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 Transmission Options.” Appendix D contains the following:



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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 Transmission Options.” Appendix D contains the following: Appendix D-1, “Cost Estimates for Electric Generation Technologies”—Table 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 2005”—Table D-2-1 provides a summary, and the remaining tables present data for summer and winter capacity (MW) and energy production (GWh) by fuel and provide other data on the New York Control Area (NYCA). Appendix D-3, “Energy Generated in 2003 from Natural Gas Units in Zones H Through K”—This appendix contains 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 States”—A map of the northeastern states shows proposed natural gas pipelines. Appendix D-5, “Coal Technologies”—Committee member James R. Katzer presents a discussion of the coal-based technologies that the committee considered and evaluated with respect to operating costs, including the technology (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 Technologies—Wind and Biomass”—Dan Arvizu of the Department of Energy’s National 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 Demand for Electricity”—Dan 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 State’s current policies related to PV technology and an accelerated PV-deployment scenario for New York State through 2020. References

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs APPENDIX D-1 COST ESTIMATES FOR ELECTRIC GENERATION TECHNOLOGIES Parker Mathusa and Erin Hogan1 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: Technology EIAa University 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 technologies have lower costs than others, the total capacity of the lower-cost generation technology may be limited—for example, a 500-MW municipal solid waste landfill gas project is unlikely. MIT calculations 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. 1 Parker 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-1-2 Cost Components for Electricity Generation Technologies Source Capital Costs ($/kWh) O&M Costs ($/kWh) Fuel Costs ($/kWh) Cost of Electricity Without Regional Multipliers ($/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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-1-3a Energy Information Administration National Average Cost Estimates (2003 dollars)   Total Costa Capacity Financing (20 year term at 10%/year) Plant Typeb Annual Cost (million $) Capital Cost ($/kWh) Operating Costs ($/kWh) Fuel Costs ($/kWh) Total Cost of Electricity ($/kWh) Delivery Cost ($/kWh)c Assumed Capacity (MW) Capacity Factor Hours Operated per Year Overnight Costs w/Contingencies ($/kW)a,b Capital Cost (million $) Annual Payment (million $) Payment ($/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 Combined Cycle (IGCC) 173.5 0.0209 0.0069 0.0122 0.0400 0.0900 550 0.90 7884 1,402 771.1 90.6 0.0209 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 Combined Cycle 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 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 Turbine 90.9 0.0056 0.0040 0.0406 0.0501 0.1001 230 0.90 7884 374 86.0 10.1 0.0056 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 Turbine 73.4 0.0059 0.0045 0.0478 0.0582 0.1082 160 0.90 7884 395 63.2 7.4 0.0059 Advanced CC with Carbon Sequestration 187.6 0.0166 0.0048 0.0381 0.0595 0.1095 400 0.90 7884 1,114 445.6 52.3 0.0166 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-1-3b Energy Information Administration National Average Cost Estimates (2003 dollars)   Variable O&M Fixed O&M Fuel Cost Plant Typea ($/kWh)a Annual (million $) ($/kW)a ($/kWh) Annual O&M (million $) Fuel Cost ($/mmBtu)b Heat Rate (Btu/kWh)a Fuel Cost ($/kWh) Fuel Cost (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 Cycle (IGCC) 0.0026 11.2 34.21 0.0043 18.8 1.47 8,309 0.0122 53.0 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 Sequestration 0.0026 8.2 17.60 0.0022 7.0 4.42 8,613 0.0381 120.1 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.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-1-4a Energy Information Administration Regional Cost Estimates (2003 dollars)   Total Costa Capacity Financing (20-year term at 10%/year) Plant Typeb Annual Cost ($ million) Capital Cost ($/kWh) Operating Costs ($/kWh) Fuel Costs ($/kWh) Total Cost of Electricity ($/kWh) Delivery Cost ($/kWh)c Capacity (MW) Capacity Factor Hours Operated per Year Overnight Costs ($/kW)a,b Capital Cost ($ million) Annual Payment ($ million) Payment ($/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 Cycle (IGCC) 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 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-1-4b Energy Information Administration Regional Cost Estimates (2003 dollars)   Variable O&M Fixed O&M Fuel Cost Plant Typea ($/kWh)a Annual (million $) ($/kW)a ($/kWh) Annual O&M (million $) Fuel Cost ($/mmBtu)b Heat Rate (Btu/kWh)a Fuel Cost ($/kWh) Fuel Cost (million $/yr) MSW Landfill Gas 0.0000 2.4 101.07 0.0128 3,032,100 0.00 13,648 0.0000 0 Scrubbed Coal New 0.0041 19.2 24.36 0.0031 14,616,000 1.47 8,844 0.0130 61.6 Integrated Coal Gasification Combined Cycle (IGCC) 0.0026 11.2 34.21 0.0043 18,815,500 1.47 8,309 0.0122 53.0 Distributed Generation Base 0.0000 0 26.81 0.0034 53,620 0.00 10,280 0.0000 0 Distributed Generation Peak 0.0000 0 26.81 0.0034 26,810 0.00 10,280 0.0000 0 Advanced Gas Combined Cycle 0.0018 5.6 10.35 0.0013 4,140,000 4.42 6,752 0.0298 94.1 Wind 10 MWc 0.0000 0 26.81 0.0095 268,100 0.00 10,280 0.0000 0 Conventional Gas Combined Cycle 0.0018 3.6 11.04 0.0014 2,760,000 4.42 7,196 0.0318 62.7 Advanced Nuclear 0.0004 3.5 60.06 0.0076 60,060,000 0.00 10,400 0.0050 39.4 Advanced Combustion Turbine 0.0032 5.7 10.72 0.0014 2,465,600 4.42 10,817 0.0478 86.7 IGCC with Carbon Sequestration 0.0039 11.8 40.26 0.0051 15,298,800 1.47 9,713 0.0143 42.8 Wind 100 MWc 0.0028 0.8 9.31 0.0033 931,000 4.42 9,183 0.0406 11.5 Advanced CC with Carbon Sequestration 0.0063 19.9 14.18 0.0018 5,672,000 4.42 9,950 0.0440 138.7 Conventional Combustion Turbine 0.0030 3.7 47.18 0.0060 7,548,800 2.46 8,911 0.0219 27.7 Biomass 0.0063 3.7 14.18 0.0020 1,134,400 4.42 11,200 0.0495 28.8 Wind 50 MW 0.0026 0.4 17.60 0.0062 880,000 4.42 8,613 0.0381 5.4 Photovoltaic 0.0000 0 10.34 0.0049 51,700 0.00 10,280 0.00 0 Solar Thermald 0.0000 0 50.23 0.0382 5,023,000 0.00 10,280 0.00 0 aAnnual Energy Outlook 2005, Basis of Assumptions Table 38, DOE (2005). bFuel prices are New York-specific. cApplied the 0.6 rule using 50 MW as the base reference. dCapital costs shown are before the 10 percent investment tax credit is applied. TABLE D-1-5 University of Chicago National Average Cost Estimates (2003 dollars)   Total Costa Capacity Plant Type Annual Cost ($/yr) Capital Cost ($/kWh) Operating Costs ($/kWh) Fuel Costs ($/kWh) Total Cost of Electricity ($/kWh) Delivery Cost ($/kWh)b Assumed Capacity (MW) Assumed Capacity (kW) Capacity Factor Hours Operated per Year Integrated Coal Gasification Combined Cycle 136,251,949 0.0199 0.0052 0.0094 0.0346 0.0846 500 500,000 0.90 7,884 Natural Gas Combined Cycle 139,350,109 0.0088 0.0030 0.0236 0.0354 0.0854 500 500,000 0.90 7,884 Pulverized Coal Steam 140,577,240 0.0167 0.0077 0.0113 0.0357 0.0857 500 500,000 0.90 7,884 Fluid Bed Coal 141,076,995 0.0179 0.0059 0.0120 0.0358 0.0858 500 500,000 0.90 7,884 Pulverized Coal Supercritical 148,369,695 0.0179 0.0085 0.0113 0.0376 0.0876 500 500,000 0.90 7,884 Nuclear Advanced Boiler Water Reactor 341,200,360 0.0238 0.0152 0.0042 0.0433 0.0933 1,000 1,000,000 0.90 7,884   Financing Total O&M Fuel Cost Plant Type Capital Costs ($/kW)a Capital Cost ($) Term (yr) Interest (%) Annual Payment ($/yr) Payment ($/kWh) ($/kWh) ($/yr) Fuel Cost ($/kWh) Fuel Cost ($/yr) Integrated Coal Gasification Combined Cycle 1,338 669,000,000 20 10 78,580,489 0.0199 0.0052 20,458,980 0.0094 37,212,480 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 Reactor 1,600 1,600,000,000 20 10 187,935,400 0.0238 0.0152 120,073,320 0.0042 33,191,640 aExcludes regional multipliers. bAssumes $0.05/kWh delivery cost, excluding line losses.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-1-6 University of Chicago Regional Cost Estimates for the New York Control Area (2003 dollars)   Total Costa Capacity Plant Type Annual Cost ($/yr) Capital Cost ($/kWh) Operating Costs ($/kWh) Fuel Costs ($/kWh) Total Cost of Electricity ($/kWh) Delivery Cost ($/kWh)b Assumed Capacity (MW) Assumed Capacity (kW) Capacity Factor Hours Operated 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 Combined Cycle 177,113,803 0.0303 0.0052 0.0094 0.0449 0.0949 500 500,000 0.90 7,884 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 Water Reactor 438,926,767 0.0362 0.0152 0.0042 0.0557 0.1057 1,000 1,000,000 0.90 7,884   Financing Total O&M Fuel Cost Plant Type Capital Costs ($/kW)a Capital Cost ($) Term (yr) Interest (%) Annual Payment ($/yr) Payment ($/kWh) ($/kWh) ($/yr) Fuel Cost ($/kWh) Fuel Cost ($/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 Combined Cycle 2,034 1,016,880,000 20 10 119,442,343 0.0303 0.0052 20,458,980 0.0094 37,212,480 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 Water Reactor 2,432 2,432,000,000 20 10 285,661,807 0.0362 0.0152 120,073,320 0.0042 33,191,640 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 $0.05/kWh delivery cost excluding line losses. TABLE D-1-7 New York City Fuel Prices ($/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.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs APPENDIX D-2 ZONAL ENERGY AND SEASONAL CAPACITY IN NEW YORK STATE, 2004 AND 2005Parker 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 (MW) Winter Capacity (MW) Energy (GWh) Energy Requirements (GWh) Energy Production/ 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 Area’s 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). 1 Parker 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-2-2 Summer Zonal Capacity, by Fuel, 2004 and 2005     Total Zonal Winter Capacity (MW) Dual-Fuel Winter Capacity (MW) Single-Fuel Winter Capacity (MW) Zone NG/FO2 NG/FO6 NG/KER NG/JF NG/BIT Coal BIT Natural Gas NG No. 2 FO2 No. 6 FO6 Jet Fuel JF Kerosene KER Methane MTE Water WAT Other OT Refuse REF Uranium UR Wood WD Wind 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   %Δ –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 5 7     499   6.7   %Δ –0.07%           –0.83% 0.99% 0.00%       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   %Δ –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     %Δ –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   %Δ –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   %Δ –13.78% –1.78%           –10.01%           0.18%   –12.3%   0.00% 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   %Δ –2.28% –3.53% –3.13% –1.95%   0.15%     0.00%     0.00% 0.00% 0.67%   –4.65%     0.00% H 2004 2,079               47             52 1,981       2005 2,069               47             52 1,971       %Δ –0.46%               0.00%             0.97% –0.50%     I 2004 3                         3 0.48 0.2         2005 3                       0.2 2 0.48           %Δ –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                 %Δ 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         %Δ 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   %Δ –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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-2-3 Winter Zonal Capacity, by Fuel, 2004 and 2005     Total Zonal Summer Capacity (MW) Dual-Fuel Summer Capacity (MW) Single-Fuel Summer Capacity (MW) Zone   NG/FO2 NG/FO6 NG/KER NG/JF NG/BIT Coal BIT Natural Gas NG No. 2 FO2 No. 6 FO6 Jet Fuel JF Kerosene KER Methane MTE Water WAT Other OT Refuse REF Uranium UR Wood WD Wind 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   %Δ –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   %Δ 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   %Δ 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     %Δ 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   %Δ –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   %Δ –4.97% 3.08%           11.00%           2.07%   –12.03%   0.00% 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   %Δ –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       %Δ –0.06%               0.00%             1.96% –0.11%     I 2004 3                         2 0.48 0.2         2005 3                       0.2 2 0.48           %Δ –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                 %Δ 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         %Δ 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   %Δ 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-6-2 Quantitative Estimates of Wind Potential in Indian Point Zones Zone Complete Wind Resource, After Environmental Exclusions; Power Class 3, 4, 5, and above Resource Within 10 Miles of Existing Transmission; Power Class 3, 4, 5, and above Postulated Possible Development (out of 10 GW total) in GE NYSERDA 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. 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 Solutions 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 reliability 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 subtracting 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. Geological Survey, and half of the second highest GAP land stewardship category, remaining U.S. Forest Service, and Department of Defense land. No other land use exclusions were subtracted. As shown, there is some potential for wind in the immediate 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 scenarios 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 dispatch 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)

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs Examination of competitive market structures that would motivate other resources to provide additional ancillary 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 issues 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 proactive 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 construction issues need to be examined to reduce uncertainty and shorten the in-service timelines, if new transmission is necessary to serve wind. Biomass Contribution Primary Source There have been extensive studies of the renewable biomass potential in New York. Information summarized in this analysis has been gleaned from the NYSERDA report Energy Efficiency and Renewable Energy Resource Development Potential in New York State—Final 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 region’s 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 alternative in burial of the wastes out of state. The report assumes continuing use of mass burn technology. For the regions defined above, the capacity would be unchanged until 2012 when the report proposes 76 MW additional 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 residues; 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 curve—GWh vs cost. The current data is not adequate 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 timeframe 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 agricultural potentials. Table D-1-3 assumes two biomass prices—biomass (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 generation 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 2 While 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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. However, this is not an incremental generation of net power as the biomass displaces coal in an existing facility. Approximately 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 residue stream but would require a change in technology to overcome 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 contribution), the economic parameters assumed include an investment 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 proposed 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 proposed on the basis of the Energy Efficiency and Renewable Energy Resource Development Potential in New York State—Final Report, dated August 2003. Similar cost and performance of the biomass-to-electric technologies are assumed 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 economic 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 (MW) Capacity (MW) Generation (TWh) Capacity (MW) Generation (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 data—New York State Data Center, http://www.nylovebiz.com/nysdc/data_economic.asp (Aug 10, 2005). MSW per capita generation—national 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 generation is for 2004, estimated from EIA Form 906.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 biomass 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 region—The counties are Bronx, Kings, New York, Queens, Richmond, Columbia, Delaware, Dutchess, Greene, Nassau, Orange, Putnam, Rockland, Suffolk, Sullivan, Ulster, Westchester 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 future updates. 1.31 tons MSW per capita per year. This was the national 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 estimate is 1.29 tons/per capita/year. Since the value is close the original estimate was not corrected. The existing capacity estimate was taken from the Renewable Electric Plant Information System (REPIS), NREL, 2002 data. The data are on a state and regional basis. Existing biogas generation (primarily landfill gas) was not included. Existing generation was taken from the EIA Form 906/ 920 using 2004 data (http://www.eia.doe.gov/cneaf/electricity/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. Assumed basis is higher heating value. Biomass potential was based on Oak Ridge National Laboratory, Biomass Feedstock Availability in the United States, State Level Data, 1999. 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. 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 Processes 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. Efficiency and capacity assumptions Biogas—35 percent efficiency (IC engine), 80 percent capacity factor Solid feeds 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. 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 Biomass Generation estimated by multiplying resource by heating value, converting to kW thermal, and multiplying by assumed efficiency to obtain kWh electric The capacity factor was used to estimate capacity: MWh divided by hours per year divided by capacity factor. MSW/CDW and Biogas Generation estimated by multiplying population estimate (both regional and state) by per capita generation, multiplying by heating value, converting to kWh thermal, and multiplying by assumed efficiency to obtain kWh electric. The capacity factor was used to estimate capacity: MWh divided by hours per year divided by capacity factor. Market Potential Technical Potential Assumes 100 percent utilization of estimated feed-stock. In 2009, the assumption is that the process will be mass burn or stoker grate for solid feeds. In 2014, the assumption is that the process will be gasification for solid feeds. IC engines at constant efficiency assumed for biogas. Although co-firing is by far the least expensive option for electricity generation, it does not increase capacity, i.e., considered fuel substitution and was not included. Achievable Potential

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs For Biomass and MSW/CDW An RPS and a Section 45 tax credit are assumed as market intervention factors. A Section 45 type credit (value not estimated) is extended to CHP systems heat production to encourage maximum process efficiency. A 25 percent penetration is assumed in 2009. With the use of higher efficiency, lower emissions, and lower-cost gasification technologies the penetration rate is increased to 50 percent in 2014. 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. 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 future electricity generation and capacity needs in the area currently 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 York’s current policies related to PV technology, and an accelerated PV deployment scenario for New York through 2020. Some important observations include: The technical potential for rooftop PV in New York is very large—on 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, reliability, 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 decline considerably over the next decade, falling from a current 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 storage, PV should be able to 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. Under an aggressive but plausible accelerated PV deployment scenario, roughly 50 MW of PV systems could be installed 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 Point’s capacity during peak periods and about 4 percent of Indian Point’s annual electricity output. In addition, under the accelerated scenario about 1 GW of PV systems could be installed in New York by 2016, generating 1,500 GWh of electricity (offsetting about 40-50 percent of Indian Point’s capacity during peak periods and 9 percent of Indian Point’s annual electricity output). Realizing this accelerated scenario would require making a clear long-term commitment, in terms of both policies and resources, to expanding New York’s 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 Point’s capacity during peak periods and 18 percent of Indian Point’s 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 created tremendous excitement about PV technology around the world on the part of governments (EC, 2004), industry (SEIA, 2004; NEDO, 2004; EPIA, 2004), and the investment 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 government 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- 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). 1 Dan 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs FIGURE D-7-1 Global PV market evolution by market segment, 1985 to 2004. SOURCE: Strategies Unlimited (2005). tinue to decline and subsidies are phased out, industry analysts 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 large—estimates of the rooftop technical potential in 2025 are on the order of 35-40 GW (NYSERDA, 2003; Navigant, 2004). If one considers only the Hudson Valley, NYC, and Long Island control areas, then the rooftop technical potential is on the order of 18-20 GW (NYSERDA 2003; Navigant 2004). This technical potential is enough to generate 27,000 GWh of electricity per year compared to the 16,700 GWh currently produced at Indian Point Units 1 and 2. Expanding the market toward this technical potential, however, will require time to develop both the market infrastructure and production capacity for PV. As noted above, global PV production exceeded 1 GW in 2004. Given that Indian Point’s 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 Point’s 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 during the next 5 to 10 years. In thinking about the potential contribution PV could make towards replacing Indian Point, it is important to emphasis the technology’s 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 enable PV to contribute significantly to grid stability, reliability, 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 storage, compressed air energy storage, a variety of end-use storage technologies, etc.). Such a strategy would be designed to draw on the strengths of each of its components. For example, 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 combination with imported Canadian hydro. This strategy would utilize 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

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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). 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 deployment 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 discussed 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-7-2 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 wholesale 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 capacity 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 average 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. 2 Letendre 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 availability 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 policies 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 rebate or “buy-down” program. The main program, administered by NYSERDA, is called New York Energy $mart and includes customers with all the major IOUs. New York Energy $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 installation of over 1.5 MW as of summer 2005. The program currently has $12 million allocated to its PV incentive program, 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 Program. LIPA launched the Solar Pioneer Program in 1999 and offered customers a substantial rebate. The rebate’s budget is tied into LIPA’s 5-year Clean Energy Initiative with a funding level totaling $37 million annually (covering multiple 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. LIPA’s 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 York’s relatively high electricity prices—the 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 sufficient 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 subscribed indicates that they are buying down the price of PV systems into a range that makes them economically attractive 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 consumers, it is of little value if consumers cannot find reputable 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 uncertainty, 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 residential PV systems over the past decade, expanding residential 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 systems 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 international 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 believe 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 intervals as follows: 55 percent between 2006 and 2010, 40 percent between 2011 and 2015, and 5 percent between 2016 and 2020. These rates are below the rates achieved in the Japanese program. A declining subsidy is implemented, set at 50 percent in 2006, declining linearly to 25 percent in 2011, and 0 percent in 2016. The combination of a declining subsidy and declining costs maintains an installed system cost to consumers below $4/W throughout the scenario. A clear long-term commitment to growing the PV industry in New York is put in place. The combination of a declining subsidy, declining system costs and rising installations 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-7-4. This scenario envisions creating a self-sustaining PV market 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. FIGURE D-7-2 An accelerated PV market development path for New York (all estimates are 2005 dollars).

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE D-7-4 Accelerated PV Deployment Scenario for New York (2005 dollars) Year Annual Installations (MW) Growth Rate (%) Cumulative Installations (MW) Installed System Cost ($/W) Buydown Rate (%) Effective Buydown ($/W) Annual State Investment (million) Installed System Cost to Consumer ($/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, Washington, 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, Solar Cell Production and Market Implementation of Photovoltaics. European Commission, Directorate General Joint Research Centre, Renewable Energies Unit, Ispra, Italy. Report EUR 21390 EN. EIA (Energy Information Administration). 2005. Electric Power Monthly. Energy Information Administration, U.S. Department of Energy, Washington, DC. (January). EPA (Environmental Protection Agency). 2005. Control of Mercury Emissions 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 Foundation. Available at www.navigantconsulting.com. NEDO (New Energy and Industrial Technology Development Organization). 2004. PV Roadmap Toward 2030 (Japanese PV Industry Roadmap). New Energy and Industrial Technology Development Organization. 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 Authority). 2003. Energy Efficiency and Renewable Energy Resource Development Potential in New York State. New York State Energy Research 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 Planner’s 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 US—Payback vs Cash Flow Determination of Fair Energy Value.” Solar 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 Future: The U.S. Photovoltaic Industry Roadmap Through 2030 and Beyond. 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: Pittsburgh.