F
Background for the System Reliability and Cost Analysis

Samuel M. Fleming1

This appendix contains the following:

1

Samuel M. Fleming is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs.



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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs F Background for the System Reliability and Cost Analysis Samuel M. Fleming1 This appendix contains the following: Appendix F-1, “The NYISO Approach,” and Appendix F-2, “Notes on the MARS-MAPS Simulations.” 1 Samuel M. Fleming is a member of the Committee on Alternatives to Indian Point for Meeting Energy Needs.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 relating to this committee’s charge: The reliability of the electrical generation and transmission system in the New York Control Area (NYCA) would be inadequate beginning in 2009 if, as is the case historically, thermally constrained transmission limits control transmission.1 The reliability criterion of loss-of-load expectation (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 consequence 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 state’s transmission system is increasingly characterized 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, particularly at the UPNY/SENY interface (just north of Pleasant Valley, New York), is thus a key aspect of considering the projected reliability of the alternating current (AC) transmission system. The New York Power Authority’s (NYPA’s) 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 Station’s units together total 1,315 MW and represent 58 percent of the scheduled retirements by mid-2008. Addition of a corrective resource—an additional 250 MW of generating capacity in New York City (Zone J), beyond NYISO’s Initial Base Case—would 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 Valley (LHV) mean, however, that voltage-constraint limits2 in the transmission system, if not corrected, would control the reliability situation, rather than thermal transmission constraints. In this situation, the projected NYCA LOLE reaches 0.395 by 2008 and 2.43 by 2010. The impact if voltage constraints were to control—and 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 additional 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, respectively. In this early-retirement scenario, the LOLE for the 1 Thermal limits relate to avoidance of overheating the transmission lines, a condition causing the lines to sag, and in some instances to touch vegetation, causing outages. 2 Voltage drop in the AC system must be tightly limited to maintain frequency and synchronous operation and to avoid physical damage both to generating equipment and equipment served as load.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 transmission 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 anticipate some of the considerations and results discussed below, 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 resources, 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 transmission 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 transmission 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. Generally, 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 carried 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 limited transfer analysis of some 16 New York power system interfaces. The objective of this part of the screening analysis was to identify the regions or corridors requiring any significant transmission-system upgrades in order to meet system 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. Multiple scenarios representing different possible system conditions (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 scenario 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 forecasts, transmission system transfer capabilities, and available 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 transmission system. The Initial Base Case and sensitivity analyses performed by NYISO also include the addition of illustrative and hypothetical “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 3 NYISO 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 Reduction Program, the Clean Water Act Cooling Water Intake Best Available Technology, new Source Review, Clean Air Interstate Rule (CAIR), Clean Air Mercury Rule, Regional Greenhouse Gas Initiative (RGGI), Regional 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. 4 From NYISO (2005), p. 35. A comprehensive transmission reliability analysis is far more complex, as discussed in the Draft Report. Such comprehensive reliability analysis considers many more factors, and can include dynamic (time-dependent) simulations. For very complex systems therefore, such comprehensive dynamic transmission analysis requires massive 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. 5 From NYISO (2005), pp. 37-38.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 assumption 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 system analysis provided the framework for the committee’s study, using the same reliability model. The NYISO results are in NYISO (2005).

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 International (GE) to run the Multi-Area Reliability Simulation (MARS) program. This model simulates, using a transportation model and Monte Carlo simulation, 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. The MARS software is the same system reliability screening tool approved by the New York State Reliability Council and used by NYISO in its Comprehensive Reliability Planning 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) program 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 Independent 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 entire interconnected system. MARS is a “transportation” model, commonly referred to as a “bubble and stick” model, connecting generation and loads in the grid—that is, connecting 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, recognizing both normal and security-related transmission constraints. 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 transmission constraints noted. MAPS calculates the annual variable operating cost (VOC) of producing electricity systemwide, 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 maintenance (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 Figure 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 scenarios thus provides a preliminary basis for comparing both reliability and trends of economic impacts among the illustrative scenarios posed by the committee. Note that the scenario analyses reported here are an early stage of analysis for hypothetical options. Additional analysis, using more sophisticated analytical tools, would be required to develop an optimized, defensible plan for Indian Point replacement options. Such an analysis was beyond the scope of the committee’s charge. NOTE: In this Appendix F-2 only, the “NYISO Initial Base Case” corresponds to “Base Case” in the draft NYISO Reliability Needs Assessment dated October 10, 2005. It assumes thermal transmission constraints control, and it employed the “Alternate New England Transmission Constraints” on the assumption that substantial loop flow of power into New England, then back into New York south of the Upstate New York/Southeast New York (UPNY/SENY) interface would be limited. The issue of what transmission constraints are appropriate has been appealed to the Federal Energy Regulatory Commission and the New York State Reliability Council by upstate power generators. The committee’s studies assumed the use of the “Alt. NE Transmission Constraints,” but the committee obviously 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. 1 Some perspective on how the variable cost of operation relates to the total cost of production of electricity is provided by comparing the contribution 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 operation—due mainly to the cost of fuel—are 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 additions 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs Perspectives on MARS and MAPS Simulations Since MAPS minimizes the projected systemwide operating 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 sensitivity study was made, using a 2008 natural gas price of $7.8/ MBtu (decreasing to $7.0 by 2015). In comparison, the Energy Information Administration (EIA) of the U.S. Department 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 introduced 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 premium of $1.11/MBtu (prices have subsequently dropped considerably). The consequences of high gas prices and volatility 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 recommended that readers should (1) appreciate that price assumptions 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 tendencies 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 system, allowing over the next 10 years for known scheduled retirements of generating capacity, and adding the firmly committed generation and transmission additions and upgrades that are projected to occur throughout the study period. The source for the data for the existing system was the MARS database maintained by NYISO staff for use in determining 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 criteria for inclusion in its Initial Base Case. Eleven additions to transmission capacity are included, all rather small with the exception of the Neptune transmission project, connecting the PJM Control Area to Long Island with a DC line of 600 MW capacity. Transmission operator (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 committee’s analyses, the units scheduled for retirement 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, several points should be kept in mind in reviewing results produced 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 regulations. Thus, some of the existing units may require future addition of emissions-control equipment, or face curtailment of operations, or may even be retired. 2 Base 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. 3 Retirements in the Initial Base Case do not include either Indian Point Unit 2 or Unit 3, but these possibilities are treated briefly in scenario analyses, subsequent to the NYISO Initial Base Case.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-1 NYISO Initial Base Case Capacity Details Adopted for the MARS Analysis Proposed Projects for Inclusion in Study Base Cases - Load Flow In-service MW Capacity Status CRPS ATBA ATRA CATR CRPS I. Generation Dates Summer Winter(**)   2010 2010 2010 2010 2015   A. Additions                       ConEd-East River Repowering I/S 298   I/S X X X X X     NY PA-Poletti Expansion 2006/01 500   UC X X X X X     SCS Energy-Astoria Energy 2006/04 500   UC X X X X X     PSEG-Bethlehem 2005/07 770 828 UC X X X X X     Calpine-Bethpage 3 2005/05 79.9   UC X X X X X     Pinelawn-Pinelawn Power 1 2005/05 79.9   UC X X 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 Ave2 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 X X     Entergy-Indian Point 3 Uprate I/S 1080   I/S X X X X X     Fortistar-VP 2007/Q2 79.9         X X       Fortistar-VAN 2007/Q2 79.9         X X       Key Span-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 X X     RG&E-Russell 2007/12 238 245   X X X X X     ConEd-Waterside 6,8,9 2005/07 167.2 167.8   X X X X X     PSEG-Albany 2005/02 312.3 364.6   X X X X X     NRG-Huntley 63,64 2005/11 60.6 96.8   X X X X X     NRG-Huntley 65,66 2006/11 166.8 170   X X X X X     Mirant-Lovett 5 2007/06 188.5 189.7   X X X X X     Mirant-Lovett 3,4 2008/06 242.5 244   X X 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 X X II. Transmission   Miles               A. Additions                   PSEG-Bergen (new)-W. 49th St.345kV Cable 2008 7.50       X X       AE Neptune PJM –LIDC Line (600 MW) 2007 65.00 UC X   X X X     LIP A-Duffy Convrtr Sta-Newbridge Rd. 345kV 2007/S 1.70 UC X   X X X     LIP A-Newbridge Rd. 345kV-138kV (2-Xfmrs) 2007/S N/A UC X   X X X     LIP A-E. Garden City-Newbridge Rd. 138kV 2007/S 4.00 UC X   X X X     LIP A-Ruland Rd.-Newbridge Rd. 138kV 2007/S 9.10 UC X   X X X     Rochester Transmission-Sta. 80 & various 2008/F N/A UC X X X X X     Liberty Radial Interconnection to NYC-230kV 2007 0.62       X X       ConEd-Dunwoodie-Sherman Crk 138kV 2005/W 7.80   X X X X X     LIP A-Riverhead-Canal(new) 138kV Operation 2005/S 16.40 UC X X X X X     LIP A-E. Garden City-Supr.Condr. Sub. 138kV 2006/S 0.38 UC X X X X X     LIP A-Northprt-Norwalk Hrbr. 138kVReplcmnt(2) 2006/S 11.00 UC X X X X X     ConEd-Mott Havn-Dunwoodie 345kV Rec.(2) 2007/S 9.99   X X X X X     ConEd-Mott Havn-Rainey 345kV Rec. (2) 2007/S 4.08   X X X X X     ConEd-Sherman Crk 345kV-138kV (2-Xfmrs) 2007/S N/A     X X X       ConEd-Sprin Brk-Sherman Crk 345kV 2007/S 10.00     X X X       LIP A- Holtsville GT-Brentwood 138kV (2) 2007/S 12.40 UC X X X X X     LIP A-Brentwood-Pilgram 138kV Operation 2007/S 4.60 UC X X X X X     LIP A-Sterling-Off Shore Wind Farm 138kV 2008/S 8.00                 O & R-Ramapo-Tallman 138kV Rec. 2007/S 3.24   X X X X X     O & R-Tallman-Burns 138kV 2007/S 6.08   X X X X X     LIP A-Riverhead-Canal 138kV 2010/S 16.40     X X X       CHG & E-Hurley Ave-Saugerties 115kV 2011/W 11.11                 CHG & E-Pleasant Valley-Knapps Corners115kV 2011/W 17.70                 CHG & E-Saugerties-North Catskill 115kV 2012/W 12.25                 Besicorp-Reynolds Rd. 345kV 2007/S 9.00       X X       Spagnoli Rd.-Ruland Rd. 138kV 2008/S 1.00       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.             SOURCE: NYISO (2005).

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 schedule for additions of new capacity could likely be relaxed somewhat through optimization studies beyond the scope of this committee’s 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 considerations 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 interpreting 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 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 1 1 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% 8% 7% *Capacity based on Summer Capability 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).

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs the late years. Also, a detailed model of all Northeast regional generating and transmission capacity does not now exist and is a goal of a regional planning task force. Providing the capability to project to 2015 would be an added challenge if the regional capacity were to be examined. The scenarios considered in this study add considerable new NYCA generation based on modern gas-fired combined-cycle units that have a low heat rate, thus require less natural gas per megawatt-hour (MWh) produced, and consequently result in lower operating costs. However, no assumption is made in the MAPS database used regarding comparable 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 generation in other areas. This might tend to lower the price-increase impact of retiring Indian Point, and could reduce imports 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 Valley). 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 substantially 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 demand reduction (270 MW) sum to only 1,820 MW over the same period. Additions to capacity or load reduction therefore 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 system requirements for future years. Throughout this study, the committee used Alternative New England Transmission Transfer Limits developed by NYISO (2005). Consequently the committee’s projections of resources needed to correct reliability to meet the LOLE standard of 0.1 are slightly higher than NYISO’s, perhaps by 200 MW.4 Readers therefore should bear in mind that, while comparisons 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 tabulations 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 recommended 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 capacity—or a correspondingly higher aggregate mix of additional generating capacity, additions to transmission capacity, and/or energy-efficiency and demand-reduction measures. In the committee’s opinion, the essential local corrections to reactive power—on the order of 2,000 Mvar in the Lower Hudson Valley—would most likely be made in a timely manner. Corrections to reactive power are less costly than additions to generation, are often installable at existing substations, and require less lead time because of lower mechanical 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 committee therefore focused on situations where thermal transmission 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. O’Neill (2004) provided a recent briefing 4 The committee saw no need to make the analyses agree perfectly, recognizing they are preliminary. Much refinement and additional analysis will be required to fully understand the implications of retiring Indian Point.

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 condenser 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 percent or so of the cost of replacing 1 MW of real power. It might be possible to use the existing generators at Indian 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 reactive 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 O’Neill (2004). Replacing the 1,000 Mvar of reactive 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 committee’s initial reliability analysis was intended to scope the amount of compensation that would be necessary 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 committee’s preliminary screening case included 150 MW of additional energy-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 additions somewhat arbitrarily to meet 2010 or 2015 objectives. 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 reactivated, or others proposed later. In sum, the committee’s screening analysis showed first that, with the additional compensatory resource capacity assumed, 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 analysis 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 scenarios examined during this study. The tables provide sufficient numerical detail to provide insight into the changes by geographic region, and the compensatory resources introduced, given each of the scenarios adopted by the committee. 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 Case—Qualifying Additions to Capacity (MW) Year Qualifying Additions to Capacity (Zone, MW) Zone G Zone H Zone I Zone J Zone K Rest of State (ROS) Yearly Total (MW) 2005 ConEd East River Repowering (J, 298, in service); Astoria Energy (J, 500); Calpine Bethpage 3 (K, 79.9); Pinelawn Power I (K, 79.9); PSEG Bethlehem (ROS, 770)       798 160 770 1,728 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-4 Committee’s Screening Study—Early Shutdown with Assumed Compensation from Planned NYCA Projects and Added Energy-Efficiency and Demand-Side-Management Measures (MW) Year Qualifying Additions to Capacity (Zone, MW) Zone G Zone H Zone I Zone J Zone K Rest of State Statewide EE and DSM Measures Yearly Total, MW Cumulative Additions Beyond NYISO Initial Base Case Cumulative Additions from 2005 2005 ConEd East River Repowering (J, 298, in service); Astoria Energy (J, 500); Calpine Bethpage 3 (K, 79.9); Pinelawn Power I (K, 79.9); PSEG Bethlehem (ROS, 770)       798 160 770   1,728     2006 NYPA Poletti Expansion (J, 500)       500       500     2007 Neptune HVDC Cable (PJM to K, 600)         600   150 750 150 2,978 2008 Reliant Astoria Repowering I (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)       1,040 533   150 1,723 1,873 4,701 2009                 0 1,873 4,701 2010 Calpine Wawayanda (G, 540); Mirant Bowline Point 3 (G, 750); EE (250); DSM (100) 1,290           350 1,640 3,513 6,341 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 Year Reference Case—Illustrative Additions (Zone, MW) Zone G, MW Zone H, MW Zone I, MW Zone J, MW Zone K, MW Rest of State (ROS) Yearly Generating Capacity Added Cumulative Additions Above CRPP, Initial Base Case (MW) NYCA LOLE, Reference Case LOLE for Early Shutdown (2008, 2010), No Further Compensation, Case b1 LOLE for EOL Shutdown (2013, 2015), No Further Compensation, Case c1 2008 SCS Astoria Energy (J, 500); Caithness (K, 383); Long Island Wind (K, 150 MW)       500 398   898 898 0.021 0.104 0.021 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 Combined Cycle (H, 580) 540 580         1,120 2,768 0.104 1.323 0.333 2014               0 2,768       2015 Reliant Astoria Repower I (J, 367); Reliant Astoria Repower II (J, 173)       540     540 3,308 0.102 1.480 1.480 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-10 Early Shutdown of Indian Point with Compensatory Resources, Case b2 Year Capacity Additions (Zone, MW) Zone G, MW Zone H, MW Zone I, MW Zone J, MW Zone K, MW Rest of State (ROS) Total for year, MW Capacity Above CRPP, Initial Base Case, MW Energy Efficiency, MW Demand Side Management, MW Cumulative Peak Demand Reduction, MW Cumulative Resources, Capacity + Load Reduction, MW NYCA LOLE After Compensation 2007                   100 50       2008 Reference Case plus Reliant Astoria Repower I&II (J, 540)       1,040 398   1,438 1,438 100 50 291 1,729 0.023 2009               0 1,438           2010 Bowline (G, 750); Wawayanda (G, 540); Transgas Energy(J, 1100) 1,290     1,100     2,390 3,828 250 100 632 4,460 0.011 2011               0 3,828           2012               0 3,828           2013 Generic Combined Cycle (H, 580)   580         580 4,408 75 75 778 5,186 0.032 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        

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-11 End-of-Current-License Shutdown of Indian Point with Compensatory Resources, Case c2 Year Capacity Additions (Zone, MW) Zone G, MW Zone H, MW Zone I, MW Zone J, MW Zone K, MW Rest of State (ROS) Total for year, MW Capacity Above CRPP, Initial Base Case, MW Energy Efficiency, MW Demand Side Management, MW Cumulative Peak Demand Reduction, MW Cumulative Resources, Capacity + Load Reduction, MW NYCA LOLE After 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 (J, 367); Bowline (G, 750); Wawayanda (G, 540) 1,290     367     1,657 2,555 250 100 632 3,187 0.006 2011 Reliant Astoria Repower II (J, 173)       173     173 2,728       2,728   2012               0 2,728       2,728   2013 Generic Combined Cycle (H, 580)   580         580 3,308 75 75 778 4,086 0.036 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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-12 Early Shutdown of Indian Point with High-Voltage Direct Current (HVDC) Cable, Case b3 Year Capacity Additions (Zone, MW) Zone G, MW Zone H, MW Zone I, MW Zone J, MW Zone K, MW Rest of State (ROS) Yearly Total, MW Capacity Above CRPP, Initial Base Case, MW Energy Efficiency, MW Demand Side Management, MW Cumulative Peak Demand Reduction, MW Cumulative Resources, Capacity + Load Reduction, MW NYCA LOLE After 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), Wawayanda (G, 540), Transgas Energy (J, 300) 1,290     300     1,590 3,028 250 100 632 3,660   2011               0 3,028           2012 1000 MW HVDC Line, Zone E to G 1,000           1,000 4,028           2013 Generic Combined Cycle (H, 580)   580         580 4,608 75 75 778 5,386   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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-13 End-of-Current-License Shutdown of Indian Point with Compensatory Resources Including 1,000 MW HVDC Transmission Lines, Case c3 Year Capacity Additions (Zone, MW) Zone G, MW Zone H, MW Zone I, MW Zone J, MW Zone K, MW ROS Yearly Total, MW Capacity Above CRPP, Initial Base Case, MW Energy Efficiency, MW Demand Side Management, MW Cumulative Peak Load Reduction, MW Cumulative Resources, Capacity + Load Reduction, MW NYCA LOLE After 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 (J, 367); Bowline Point (G, 750); Wawayanda (G, 540) 1,290     367     1,657 1,657 250 100 632 2,289   2011 Reliant Astoria Repower II (J, 173)       173     173 1,830           2012 1000 MW HVDC Line, Zone E to Zone G 1,000           1,000 2,830           2013 Generic Combined Cycle (H, 580)   580         580 3,410 75 75 778 4,188   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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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-14 Early Shutdown of Indian Point with Higher Efficiency and Demand-Side Management, Case b4 Year Capacity Additions (Zone, MW) Zone G, MW Zone H, MW Zone I, MW Zone J, MW Zone K, MW ROS Yearly Total, MW Capacity Above CRPP, Initial Base Case, MW Energy Efficiency, MW Demand Side Management, MW Cumulative Peak Load Reduction EE/DSM, MW Cumulative Resources, Capacity + Load Reduction, MW NYCA LOLE After Compensation 2007                             2008 Reference Case plus Reliant Astoria Repower I&II (J, 540)       1,040 398   1,438 1,438         — 2009               0 1,438         — 2010 Bowline Point (G, 750); Wayawanda (G, 540) 1,290           1,290 2,728         — 2011               0 2,728         — 2012               0 2,728         — 2013 Generic Combined Cycle (H, 580)   580         580 3,308         — 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). Reference Case b4 Savings 2008 33,330 2010 34,200 2013 35,180 2015 35,670 33,719 1,951

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-15 End-of-Current-License Shutdown of Indian Point with Higher Efficiency and Demand-Side Management, Case c4 Year Capacity Additions (Zone, MW) Zone G, MW Zone H, MW Zone I, MW Zone J, MW Zone K, MW ROS Yearly Total, MW Capacity Above CRPP, Initial Base Case, MW Energy Efficiency, MW Demand Side Management, MW Cumulative Peak Load Reduction EE/DSM, MW Cumulative Resources, Capacity + Load Reduction, MW NYCA LOLE After Compensation 2007                             2008 Same as Reference Case       500 398   898 898       898   2009               0 898           2010 Reliant Astoria Repower I (J, 367); Bowline Point (G, 750); Wayawanda (G, 540) 1,290     367     1,657 2,555       2,555   2011 Reliant Astoria Repower II (J, 173)       173     173 2,728           2012               0 2,728           2013 Generic Combined Cycle (H, 580)   580         580 3,308       3,308   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). Reference Case c4 Savings 2008 33,330 2010 34,200 2013 35,180 2015 35,670 33,719 1,951

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-16 Early Shutdown Without Compensatory Resources Beyond the Reference Case—Impact 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% 11% 11% NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables—990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appendix B. SOURCE: Hinkle et al. (2005). TABLE F-2-17 End-of-Current-License Shutdown Without Compensatory Resources Beyond the Reference Case—Impact 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 Cables—990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appendix B. SOURCE: Hinkle et al. (2005). TABLE F-2-18 Committee’s Reference Case—Impact 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% 16% 16% NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables—990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appendix B. SOURCE: Hinkle et al. (2005). TABLE F-2-19 Early Shutdown with Additional Compensatory Resources—Impact 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 Cables—990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appendix B. SOURCE: Hinkle et al. (2005).

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs TABLE F-2-20 End-of-Current-License Shutdown with Additional Compensatory Resources—Impact 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 Cables—990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appendix B. SOURCE: Hinkle et al. (2005). TABLE F-2-21 Additional Compensatory Resources, Including 1,000 MW North-South HVDC Transmission Line—Impact on NYCA Reliability and Reserve Margin, Cases b3 and c3 Zone Case b3 2015 Case c3 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% 14% NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables—990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appendix B. SOURCE: Hinkle et al. (2005). TABLE F-2-22 Additional Compensatory Resources, Including Higher Energy Efficiency and Demand-Side-Management Penetration—Impact on NYCA Reliability and Reserve Margin, Cases b4 and c4 Zone Case b4 2015 Case c4 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% 17% NOTE: LOLEs were calculated using SCRs (975 MW) and UDRs (HVDC Cables—990 MW). NYCA Reserve Margin reported includes SCRs, but not UDRs. For zones see Table F-2-7. Abbreviations are defined in Appendix B. SOURCE: Hinkle et al. (2005).

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs 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 ($ millions) 2010 ($ millions) 2013 ($ millions) 2015 ($ millions) 2008 (%) 2010 (%) 2013 (%) 2015 (%) 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 Prices—Reference 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 Prices—Early 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 Prices—End-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 0         Zone J 1,531 1,301 1,622 2,374 39.9 18.9 48.2 117.0 Zone K 479 352 467 644 46.6 7.7 42.8 96.8

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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs   Annual Cost of Operation Change from 2008 NYISO Initial Base Case   2008 ($ millions) 2010 ($ millions) 2013 ($ millions) 2015 ($ millions) 2008 (%) 2010 (%) 2013 (%) 2015 (%) 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 Cables—990 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). 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 Research 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. O’Neill, Richard. 2004. “Reactive Power: Is it Real? Is It in the Ether?” Paper presented at the Harvard Electric Policy Group, Austin, Tex., December 2.