs in 2002 to achieve an estimated nation-wide saving of 47.6 trillion source Btu and cost savings ex-ceeding $333 million. Most interestingly, the largest estimated energy savings resulted from workshops and train-ing, codes and standards, energy audits, retrofits, and techni-cal assistance.

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174 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER References Bachrach, Devra, Matt Ardema, and Alex Leupp. 2003. Energy Efficiency Leadership in California: Preventing the Next Crisis. Report to the Natural Resources Defense Council and the Silicon Valley Manufactur-ing Group, April.

Boston Edison Company. 1994. Large Commercial and Industrial Retrofit Program. Results Center Profile No. 116.

Brown, Marilyn A., Mark D. Levine, Walter Short, and Jonathan G.

Koomey. 2001. Scenarios for a Clean Energy Future. in Energy Policy, 29(14):179-1196.

California Energy Commission. 2003. Accessing the Energy Savings Po-tential in Californias Existing Buildings. Interim Report to the Legisla-ture in Response to AB 549. November.

Energy Trust of Oregon. 2003. Energy Efficiency and Conservation Mea-sure Resource Assessment for the Residential, Commercial, Industrial, and Agricultural Sectors. January.

New England Electric System. 1992. Small Commercial and Industrial Ef-ficiency Program. The Results Center Profile Number 1.

North Carolina Energy Policy Council. 2004. Clean Energy Funding for North Carolina: An Impact Analysis of State Energy Office Programs.

September, Appalachian State University Energy Center.

Northwest Power and Conservation Council. 2005. The Fifth Northwest Electric Power and Conservation Plan.

NYSERDA (New York State Energy Research and Development Author-ity). 2003. Energy Efficiency and Renewable Energy Resource Devel-opment Potential in New York State. Final Report. NYSERDA, Albany, N.Y.

Ohio Department of Development. 2004. Energy Efficiency Success Story:

City of Toledo. Office of Energy Efficiency, Community Development Division. Toledo, Oh.

Plunkett, John and Ashok Gupta. 2004. State of New York Public Service Commission: Proceeding on the Motion of the Commission as to the Rates, Charges, Rules and Regulations of Consolidated Edison Com-pany of New York, Inc. for Electric Service. December 15.

Prindle, William, et al. 2003. Energy Efficiencys Next Generation: Innova-tion at the State Level. Report for the American Council for an Energy-Efficient Economy. November.

Public Utility Commission of Texas. 2000a. Substantive Rule, Chapter 25.

Electric., Preamble Proposal for Adoption at 2/24/00, (02/23/00) Avail-able at http://www.puc.state.tx.us/rules/rulemake/21074/022300 pre.pdf. Accessed December 12, 2005.

Public Utility Commission of Texas. 2000b. Energy Efficiency Programs Project #21074 Available at http://www.puc.state.tx.us/rules/

rulemake/21074/21074.cfm. Accessed December 12, 2005.

Rufo, Michael and Fred Coito. 2002. Californias Secret Energy Surplus:

The Potential for Energy Efficiency. September 23.

Sacramento Municipal Utility District. 1994. Residential Peak Corps Pro-gram. Results Center Profile No. 83. November.

School District of Philadelphia. 1995. Save Energy Campaign. Results Cen-ter Profile No. 114. September.

Schweitzer, Martin and Bruce E. Tonn. 2005. An Evaluation of State En-ergy Program Accomplishments: 2002 Program Year. Department of Energy. June.

Seattle City Light. 1992. Low Income Electric Program. Results Center Profile No. 20. March.

Sedano, Richard and Catherine Murray. 2005. Electric Energy Efficiency and Renewable Energy in New England: An Assessment of Existing Policies and Prospects for the Future. May.

Vermont Department of Public Service, 1998. Vermont Electric Utility Demand Side Management Accomplishments: History and Current Trends. September.

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APPENDIX G 175 APPENDIX G-3 ESTIMATING DEMAND-RESPONSE POTENTIAL The estimated potential for demand-response programs to reduce peak demand in the Indian Point area is based on the experience to date with three NYSERDA programs that avoided a total of 700 MW of peak demand in the state of New York in 2004.

The first step in the estimating process involved appor-tioning the 700 MW of peak reduction to Zones I, J, and K.

Table 4.1 of the Comprehensive Reliability Planning Pro-cess Draft Reliability Needs Assessment (NYISO, 2005) was used as the basis for the apportionment. It provides the ap-proximate summer peak loads by zone in New York State, but aggregates three zones (G, H, and I) into the Lower Hudson Valley. After apportioning that value to Zone I, it is estimated that Zones I, J, and K have 17,697 MW of peak load, or 55 percent of the statewide total (31,770 MW). Thus, it can be estimated that Zones I, J, and K could account for 55 percent of the 700 MW of peak reduction from demand-response programs in 2004, or 385 MW.

The second step in the estimating process involves ad-justing the 385 MW to reflect what might be achieved if the three 2004 demand-response programs of NYSERDA were doubled in budget. The committee assumed diminishing re-turns, such that a doubling of budget delivers an increment of only 50 percent. This brings the estimated potential for expanded summer peak reduction to approximately 200 MW. It is assumed that these load reductions could be achieved by the year 2010, since demand reductions can be achieved quickly.

As with efficiency, it takes time to expand demand-response program activities, to attract more program partici-pants, and to purchase and install new demand-response equipment. Therefore, it is assumed that only 50 MW of additional peak reduction could be achieved in 2007, increas-ing to 200 MW by 2010. It is also assumed that the project increases in potential for the years 2013 (275 MW) and 2015 (300 MW).

Reference NYISO. 2005. Comprehensive Reliability Planning Process and Draft Re-liability Needs Assessment. September 1.

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176 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER 1Letendre et al. (2003) analyzed data on the day-ahead hourly wholesale price of electricity from NYISO from the summer of 2002, combined with satellite-derived solar resource data, and found that the average PV avail-ability for all 32 peak power price days in the summer of 2002 was 79 percent. In other words, on average in the NYISO control area, distributed PV systems would have been operating at roughly 80 percent of their ideal output during the days when power prices spiked above 20¢/kWh in the wholesale market.

2Information is available online at http://www.irecusa.org. Accessed No-vember 12, 2005.

APPENDIX G-4 ESTIMATING PHOTOVOLTAICS FOR DEMAND REDUCTION Current and Projected Costs Table G-4-1 presents an overview of the current and pro-jected cost of electricity from photovoltaic technology through the year 2016. The two key markets for photovolta-ics (PV) are assumed to be distributed residential systems and distributed commercial systems. Thus, the high and low ranges are based on current and projected costs in these two market segments. As shown in the table, the levelized cost of energy from PV is projected to drop from the current 23 to 38¢/kWh to 12 to 20¢/kWh in 2016.

It is important to note that the costs shown in the table are those experienced by the end userthat is, they should be compared with retail rather than wholesale electricity rates.

In addition, since the production from PV is nearly coinci-dent with peak demand in New York State,1 a strong argu-ment can be made for valuing PV in a planning context at a rate higher than the average retail rate in New York. For example, Perez et al. (2004a) used average NYISO day ahead hourly wholesale price of electricity data in the metropolitan New York City and Long Island during 2002 to estimate the solar-weighted wholesale price (weighted by PV output as a proportion of the total output). Using these data, they con-cluded that combining PV with a limited amount of load management (to enable PV to claim a capacity value close to 100 percent) would have increased the value (i.e., the systemwide cost savings) of residential PV during 2002 from 15¢/kWh (the average retail rate in that year) to 21.3¢/kWh in NYC and from 12¢/kWh (the average retail rate in that year) to 20.3¢/kWh on Long-Island. As shown in Table G 2, if PV system owners could capture this value through in-terconnection rules, rate-structures, etc., then PV technology could become a rapidly expanding and self-sustaining in-dustry in New York State during the next decade.

Accelerated Photovoltaic Technology Deployment Scenario for the New York City Area The rapid growth in the global PV market during the past decade was driven largely by government subsidy programs, particularly in Japan, Germany, and a few states in the United States (including California and New York). New York State provides a variety of incentives, in the forms of loans, grants, and tax credits for the installation and use of PV systems by residential and business customers.2 The projection dis-cussed here also will not be achieved without subsidies, but they will be phased out over 10 to 15 years. By about 2018, the technology should be cost-effective without subsidies, and New York will have a substantial energy contribution from a source with attractive environmental and security at-tributes.

The existing subsidy programs for PV systems in New York are well subscribed, indicating that accelerated PV de-ployment is quite possible. Current installed system prices are about $8/W in New York State, with a $4/W buy-down, leaving a final cost to the consumer of about $4/W. If fi-nanced over the life of a system (30 years) at a 6 percent interest rate (~4 percent real interest rate after tax benefits) the levelized cost of energy from such a PV system would be about 13.5¢/kWh. With current average residential electric-ity prices above 20¢/kWh in New York City, an investment in a PV system could look attractive to many consumers.

The accelerated deployment scenarios considered in the present study is modeled on a Japanese program, which pro-vided a declining subsidy to residential PV systems over the past decade. Residential PV installations expanded in Japan from roughly 2 MW in 1994 to 800 MW in 2004 (Ikki, 2005).

In its accelerated scenario, the committee contemplated a growth rate of roughly one-half that experienced in Japan to compensate for the difference in circumstances from the Japanese conditions to those in New York. The average price of residential PV systems installed in Japan in 2004 was

$6.2/Wthat is, about 25 percent lower than in New York today. This cost differential is a reflection of the difference between a well-functioning and an emerging market for PV systems. PV modules and inverters are commodities whose prices are largely driven by international markets; however, labor and balance of system cost (which typically account for 30 to 40 percent of total system cost) are driven by local policies and market development.

Figure G-4-1 shows an accelerated market-development path for the New York City area. This scenario is not a model result, but an estimate of what could be achieved under the following assumptions:

The estimated technical potential for rooftop installa-tions in the New York City area (Hudson Valley, New York City, and Long Island) in 2025 is 18-20 GW (NYSERDA, 2003; Navigant Consulting, 2004).

The cost projection is in line with what the DOE Solar Energy Technology Program and the U.S. PV industry be-lieves will be achieved over the next 10 to 15 years in the Copyright © National Academy of Sciences. All rights reserved.

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APPENDIX G 177 TABLE G-4-2 Accelerated PV Deployment Scenario for the New York City Area Installed Installed Annual System Annual Growth Cumulative System Effective State Cost to Installations Rate Installations Cost Buy-down Buy-down Investment Consumer Year (MW)

(%)

(MW)

($/W)

Rate

($/W)

(millions)

($/W) 2006 6.0 40 10.2 7.70 50 3.85 23.10 3.85 2007 8.4 40 18.6 7.36 47 3.46 29.06 3.90 2008 11.8 40 30.4 7.02 44 3.09 36.32 3.93 2009 16.5 40 46.8 6.68 41 2.74 45.09 3.94 2010 23.0 40 69.9 6.34 38 2.41 55.53 3.93 2011 32.3 25 102.1 6.00 35 2.10 67.77 3.90 2012 40.3 25 142.5 5.70 31 1.77 71.28 3.93 2013 50.4 25 192.9 5.40 27 1.46 73.51 3.94 2014 63.0 25 255.9 5.10 23 1.17 73.93 3.93 2015 78.8 25 334.7 4.80 19 0.91 71.85 3.89 2016 98.5 15 433.2 4.50 15 0.68 66.47 3.83 2017 113.3 15 546.4 4.25 10 0.43 48.13 3.83 2018 130.2 15 676.7 4.00 5

0.20 26.05 3.80 2019 149.8 15 826.5 3.75 0

0.00 0.00 3.75 2020 172.2 15 998.7 3.50 0

0.00 0.00 3.50 NOTE: All estimates are in 2005 dollars.

TABLE G-4-1 Current and Projected Distributed PV Cost Current (2004)

Projected (2016)

Considerations Low High Low High Capital cost ($/W) 6 8

3.5 4.5 O&M cost (¢/kWh) 3 6

1 2

DC-AC conversion efficiency (%)

93 91 95 95 Fuel cost (¢/kWh) n.a.

Levelized cost of electricity (¢/kWh) 23 38 12 20 Availability 17% CF, i.e., daylight hours only (without storage).

Reliability Very reliable, can help reduce stress on grid.

Environmental considerations Clean, quiet, and easy to site.

Site retrofit potential Limited: Requires ~ 100 sq. ft./kW. Could install ~50 MW using ~50% of the Indian Point site.

Other issues Very large technical potential, but will require time to penetrate market/develop market infrastructure.

NOTE: O&M, operation and maintenance; AC-DC, direct current-alternating current; N.A., not available. All estimates are in 2005 dollars. Levelized cost of electricity calculation assumes system is financed over the 30-year life of system. Low estimates are based on a commercial system with 17 percent capacity factor, 10 percent federal investment tax credit, federal accelerated depreciation, and 7 percent real (after tax) discount rate. High estimates are based on a residential system with 17 percent capacity factor and 4 percent real (after tax) interest rate. O&M costs are dominated by inverter replacement cost. Current inverters lifetimes are 5-7 years, with expected lifetimes rising to 10-15 years over the next decade.

SOURCE: Based on data and projections in DOE (2004), Margolis and Wood (2004), and SEIA (2004).

United States (DOE, 2004; SEIA, 2004). In other words, it is an aggressive but plausible projection.

The average annual growth rate was set in 5-year inter-vals as follows: 40 percent between 2006 and 2010, 25 per-cent between 2011 and 2015, and 15 percent between 2016 and 2020. These rates are well below (roughly one-half) the rates achieved in the Japanese program.

A declining subsidy is implemented, set at 50 percent in 2006, declining linearly to 35 percent in 2011, 15 percent in 2016, and 0 percent in 2019. The combination of a declin-ing subsidy and declining costs maintains an installed sys-tem cost to consumers below $4/W throughout the scenario.

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178 ALTERNATIVES TO THE INDIAN POINT ENERGY CENTER Installed Cost (Left)

Cumulative Installations (Right)

Cumulative Installations (MW) ployment will require the availability of reputable installers, which in turn depends on a clear, long-term policy commit-ment. Setting up a new business (getting certified, training staff, and so on) requires a substantial investment of re-sources. Entrepreneurs need to believe they will be able to recoup this investment over time. Policy uncertainty, in this context, creates a substantial barrier to building a viable lo-cal PV distribution, installation, and maintenance industry.

Achieving the high growth rates envisioned during the 2006-2015 period will require investing additional resources (on the order of $10 million per year) in programs aimed at helping entrepreneurs establish PV businesses and boosting public awareness of PV in the New York City area.

Additional detail for this scenario is shown in Table G 2. This scenario envisions creating a self-sustaining PV mar-ket in New York City area by 2019. Under this scenario about 1 GW of PV systems would be installed in the New York City area by 2020. Achieving this goal would require a total public investment of roughly $420 million (discounted to present value at 7 percent) between 2006 and 2018, thus equivalent to a present value cost of roughly $420/KW installed.

Under an aggressive but plausible accelerated PV deploy-ment scenario, about 335 MW of PV systems could be in-stalled in the New York City area by 2015 (generating roughly 500 GWh of electricity per year). Assuming a ca-pacity factor of 0.75 relative to peak load (to account for the slight non-coincidence of peak load and PV output, and the inevitable outages of some PV systems), this level of PV installations could offset about 250 MW (12 percent of In-dian Points capacity) during peak periods and about 3 per-cent of Indian Points annual electricity output. The rate of installation could continue to grow for many years even with-out public subsidy after 2018.

REFERENCES DOE (Department of Energy). 2004. Solar Energy Technologies Program, Multi-Year Technical Plan 2003-2007 and Beyond. Report DOE/GO-102004-1775. Office of Energy Efficiency and Renewable Energy, U.S.

Department of Energy, Washington, D.C.

Ikki, Osamu. 2005. PV Activities in Japan. RTS Corporation, Tokyo, Japan.

May.

Letendre, Steven, et al. 2003. Solar and Power Markets: Peak Power Prices and PV Availability for the Summer of 2002. Paper presented at ASES 2003, Austin, Tex., June.

Margolis, Robert M., and Frances Wood. 2004. The Role for Solar in the Long-Term Outlook of Electric Power Generation in the U.S. Paper presented at the IAEE North American Conference in Washington, D.C.,

July 8-10.

Navigant Consulting. 2004. PV Grid Connected Market Potential in 2010 under a Cost Breakthrough Scenario. Report to The Energy Founda-tion. Available at www.navigantconsulting.com. Accessed November 10, 2005.

NYSERDA (New York State Energy Research and Development Author-ity). 2003. Energy Efficiency and Renewable Energy Resource Devel-opment Potential in New York State. New York State Energy Research and Development Authority, Albany, New York. Available at www.

nyserda.org. Accessed November 10, 2005.

Perez, Richard, et al. 2004a. Quantifying Residential PV Economics in the USPayback vs Cash "ow Determination of Fair Energy Value. So-lar Energy 77: 363-366.

Perez, Richard, et al. 2004b. Solar Energy Security. REFocus July/

August: 24-29.

SEIA (Solar Energy Industries Association). 2004. Our Solar Power Fu-ture: The U.S. Photovoltaic Industry Roadmap Through 2030 and Be-yond. Solar Energy Industries Association, Washington, D.C.

FIGURE G-4-1 Accelerated PV market development path for the New York City area.

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