ML11348A160

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New York State (NYS) Pre-Filed Hearing Exhibit NYS000056, Indian Point Retirement Options, Replacement Generation, Decommissioning/Spent Fuel Issues, and Local Economic/Rate Impacts, Prepared for the County of Westchester and the County of
ML11348A160
Person / Time
Site: Indian Point  Entergy icon.png
Issue date: 06/09/2005
From:
Levitan & Associates
To:
Atomic Safety and Licensing Board Panel
SECY RAS
Shared Package
ML11348A126 List:
References
RAS 21536, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
Download: ML11348A160 (233)
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Text

NYS000056 Submitted: December 14, 2011 Inilian Point Retirement Options, ReplacememGeneraJion, DecommissioninglSpentFuelIssues, and Locnl EC01Wmic I Rnte Impacts OAGI0000197_001

M!\RKET DESIGN ECONOMICS AND rOWER SYSTeMS June 9, 2005 County Executive Andrew 1. Spano Michaelian Office Building 148 Martine Avenue

\Vhite Plains, NY 10601 Re: Indian Point Retirement Options and Associated Issues I Impacts

Dear County Executive Spano,

Levitan & Associates, Inc. is pleased to provide the County of Westchester and the County of Westchester Public Utility Service Agency vvith this report that identifies retirement options for the Indian Point Energy Center. Our report covers the legal and regulatory background of acquisition through condemnation, likely sources of replacement power and the associated rate impacts, decommissioning and spent fuel management issues, economic impacts of retirement, and estimated compensation amounts that could be due Entergy under an acquisition scenario or through a consensual agreement for a voluntarily shutdo\VJl. Our scope of work did not include quantifYing the broad array of safety and homeland security issues that have the potential to impact the value of Indian Point.

Despite having fewer years of operation left under its existing operating licenses, Indian Point's value has increased since Entergy purchased the units in 2000 and 2001. The increased value is due to improved performance, higher market prices for its energy output, and the opportunity to extend its licenses for an additional hventy years. License extension, however, vviil be expensive and risky. In order to extend its operating licenses, Indian Point vvill have to convert to a closed-cycle system using cooling towers that vvill avoid hanning Hudson River fish stocks, but vviil reduce plant performance and require a nine-month shutdo\VJl. Other repairs and improvements would be expected to bring the total cost of license extension to approximately $1 billion. Although our analysis indicates that this cost would be oUhveighed by the earnings from operating an additional hventy years, voluntary retirement may be a viable option. Local, state, and federal stakeholders should cooperate to provide Entergy with sufficient compensation and encourage on-site replacement generation that could mitigate the impacts that retirement will have on the local economy.

If an agreement to retire Indian Point were armounced at least three-to-four years in advance, we expect that market prices, possibly bolstered by downstate utility actions, would encourage sufficient replacement generation. System reliability objectives would be safeguarded and market capacity prices would be virtually unchanged, provided such replacement generation was commercialized on a timely basis. However, if the hvo Indian Point units were retired before the licenses expired in 2013 and 2015, we expect market OAGI0000197_002

County Executive Andrew J Spano June 9, 2005 Page 2 of3 energy prices to increase. The typical Westchester residential bill would increase by

$l.55/month based on standard New York Public Service Commission consumption data.

Ratepayers in New York City, Long Island, and the Albany area would see smaller increases, while residents in the western part of the State would be relatively unaffected. Early retirement would also cause power plant air emissions to increase. We were not asked to investigate how cost-effective conservation, load management, distributed generation, and renewable energy sources could replace Indian Point or mitigate these rate impacts.

Retirement, whenever it occurs, will inevitably impose local impacts due to reductions in property tax payments, employment, and local spending on goods and services. The Hendrick Hudson School District receives over 80% of those property tax payments, about one-third of its annual revenues. Many adverse impacts would not materialize until five-to-ten years, as employment and local spending would continue during decommissioning and spent fuel activities. On the positive side, retirement would improve the health of the Hudson River fisheries and provide public safety and homeland security benefits. While the preferred way to avoid or mitigate the local impacts would be to promote the development of on-site replacement generation, license extension, with the attendant construction of cooling towers, would almost certainly preclude that option.

If Indian Point was acquired through condemnation, Entergy would be entitled to just and reasonable compensation. We estimate such compensation to range from $l.8 billion to $2.7 billion, assuming a two-to-three year condemnation process beginning in 2005. Acquisition would also saddle the condemnor with $241 million of spent nuclear fuel costs and nuclear decommissioning risks. However, the high cost oflicense extension presents a window of opportunity. Since we estimate that cooling tower construction will take about three years, a consensual agreement reached before 2011 would allow Entergy to avoid the high incremental capital outlays yet continue to operate Indian Point through the end of the license terms. Compensation in this scenario would range from $0.5 billion to $1.4 billion, much less than the condemnation scenario.

The compensation estimates assumes that the U.S. Nuclear Regulatory Commission would approve license extension. Any risk of license extension would lower our dollar estimates. In either case the County could, in theory, fund its share of any compensation payment through General Obligations Bonds that would require a public referendum. We caution that a large bond issuance has the potential to impair the County's high credit rating and would have to satisfy municipal finance regulations.

For these reasons, retiring Indian Point will require a combined local, state, and federal effort that balances the rights of the plant owner with the public's mandate for security. A replacement gas-fired plant at the site is feasible and would offer advantages to all of the stakeholders. New York State, perhaps through the New York Power Authority, could support negotiations with Entergy and contribute to any arrangement for compensation and replacement generation.

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County Executive Andrew 1. Spano June 9, 2005 Page 3 of3 Levitan & Associates, Inc. greatly appreciates the opportunity to have assisted Westchester and the COllllty of Westchester Public Utility Service Agency. On behalf of the entire project team, we thank you for the privilege of this engagement.

Sincerely yours, Seth G. Parker Vice President & Partner OAGI0000197 004

TABLE OF CONTENTS Executive Summary Report

1. Plant Background and Performance 1.1. Plant History ................................................................................................................... 1 1.2. Entergy Business Segments ............................................................................................ 2 1.3. Pressurized Water Reactors ............................................................................................ 2 1.4. Plant Performance ........................................................................................................... 4 1.5. Capacity Rating ............................................................................................................... 4 1.6. Capacity Factor ............................................................................................................ ... 5 1.7. Operating Life ............................................................................................................... 10
2. Legal and Regulatory Issues 2.1. Introduction ................................................................................................................... 11 2.2. Eminent Domain Laws .................................................................................................. 11 2.3. Eminent Domain Process .............................................................................................. 13 2.4. Compensation under New York Law ............................................................................ 16 2.5. Westchester County Laws and Regulations .................................................................. 18 2.6. County of Westchester Public Utility Service Agency ................................................. 19 2.7. Tax-Exempt Financing .................................................................................................. 20 2.8. Nuclear Regulatory Commission Regulations .............................................................. 23
3. Replacement Generation 3.1. Introduction ................................................................................................................... 30 3.2. Base Case with Retirement in 2013/2015 .............................................. ....................... 31 3.3. License Extension Case with Retirement in 2033/35 ................................................... 31 3.4. Immediate Retirement without Market Response ......................................................... 32 3.5. Planned Retirement with Market Generation Response ............................................... 32 3.6. Retirement with Market Transmission Response ......................................................... 34 3.7. Entergy Gas-Fired Replacement Generation at IP Site ................................................. 38 3.8. Conversion of IP to Natural Gas ................................................................................... 42 3.9. Alternative Energy Sources .......................................................................................... 43 3.10. County / Cowpusa Alternatives .................................................................................. 43
4. Plant Valuation 4.1. Introduction ................................................................................................ ................... 45 4.2. Cost Approach ............................................................................................................... 45 4.3. Comparable Sales Approach ......................................................................................... 48 4.4. Earnings Approach ........................................................................................................ 51 4.5. Revenues ....................................................................................................................... 51 4.6. Operating Expenses ....................................................................................................... 56 4.7. Discount Rate ................................................................................................................ 68 4.8. Valuation / Compensation Results ................................................................................ 77
5. Decommissioning and Spent Nuclear Fuel 5.1. Decommissioning .......................................................................................................... 84 5.2. Indian Point Decommissioning ..................................................................................... 84 OAGI0000197_005

5.3. Decommissioning Funding ........................................................................................... 86 5.4. Current Challenges ........................................................................................................ 89 5.5. Decommissioning Funding Status ofIP ........................................................................ 90 5.6. Spent Nuclear Fuel Management .................................................................................. 92

6. Economic and Rate Impacts 6.1. Economic Impacts ....................................................................................................... 100 6.2. Economic Multipliers .................................................................................................. 100 6.3. Property Taxes and Property Values ........................................................................... 101 6.4. Employment and Employee Compensation ................................................................ 104 6.5. Payroll and Corporate Income Taxes .......................................................................... lOS 6.6. Local Spending on Goods and Services ...................................................................... 106 6.7. Market Electricity Prices ............................................................................................. 107 6.8. Local Community Support .......................................................................................... 109 6.9. County Emergency Planning ...................................................................................... 110 6.10. Fishery Impacts ......................................................................................................... 110 6.11. Air Emissions ............................................................................................................ 113 6.12. Total Economic Impact ............................................................................................. liS 6.13. Total Costs and Rate / Economic Impacts ................................................................ 119 6.14. Rate Impacts .............................................................................................................. 121 List of Attachments:
1. Performance Effects of Cooling Towers
2. New York Eminent Domain Process Timeline
3. Chapter 875 of the Westchester County Charter
4. Entergy Zoning Variance
5. Time for a New Start for U.S. Nuclear Energy?
6. Evaluating Risks Associated With Unregulated Nuclear Power Generation
7. Triggering Nuclear Development
8. The Business Case for Building a New Nuclear Plant in the U.S.
9. Report of Bodington & Company regarding Discount Rate
10. Fair Market Value Calculations II. GAO Report: Nuclear Regulation (Excerpt)

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LIST OF FIGURES Figure 1 - Diagram of Pressurized Water Reactor .................................................................... 3 Figure 2 - Location of Replacement Generation by County and Zone ................................... 34 Figure 3 - New York Zones and Transmission Pathways ....................................................... 35 Figure 4 - Nuclear Plant Sales - Plant Size and Purchase Price ............................................. 50 Figure 5 - Nuclear Plant Sales - Transaction Date and Price ................................................. 51 Figure 6 - Base Case (Retirement in 2013/15) Forecast of Market Energy Prices ................. 53 Figure 7 - Base Case (Retirement in 2013115) Forecast of Market Capacity Prices ............... 54 Figure 8 - Life Extension Case Revenue Forecast w/ 20-year License Extension .................. 55 Figure 9 - Estimated Base Case (Retirement in 2013/15) Operating Expenses ...................... 56 Figure 10 - Industry Average Non-Fuel O&M Costs (1981-2003) ......................................... 60 Figure 11 - Industry Average Fuel Costs (1981-2003) ........................................................... 62 Figure 12 - Schematic Diagram ofIP2 Spent Fuel Pool ......................................................... 64 Figure 13 - Example of Reactor Vessel Head Cracking .......................................................... 65 Figure 14 - Original License Term EBITDA .......................................................................... 78 Figure 15 - License Renewal Term EBITDA. ......................................................................... 79 Figure 16 - Annual Net Cash Flow ForecasL ......................................................................... 80 Figure 17 - IP2&3 FMV vs. Transaction year ........................................................................ 81 Figure 18 - Holtec HI-STORM Storage System ..................................................................... 95 Figure 19 - Dry Runs at the FitzPatrick Plant Prior to Actual Loading .................................. 96 Figure 20 - Compact Spacing of HI-STORMs at the FitzPatrick ISFSI ................................. 97 Figure 21 - Yucca Mountain ................................................................................................... 98 Figure 22 - Base Case (Retirement in 2013/15) IP Employment .......................................... 104 Figure 23 - IP2&3 Employment Comparison of Retirement Scenarios ................................ 105 Figure 24 - New York Income Tax ....................................................................................... 106 Figure 25 - Change in County Electricity Costs by Scenario ................................................ 108 Figure 26 - Change in State Electricity Costs by Scenario ................................................... 109 Figure 27 - NOx Emissions Under Base Case and License Extension Scenarios ................. 114 Figure 28 - Total Economic Impact to the County by Scenario ............................................ 118 Figure 29 - Total Economic Impact to the State by Scenario ................................................ 118 Figure 30 - Forecast of Market Energy Prices in Westchester. ............................................. 125 Figure 31- Comparison of Residential Bills by Scenario: 2005,2008 ................................. 126 Figure 32 - Long-Term Trends of Monthly Bills by Scenario .............................................. 126 OAGI0000197_007

LIST OF TABLES Table I - 2004 Net Capacity Ratings ........................................................................................ 4 Table 2 - Changes in Net Capacity Ratings ............................................................................... 5 Table 3 - Reported Capacity Factors ......................................................................................... 6 Table 4 - Historical Nuclear Industry Capacity Factors ............................................................ 7 Table 5 - Historical Capacity Factors (%) for Entergy Utility Nuclear Plants .......................... 8 Table 6 - Sources of Tax-Exempt Financing ........................................................................... 23 Table 7 - Nuclear License Transfers ....................................................................................... 24 Table 8 - Nuclear Plant License Extensions ............................................................................ 26 Table 9 - Indian Point Purchase Prices .................................................................................... 47 Table 10 - Cost-Based Valuation ............................................................................................ 48 Table 11 - Base Case (Retirement in 2013/15) Energy and Capacity Revenues .................... 55 Table 12 - Estimated Personnel Levels and Expenses with 2013115 Retirement ................... 58 Table 13 - Estimated Breakdown ofIP Maintenance Expenses .............................................. 59 Table 14 - Estimated Non-Fuel O&M Expenditures ............................................................... 60 Table 15 - Market Values ofCL&P's Nuclear Assets ............................................................ 73 Table 16 - 2003 Key Indicators of Entergy's Business Segments .......................................... 75 Table 17 - Reported Profitability of Non-Utility Nuclear Business Segment ......................... 76 Table 18 - Estimated Profitability of Entergy Non-Utility Nuclear Business Segment .......... 77 Table 19 - Selected Case Valuations - Acquisition by Condemnation ................................... 82 Table 20 - Compensation for Voluntary Retirement Cases ..................................................... 83 Table 21 - Decommissioned Commercial Nuclear Plants ....................................................... 88 Table 22 - Decommissioning Cost and Fund Status ............................................................... 90 Table 23 - GAO Analysis of Decommissioning Funds ........................................................... 91 Table 24 - Combined IP2&3 PILOT Schedule ..................................................................... 102 Table 25 - Direct and Total Economic Impact of Lost PILOT ............................................. 103 Table 26 - Entergy Local Spending in 2002 .......................................................................... 107 Table 27 - Fish Mortality and Valuation ............................................................................... 112 Table 28 - Fish Mortality Valuation - Allocation to County and State ................................ ll2 Table 29 - Indicative New York State Air Emissions Impacts ............................................. ll4 Table 30 - Total Economic Impact to County by Scenario for Selected Years .................... ll6 Table 31 - Total Economic Impact to State by Scenario for Selected Years ........................ ll6 Table 32 - Direct and Total Costs - 2008 Acquisition by Condenmation ............................ ll9 Table 33 - Direct and Total County Impacts - 2008 Acquisition by Condenmation ............ 120 Table 34 - Direct & Total State Impacts - 2008 Acquisition by Condemnation .................. 120 Table 35 - Total Direct and Indirect County Costs - 2013115 Voluntary Retirement .......... 121 Table 36 - 2004 Monthly Con Edison Westchester Electric Bills ........................................ 122 Table 37 - Average Change in Market Energy Prices ........................................................... 124 OAGI0000197_008

GLOSSARY AND ACRONYMS alc - Alternating Current Algonquin - Algonquin Gas Transmission ANOl&AN02 - Arkansas Nuclear Units 1&2 BWR - Boiling Water Reactor CapEx - Capital Expenditures CAPM - Capital Asset Pricing Model CFR - Code of Federal Regulations CL&P - Connecticut Light and Power CO 2 - Carbon Dioxide Con Edison - Consolidated Edison Company of New York, Inc.

COWPUSA - County of Westchester Public Utility Service Agency CTA - Competitive Transition Assessment dlc - Direct Current DCF - Discounted Cash Flow DEC - N. Y. Department of Environmental Conservation DECON - Radioactive materials are removed or decontaminated DOE - U.S. Department of Energy DPUC - Connecticut Department of Public Utility Control EBITDA - Earnings Before Interest, Taxes, Depreciation, and Amortization EDPL - Eminent Domain Procedure Law EIA - U.S. Energy Information Agency Entergy - Entergy Corporation ENTOMB - Radioactive materials are encased and maintained I monitored.

EPA - U.S. Environmental Protection Agency FEIS - Final Environmental Impact Statement FMV - F air Market Value GAO - U.S. Government Accountability Office GGNS - Grand Gulf Nuclear Station GO - General Obligation (County tax-exempt bonds)

GTCC - Greater Than Class C (nuclear waste)

IP - Indian Point Energy Center IPI - Indian Point Unit 1 IP2 - Indian Point Unit 2 IP3 - Indian Point Unit 3 IRR - Internal Rate of Return ISFSI - Independent Spent Fuel Storage Installation ISO-NE - Independent System Operator-New England ktons - Thousand Tons kWh - Kilowatt-Hour (a measure of energy)

LLC - Limited Liability Corporations MAC - Monthly Adjustment Charge (charged by Con Edison)

MPF - Market Price Forecast MW - Megawatt (a measure of capacity; equivalent to 1,000 kW)

MWth - Megawatt of thermal energy (1 MWth can generate approximately 0.3 MW)

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MWh - Megawatt-hour (equivalent to 1,000 kWh)

NEI - Nuclear Energy Institute NOx - Nitrogen Oxides NPDES - National Pollutant Discharge Elimination System NRC - u.s. Nuclear Regulatory Commission NYISO - New York Independent System Operator NYPA - New York Power Authority NYPSC - New York Public Service Commission NYSERDA - New York State Energy Research and Development Authority O&M - Operations and Maintenance ORPS - New York Office of Real Property Services PASNY - Power Authority of the State of New York PILOT - Payment in Lieu of Tax PJM - Pennsylvania-New Jersey-Maryland Interconnection PPA - Power Purchase Agreement PWR - Pressurized Water Reactor PWSCC - Primary Water Stress Corrosion Cracking RB -River Bend RFP - Request for Proposal RG&E - Rochester Gas & Electric, part of Energy East Corporation ROE - Return on Equity ROlC - Return on Invested Capital RPV - Reactor Pressure Vessel SAFSTOR - Nuclear facility is maintained / monitored to allow radioactivity to decay S&P - Standard & Poor's SEC - U.S. Securities and Exchange Commission SEQR - State Environmental Quality Review SNF - Spent Nuclear Fuel S02 - Sulfur Dioxide SPDES - State Pollution Discharge Elimination System TMI - Three Mile Island U-235 - Uranium 235 U-238 - Uranium 238 W3 - Waterford 3 WACC - Weighted Average Cost of Capital WIDA - Westchester County Industrial Development Agency Zones A-E - Western and Northern New York Zone F - Capitol District Zones G,H,& I - Westchester and rest oflower Hudson River Valley Zone J - New York City Zone K - Long Island OAGI0000197_010

Limitation of Liability This report has been prepared for the County of Westchester and the County of Westchester Public Utility Service Agency for the sole purpose of evaluating economic, technical, and certain legal issues surrounding the operation and retirement of the Indian Point Energy Center. The findings and conclusions contained herein depend on the assumptions identified in this report. While Levitan & Associates, Inc. believes these assumptions to be reasonable, there is no assurance that any specific assumption will actually occur and we make no assurances except those explicitly set forth herein. Levitan &

Associates, Inc., the County of Westchester, and the County of Westchester Public Utility Service Agency do not make any warranty, expressed or implied, with respect to the use of information or methods disclosed in this report, and do not assume any liability with respect to the use of information or methods disclosed in this report.

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Executive Summary Introduction In June 2004, Levitan & Associates, Inc. (LAI), a Boston-based management consulting finn specializing in the energy industry, was retained by the County of Westchester (Westchester or the County) and the County of Westchester Public Utility Service Agency (COWPUSA) to evaluate economic, technical, and certain legal issues surrounding the operation and retirement of the Indian Point Energy Center (IP). Since 9/11, IP has been a lightning rod for safety and security concerns. In response to these concerns, the County has expressed an interest in assessing the feasibility of alternative options to facilitate IP's retirement. In conducting this analysis, LAI has been assisted by WPI, a nuclear advisory finn specializing in plant decommissioning, safety, and spent nuclear fuel (SNF) advisory services.

LAI has identified and evaluated two options for the County to facilitate IP's retirement:

acquire the plant by condemnation or reach a consensual agreement to voluntarily retire the plant with IP's owner, Entergy Corporation (Entergy). LAI assessed IP's current and expected perfonnance, estimated the economic impacts of retirement, identified the likely sources of replacement generation and impact on customer rates, calculated the compensation due Entergy, and described the requisite decommissioning and SNF activities. LAI's scope of work did not include the breadth of safety and homeland security issues associated with ongoing operation of IP, or the potential for alternative energy technologies to replace it.

Background

When the New York power market was deregulated in the late 1990s, utilities divested their power plant assets. Some power plants have power purchase agreements (PP As) with utilities and other load-serving entities that establish power quantities and prices. The majority of power plants in New York State are merchant plants that do not hold PPAs and compete to sell their output at market prices administered by the New York Independent System Operator (NYISO). Since wholesale power markets became competitive, Entergy has acquired various nuclear power plants in New York and New England, including IP.

There are three nuclear units at the IP site. Indian Point 1 (IP 1) and Indian Point 2 (IP2) were sold by Consolidated Edison Company of New York, Inc. (Con Edison) to Entergy in September 200l. IPI was deactivated in 1974, and will be decommissioned at a later date in conjunction with the decommissioning of IP2 and Indian Point 3 (IP3). Entergy purchased IP3 along with the FitzPatrick station from the New York Power Authority (NYPA) in November 2000. The nominal generation capacity of each IP unit is about 1,000 megawatts (MW). IP therefore represents about 5% of the total installed generation capacity throughout New York State. In tenns of energy output, IP2&3 collectively account for about 10% of New York's electricity requirements. IP2&3's Nuclear Regulatory Commission (NRC) operating licenses are scheduled to expire in 2013 and 2015, respectively. In accord with industry trends, Entergy could apply for license extensions for up to an additional twenty years, provided certain operating, enviromnental, and safety conditions are met.

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Entergy is a Louisiana-based integrated energy holding company with both utility and non-utility business segments. Entergy owns and operates five utility-owned and five non-utility nuclear power plants; the non-utility plants are located in New York and New England. Since Entergy acquired IP from Con Edison and NYP A, the units have operated at relatively high capacity factors. After Entergy completed the acquisitions, skyrocketing natural gas and oil prices have materially increased the market value of IP' s output. Average market energy prices in Westchester increased 26% from 2001 to 2004. Moreover, the outlook on premium fossil fuel prices, coupled with regulatory changes in New York promulgated by NYISO, portend continued pressure on market energy and capacity prices for the foreseeable future.

Thus the value of IP has improved since Entergy's acquisition. Against this backdrop, the County and COWPUSA have a limited number of strategic options to shut down IP.

Findings

  • There are two principal options to retire IP early - acquisition through condenmation or a consensual agreement with Entergy for a voluntary shutdown. Either option will require compensating Entergy for lost profits net of avoided costs and capital expenditures (CapEx). Condemnation would also involve the assumption of decommissioning and SNF responsibilities, as well as financial risks. Entergy would retain those responsibilities and risks under a consensual agreement.
  • A condenmation process is likely to take several years, depending on how quickly the condenmation was sought and whether Entergy contests the original compensation offer. If the condenmation was successful, Entergy would be entitled to just and reasonable compensation. For example, if the process started now and was completed by January 1,2008, we estimate that Entergy would have to be paid $1.4 - $l.8 billion in compensation for lost profits through the current license terms, plus $0.3 - $l.0 billion for the twenty year license extension period. While the decommissioning funds should be sufficient to cover decommissioning activities, the condemnor would become responsible for SNF costs that we estimate at approximately $241 million over the following six years.
  • Under a consensual agreement in which Entergy would voluntarily retire IP, Entergy would retain the responsibilities and risks of nuclear plant ownership. Entergy may be receptive, given the high cost (estimated at $1 billion), uncertain financial return, and likely political quagmire associated with operating beyond the current NRC license terms. Assuming a January 1, 2010 agreement 1 payment date and a 2013/15 retirement date, i.e. at the end of the existing license terms, we estimate the value of Entergy's lost profits to be $0.5 - $1.4 billion for the twenty year license extension period. These values do not account for any risk that the NRC could deny Entergy's request for license extension, which would lower our compensation estimates.
  • LAI estimated the ranges of compensation values under each option by forecasting IP revenues, expenses, and cash flow, then applying high and low discount rates that reflect the risks of a merchant nuclear plant. The wide range in compensation values is due to the high and low discount rates as well as the effect of compounding over 11 OAGI0000197_013

time. Any change in the payment dates assumed in the retirement options identified above would change our compensation estimates.

  • Condemnation of IP by the County is legally difficult and financially risky. On the other hand, a consensual agreement should be achievable and could involve other stakeholders such as the State of New York, NYPA, New York City, and other utility and government stakeholders. The challenge for a consensual agreement would be to convince Entergy to retire IP voluntarily and, ideally, develop replacement generation on the IP site.
  • Retirement of IP presents economic and rate impacts beyond compensation costs.

These impacts will inevitably occur whenever IP ceases operation, so the question is not whether there will be impacts from IP retirement; the question is when these impacts will occur. Many of these impacts could be avoided or mitigated by development of on-site replacement generation. Local impacts would include loss of payments in lieu of tax (PILOT), the bulk of which go to the Hendrick Hudson School District. Local employment and spending benefits would disappear about ten years after retirement, once the site is decommissioned and SNF is in dry storage. Local community support activities would cease, and power plant emissions would increase.

  • The largest quantifiable positive impact of retiring IP would be the improved health of the Hudson River fisheries, which would benefit residents beyond the local communities. These fisheries would also benefit if IP is converted to closed-cycle cooling, although Hudson River water may still be required for emergency cooling.

While retiring IP would result in public safety and security benefits, we have not tried to quantify those benefits. A minor benefit of retiring IP would be that the County could avoid emergency service costs.

  • The greatest negative impact of retiring IP before its license expires in 2013/15 would be a rise in market energy prices, even with the timely addition of replacement generation. We estimate that a minimum of three-to-four years is required from the time IP's retirement is announced to develop and construct new power plants.

Retirement through a consensual agreement with Entergy, or if Entergy was unable to extend the NRC licenses, should provide sufficient lead time to develop replacement generation on the IP site or elsewhere in the downstate region. In practice, lenders and investors are unlikely to rely on uncertain market prices to justify new merchant projects. Therefore downstate utilities might decide to offer PPAs to assure their customers of sufficient resources. It is not known how the New York Public Service Commission (NYPSC) would react to a new PP A commitment. If necessary, the NYISO or NYP A could make short-term arrangements to assure bulk power security.

  • Since Entergy has not yet filed an application with the NRC to renew IP's licenses, our working assumption has been that IP will be retired at the end of the existing license terms. Therefore a voluntary retirement on the same dates would impose virtually 111 OAGI0000197_014

identical economic and electric rate impacts on County and New York residents retirement in 2013115 would not impose any additional economic or rate impacts.

  • Extending the NRC licenses will likely cost Entergy over $1 billion, principally to convert from a once-through cooling system using the Hudson River to a closed-cycle system using cooling towers. Constructing the towers will require a local zoning variance, each IP unit would have to be shut down for roughly nine months for the conversion, and future plant performance would suffer. In spite of these hurdles, the economics of license extension appear favorable from Entergy's perspective, unless gas prices decline materially (thus lowering the value of IP output) or conversion costs are higher than expected. However, the significant costs and risks provide the County, State, NYP A, and other interested stakeholders a window of negotiating opportunity through about 2010, after which cooling tower construction would probably need to commence. We believe that the cooling towers would require considerable space on the IP site and preclude any chance for on-site replacement generation.
  • Converting the IP units to gas-fired generation is not feasible. However, the existing site is well-suited for new replacement gas-fired generation, particularly with the existing high-voltage transmission infrastructure and the Algonquin Gas Transmission (Algonquin) interstate natural gas pipeline adjacent to the site, provided that cooling towers for the nuclear units are not installed. It is not the County's legal responsibility to replace the generation capacity to maintain adequate reserve margins if IP were to retire. Nevertheless, on-site replacement generation has the potential to avoid or mitigate the costs and impacts of a voluntary retirement.
  • The development of on-site replacement generation could be facilitated through a variety of mechanisms. For example, surplus property on the site could be leased to a generation developer if Entergy itself did not want to develop a replacement plant.

Alternatively, the market risks of on-site replacement generation could be avoided through a PP A with a credit-worthy purchaser such as NYP A or others who can re-sell the power to retail customers. While COWPUSA has the authority to enter into a long-term PP A and provide retail service to Westchester residents, it does not have a large customer base and may not be able to effectively compete with Con Edison. A third mechanism, providing tax-exempt financing for an on-site replacement plant, may not be possible under current federal tax provisions, although Congress could adopt legislation that would make such an option possible.

  • SNF will be stored in specially-designed dry casks on-site starting next year. It is anticipated that the SNF will eventually be shipped to Yucca Mountain, the nation's planned SNF repository in Nevada. Entergy will have to bear the on-site SNF storage costs until then, and remove any non-radioactive materials. We estimate that it will take ten years after retirement until all SNF and radioactive materials could be removed, provided Yucca Mountain is opened in 2010 as planned. This date may slip due to recent licensing delays, which will require additional quantities of SNF to be stored on-site over a longer period of time.

IV OAGI0000197_015

  • Other radioactive materials will be stored on-site until a disposal site is licensed. The IP decommissioning funds should be adequate to cover decommissioning costs, assuming that the three IP units will be decommissioned in an integrated program.

Recommendation Acquiring IP through condemnation is not recommended because it would require assuming nuclear decommissioning and SNF management responsibilities, and is fraught with financial costs and risks that have the potential to impose material economic hardships. A consensual agreement is the better option, in which the County, together with other stakeholders such as the State, NYPA, and New York City, can muster political pressure to discourage relicensing and can negotiate and fund a financial compensation and replacement generation package.

The high CapEx associated with license extension, coupled with the potential uncertainties surrounding the NRC approval and local zoning process, offers a window of opportunity to negotiate a retirement date, perhaps at the end of the current NRC license terms. Reaching a consensual agreement no later than year-end 2010, with the support of the State and its Congressional delegation, would allow sufficient time for replacement generation to be developed, including on the IP site, by 2013/15. Other strategies to induce Entergy to retire IP early through State or federal action appear unprecedented, but are possible with State and Congressional support.

A consensual agreement to voluntarily retire IP would provide sufficient time to structure the best possible solution for Westchester residents. We recommend that a consensual agreement include on-site replacement generation to avoid or mitigate the costs and impacts of IP retirement. An on-site gas-fired combined cycle replacement plant, for example, would provide benefits to Entergy and the State as well. Entergy would have an attractive investment opportunity in New York, and State residents (outside of Westchester) would enjoy the bulk of the benefits from improving the health of the Hudson River fisheries. The State should participate in a consensual agreement and be part of the IP solution.

Acquisition by Condemnation The ability to acquire IP through a condemnation proceeding is based on principles of eminent domain. Our evaluation of applicable regulations indicates that this option is feasible but risky. In brief, the condemnor would have to conduct a public hearing, make a public determination to condemn and acquire the plant, offer a price based on a property appraisal, and then file a petition that is accepted by the Westchester Supreme Court. This option has some significant drawbacks and entails difficult ownership responsibilities:

  • If IP were immediately deactivated upon acquisition, the condemnor would have to obtain management expertise that satisfies stringent NRC standards to decommission the units and handle radioactive materials. SNF would remain on the site at least a decade, obligating the condemnor to provide appropriate security measures. The availability and cost of obtaining this nuclear expertise are highly uncertain.

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  • The existing decommissioning funds, designed to cover the costs to decommission the radioactive materials, should be adequate. However, there is no guarantee, and any shortfall would impose significant decommissioning costs on the condemnor. The funds do not cover the cost to store the SNF, or to remove non-radioactive materials.
  • Under New York law, Entergy would be entitled to just and reasonable compensation for the condemnation of IP. The compensation amount would be set by a court-ordered appraisal and reflect then-prevailing market, operating, and regulatory conditions, and therefore could be higher than our estimate.
  • The County or New York State could be the condenming authority, thereby assuming all attendant responsibilities and risks. Since retiring IP benefits State residents beyond Westchester County, it may make sense for NYPA to be responsible for decommissioning and SNF activities.

Present Value Summary - Acquisition in 2008 versus Retirement in 2013/15 (2008 $ millions; excludes indirect impacts; assumes no replacement generation)

Costs Shared by Stakeholders Entergy Compensation Original License Term $1,465 - $1,831 Renewal Option $ 289 - $ 913 Sub-Total $1,754 - $2,744 Spent Nuclear Fuel $ 241 Total $1,995 - $2,985 Rate 1 Economic hnpacts County New York State Electric Market Impact $ 216 $ 1,742 Economic Impacts (benefits in parenthesis)

Property Taxes $ 143 $ 143 Employment $ 123 $ 820 Local Spending $ 89 $ 341 Community Support $ 6 $ 6 County Emergency Planning ($ 35) ($ 35)

Corporate Income Tax $ 8 $ 167 Hudson River Fisheries ($ 220) ($ 2,198)

Air Emissions ~ ~

Sub-Total $ ll6 ($ 715)

Total $ 332 $ 1,027 For purposes of this analysis, we have assumed that condemnation proceedings would commence immediately, and IP would be acquired and shut down on January 1, 2008. Two types of costs arise under the acquisition option: (i) compensation due Entergy and taking on VI OAGI0000197_017

the SNF responsibilities, and (ii) electric rate and economic impacts. We estimate compensation due Entergy at $l.75 - $2.74 billion, plus the condemnor would become responsible for $241 million of SNF costs. We estimate the State-wide rate and economic impacts at $l.03 billion, of which the County would shoulder 21 %. All of these costs and impacts are expressed in present value terms as of January 1, 2008, as itemized in the summary tables above, and are relative to our base case assumption of IP retirement in 2013/15 at the end of the existing license terms.

  • The largest cost component is compensation due Entergy. LAI provided a low and high range of compensation values due to uncertainty about a key valuation assumption, the appropriate discount rate for Entergy' s future revenues from IP2&3.

The low end of the compensation range, $l.75 billion, is associated with a high discount rate of 20%, the high end of our estimate of Entergy' s cost of funds (combined debt and equity) for a merchant nuclear power facility. The high end of the compensation range, $2.74 billion, is associated with a low discount rate of 14%, the low end of our estimate of Entergy's cost of funds. We assumed that Entergy would receive full credit for lost earnings over the license extension period. Any risk that the NRC would not approve license extension would lower the estimated value for the license extension period. Ideally, the County could participate jointly with the State, NYPA, New York City, and other stakeholders, in the acquisition and compensation arrangement.

  • The condemnor would incur SNF costs, estimated at $241 million. The eXlstmg decommissioning funds should be adequate to cover all decommissioning costs.
  • The present value of the electric market impact on the County is estimated at $216 million, and $l. 74 billion for the entire State. Estimated rate impacts reflect our assumption that long-term utility PP As provide a 50% hedge against higher market energy prices. Typical residential bills in Westchester would increase $l.55/month if IP retires before 2013/15, and by about $0.73/month in New York City.
  • Total direct economic impacts (excluding electricity prices) are estimated to have a negative present value of $116 million for the County and a positive present value of

$715 million for the entire State as follows:

Lost PILOT revenues from 2008 through 2015 would total $143 million for the County; the rest of the State would not be directly affected.

Significant manpower would be required at the site for decommissioning and SNF activities, so that reduced employment and local spending would not affect the County for five-to-ten years. The present value of lost wages would total $123 million in the County and $820 million in the entire State.

Reduced local spending on goods and services would total $89 million in the County and $341 million in the entire State.

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Reduced local community support, e.g. monetary contributions and employee volunteer efforts, would total $6 million in the County and would not affect the rest of the State.

Reduced County emergency planning expenses would save the County $35 million and would not affect the rest of the State.

Lost corporate income taxes would total $167 million in the State, and $8 million to the County, assuming a 5% allocation (consistent with County / State population ratio ).

The health of Hudson River fisheries would improve and provide significant benefits estimated at $2.2 billion for the State. Lacking a good basis for assigning this benefit, we assumed that a nominal 10% would accrue to County residents.

Emissions of air pollutants from power plants across New York State would increase. We estimate the impact to be $41 million for the State, of which $2 million would be allocable to the County based simply on population.

Voluntary Retirement Westchester, in conjunction with the State, NYPA, New York City, and other stakeholders could negotiate a consensual agreement for Entergy to retire IP. A voluntary retirement would avoid the costs and risks of an acquisition, keep in place Entergy's operation and management resources, and provide significant flexibility to arrange a compensation package and develop replacement generation on site:

  • A voluntary retirement could be agreed upon with an actual shutdown date at some date in the future to allow sufficient time for market participants to replace IP's capacity in an orderly fashion. In our view, the announced retirement of IP would encourage market participants to replace substantially all of the generation capacity in the downstate region, possibly supported by long-term PP As offered by downstate utilities. A minimum of three-to-four years would be adequate to develop replacement generation to assure system reliability. While there are many power plant sites that could be developed, on-site replacement generation is preferred as it could avoid or mitigate the local economic impacts of retiring IP.
  • Entergy would request substantial compensation in exchange for agreeing to retire IP and to not pursue license extension. However, retiring IP at the end of the current license terms would allow Entergy to avoid the costs and risks associated with the license extension process, including NRC approval and the requisite zoning variance.

LAI's estimate of the CapEx for license extension is over $1 billion for cooling towers and other plant repairs / improvements. The NRC has not rejected any license extension applications to date, but approval of Entergy's application is not certain given IP's unique siting and cooling system challenges.

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  • If Entergy retires IP by 2013/15 and does not construct the cooling towers, there would be sufficient acreage for a gas-fired power plant. Three years ago, Entergy proposed the addition of an on-site gas-fired plant, but subsequently withdrew its application. COWPUSA has the authority to purchase power from an on-site replacement plant through a PP A, but currently sells power only for economic development purposes. Providing retail service would be a major step for COWPUSA and would impose associated administrative and operational costs. LAI considered a strategy for COWPUSA to buy power directly from the on-site generator to avoid transmission charges, but that strategy was not effective. In addition, the Monthly Adjustment Charge (MAC) component levied by Con Edison for Westchester residents will be equalized, removing a potential cost advantage for COWPUSA.
  • Ignoring PSC directives to encourage retail choice and competition among generators, it would be preferable for a utility with a large retail customer base, such as NYP A or Con Edison, to enter into a long-term PP A for on-site replacement generation, perhaps in conjunction with COWPUSA. A PP A with credit-worthy counterparty such as NYP A or Con Edison would also assure project financeability.
  • There would be no electric market and economic impacts because IP would be retired on the same date as in our base case assumption, 2013/15.

Present Value Summary - Voluntary Retirement in 2013/15 (2011 $ millions; excludes indirect impacts; assumes no replacement generation)

Costs Shared by Stakeholders Entergy Compensation Original License Term nla Renewal Option $ 495 - $1,376 Sub-Total $495 - $1,376 Spent Nuclear Fuel nla Total $495 - $1,376 We have assumed that a consensual agreement with Entergy would be reached by January 1,2011, to retire IP at the end of the existing license terms. In this case, the only cost that would be incurred is the compensation cost due Entergy. Entergy would remain responsible for SNF and decommissioning. In effect, Entergy's option to extend IP's licenses would be bought out. We estimate compensation due Entergy at $0.5 - $1.4 billion in present value terms as of January 1, 2011, the assumed payment date. As before, the compensation range is due to the uncertainty of the discount rate that would be developed in the negotiatIOns. Entergy would continue to be responsible for SNF costs, and the rate and economic impacts would be no different than if IP were shut down on its "natural" retirement dates at the end of the existing license terms.

As with the acquisition option, the compensation amounts that we estimated represent an upper limit, because we ascribed full value to the cash flows Entergy would earn during the IX OAGI0000197_020

twenty year license extension period. We effectively assumed that Entergy faces no risk of the NRC rejecting the application for license extension. While there is some uncertainty surrounding the relicensing effort, we have not tried to calculate either the likelihood of NRC rejection of Entergy's application for IP license extension or the resulting change in the compensation value.

State and Federal Action Any action by the state or federal government to require Entergy to retire IP prior to the expiration of the current operating licenses would be unprecedented. In such an event, the State or federal government would likely provide the compensation due Entergy. The State would be bound by similar eminent domain regulations as the County, but the regulatory basis and condemnation process for federal action was not part of LAI's scope of work. However, State and congressional support for County actions could greatly improve the chances of a successful negotiating outcome and reduce the County's compensation burden.

Congressional action would likely be needed to obtain tax law changes that would make tax-exempt financing possible for replacement generation on the IP site.

License Extension The NRC licenses for IP2&3 expire on September 28, 2013 and December 12, 2015, respectively. In light of the high value of energy and capacity in downstate New York and pressures on oil and gas producers throughout North America, we believe that the forward economics would support Entergy's decision to apply for a twenty year license extension. In order to receive NRC approval, Entergy will have to demonstrate that all of the systems, structures, and components that are critical to IP' s safe operation can continue to function for the term of the license extension. IP's proximity to New York City and the efficacy of its Emergency Evacuation Plan would not be considered in a typical license extension process under existing NRC regulations. Given the strong public and political attitudes about IP, the NRC may not view an application from Entergy for license extension as typical.

In order to continue operating beyond the term of the initial licenses, the New York Department of Environmental Conservation (DEC) has required Entergy to convert from the existing once-through cooling system that utilizes Hudson River water to a closed system with cooling towers. We estimate that the future cost of converting to cooling towers plus other repairs and improvements that would likely be undertaken will be $1 billion. Conversion would require that each unit be shut down for roughly nine months, plant output would be reduced by roughly 4% due to pumping requirements and other internal loads, and plant operation and maintenance costs would increase due to age-related problems. The closed-cycle cooling design will likely be scrutinized by the NRC in any application for license extension, and cooling towers will require a zoning variance from the Village of Buchanan.

The NRC has approved extension requests for 30 nuclear plants at 17 sites to date, and has not denied any requests. However, Entergy does face some risk that IP's application for license extension will not be approved, particularly verifying that the plant design, including conversion to the closed cooling cycle, meets current safety standards. The effectiveness of x

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opposition from New York State interveners before the NRC is unknown. If the NRC denied Entergy's application for license extension, the County and other stakeholders would not have to fund compensation costs. However, we do not recommend relying on such a strategy.

From an economic perspective, we calculate that license extension would be cost-effective in relation to the value of capacity and energy from the units over the anticipated twenty years of extended plant life. However, if the CapEx requirement is higher than our $1 billion estimate, if the NRC approval is for less than twenty years, or if power prices are lower than our forecast, Entergy may be less inclined to pursue license extension, and our compensation estimates would be lower.

Replacement Generation We believe that announcing IP's retirement at least three-to-four years in advance will allow sufficient time to develop replacement generation. One scenario we examined contemplates the postulated immediate retirement of IP, an unrealistic assumption that would by definition preclude sufficient time for replacement generation, thereby threatening the reliability of the state's bulk power system. The immediate retirement of IP would cause energy and capacity prices to soar. To ensure resource adequacy, we would expect NYISO to implement a number of expensive short-term fixes to ensure grid security prior to the commercialization of new generation resources.

If IP were to be retired, LAI believes that the resulting market price signals would be attractive for replacement generators. It may nevertheless be necessary for downstate utilities to backstop the development of replacement capacity through PP As. While the current financial markets are wary of lending to projects that have merchant risk, projects with PPAs provide credit support that facilitate debt and equity financing. Whether those downstate utilities could be reasonably assured of recovering all PP A costs is outside the scope of this inquiry.

We examined the range of possible replacement generation options and concluded that they would likely be gas-fired and located in the downstate region. This conclusion is consistent with possible replacement generation at the IP site and with proposed combined cycle plants in Orange and Rockland counties over the last few years. Generation additions in upstate New York would not be economic without expensive transmission upgrades. Assuming utility support through PP As, the requisite generation capacity would likely be permitted and developed on a timely basis. Other infrastructure improvements, in particular, increasing gas pipeline deliverability, would also be required. Major electric transmission improvements would not be necessary in light of the existing transmission infrastructure from IP southward.

Replacing IP's capacity may be facilitated, in part, by New York's Renewable Portfolio Standard that requires utilities to increase their purchases of renewable energy over the next decade. How much new capacity and energy could be derived from renewable technologies in the downstate New York region was outside our scope of work.

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It is not feasible to convert any of the existing IP units to gas-fired operation. However, the site is well-situated for new gas-fired combined cycle replacement generation so long as cooling towers are not installed, which would utilize valuable remaining space. Entergy proposed developing 330 MW of new gas-fired simple cycle generation at the IP site three years ago, but later withdrew the application. We believe the remaining on-site acreage is sufficient for more than 330 MW of new generation. Algonquin traverses the site and IP's retirement would free up electric transmission capacity. Although Algonquin is fully subscribed with virtually no surplus capacity throughout the winter season, planned pipeline projects and expansions should make the IP site attractive for new gas-fired generation.

Expensive pipeline upgrades on Algonquin would be required to provide firm year-round deliveries. The quality of non-firm transportation during the winter is uncertain, particularly in light of complex market dynamics associated with new gas supplies entering the system.

To the extent a new combined cycle plant received an air emissions permit that allowed burning distillate oil up to 30 days per year, non-firm service might still entail interruptions during the heating season.

While it is not Westchester's legal responsibility to replace IP capacity, facilitating the development of replacement generation at the IP site is one way that the costs and economic impacts ofIP's retirement could be avoided or mitigated. In this regard, COWPUSA may be able to support NYPA's efforts to execute a PPA and purchase power from the replacement plant. While both utilities have large customer bases, neither party would be obligated to do so. In fact, Con Edison has taken a number of steps to lessen its reliance on PP As in response to state regulatory initiatives to promote competition. Alternatively, part of the IP site could be purchased and leased to a developer, which would maintain PILOT and local spending as well as provide construction opportunities. We do not recommend that COWPUSA consider plant ownership given the competitive market pressures and operational challenges. The National Academy of Sciences has recently been asked to conduct a study for the U.S.

Department of Energy (DOE) to identify and evaluate conventional and alternative energy options to replace IP. For its part, the County may also want to pursue cost-effective conservation, load management, distributed generation, and renewable energy sources in Westchester.

Valuation LAI estimated the value of IP using standard appraisal techniques. The preferred technique for an income-producing property, referred to as the Earnings Approach, requires forecasting revenues and expenses, and discounting the resulting cash flows back to a specified date using an appropriate discount rate. LAI forecasted IP revenues using a system dispatch simulation model that reflects the hourly power market operation under existing regulations and expected levels of plant performance. Expenses were forecasted based on a detailed economic study of IP prepared by the Nuclear Energy Institute (NEI), a nuclear industry policy organization, as well as on publicly available data. Other local economic impacts, including property taxes, employment, and local spending, were considered separately.

The derivation of the appropriate discount rate applicable to IP's cash flows is challenging. In addition to market risk attributable to all merchant generation owners who merchandise Xli OAGI0000197_023

output without the benefit of a compensatory PP A, nuclear plant owners face a broad spectrum of discernible risks, such as safety compliance, decommissioning, SNF, mishap repairs, latent technical defects, extended outages, and changes in government regulation. In order to bound the range of reasonable plant values applicable to IP, LAI estimated a high discount rate of 20% and a low of 14%. The higher discount rate provides a lower plant value

/ compensation payment, and vice versa. We did not include a risk premium for possible NRC rejection on Entergy's application for life extension, which would depress plant values and compensation estimates. In our valuation estimates, we have assumed that once IP ceases operating, the decommissioning funds can be utilized to recover all costs of removing and storing radioactive materials. Non-decommissioning costs, such as SNF management and disposal of non-radioactive structures, cannot be recovered from the funds and would have to be borne by the owner.

LAI utilized a different discount rate to calculate the present value of rate and economic impacts. Evaluating these impacts from the County's point of view, we estimate that the County's financing cost is approximately 4.0% based on the cost of issuing tax-exempt debt.

Tax-Exempt Financing If IP were acquired through condemnation or if Entergy agreed to a voluntary shutdown, we believe that compensation could be funded by issuing tax-exempt general obligation (GO) bonds. If the County were the acquiring entity, it would have to acquire an ownership interest, or else develop a business structure with the assistance of legal counsel that satisfies the State's municipal finance regulations without being exposing to nuclear plant ownership-type risks. However, acquisition by the County would be problematic as a large GO issuance would stretch the County's debt capacity and probably lower the County's AAA credit rating.

A lower rating would increase the cost of debt to compensate Entergy as well as the cost of any future County debt issuances. For these reasons, it might be better to have the State or NYP A, which has the experience to manage the IP asset, issue the bonds. It may be possible for Entergy to remain responsible for decommissioning and SNF management through an easement or sale and lease-back transaction, provided the NRC accepted this arrangement.

We do not believe COWPUSA or the Westchester County Industrial Development Agency (WID A) could have a role in funding Entergy's compensation. COWPUSA does not have statutory authority to either issue bonds or to own power generating facilities. WIDA issues Revenue bonds that must be supported by a pledge of revenues from the ultimate borrower.

However, WIDA or another issuing authority might be able to facilitate on-site replacement generation by issuing tax-exempt debt if Congress supported changes to federal tax law.

Decommissioning and Spent Fuel Management Decommissioning, i. e. the removal of all radioactive materials that are controlled under the NRC licenses, does not include SNF and non-radioactive material. The removal and long-term storage of SNF is the responsibility of the DOE. It is expected that SNF will be stored on-site and eventually shipped to Yucca Mountain starting no earlier than 2010, although that date is uncertain. Non-radioactive material, such as cooling towers, water inlet structures, and X111 OAGI0000197_024

buildings, would be removed by Entergy or successor site owners using conventional methods. The IP site will be decommissioned by placing highly radioactive materials, including the reactor vessel and other structural materials, in special containers that will likely have to be stored on site for the foreseeable future. Currently, no licensed disposal site exists for IP's highly radioactive materials, although Yucca Mountain may be able to accept such waste if its license is amended.

After removal from the reactor vessels, SNF is stored in on-site storage pools for five years to allow the fuel to cool down. Since Yucca Mountain will not open until at least 2010 and IP is running out of storage pool space, Entergy has received approval for, and is constructing an Independent Spent Fuel Storage Installation (ISFSI) on-site. SNF that has cooled sufficiently will be removed from the storage pools, placed in dry storage casks, and stored at the ISFSI until they can be shipped to Yucca Mountain. Upon retirement, we estimate that it will take ten years to remove all of the SNF from the IP site.

There are separate decommissioning funds for each of the three IP units. The IP1&2 funds and liabilities were transferred to Entergy. NYP A retained the fund and liability for IP3 but has the right to require Entergy to assume the liability provided that it is assigned the decommissioning fund. A report by the U.S. Government Accountability Office (GAO) indicates that IPI was under-funded, and funding for IP2&3 was adequate. However, it is reasonable to assume that Entergy will be able to conduct an integrated decommissioning effort for all three units that will reduce costs, in which case we believe that the combined decommissioning funds will be sufficient.

Economic Impacts Retiring IP, without simultaneous development of on-site replacement generation, would result in the loss of PILOT, jobs, and local spending, higher emissions of certain air pollutants, and higher electricity bills. On the other hand, the County's emergency planning costs would decline and the health of the Hudson River fisheries would improve. These impacts will result whenever IP is retired, but could be avoided or mitigated if replacement generation is developed at the site. Consistent with standard socio-economic analysis, we used economic multipliers to estimate the secondary, or indirect, economic impacts in Westchester and throughout the State.

  • Entergy executed agreements that established a PILOT schedule of $18.8 million in 2005, escalating to $26.8 million by 2014. The Hendrick Hudson School District receives over 80% of these payments and would be most affected by the loss of PILOT, which accounts for one-third of its revenues. Remaining PILOT is shared among the town of Cortlandt, the Verplanck Fire District, and the County. A PILOT schedule for on-site replacement generation would have to be negotiated among Entergy and these parties. We believe that the ISFSI currently being installed on-site will not alter the existing PILOT schedule .
  • If IP is retired PILOT would cease unless replacement generation is developed on-site.

IP2&3 would be subject to much lower property taxes at then-current rates. While XIV OAGI0000197_025

IP's retirement may increase property values for nearby homeowners, property tax rates may be higher to make up for lost PILOT.

  • Entergy has announced plans to reduce IP personnel in the next two years, at which point the direct and indirect contribution to Westchester is expected to be $26 million/year. Whenever IP is retired overall staffing levels will be reduced gradually because decommissioning personnel will be required for approximately ten years.

Once that work is completed and the SNF is removed for disposal, the site can be re-used. Development of on-site replacement generation could provide another source of employment. The number of jobs would actually increase while decommissioning, SNF storage, and construction activities for on-site replacement generation were taking place.

  • IP spends approximately $12 million/year on goods and services in Westchester, and

$55 million on a state-wide basis. These payments will also gradually disappear as decommissioning and SNF work are completed, but development of on-site replacement generation could avoid or mitigate these impacts.

  • We estimate, on an indicative basis, New York power plant emissions of nitrogen oxides (NOx) will increase by 4.0% and sulfur dioxide (S02) by 2.6% if IP is retired, as other plants, new and existing, will have to operate additional hours every year.

According to statistics from the u.s. Environmental Protection Agency (EPA), power plants are responsible for approximately one-eighth of New York NOx emission and one-half of S02 emissions. Therefore the overall state-wide increase from retiring IP would be about 0.5% and 1.4%, respectively.

  • Monetary contributions and IP employee volunteer efforts to the local community, which totaled $0.3 million in 2002 and $1.2 million in 2003, may continue at a lower level once IP retires, until decommissioning was completed and SNF was removed from the site. We estimated 2005 contributions of $0.8 million, escalating with inflation as long the plant continues to operate. However, if Entergy were to develop replacement generation on the IP site it may be expected to continue monetary and volunteer contributions to the local community.
  • The County would have to continue providing emergency services as long as SNF remains on site. These services cost Westchester $4.2 million in 2002, net of contributions from the State, and could be substantially reduced after IP is retired.
  • We estimate the value of fish mortality due to using Hudson River water for cooling to be $309 million based on mortality statistics developed by the DEC and standard industry fish values. Retiring IP would eliminate this impact significantly except for a small amount of cooling water that may be required for the SNF storage pools. Since residents throughout the State would benefit from improving the health of fish stocks in the Hudson River, we recommend that the State play a role in fostering a consensual agreement and in compensating Entergy.

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Electric Rate Impacts

  • There are three types of wholesale electricity products: energy that is metered and paid for based on usage, capacity to ensure sufficient energy supplies and paid for regardless of usage, and ancillary services products required to maintain a stable and efficient bulk power system. All customer bills include charges for these wholesale products as well as for local delivery. Energy is the largest component and comprises roughly one-third of a residential bill for a customer consuming 500 kilowatt-hours per month (kWh/month). Utilities purchase energy and capacity for their customers in two ways: from the market at prices that reflect daily and hourly conditions, and through long-term PP As with generators. PP As provide retail customers with some insulation from short-term changes in market prices.
  • IP has a low operating cost and is normally dispatched whenever it is available. If IP retired prior to 2013/15, market energy prices in Westchester and the Hudson River Valley would increase by an average of 8.4%, even with the timely addition of replacement generation. Market energy prices in New York City would likely increase by an average of 3.8%, and slightly less on Long Island. Elsewhere in New York, we expect less than a 1% impact. If IP voluntarily retired in 2013115, there would not be any market price impact compared to the base case assumption of retirement at the end of the existing license terms. Our expectation of sufficient and timely replacement generation would leave market capacity prices unchanged.
  • If IP retired in 2008, typical residential bills in Westchester would increase by an average of about $1.55/month though 2015 and about one-half of that amount in New York City. In the unrealistic scenario in which IP was retired immediately without replacement generation, market energy and capacity prices would soar and service reliability would be impaired until short-term generation measures were implemented.

Action Plan The County's goals of retiring IP, minimizing economic and rate impacts on County and State residents, and maintaining system reliability are not inherently incompatible. While an immediate shutdown would have serious consequences, the County could pursue its goals through an orderly retirement strategy. We recommend that the County spearhead an agreement with New York State, Entergy, NYPA, and other stakeholders that focuses on two key initiatives - voluntary retirement in 2013/15 at the end of the current NRC license terms and encouraging on-site gas-fired replacement generation. This would allow Entergy to continue earning profits for the term of the current NRC licenses as originally envisioned, avoid the high cost of license extension, and pursue an on-site investment opportunity that takes advantage of existing infrastructure. Local communities and school districts could preserve some level of PILOT, employment, and local spending on goods and services.

Lastly, an agreement reached by year-end 2010 would allow sufficient time for Entergy and other developers to install sufficient replacement generation.

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1. PLANT BACKGROUND AND PERFORMANCE 1.1. PLANT HISTORY Con Edison was the owner and developer of the IP site that covers 239 acres in the Village of Buchanan. IPI entered commercial operation in 1962 but was shut down in 1974 due to concerns over the emergency core cooling system. IP2 entered commercial operation in August 1974 and IP3 became commercial in August 1976. The combined nominal generation capacity ofIP2&3 is about 2,000 MW. Together they represent 5.3% of the New York's in-state generation capacity, and generate 10.1% of the State's electrical energy requirements.!

In 1976 Con Edison sold IP3 to NYPA. In November 2000 NYPA sold IP3 to Entergy.2.3 At the time of the sale NYP A executed a PP A to purchase the entire IP3 output (i. e. capacity, energy, and ancillary services) through 2004. In addition, NYPA and Entergy executed a Facilities Agreement for NYPA to share in any savings should Entergy purchase additional nuclear units in New York (including IP2), and a Value Sharing Agreement for NYPA to share in the revenues from IP3 in the event that the average market price level exceeds certain predefined levels. NYP A and Entergy agreed to negotiate in good faith for NYP A to purchase the total output beyond the term of the original PP A. The parties did not extend the PPA, but NYPA agreed to purchase 500 MW of energy and capacity from IP from 2005 to 2008 as a result of a competitive Request for Proposal (RFP)4 In September 2001 Con Edison sold IPl&2 to Entergy. At the time of the sale, Con Edison agreed to purchase the capacity of IP2, less up to 20 MW, through 2004 under a Capacity Purchase Agreement, with an option to continue purchasing capacity thereafter. Con Edison also agreed to purchase the energy of IP2, less auxiliary power and 45 MW of station use, through 2004 under a separate PP A. Con Edison has arranged to purchase decreasing amounts of energy and capacity from 2005 to 2009 5 Entergy operates IP under Operating Licenses granted by the NRC. The NRC license for IP2 is due to expire on September 28, 2013 and the license for IP3 is due to expire on December 12, 2015. Entergy could apply for up to twenty year license extensions for each unit, as described later on in this report.

1 Based on 2003 data. IP2&3 provide a higher percentage of the State's energy requirements compared to their capacity contribution because the units are base loaded and operate at high capacity factors.

2 The sale ofIP3 was part of a larger transaction in which Entergy also acquired the James A. FitzPatrick nuclear power plant in Oswego, New York.

3 Entergy owns the IP assets through limited liability corporations (LLC) - Entergy Nuclear Indian Point 2, LLC, and Entergy Nuclear Indian Point 3, LLC Each LLC is a wholly-owned subsidiary of Entergy Nuclear Holding Company #1, which is itself a wholly-owned subsidiary of Entergy. LAI has not distinguished among these entities for the purpose of this study.

4 NYPA 2004 Annual Report, page 26.

5 Capacity purchase data from Con Edison 2004 Form lO-K filing, page 147. Energy purchase data from Entergy 2004 Annual Report, page 39.

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1.2. ENTERGY BUSINESS SEGMENTS Entergy is an integrated energy company engaged in electric power production, retail electric distribution, energy marketing and trading, and gas transportation. Entergy is a large corporation, with annual revenues of $9.2 billion in 2003 and earnings of just under $l.0 billion. The company is organized into three primary business segments:

  • Entergy's utility business segment includes electric utilities in Arkansas, Louisiana, Mississippi, and Texas, as well as a small amount of natural gas distribution activities.

These electric utilities own and operate five rate-based nuclear plants - Arkansas Nuclear One (units 1&2), Grand Gulf, River Bend, and Waterford 3.

  • Entergy owns and operates five non-utility (i.e. merchant) nuclear power plants in New York and New England, including IP2&3, FitzPatrick, Pilgrim, and Vermont Yankee. Entergy provides services to those and other nuclear plant owners. Entergy's utility-owned and non-utility nuclear assets make it the second-largest nuclear generator in the U. S.
  • Entergy's Energy Commodity Services used to provide trading services and gas transportation / storage services through Entergy-Koch, LP, but that business was being divested as of September 2004. Entergy's Energy Commodity Services used to own and operate non-utility wholesale power assets, but most of those assets have been divested as well.

1.3. PRESSURIZED WATER REACTORS Of the several types of nuclear power reactors in the world, only Pressurized Water Reactors (PWRs) and Boiling Water Reactors (BWRs) are in commercial operation in the U.S. There are currently 104 nuclear power plants licensed to operate in the U.S., of which 69 are PWRs and 35 are BWRs. The 104 nuclear power plants together generate about 20% of U.S.

electrical requirements. In BWRs, water is heated by nuclear fuel and boils to steam in the reactor vessel. The stearn is then piped directly to the turbine, driving the electric generator and producing electricity.

The IP units are PWRs with primary and secondary water loops. Each unit has a containment structure that houses the primary loop components, including the reactor vessel, pressurizers, and a steam generator. The reactor vessel uses nuclear fuel rods that contain uranium to heat the primary loop water to about 620°F. The amount of heat is modulated by control rods that can absorb nuclear radiation within the reactor vessel. The water in the primary loop is maintained in a liquid state by keeping it under tremendous pressure, about 2235 psig, using pressurizers.

2 OAGI0000197_029

Figure I-Diagram of Pressurized Water Reactor

'One-Ihlrd of the fuel m each IPuIl11lS replaced every 24 months OAGI0000197_030

1.4. PLANT PERFORMANCE Power plant perfonnance is best expressed in tenns of capacity, how much electrical energy can be delivered into the transmission grid, and capacity factor, the amount of power generated in a year expressed as a percentage of the amount that could be generated if the plant were to operate at 100% capacity in every hour of the year 7 This section also addresses the expected operating lives of the units.

Recent and near-tenn expected operating improvements and system analyses have allowed Entergy to increase the capacity ratings of IP2&3. However, we expect their capacities will be lower after 2013/15 if the plant is converted from once-through cooling using water from the Hudson River to a closed system using cooling towers. While IP2&3's capacity factors have improved to a combined average of 94.3% since Entergy acquired the plants, we believe that an 85% capacity factor is a more reasonable long-tenn assumption based on a variety of factors, including Entergy's own expectations at the time the NRC licenses were transferred.

1.5. CAPACITY RATING 8

NYISO establishes summer and winter capacity ratings for each plant in the State NYISO capacity ratings depend on tests that demonstrate the actual amount of power that can be delivered to the transmission grid 9 As of January 1, 2004, IP2&3 had summer and winter ratings as noted in Table 1 below.

lO Table 1- 2004 Net Capacity Ratings Season IP2 IP3 Summer 987.6 MW 993.1 MW Winter 985.5 MW 1,00l.4 MW The NYISO ratings are based upon actual plant tests and are good indicators of the amount of power that IP2&3 can deliver for sale. LAI used the NYISO ratings, adjusted for NRC-approved "uprates" (i.e. increases in capacity ratings), for system modeling and financial analysis purposes. The NRC regulates the maximum thennal power level at which a nuclear power plant may operate, which in turn detennines the unit's electric capacity. The NRC has granted the following increases in IP2&3 thennal capacity ratings in the past two years:

7 Power plant efficiency is expressed in terms of heat rate.

8 NYISO is a not-for-profit organization fonned in 1998 as part of the restructuring of New York State's electric power industry. NYISO is responsible for the reliable, safe and efficient operation of the State's major transmission system and administers an open, competitive, and nondiscriminatory wholesale electricity market in the State.

9 Power plants have gross generation ratings equal to the total amount of electric power generated before accounting for station loads, e.g pumps, lighting, instrumentation. The net rating is the amount of power that can be delivered into the transmission grid after providing those station loads.

10 Source: NYISO.

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  • The NRC approved a 1.4% increase in IP3's rating in November, 2002, due to improved feedwater flow measurement that reduces uncertainty. We believe that the NYISO values incorporate this increase.
  • The NRC approved a 3.26% increase in IP2's rating in October, 2004, due to minor component upgrades, e.g. valves, pumps. LAI believes that the resulting NYISO rating will increase by a similar percentage, equivalent to 32.2 MW.
  • In June 2004 Entergy submitted an application to further increase the thermal capacity rating of IP3 by 4.85% that the NRC approved on March 24, 2005. We believe that the NYISO rating of IP3 will increase by approximately 48.2 MW.

The last two uprates have been incorporated into the IP capacities for 2005-2013/15 as shown in Table 2 below.

Table 2 - Changes in Net Capacity Ratings (summer ratings)

IP2 IP3 Current Rating 987.6 MW 993.1 MW NRC UQrates +32.2MW +48.2MW 2005- 2013115 1,019.8 MW 1,04l.3 MW Decrease due to

-4% -4%

cooling towers After 2013/2015 979.0 MW 999.6 MW While these recent and near-term expected improvements have allowed Entergy to increase the capacities of IP2&3, conversion to cooling towers after 2013/15 would lower their net output. First, the units will face increased station loads due to pumping required for cooling towers, particularly if the towers are sited on the bluff approximately 100 feet above the level of the river. Second, the cooling towers will not be as effective in lowering the cooling water temperature, particularly during the hot summer months, thereby lowering the efficiency of the units. As further explained in Attachment 1, we estimate that cooling towers will decrease the capacity ratings of IP2&3 by 3%-5% per unit. We have assumed a mid-point value of 4%,

as shown in Table 2.

1.6. CAPACITY FACTOR Power plants can rarely operate at 100% capacity factors because of scheduled outage activities (e.g. regular maintenance, refueling), unplanned outages (also referred to as forced outages), and increased surveillance requirements often required for older plants. These activities can require a plant to be operated at part-load or to be temporarily shut down. In order to estimate the near-term and long-term capacity factors for IP, LAI examined a number of data sources, including Entergy's expected capacity factor estimate, historical IP capacity factors, capacity factor data for Entergy's other nuclear plants, the problem of unanticipated extended outages as addressed in a speech by NRC Chairman Nils J. Diaz (excerpts of which 5

OAGI0000197_032

are provided on page 9), and other factors. LAI believes that an 85% capacity factor for both IP units is reasonable for simulation modeling and financial analysis purposes over the long term. This capacity factor assumption excludes the period IP2&3 would be shut down, estimated at nine months per unit, if the once-through cooling systems are replaced by hybrid cooling towers in the license extension scenario l l Entergy's Expected Capacity Factor - In its application to the NRC to acquire the IP2 license, Entergy estimated that it will "operate IP2 at an average capacity factor of 85%." In response to a request for additional information, Entergy justified the 85% value based on its success at other plants, the capital improvements made by Con Edison just prior to the sale, improving fleet performance, and Entergy' s experience with IP3. 12 Indian Point Capacity Factor - Prior to Entergy's purchase, IP2&3 had significant operational problems in the 1990s that resulted in poor availability and low capacity factors. Through 2004, the lifetime capacity factors for IP2&3 are 64.7% and 60.5% respectively, reflecting many years of poor performance prior to Entergy ownership.13 Plant capacity factors since Entergy acquired the plants have improved and are listed in Table 3 below.

Table 3 - Reported Capacity Factors 14 Year IP2 IP3 Indus. Avg.

2001 nla 93.9% 89.4%

2002 90.7% 98.3% 90.3%

2003 90.9% 97.6% 87.9%

2004 89.5% 101.7% 90.5%

Averages 90.4% 97.9% 89.5%

The capacity factors for IP2&3 were high compared to the industry averages listed above, but we do not expect IP's capacity factors to continue at these levels for three key reasons:

  • IP2 was sold to Entergy in a better-than-average condition. Con Edison spent over

$150 million to replace the four steam generators in IP2 just before sale to Entergy as well as other major enhancements to plant equipment (e.g. new plant simulator, new condenser tubes and tube sheets, new main feedwater heaters, a new optimized high-pressure turbine rotor). These enhancements have allowed IP2 to achieve high capacity factors for the first few years of Entergy operation, but we expect the plant to return to a more typical level of performance as equipment and systems age, and as maintenance and CapEx requirements increase.

11 LAI accounted for the nine month shutdowns in our financial projections.

12 Response to the NRC's Request for Additional Information Regarding License Transfer Application, April 16, 2001.

13 NEI Report u.s. Nuclear Power Plant Capacity Factors (MDC Net).

14 Source: NEI.

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  • The plant and industry capacity factor data reported by NEI and incorporated in Table 3 appear skewed on the high side. For example, the 2004 NEI capacity factor data for that year have twenty plants with capacity factors above 100%, leading us to suspect that the NEI data underestimates the actual plant capacities. IS In particular, the NEI capacities for IP2&3 are listed as 956 MW and 979 MW, respectively, which are about 6% less than the estimated 2005-2013115 capacities provided earlier in Table 1.

Using lower capacities for calculating capacity factors makes plant capacity factors appear higher than if more accurate capacity values were used. If we recalculate IP2&3's 2004 capacity factors using the estimated capacities of 1,019.8 MW and 1,041.3 MW, the capacity factors would be reduced by 5.6% and 6.1 %, respectively.

  • Industry capacity factor data according to NEI has increased significantly in the past few years and may not be sustainable. For example, while the average capacity factor for 2002-04 was 89.6% as listed in Table 4, the average for the proceeding three year period, 1999-2001, was 87.6%, a value in line with our long-run expectation for Ip 16 Table 4 - Historical Nuclear Industry Capacity Factors17 Years Cap Factors.

Avg. 2002-04 89.6%

Avg. 1999-2001 87.6%

Avg. 1996-98 75.2%

  • The NEI data does not include units on extended outages that are repamng or replacing major pieces of equipment. For example, the NEI data excludes Brown's Ferry Unit 1, which was shut down in 1985 but is scheduled to return to service in 2007.

Capacity Factors at Other Entergy Plants - Entergy owns and operates five utility rate-based nuclear plants: Arkansas Nuclear Units 1 & 2 (ANOI and AN02), Grand Gulf Nuclear Station (GGNS), River Bend (RB), and Waterford 3 (W3). The chart in Table 5 below, taken from the NRC's letter of August 27, 2001 approving the transfer of the IP2 license, provides historical capacity factor data for these five plants. These plants had an average capacity factor of 85.7% over the period that Entergy had operating responsibility.

15 One plant, Arkansas Nuclear One unit 2, has a reported capacity factor of 114.5%.

16 The average industry capacity factor for 2004 was 90.5% according to NEI data.

17 Source: NEI.

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Table 5 - Historical Capacity Factors (%) for Entergy Utility Nuclear Plants'S AN01 AN02 GGNS RB W3 1985 70.90 63.50 54.20 68.80 1986 48.80 70.60 42.20 77.50 1987 65.00 87.90 77.90 78.90 1988 53.80 65.60 95.60 88.20 69.20 1989 46.10 72.80 78.40 58.40 80.80 1990 56.30 94.90 74.00 68.20 91.40 1991 89.31 81.47 91.15 81.56 77.25 1992 79.43 73.04 81.39 33.60 80.72 1993 83.66 97.72 78.88 64.13 97.05 1994 98.30 89.47 96.03 59.59 84.23 1995 81.63 75.76 77.32 96.72 82.44 1996 85.61 93.73 89.38 83.44 94.54 1997 99.01 92.56 102.91 83.21 71.37 1998 84.89 91.50 87.43 95.54 91.54 1999 91.69 82.85 79.91 69.58 79.02 2000 87.29 69.86 100.79 89.43 89.78 Ave. Before 56.82 75.88 70.38 65.68 77.77 EOI Ave. After 88.08 84.80 88.52 82.50 84.79 EOI NOTE: Data listed above the double line are for years prior to the facilities being operated by EOI. Although EOI became the operalorfor ANO 1 & 2, GGNS, and W3 in 1990, the NRC siaffconsiders the performance of these plants forlhal year to be predominanlly influenced bylhe management practices oflhe previous Unanticipated Extended Outages - IP2&3 are currently on 24-month fuel cycles in which approximately one-third of the fuel in each unit is replaced. Refueling takes about 40 days.

For the remaining IP2&3license term (i.e. without license extension), we anticipate that there may be one or more extended outages per unit depending on work that emerges as a result of equipment inspections or due to scheduled equipment replacement. In addition to refueling outages, other unanticipated outages will inevitably occur as a result of equipment malfunction, condenser performance, or other events.

The subject of unanticipated extended outages was addressed in the following quote from a speech NRC Chairman Diaz gave to the Institute of Nuclear Power Operations 25 th Annual CEO Conference, which was held on November 3-4, 2004.'9 18 EOI refers to Entergy Operations Inc.

19 NRC Speech No. S-04-0IS, U.S. NRC Chairman Nils 1. Diaz at the Institute of Nuclear Power Operations 2S ili Annual CEO Conference, November 3-4, 2004 OAGI0000197_035

"At this point, I will take a few minutes to discuss with you one perspective on the existing data on nuclear power plant events, shutdowns and extended shutdowns by reviewing the distribution of extended shutdowns during the last 25 years, beginning after Three Mile Island (TMI) and therefore not including the shutdown of TMI-2 .... You may be a bit surprised by the fact that there have been at least 140 unplanned shutdowns lasting six months or longer since 1979. Excluded are some plants that permanently shutdown for economic or political reasons, in our judgment. Also excluded are routine shutdowns for planned maintenance or modifications, regardless of the length of the shutdown ...

" ... There were approximately 418 unplanned shutdown months (or 35 reactor shutdown years) from 1996 through 2004. It is not until 1999, or even 2001, that a very significant reduction was maintained.

"A brief analysis of the 52 unplanned shutdowns since 1979 lasting longer than a year reveals a set of reappearing causes. One could group the causal factors as shown in Table 1:

No. of Shutdowns Longer Shutdowns Avg. length Apparent Cause than One Year (months)

Design basis or 18 38 licensing basis Material degradation 15 16.5 Management issues 12 25 Equipment failures 7 19 "I would like to point out that, based on the numbers in Table 1, issues relating to 'design basis or licensing basis' contributed to about 50 percent of the total industry-wide shutdown time (for shutdowns since 1979 lasting longer than a year). If you add "management issues" to these, the combination contributed almost three quarters of the total industry-wide shutdown time."

Age-Related Degradation of Components - The IP units are relatively old and will require increasing levels of surveillance and maintenance in the future as structures and equipment age and become degraded. Age-related degradation is a generic term applicable to virtually all structures and components. Aging degradation concerns considered to be significant for PWR reinforced concrete containment structures include:

  • Loss of strength and modulus due to elevated temperatures.
  • Scaling, cracking, and spalling due to freeze-thaw cycles.
  • Increase of porosity and permeability, cracking, and spalling due to leaching of calcium hydroxide, attack by aggressive chemicals, and reaction with aggregates.

9 OAGI0000197_036

  • Age-related degradation is also applicable to all components. For example, the age-related degradation concerns and mechanisms for IP2&3 primary coolant loop piping, valves, and fittings are as follows:

o Primary water-induced stress corrosion cracking of high temperature / high pressure systems and equipment.

o Increase in ductile-to-brittle transition temperature of the primary coolant loop piping due to thermal embrittlement.

o Leakage of safety and relief valve flanges and bolts due to boric acid corrosion and normal wear.

o Leakage and crack initiation / growth in nuts and bolts due to stress relaxation corrosion cracking.

o Loss of strength in integral supports due to fatigue over time.

While age-related degradation is a concern at IP, the in-service inspection and monitoring programs are designed to address issues as they arise. Any items would be repaired and/or replaced during maintenance outages as described above. Given the current state of IP2&3, there is a low probability of any major age-related degradation problems through the end of the current NRC license terms. However, if IP continues to operate under an extended NRC license, the probability of such problems, which typically can only be mitigated at substantial expense, will increase.

1.7. OPERATING LIFE In LAI's opinion, it is likely that the plant will continue to operate through the term of the current IP licenses, unless (i) the County is successful in acquiring IP, (ii) Entergy voluntarily agrees to retire IP, or (iii) a catastrophic event were to occur. As discussed in the Plant Valuation section of this report, there are economic advantages for Entergy to apply to the NRC for license extensions of lengths of up to twenty years despite IP's unique challenges regarding Entergy's ability to verify IP's design basis against current standards and to satisfy emergency planning / evacuation regulations. Therefore two sets of financial valuations, provided in Section 4, were conducted - one assuming IP is retired at the end of the current license terms and one assuming the IP licenses were extended for an additional twenty years.

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2. LEGAL AND REGULATORY ISSUES 2.1. INTRODUCTION In its original RFP regarding IP, the County requested a comprehensive review of the strategies to acquire IP through condemnation actions. LAI also considered an alternative strategy of negotiating a consensual retirement with Entergy. We have identified a number of 20 advantages and concerns associated with each option to retire IP as discussed below The acquisition and voluntary retirement options would both be expensive because the County would have to pay compensation to Entergy in either case. However, a voluntary retirement has a number of advantages, principally avoiding the significant responsibilities, costs, and risks associated with nuclear plant ownership, even one that is no longer actively generating electricity. Voluntary retirement also would provide Westchester with significant flexibility in structuring a compensation package and provide the opportunity to coordinate the closure of IP with the development of replacement generation on the site, which would help mitigate any adverse economic consequences. Proceeding with a voluntary retirement would also permit the State and other stakeholders to participate in the negotiations and share in payment of compensation to Entergy. Moreover, we are not aware of any nuclear power plant that has ever been acquired or retired through condemnation proceedings.

This section provides an overview of state and county eminent domain laws, NRC regulations, and other legal and regulatory issues that would govern the acquisition or voluntary negotiated retirement option. We describe the possible roles of the County and COWPUSA, including opportunities to oppose license extension.

2.2. EMINENT DOMAIN LAWS Acquisition of IP through condemnation proceedings would be governed by New York State's Eminent Domain Procedure Law (EDPL), enacted in 1977 and made effective July 1, 1978. EDPL provides "the exclusive procedure by which property shall be acquired by exercise of eminent domain." The previous Condenmation Law had been used only where a condenming authority did not have its own eminent domain statutes, which made for confusing and inconsistent results. The EDPL provides a more uniform basis for obtaining 21 more consistent eminent domain results throughout the state The County is authorized to exercise the power of eminent domain under §74 of the General Municipal Law, which allows 20 We do not know if a state or federal action could require Entergy to retire IP, but this would be an unprecedented event. A consideration of such an action was outside our scope of work. In such an event, the action could trigger liability to pay compensation to Entergy.

21 Tlie Green Island Power Authority tried to acquire by eminent domain a 6 MW liydroelectric project in tlie late 1990s from Niagara Mohawk Power Corporation, but was unsuccessful. We are not aware of any successful power plant acquisition by eminent domain in New York.

OAGI0000197_038

municipal corporations (such as the County) to take and hold real property, and to acquire title of such property by condemnation if it is unable to agree with the owners for the purchase. 22 In addition, the County is authorized to acquire power generation property under §360 of the General Municipal Law that provides "Notwithstanding any general or special law, any municipal corporation may construct, lease, purchase, own, acquire, use and/or operate any public service within or without its territorial limits, for the purpose of furnishing to itself or for compensation to its inhabitants, any public service similar to that furnished by any public utility company specified in article four of the public service law".

The prerequisites for the lawful use of eminent domain are as follows:

  • Due Process of Law - The County must follow the expressed provisions of the EDPL to ensure due process.
  • Notice and Hearing - EDPL lays out specific requirements for public notice and hearings that would permit Entergy to contest the condemnation.
  • Public Use Required - The sine qua non of the sovereign power of eminent domain is that the property taken must serve a public purpose and use. EDPL provides for judicial review of a condemnor's determination of public use.
  • Compensation - The requirements of due process are satisfied where there are provisions made for just and reasonable compensation for property taken by eminent domain, and payment is made without unreasonable delay.
  • Waiver of Right of Due Process - Constitutional due process protections against a taking of property in eminent domain may be waived. Such waiver, however, must be voluntary and cannot be contrary to public policy or public morals. Waiver may be made orally, or by implication as where the owner accepts payment for the taking.

22 In addition to the power of eminent domain, the County also has what is referred to as "police power" that is used to regulate, or even take away, an owner's ability to use and enjoy his property in order to promote or conserve the public safety, health, and morality. The government exercises police power in a variety of ways, such as by adoption of legislation. Local government, towns and villages, may use this power by such means as zoning and subdivision controls. However, due to federal law, it is highly doubtful that fhe County could adopt regulations restricting the ability of Entergy to operate IF. Skull Valley Band of Goshute Indians v.Nielson, 376 F .3d 1223 (lOth Cir. 2004) addresses fhe use of police power to adopt safety regulations concerning disposal of nuclear waste. Assuming that regulation were possible, the most fundamental difference between the exercise of eminent domain and police power is that an acquisition under the power of eminent domain gives rise to just and reasonable compensation to the owner, while losses arising from the exercise of police power have been traditionally viewed as non-compensable. However, both the United States Supreme Court and the New York courts have recognized that if a regulation calls upon a property owner to sacrifice all economically beneficial uses in the name of the common good that leaves the property economically idle, the owner has suffered a taking of property for which compensation must be paid. See Palazzolo v. Rhode Island, 533 US. 606 (2001); Smith v.

Town o/Mendon, 4 N.y'3d 1, N.Y.S.2d(2004). If the County were to attempt to acquire IF or close it by police power, it would be anticipated that Entergy would strongly argue that such an attempt violates federal law and, even if pennissible, would require fhe County to pay compensation to Entergy.

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  • Property That May Be Taken - Generally all private property, both real and personal, is subject to the sovereign power of eminent domain. A private corporation's property may be taken by eminent domain in the same manner as the property of a private individual. 23 It should also be noted that the State of New York could act as the condenming authority as well as the County, so long as all the requirements noted above were met by the contemplated acquisition.

2.3. EMINENT DOMAIN PROCESS Public Hearing - The first step in the eminent domain process would be for the condemning authority to issue a notice that it is conducting a public hearing on an eminent domain matter.

The notice must be given between 10 and 30 days prior to the hearing by publishing notice in at least five successive issues in a daily paper of general circulation in the area. In addition, the statute now requires that notice be served upon the record owner of the property as shown on the real estate tax billing records. At the hearing, the condemning authority must outline the public purpose, proposed location, or alternative locations of the public project. The public would be invited to participate in this hearing and a record must be kept of the proceedings.

Within ninety days of the hearing, the condemning authority shall make public its determination and findings concerning the project and publish a brief synopsis in at least two successive issues of an "official" newspaper. The synopsis must be served upon the record owner according to the tax billing records. The determination and findings shall specifically note (i) the public use, benefit, or purpose to be served by the proposed project, (ii) the approximate location of the project and reasons for the selection of the site, (iii) the general effect of the proposed project on the environment and residents of the locality, and (iv) other relevant factors 24 There is an exemption for this initial hearing requirement if the condemning authority must submit the information noted above to a local, state or federal subdivision in order to obtain a permit or license. While the County would indeed have to submit such information to state and federal agencies to take over IP's environmental permits and nuclear operating licenses, 23 A proceeding to take real property includes any rights, interests, or easements and appurtenances. Lands under water adjacent to upland property are deemed appurtenances to the upland property and part of the taking, and so would include any IP property or rights, etc., that extend into the Hudson River.

24 The principle of Public Use is recognized by the EDPL which provides for judicial review of a condemnor's determination following a pre-acquisition hearing as to the public use, benefit, or purpose served by the proposed project. In determining whether the use is in fact public or private, a court may look beyond a legislative declaration as to the nature of the use. However, an express declaration in the statue authorizing the taking of property that the taking is for a public use is common and legislative findings in this respect are entitled to great weight if properly supported.

13 OAGI0000197_040

LAI suggests that it would be prudent to keep an initial public hearing under the condemnation option. 25 Within 30 days of publishing the detennination and findings by the condemning authority, any aggrieved party can seek review by the Appellate Division, i.e. the initial level of appeals court in New York State. The court's scope of review is limited to whether:

  • The proceeding was in confonnity with the federal and state constitutions.
  • The proposed acquisition is within the condemning authority's statutory jurisdiction or authority.
  • The condemning authority's detennination and findings were made in accordance within the procedures of Article 2 of the law that deals with notifying the public of the detennination of need and location of a public project as required, and Article 8 of the Enviromnental Conservation Law, the state's environmental quality act.
  • A public use, benefit or purpose will be served by the proposed acquisition.

Note that this review does not consider value, but merely the steps taken to announce the project and detennination of public good.

Appraisal and Offer - At this point in the condemnation process, the property to be acquired by the condemning authority would be appraised on behalf of the authority by a certified appraiser. 26 The condemning authority shall have the right to inspect the property prior to vesting of title in the authority. The condemning authority is under a statutory obligation to establish an amount it believes represents just compensation for the property. The condemning authority would then make a written offer to the property owner to acquire the property. Whenever possible, the condemning authority should make the offer prior to acquiring the property and should, whenever possible, include within the offer an itemization of the total direct, the total severance or consequential damages, and benefits as each may apply to the property27 The property owner may either accept the offer as payment in full or reject the offer and instead elect to accept such offer as an advance payment, in which case such election would not prejudice the owner's right to claim additional compensation. Upon the acceptance of the written offer, the condemning authority would enter into an agreement or stipulation with the owner providing for payment pursuant to such arrangement either as payment in full or as an 25 The statute specifically exempts projects involved in proceeding under Articles 7 and 8 of the Public Service Law covering transmission projects and major electric generating facilities, respectively. Article 8 was replaced by Article 10 which expired at the end of 2002.

26 A tirneline is provided as Attachment 2.

27 We note that the owner holding, using or occupying the property acquired by this process would be liable to the condemning authority for the fair and reasonable value of such holding, use or occupancy from the date of the acquisition to the date the property is vacated and possession is surrendered to the condemning authority.

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advance payment. The offer would be deemed rejected in the event that the owner fails or refuses to notify the condenming authority in writing within 90 days that the offer is accepted.

Condemnation Proceedings - Under the EDPL the County may commence proceedings to acquire IP up to three years after the conclusion of the latter of:

  • Publication of its determination and findings concerning the public need and location of the project (referred to as an acquisition map) pursuant to Article 2 of the EDPL;
  • The date of the order or completion of the procedure that constitutes the basis for exemption from making such pre-acquisition determinations and findings; or
  • Entry of the final order or judgment on judicial review 28 The condemning authority would begin the process of obtaining an order to acquire the property and for permission to file the acquisition map by presenting a verified petition to the State Supreme Court in the judicial district where the property to be acquired is situated, in this case Westchester County. The condemning authority would also file a notice of the proceeding with a description of the property and the names of the land-owners in the office of the County Clerk where the property is located.

At least 20 days prior to the return date of the petition, the condemning authority must serve a notice of time, date, and place of the proceeding upon the property owners as well as a proposed acquisition map. Between 10 and 30 days before the return date of the application, the condenming authority would advertise such action and map for ten successive issues in a general circulation newspaper in the area.

The condemning authority would then present the State Supreme Court with a petition stating that the appropriate procedure has been followed. The property owner may appear and interpose a "verified answer" which must contain a specific denial of each material allegation of the petition questioned by the owner in a manner constituting a defense to the proceeding.

Unless the court adjourns the application, the court would direct the immediate filing and entry of the order granting the condemning authority's petition and file it, along with the acquisition map, in the office of the county clerk in which the property is located. Upon the filing of the order and the acquisition map, the acquisition of the property would be considered complete and title to the property would be vested in the condemning authority 29 28 If the County were to fail to commence proceedings to acquire IF before the expiration of the three-year period, the condemnation effort would be deemed abandoned, and the County would have to complete the pre-acquisition hearing and publication requirements again prior to restarting the acquisition proceedings.

29 Note that if, after acquisition, the condemning authority abandons the property and the property has not been materially improved, the condemning authority may not dispose of the property or any portion of it for private use within 10 years of the acquisition without first offering the former owner a right of first refusal to purchase the property at the amount of the fair market value at the time that the fonner owner is offered the property.

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Compensation Aooeal - Once the order and acqUisItion map are filed, the condemning authority would serve a notice of acquisition upon the owner within thirty days or publish such information for ten consecutive days in a paper of general distribution in the area. If the owner believes that the monetary offer for the property is insufficient, the owner must file a claim for damages within three years from the later of the date of notice of acquisition or date of vesting of title. The State Supreme Court in Westchester would have jurisdiction in the case of IP, and would have the authority to determine the compensation due Entergy. The Court would also have the jurisdiction to determine all questions relating to title and priority of interests relative to the acquisition. In the course of this proceeding, the Court may be faced with appraisals submitted by the owner as well as the one that the condemning authority is required to prepare and submit.

The Court, after hearing the testimony and viewing the appraisals, would determine the compensation due to the owner for damages as the result of the acquisition. The decision of the Court would result in the preparation and entry of an appropriate judgment. The owner would be entitled to lawful interest from the acquisition date to the actual payment date. The Court has the power to make a final and binding determination of value, and there would be no assurance that the County's estimated compensation would not be significantly exceeded.

This is a major risk of the condenmation option.

If either party were to file an appeal, the condemning authority would pay such portion of the award to the Court from which appeal has not been taken. If an appeal is filed by any party, the condemning authority may deposit in a special interest-bearing account all or any part of the amount directed to be paid in the award other than any advance payment already made.

In the event that the condemning authority abandoned the procedure to acquire the property or a court of competent jurisdiction determined that the condemning authority was not legally authorized to acquire the property, the condenming authority would be obligated to reimburse the property owner an amount for actual and necessary costs, disbursements, and expenses including reasonable attorney, appraisal, and engineering fees, and other expenses actually incurred by the owner because of the condemnation procedure.

It should also be noted that Entergy could attempt to prevent or delay the condemnation through the commencement of litigation in federal or state court. Thus, it should not be assumed that the condemnation process would be as clear-cut as presented and it may be assumed that condemnation efforts would entail substantial litigation costs, involving attorneys' fees, experts' fees and other significant expenses.

2.4. COMPENSATION UNDER NEW YORK LAW The amount of compensation that the County would have to pay Entergy pursuant to the Supreme Court's final order is called an "award". New York courts have disapproved of the practice of making lump sum awards that do not identify the sources and estimates of value.

Instead, the courts make separate findings as to the amount awarded for the direct taking and the amount awarded for consequential damages, if any, setting forth the basis for each amount. Any award paid to Entergy must be "just" in an exercise of eminent domain. Under state law, consideration must be given to market value, improvements, direct loss, and 16 OAGI0000197_043

consequential loss in detennining the measure of damages. There are no fixed rules and there are no inflexible fonnulae to detennine a specific dollar amount to be awarded in a condenmation proceeding. Only the goal is fixed - a just and reasonable award that is the fair equivalent of the loss actually incurred. Such amount is usually expressed as the amount a prudent buyer might be expected to pay a willing seller in the open market, usually referred to as fair market value (FMV)3o The taking of public utility property (such as a power generating facility) by eminent domain presents unique problems of valuation. There are few comparable sales to assist in detennining FMV, and a limited market for such property (in the usual sense). The usual method of fixing the value of appropriated property by ascertaining its FMV, and the principal that compensation is measured by the loss to the owner, not the benefit or worth of a property to the taker, are not applicable to a taking of public utility property if they will result in a manifest injustice to the owner or to the public. Moreover, a taking of public utility property involves not only the physical assets but also the business, the two being practically inseparable. Lastly, the purpose of the taking must be considered, i.e. whether the condenmor is seeking removal of the property or the continued operation as a going concern. Thus, no rigid measure is prescribed for the detennination of just compensation, and one must exercise judgment according to the circumstances of the particular case.

Valuation Methods - There are three standard valuation methods that are typically used to estimate the FMV of properties - the Income Approach, Comparable Sales Approach, and Reproduction or Replacement Cost Approach. For properties that have a going concern value such as IP, the Income Approach is most often utilized, and the other valuation methods are often used to support the Income Approach. LAI has considered values for IP using all three approaches, but has relied on the Income Approach to calculate the compensation amounts as described in the Plant Valuation of this report.

  • The Income Approach relies on an estimate of the future net income or cash flow that can be reasonably realized from the property. The future cash flow is usually discounted to arrive at a present equivalent value of those future cash flows.

Alternatively, the net income expected to be earned can be capitalized by a percentage figure representing the acceptable return that a willing buyer could anticipate on his investment. In either case the discount factor or the capitalization rate must reflect the benefits and risks of the subj ect property, market conditions, and other key detenninants of value. LAI has prepared a discounted cash flow (DCF) estimate of IP's value based on reasonable and supportable estimates of revenues, expenses, and net income that would accrue to Entergy.

  • The Comparable Sales Approach (also referred to as Market Data Evaluation) relies on an analysis of data from sales of comparable properties. Comparability does not 30 FMV is based on the highest and best use to which the property could be put and not on any such limited use to which a particular owner might happen to be putting it to at the time of the its appropriation. Thus FMV could be predicated upon a higher and better use than that for which the property is currently being utilized, but this is not relevant to the IF property.

17 OAGI0000197_044

necessarily connote many sales, and it does not necessarily mean identical properties.

In this case comparable properties are domestic nuclear plants that are exposed to market risks, i. e. merchant plants that are not utility rate base property. There have been seven financial transactions involving merchant nuclear plants that have market risk since the first IP unit was sold to Entergy.

  • The Reproduction Cost Approach involves estimating the cost of reproducing the subject property as long as the property would be replaced in kind. A similar method, the Replacement Cost New Less Depreciation Approach relies on the current cost of a property of equivalent function built to current standards and under current conditions.

Both the Reproduction and Replacement Cost Approaches include all reasonable and necessary expenditures in the recreation of the existing or an equivalent structure.

Past Appraisals - The New York Office of Real Property Services (ORPS) is a state entity whose purpose is: "To lead the State's efforts to support local governments in their pursuit of real property tax equity." ORPS is governed by a Board of five members appointed by the Governor, with the advice and consent of the Senate. The Board chairperson is designated by the Governor, and their eight-year terms are staggered so that no two members' terms expire in the same year. The Board oversees administration of real property assessments in New York State, including (i) estimating the full value of real property in towns and cities for equalization purposes, (ii) assisting local governments to improve the administration of their property assessment and tax systems so they are equitable for taxpayers, and, (iii) training and certifying assessors and county directors of real property tax services.

While an appraisal for tax purposes is not necessarily the same as an appraisal for eminent domain purposes, ORPS prepared a valuation of IP for the Town of Cortlandt's 2001 tax equalization rate. However, IP currently makes PILOT payments under agreements dated January 1, 2002 that were negotiated with Cortlandt, the Hendrick Hudson School District, and the County. While ORPS does not prepare valuations for any property covered under a PILOT agreement, informal discussions with ORPS indicated that the Income Approach, using a DCF calculation, would be the most appropriate method in valuing IP, and that the Cost Approach and the Comparable Sales Approach would be less useful. This is entirely consistent with LA!' s approach in this report.

2.5. WESTCHESTER COUNTY LAWS AND REGULATIONS Chapter 233 of the Westchester County Charter, entitled Board of Acquisition and Contract,

§233.2l, describes the conditions and the process under which the County may acquire property by condemnation. It should be noted that this section was placed in the Charter in 1948 and hence prior to the passage of the EDPL:

"The County Board may, or shall, when required by law, authorize the acquisition by the county of title to, or any interest in, real property for any purpose. .. Wherever and whenever in any general, special or local law it is provided that property may be acquired 'by condemnation' or 'by condenmation proceedings' or by similar methods, the county is hereby 18 OAGI0000197_045

authorized and empowered to acquire title thereto under the provisions of this title."

§233.31(l) of the Charter continues as follows:

"Whenever the County Board has authorized such acquisition and has made an appropriation therefore, the Board of Acquisition and Contract may acquire the property by purchase, condenmation or otherwise, and if the property is to be acquired by condemnation, the compensation to be made to the owner or owners thereof shall be ascertained pursuant to the provisions of this title."

Subsection 2 of §233.31 of the County Charter is aimed at the possibility that the County might acquire "utility property":

"If the property or any interest therein to be acquired hereunder is owned or held and used for a public utility purpose by a public or private corporation, the county, at its own option, may (a) allow such corporation, in lieu of any and all damages, without expense, loss or damage, directly or indirectly to it, to continue the use of the same for such purpose, with, however, not rights in excess of those existing previous to such acquisition or inconsistent with the use for which the property or interest with the use for which the property or interest is be acquired, or (b) may allow such corporation, in lieu of any and all damages, the use of such other real estate owned by the county or to be acquired for the purposes of this title as will afford a practical route, location or use for such public utility purpose and is commensurate with and adapted to its needs, provided also that such corporation shall not directly or indirectly be subj ect to any expense, loss or damage by reason of such change in route or location, but such expense, loss or damage shall be borne in like manner as the expenses incurred for carrying out the provisions of this title, or (c) may direct that compensation or damages be ascertained and awarded to such corporation, in which case such corporation shall be governed by the provisions of section 233.81 of this article."

Thus it appears that section (b) above describes the ability of the County to provide alternative real estate for Entergy to use to construct another generation facility to replace IP, if required.

2.6. COUNTY OF WESTCHESTER PUBLIC UTILITY SERVICE AGENCY Chapter 875 of the Westchester County Charter, Public Utility Service Agency, lays out COWPUSA's rights and responsibilities 31 The legislation creating COWPUSA was drafted in 1982 and the legislation was passed in that year by a public referendum. The introductory language notes that the County had been concerned for some time with the high cost of electricity in the Con Edison service area and its effect on the economic growth and well being of the County. The charter provision states "The creation of a County Public Utility 31 Provided as Attachment 3.

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Service Agency will enable the county to contract for or otherwise purchase or acquire lower cost electric energy in the fonn of hydroelectric power and other economical fonns of electricity from the State of New York or from any state agency, municipal, public or private corporation. "

  • §875.31(l) under Powers and Duties states "the agency, on behalf of the county, shall have the power to establish, construct, lease, purchase, own, acquire, and/or operate a public electric utility service within and/or without the territorial limits of the county for the purpose of furnishing to the county or for compensation to inhabitants of the Con Edison Service Areas of the county any electric service similar to that furnished by any public utility company ... "
  • Subsection (2)(f) states that the agency "Shall have the authority to enter into contracts, leases and other instruments and to acquire, hold and dispose of real or personal property necessary and convenient to the exercise of its powers."
  • Subsection (3) states "Nothing herein should be construed as authorization for the county or the agency on behalf of the county to exercise any power of condemnation or to establish generation, distribution, and/or transmission facilities separate from the Con Edison generation, distribution, and/or transmission system in the Con Edison Service Area of the county."

COWPUSA does not have the power to own and operate generation facilities if the County wanted either to continue operating IP for some period of time or to play an active role in replacing the lost IP capacity. Thus COWPUSA could not be the municipal corporation that would condemn the IP property and take over ownership. However, COWPUSA could operate a "public utility service" in which it would buy power on a wholesale basis and sell power on a retail basis to residents in Westchester. In particular, COWPUSA could purchase power from a replacement power plant owned and operated by Entergy, thereby encouraging replacement generation at the IP site. The merit of COWPUSA purchasing power under a PPA would hinge of COWPUSA's ability to develop a significant customer base.

2.7. TAX-ExEMPT FINANCING Tax-exempt financing is considered in this assignment for three distinct potential purposes: (i) providing a compensation payment to Entergy to retire IP under a voluntary agreement, (ii) compensating Entergy for the acquisition of the existing IP plant through eminent domain, and (iii) financing a replacement plant at the IP site. There are three possible issuers of such debt: the County, WIDA, and COWPUSA if the enabling legislation were broadened to allow the agency to allow it to own and operate a power plant and to issue tax-exempt bonds to purchase an existing asset or own an asset. 32 32 Any changes to the COWPUSA legislation would involve approvals by the County legislature and, possibly, by public referendum; COWPUSA's authority could potentially be expanded by state legislation.

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Tax-exempt debt is a low-cost way to raise funds due to the bondholder's ability to avoid paying federal and state income taxes on the interest and principal income. The County has an AAA credit rating, the highest available and the same rating as the federal government, indicating that rating agencies believe the risk of County default is very low. Any bonds would be GO bonds that would obligate the County and its residents, through tax revenues, for repayment of principal and interest. Any County GO issuance over $10 million must be approved though a public referendum. As of September 2004, the County had total debt outstanding of $705.7 million and net indebtedness of $563.1 million, equivalent to 9.6% of the County's net debt limit of $5.79 billion 33 The County's AAA credit rating means the cost of raising debt funds would be low, especially compared to corporations 34 However, a large issuance, e.g. on the order of $1 billion or more, would likely cause the County to receive a lower credit rating, raising the cost of debt for this and future issuances. Informal discussions indicate that the credit rating would slip in the event of an issuance of the size necessary to fund the compensation payment to Entergy for IP. If the County were to issue GO bonds, the standard practice is to issue series of bonds with varying maturities that result in level principal payments. Under recent market conditions, the average interest rate for a series of GO bonds that had a twenty year final maturity would be 3.8%-4.0%; a thirty year final maturity would be 4.2%-4.3%. These interest rates reflect the anticipated reduction in the County's credit rating to AA or A. The cost to each of Westchester's one million residents for a $1 billion tax-exempt GO bond issuance would be about $70 per year over twenty years, or $55 per year over thirty years if debt service payments were spread out over a longer period oftime 35 Based on informal discussions with County's staff and others, a general description of each of the three issuers and the advantages / disadvantages are as follows:

  • The County can issue GO bonds for public purposes subject to a County bonding limit and other restrictions. The County has sufficient debt capacity to pay Entergy, but credit rating would likely be impaired. In addition, it may be more difficult to issue GO bonds under the voluntary retirement arrangement. The County may be required to have an ownership-type interest to satisfy State regulations concerning municipal finance. This issue requires additional investigation, probably with the County's bond counsel, and any debt issuance to compensate Entergy without an ownership-type interest in IP may require State and County legislation.
  • The WIDA is an intermediary for borrowers that use the funds for investments that benefit County residents. Any WIDA bonds would be Revenue Bonds in which revenues earned by the borrower would be pledged to the bondholders. Interest and principal payments could only be made from borrower revenues, and neither the County nor the WIDA would be responsible for any contributions. Revenue bonds 33 The County debt limit is 7% of the five year average full valuation of taxable real estate.

34 By way of comparison, Entergy is rated BBB.

35 Based on these estimated interest rates, LAI assumed a County discount rate of 4.0% for this assignment.

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may be tax-exempt provided the underlying investment satisfies IRS and state rules.

The WIDA has significant flexibility to issue debt, but is subject to a state volume cap that limits the amount of debt that can be issued in anyone year. 36 If IP were acquired through acquisition or were voluntarily retired there would not be any revenue stream to support WIDA bonds. However, it may be possible for WIDA to facilitate on-site replacement generation if the relevant federal tax laws were changed to permit the se of tax-exempt financing for the private use of a new power plant.

  • COWPUSA does not currently have any authority to condemn, issue debt, or own power generation, transmission, or distribution facilities. If COWPUSA were authorized to issue debt, it is likely that it would be restricted to power generation, transmission, and distribution assets in keeping with the spirit of its original purpose, and thus may not be able to issue debt to compensate Entergy under a voluntary retirement arrangement. Bonds issued by COWPUSA would avoid a state volume cap allocation and would not be subject to local furnishing rules.

Acquisition of IP - If the County were to acquire IP by eminent domain, the County could issue GO bonds (subject to the conditions identified above )37 Voluntary Retirement - If Entergy were to retire IP under a consensual agreement, Entergy would retain ownership of the plant. One of the potential issuers of any debt needed to fund the payment of compensation to Entergy would be Westchester County, since there would not be a revenue-generating asset immediately in place that could support WIDA Revenue Bonds.

In the event that the County wanted to compensate Entergy through another mechanism, GO bonds could also be used to purchase a portion of the IP site not required for decommissioning or SNF purposes. We do not have sufficient information about the site and plant layout to estimate the potential acreage that could be purchased, or the price per acre that the County could reasonably pay. The County would need to be assured that any GO bond issuance satisfied New York municipal finance regulations.

Replacement Plant - If Entergy were convinced to retire IP and construct replacement generation at the IP site, it appears that tax-exempt financing may not be possible under present law. The County is prohibited from using GO bonds for private purposes. WIDA can issue Revenue Bonds, but financing a replacement power plant may not qualify for tax-exempt status. Power plants whose output was consumed locally used to be able to qualify for tax-exempt treatment of debt prior to 1997, but that option, referred to as "local furnishing" or the "two county rule", is no longer available 38 Westchester could urge its 36 New York State caps the total amount of public tax-exempt financing that can be issued annually. Issuers must receive an allocation of the annual volume cap in advance.

37 Legal and financing issues regarding the ability of New York State to acquire IF by eminent domain was outside the scope of our assignment.

38 Prior to 1997, power plants that could demonstrate that all of their output was consumed within an area no larger than (i) a city and one contiguous county, or (ii) two contiguous counties, could qualify for tax-exempt debt financing under local furnishing provisions. The IRS has tightened the requirements for a number of categories that qualify for tax-exemption. As of January 1, 1997, the owner of such a power plant (cont'd) 22 OAGI0000197_049

Congressional representatives to amend the tax code to permit such a financing. Further, as noted above, COWPUSA does not currently have authority to finance a power plant 39 Our findings regarding the potential issuers of tax-exempt bonds are summarized in the table below:

Table 6 - Sources of Tax-Exempt Financing Payment to Entergy IP Acquisition Replacement Plant Westchester County Yes Yes No Westchester IDA No No Unlikely COWPUSA No No Not presently 2.S. NUCLEAR REGULATORY COMMISSION REGULATIONS License Transfers - Nuclear power plants have traditionally been built for, owned, and operated by electric utility companies. In general, these utilities have regulatory and fiduciary responsibilities for operations and decommissioning that are based on a single owner over the plants' life-cycle. Over the past decade, deregulation, competitive market forces, and other economics of ownership have led to many nuclear plants changing hands. In every case the NRC has approved the transfer of the plant asset, i.e. ownership, and operating authority, i.e.

license. In Table 7 we list the approved license transfers as of year-end 2003.

An applicant must satisfy a variety of technical and financial qualifications regarding the ability to own and operate a specific nuclear plant in order to receive NRC approval to take over an operating license 40 The federal requirements that govern NRC approval include, but are not limited to, the following sections of the Code of Federal Regulations (CFR):

  • 10 CFR Part 2, Subpart M - Public Notification, Availability of Documents and Records, Hearing Requests and Procedures for Hearings on License Transfers
  • 10 CFR 50.33 - Contents of applications, general information
  • 10 CFR 50.75 - Reporting and recordkeeping for decommissioning planning
  • 10 CFR 50.80 - General guidance for transfer to licenses would have to demonstrate that it has been actively involved in the local furnishing of electricity in Westchester prior to that date. It does not appear that Entergy could satisfy this requirement.

39 See footnote 26 40 Section 184 of the Atomic Energy Act of 1954 and NRC regulations 10 CFR 50.40.

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  • 10 CFR 50.140 - Financial protection requirements and indemnity agreements Table 7 - Nuclear License Transfers 41 Plant Old Licensee New Licensee Three Mile Island-I GPUInc. AmerGen Pilgrim Boston Edison Co. Entergy Clinton Illinois Power Co. AmerGen Oyster Creek GPUInc. AmerGen FitzPatrick NY Power Authority Entergy Indian Point 3 NY Power Authority Entergy Nine Mile Point I & 2 Niagara Mohawk Power Corp. Constellation Energy Peach Bottom I. 2 & 3 Conectiv ExelonlPSEG Hope Creek Conectiv ExelonlPSEG Salem I & 2 Conectiv ExelonlPSEG Millstone I Northeast Utilities Dominion Energy Millstone 2 Northeast Utilities Dominion Energy Millstone 3 Northeast Utilities Dominion Energy Indian Point I & 2 Can Edison and NYPA Entergy Vermont Yankee Vermont Yankee Entergy Seabrook Unit I N. Atlantic Energy Service FPL Group.

Beaver Valley I & 2 Dusquesne Light Co. Inter-Utility Davis-Besse T aledo Edison Co. Inter-Utility Perry Cleveland Elec. Illuminating Inter-Utility Duane Arnold IES Utilities Inter-Utility Kewaunee Wisconsin Public Service Inter-Utility Point Beach I & 2 Wisconsin Public Service Inter-Utility Monticello Northern States Power Inter-Utility Prairie Island I & 2 Northern States Power Inter-Utility Technical requirements focus on the applicant's ability to operate and maintain the plant safely. The applicant must demonstrate the appropriate staff size, training, nuclear power plant management experience, etc. The NRC evaluates the applicant's financial qualifications to fund all operations, including maintenance, repairs, as well as decommissioning and spent fuel management, i.e. on-site storage and future shipment to Yucca Mountain. The NRC also requires owners to put in place sufficient insurance and to obtain funds necessary to operate the plant safely.

The County does not currently have the ability to meet most of the NRC's requirements. In theory, it would be possible for the County to put in place a management / operating /

maintenance team to take over IP and satisfy the NRC's regulations. The County would have three options in this regard: (i) hire experienced and capable staff internally, (ii) execute a contract with Entergy to utilize the existing IP staff, or (iii) execute a contract with another 41 Source: NRC and NEI 24 OAGI0000197_051

company that can operate (or at least maintain) IP and then transition to decommissioning and spent fuel management. In practice, however, any option that would allow the County to take over IP would be expensive, difficult, and would take several years to implement. In addition to the many operational hurdles, the ownership of a nuclear plant would subject the County to significant and potentially expensive risks.

License Extension - Entergy operates IP2&3 under Operating Licenses granted by the NRC that will expire on September 28, 2013 and December 12, 2015, respectively. In order to obtain license extensions, Entergy would have to prepare and submit applications several years prior to the expiration dates that address safety (especially the aging of systems, structures, and components) and environmental issues 42 The NRC staff would then conduct a thorough evaluation of these issues and prepare reports. Safety findings would then be presented to the Advisory Committee on Reactor Safeguards, an independent group comprised of academic and scientific experts that reviews NRC staff reports. Safety and environmental reports prepared by NRC staff are subject to public review and meetings, and formal adjudicatory hearings may be required. The entire process can take many years, so owners apply for license renewals as much as five years or possibly longer, before the initial expiration date.

Recent experience indicates that nuclear plant owners are requesting and receiving twenty year life extensions at the end of their initial license terms unless (i) there has been an accident (e.g. Three Mile Island 2); (ii) there is a significant technical problem such as nozzle cracking, boric acid leakage, or corrosion, or economic conditions of significant nature or magnitude makes continued operation impractical or uneconomic; or (iii) in the case of a municipal utility, there was significant public pressure and a willingness by the residents to shut down and bear the decommissioning and replacement power costs (i.e. Rancho Seco).

There have been a number of plants that have been shut down, especially for technical or 43 economic reasons In every other instance, the NRC has granted license extensions to the nuclear plant owners that have requested them. A list of plants that have received license extensions is provided below.

42 10 CFR 54 and 10 CFR 51, respectively.

43 Plants that have been shut down prior to or at the end of their NRC license tenn include Zion I &2, Millstone I, Maine Yankee, Connecticut Yankee, Trojan, San Onofre I, Yankee Rowe, Shoreham, Fort st. Vrain, Rancho Seco, Three Mile Island 2, Dresden I, Peach Bottom Unit I and Indian Point 1.

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Table 8 - Nuclear Plant License Extensions 44 Plant Owner Extension Date Calvert Cliffs, Units 1&2 Baltimore Gas & Electric 3/23/00 Oconee Nuclear Station, Units I, 2, & 3 Duke Energy 5/23/00 Arkansas Nuclear One, Unit I Entergy Operations, Inc. 6112/01 Edwin I. Hatch Nuclear Plant, Units 1&2 Southern Nuclear 1/7/02 Turkey Point Nuclear Plant, Units 3&4 Florida Power & Light 7117/02 North Arma, Units 1&2 and Surry, Units 1&2 Virginia Electric & Power 3/20/03 Peach Bottom, Units 2&3 Exelon Generation 5/7/03 St Lucie, Units 1&2 Florida Power & Light 10/2/03 Fort Calhoun Station, Unit I Omaha Public Power 11/4/03 McGuire, Units I &2 and Catawba, Units 1&2 Duke Energy 12/3/03 H.B. Robinson Nuclear Plant, Unit 2 Carolina Power & Light 4119/04 RE. Ginna Nuclear Power Plant, Unit I Rochester Gas & Electric45 5119/04 Vc. Summer Nuclear Station, Unit I S. Carolina Gas & Electric 4/23/04 Dresden Units 2&3, and Quad Cities Units 1&2 Exelon Generation 10/28/04 In addition to IP, there are three other nuclear power stations with a total of four reactors in New York. Rochester Gas & Electric commenced the license renewal process in August of 2002 for the 497 MW RE. Ginna plant, now owned by Constellation Energy. The final NRC approval occurred just under two years later. The license for the 840 MW lA FitzPatrick plant expires in October 2014. The licenses for Nine Mile Point 1&2 expire in August 2009 and October 2026, respectively.

Entergy has filed license extension applications for the two units at its utility-owned Arkansas Nuclear One station. The NRC approved an extension for Unit 1 in June 2001, and is scheduled to issue a decision for Unit 2 in August 2005. Entergy planned to submit an application to extend the license for the non-utility Pilgrim nuclear plant in December 2004, and filed a Proposed Schedule of Submittal of License Renewal Applications that envisioned five additional applications over the next three years 46 An Updated Schedule was submitted to the NRC on May 19, 2005 that identifies a January 2006 application date for Pilgrim.

Although the plant identities are not specified in either the Proposed Schedule or Updated Schedule, it is likely that the applications to extend the IP2&3 licenses are included.

If the NRC did not approve license extension for IP2&3, Entergy would have to cease operations and commence decommissioning and SNF activities as described in section 5 of this report. While this scenario would provide the County with its desired outcome without incurring compensation costs, we reiterate the point that the NRC has not denied an application to date. Therefore LAI does not recommend that the County rely on a strategy of convincing the NRC to reject Entergy's application to extend the IP licenses.

44 Source: NRC 45 Constellation Energy recently purchased the RE. Ginna plant 46 Accension Number ML031280234 26 OAGI0000197_053

Challenges for IP License Extension - Current power prices in New York, buoyed by high natural gas and oil prices, improve the economics of nuclear power plant life extension. In downstate New York, market energy prices during on-peak hours are strongly correlated with commodity gas prices. Increasingly, downstate market energy prices during off-peak hours are correlated with gas prices as well. The outlook for natural gas prices over the remainder of this decade reflects tight supplies and robust demand; hence, a material decline and sustained reduction in commodity prices is not likely. Against the backdrop of high fossil fuel prices, Entergy's commitment to nuclear power coupled with NYISO's fuel diversity and bulk power security requirements are likely to result in Entergy's application to the NRC for license extensions for IP2&3.

Nevertheless, IP has many unique challenges that must be met in order to be relicensed, including receiving approval of the design to convert the once-through river water cooling system to closed-cycle cooling towers. While presently outside the NRC's typical license extension scope of review, ongoing security concerns and emergency evacuation plans also represent compelling regulatory challenges. If security concerns and emergency evacuation issues are added to the NRC's scope of review as the County has recently urged, the issue of relicensing may become more problematic for Entergy and any relicense could be conditioned upon security and evacuation requirements that involve substantial costs to Entergy.

Moreover, the application for license extensions would undergo a review process that would include public involvement; hence, interveners may raise the adequacy of plant changes and modifications, both those already installed and any that need to be installed, to ensure that the plant is built and operated to current standards. While there may be systems and/or components at IP2&3 that are "grandfathered" against current regulatory requirements, most are not grandfathered and could be challenged. We believe that the principal challenges for Entergy to satisfy NRC requirements are as explained below:

Design Verification - Like all plants built in the 1960s and 1970s, IP2&3 were designed to meet the nuclear design standards in place at that time. In order to have their licenses extended, Entergy will have to demonstrate that all safety-related systems, structures, and components meet current, more stringent, design and construction standards, which may require additional design work and Cap Ex.

Examples of these design standards include fire protection systems / requirements (e.g.

cable separation and alternate reactor shutdown capabilities), seismic design, and upgrading / implementing the necessary quality assurance programs. During the re-licensing process, the NRC will examine the proposed closed-cycle cooling system that would be included with Entergy's license extension application. The NRC will focus on safety considerations, including the design, location, and component safety classification and construction requirements of the proposed closed-cycle cooling system. This would include potential impacts to IP's systems, structures, and components that are important to safety if the proposed closed-cycle cooling system, including the cooling towers, were to fail, as well as how Entergy has incorporated an "ultimate heat sink" to provide emergency cooling in the closed-cycle design. In addition, the NRC is currently reviewing its relicensing criteria and it is possible that more stringent standards may be imposed.

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Emergency Planning - IP is 35 miles from New York City. While IP's location may not have been a critical issue when the licenses were issued thirty years ago, the NRC is sensitive to location issues in today's post-9/ll environment. Strictly speaking, the location of previously approved nuclear plants has not typically been a factor in NRC license extension decisions. However, the County is urging that the NRC formally change its regulations to include emergency evacuation as a relicensing factor. In reality, evacuations in the event of an emergency will be problematic without the active cooperation of the local towns and Westchester County. While there have been instances of the NRC approving Emergency Plans that lacked local support, we anticipate that Entergy will experience greater difficulties as a result of the high level of embedded mistrust about plant safety by County residents .. Moreover, the relative proximity of IP to New York City adds an additional level of concern. There may be vocal opposition to NRC relicensing from New York City as well as from the other surrounding counties, i.e. Rockland, Putnam, and Dutchess.

Environmental Impacts - IP will have to install a closed-cycle cooling system to operate beyond the terms of the existing licenses. The most prominent feature of the system will be cooling towers that must be sited to maximize air flow and dispersion.

This presents a logistical challenge for Entergy - the bluffs above the units would be the ideal site, but natural draft cooling towers would create a plume of evaporated cooling water. This would be of particular concern during winter operations when icing conditions would be created on downwind structures and roads, possibly for several miles. Forced draft cooling towers are an alternative, but require more space and have higher operating expenses.

Financial Risk - To the extent that IP2&3 would have to be back-fitted involving lengthy programs to construct cooling towers and tie into the existing plants, that work may be required to be completed, or at least started, prior to the final decision on the license extension. This type of construction project requires significant planning and effort, and the potential risks of design, construction, cost, and schedule would add to Entergy's license extension risk. Therefore our analysis assumes that IP faces financial as well as technical risk in obtaining license extensions from the NRC. We have factored these risks into our analysis by estimating IP's value assuming no license extension (thereby avoiding the cooling conversion costs) and with license extension (with the associated CapEx).

Opportunities for Public Participation - Assuming that Entergy does apply for extensions to the existing licenses, the County and its residents will have opportunities to express their opinions through public hearings and comments. The County and residents could also question the adequacy, planning and implementation ofIP's Emergency Plan. If the County or residents can demonstrate that they would be adversely affected by the extension, they could request a formal adjudicatory hearing before a three person licensing board 47 Parties would be able to present witnesses at the formal hearing who could be questioned and cross-examined. The board would then establish a record with full findings of fact for the NRC to 47 10 CFR Part 2 28 OAGI0000197_055

make its license extension decision. However, having a formal hearing would not provide any party with new or expanded grounds for NRC to deny a license extension.

Zoning Variance - In addition to NRC approval of license extension, Entergy will likely require a zoning variance. IP is in the M-2 zoning classification which is noted as "Planned Industrial District" within the Village of Buchanan. Permitted uses in this zone include gas stations, auto repair shops, oil change facilities, and a gypsum board manufacturing plant.

Uses by Special Permit of the Planning Board or Zoning Board of Appeals include sheet metal shops, lumber yards, masonry supply, welding, plumbing, heating and alc businesses, and "peaceful use of atomic energy". Entergy received a variance for a support building at the IP site in 2002, a copy of which is provided as Attachment 4. The variance decision increases the height permitted in the zone from 35 feet (which is usual for industrial zones) to 59 feet, plus an additional 10 feet for a roof screen to conceal mechanical systems. Thus the construction of cooling towers, which could be as large as 300 feet in diameter and 550 feet in height, would require a new variance and provide an opportunity for County and residential opposItion. However, state and local efforts to take safety-related decisions concerning nuclear facilities appear to be preempted by federal law.

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3. REPLACEMENT GENERATION 3.1. INTRODUCTION The New York State Reliability Council has adopted an electric reliability standard of one outage in ten years, a common standard used throughout the U.S. NYISO adopted a statewide installed reserve margin of 18% to achieve this reliability standard 48 In addition, New York City and Long Island have locational capacity requirements that recognize transmission limitations into those areas. An analysis of the New York reserve margin (with IP2&3 in service) indicates that the State is expected to have sufficient generating resources through 2010, and that new generation capacity will be required starting by 2011. Much of this new capacity will be required in the downstate region where most of the demand growth is located, since there is not sufficient transmission capacity to deliver additional power from the western or northern parts of the state. In every case we evaluated, except the unrealistic immediate retirement case, we assume that enough replacement capacity would be developed to maintain the State's 18% reserve margin target.

Project developers are keenly tuned to market dynamics in New York. They would realize that retiring IP would cause market energy and capacity values to increase across the downstate region. These price signals would be important, given IP's size and location, to encourage the development of new generation andlor transmission projects that would replace the lost capacity. These new generation projects could include decentralized and renewable resource options. If the retirement of IP were announced in advance, developers would be able to calculate the economic feasibility of their projects and pursue those that make financial sense in time to maintain the state's reliability requirement. In addition, utilities in the downstate regions might offer long-term PP As for new replacement generation. PP As offer generators market certainty and reduce price risk, improving the opportunity for owners to obtain debt and equity financing in today's skittish financial markets.

The developers' ability to respond to market price signals and the utilities' interest in contracting for new generation are central to our analysis. We believe that developers would require a minimum of three-to-four years to plan, permit, and construct a gas-fired combined cycle project. Perhaps six months to a year could be shaved off the time for a simple cycle project 49 The early project development work can often be accomplished at minimal cost, even if a formal retirement plan was not announced, in order for the developer to get a "head start" on competitors 50 Such tasks encompass conceptual design, site control, preliminary 48 An 18% reserve margin requires that the installed generating capacity in New York at the time of the statewide peak demand must be at least 118% of that peak demand.

49 Simple cycle plants are comprised of gas turbines and electric generators, are relatively inexpensive to construct, are relatively expensive to operate, and are well-suited to peaking duty. Combined cycle plants are more expensive to construct because they add heat recovery stearn generators and stearn turbines to improve plant efficiency. As a result they are better-suited for intermediate or base-load duty, and operate at higher capacity factors.

50 Projects that have been proposed but are not being actively pursued described further on in this section, are consistent with this description.

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fuel supply and power offtake arrangements, and initial permit applications. The remaining project development and construction time would be approximately three years for a combined cycle plant, and less for simple cycle. Thus we would recommend that any voluntary retirement be announced at least three-to-four years in advance, to give the market enough time to develop replacement capacity 51 Acquisition by condemnation would take a number of years as well, again giving the market sufficient time to respond.

LAI has evaluated a broad list of generation and transmission alternatives to IP. Transmission alternatives within the state would also require generating capacity to maintain the state's reliability standard. Transmission alternatives that tie into neighboring markets could import firm energy (i. e. energy with capacity value) that would not require in-state generation. The cases that we considered are listed below. We note that the market generation responses imbedded in many of these cases could include a gas-fired power plant developed at the IP site.

  • Base Case with Retirement in 2013/2015
  • License Extension Case with Retirement in 2033/2035
  • Retirement in 2005 without Market Response
  • Planned Retirement with Market Generation Response
  • Retirement with Market Transmission Response 3.2. BASE CASE WITH RETIREMENT IN 201312015 The existing NRC license expiration dates of 2013/15 define our Base Case scenario against which we evaluate other options. If Entergy announced an agreement to retire IP2&3 on those dates at least three, and preferably four years in advance, there would be more than enough time for project developers and downstate utilities to respond. LAI has postulated a mix of gas-fired simple cycle peaker units and combined cycle plants that would be developed in or close to Westchester. The mix was determined by evaluating the forecasted economics of these plant types at the time the capacity is required, and then adding the plant type that is most financially attractive, i.e. has the lowest net capacity revenue requirement.

3.3. LICENSE EXTENSION CASE WITH RETIREMENT IN 2033/35 If the NRC licenses for IP2&3 are successfully extended for twenty years, no replacement plants would be required to replace IP capacity. In this scenario, our forecast of market energy prices include IP2&3 in the supply mix, but at lower levels of output as described in the Plant Performance section. Of course, there would still need to be some gas-fired capacity additions to meet load growth and maintain the state's 18% reserve margin requirement.

51 The development of replacement generation on the IP site itself could help mitigate adverse economic impacts to the local governments and the local economy.

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3.4. RETIREMENT IN 2005 WITHOUT MARKET RESPONSE LAI ran an extreme case in which IP would have been retired on January 1, 2005, without any market response in order to test the effects of the state having less than an 18% reserve margin 52 We believe this case is unrealistic, since project developers would take full advantage of the economic opportunity created by IP's retirement. Shutdown without a market response would prevent the state from achieving its 18% installed capacity margin and reduce the reliability of the bulk power system 53 Even if some type of immediate shutdown were mandated by an unprecedented State or federal government fiat, NYISO would likely implement some type of emergency capacity and energy replacement plan that would minimize the disruptions to the bulk power grid. 54 3.5. PLANNED RETIREMENT WITH MARKET GENERATION RESPONSE The absolute earliest retirement scenario, given a two-to-three year acquisition process, would be January 1, 2008. Under our base case assumptions, New York is expected to have 900 MW of capacity in excess of the 18% reserve margin in 2008. Therefore if IP2&3 were to be retired by 2008, approximately 1,100 MW of replacement generation would be needed in that year. This replacement capacity could be located at the IP site if Entergy or another developer pursued a project there, or could be located elsewhere in the downstate region. While gas pipeline upgrades may be required to serve a particular project, large-scale electrical transmission improvements would not be necessary in light of the existing transmission infrastructure from IP to New York City and Long Island. While the County is not obligated to replace IP capacity in the event of a successful condemnation or voluntary retirement, it would be beneficial to encourage replacement generation at the IP site in order to help mitigate adverse economic impacts to local governments and the local economy. In response to NYISO's recent implementation of the installed capacity demand curve mechanism, market participants would be motivated to develop replacement capacity. Investors' unwillingness to rely on volatile market energy prices and weakness in the capital markets might require Con Edison or other downstate utilities to enter into a compensatory PP A to help attract equity and debt investors.

The NYISO has divided up the state into eleven zones for planning purposes. Zones A-E comprise the western region, Zone F around Albany is referred to as the Capital District, 52 This case is comparable with the GE / NERA Study prepared for Entergy in March 2002, Electricity System Impacts of Nuclear Shutdown Alternatives, in which the authors focused on reliability, energy price, and consumer expenditure impacts. The authors assumed that there would not be any market response or NYISO action, leading to dramatic but umealistic conclusions of reduced reliability, higher energy prices, and higher electricity expenditures.

53 Quantifying the reliability impact on ratepayers, e.g. in terms of Loss-of-Load expectations, was beyond the scope of this assignment.

54 For example, ISO-NE and the local utility, Connecticut Light & Power, have recognized that the southwestern Connecticut region has insufficient generation and transmission infrastructure, and have issued "Gap" RFPs to locate generation within that region on a short-term basis to maintain local reliability until the planned 345 k V transmission projects are completed.

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Zones G, H, and I include Greene, Ulster, Dutchess, Orange, Putnam, Rockland, and Westchester and are treated as one region in our simulation modeling, Zone J is New York City, and Zone K is Long Island. Over the past few years, many plants have been constructed in New York City and on Long Island. Other projects that have been proposed in Zones G, H, and I but have not been developed are as follows:

  • Wawayanda - This is a 540 MW gas-fired combined cycle plant that was proposed by Calpine to be located in Orange County, i.e. Zone G. Wawayanda was designed to utilize two G E 7FB gas turbines, heat recovery steam generators, and a steam turbine, with dry cooling towers to minimize water consumption. Calpine submitted an Article X application to the NYPSC which certified the project on October 22, 2002.

Wawayanda was to be connected at new substation on NYPA's Marcy-South 345 kV line and was to receive gas via a 20 mile lateral to Tennessee Gas line in New Jersey.

Construction has not yet commenced.

  • Bowline - The 750 MW Bowline gas-fired combined cycle project was proposed at the existing Bowline plant (i.e. two 600 MW gas/oil units) by the plant owner, Mirant.

The project, located in Rockland County, i.e. Zone G, received Article X certification on March 26, 2002, but construction was halted by Mirant's bankruptcy. Bowline was designed to utilize three GE 7F A gas turbines, heat recovery steam generators, and a steam turbine, with hybrid cooling towers. The project was to be connected via upgrades on the existing transmission right-of-way, and was to receive gas via a new 4.2 mile lateral to Columbia.

  • Tome Valley - The 501 MW Tome Valley gas-fired simple cycle project was proposed by Sithe and was to be located in Rockland County, i.e. Zone G. The project was originally designed to be 827 MW combined cycle and was revised to 510 MW, utilizing three GE 7FB gas turbines. Tome Valley was to be connected to the Ramapo substation, but the Article X application was withdrawn in December 200l.
  • Ramapo - The 1100 MW Ramapo gas-fired combined cycle project was proposed by American National Power and was to be located in Rockland County, i.e. Zone G.

Ramapo was designed to utilize four ABB GT24 gas turbines and be connected to the Ramapo substation. American National Power submitted an Article X Application in January 2001, but withdrew the Application in September 2002.

Power plants greater than 80 MW built in New York formerly required approval of the New York State Board on Electric Generation Siting and the Environment (commonly referred to as the Siting Board) under Public Service Law Article X55 The Siting Board consists of members of the NYPSC, the DEC, and other stakeholders. The Article X certification bundled all state reviews and approvals, including air permits, siting, and water use /

discharge. Although the Siting Board encouraged conformance with local regulations, Article X obviated the need to obtain local permits. Upon Article X certification, virtually all of the 55 Projects less than 80 MW had to go through the State Environmental Quality Review process.

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Figure2-LocationofReplacement Generationby County and Zone OAGI0000197_061

York Control Area transmission system with the major interfaces defined in-state and with the Pennsylvania-New Jersey-Maryland (PJM) market.

Fignre 3 - New York Zones and Transmission Pathways Total Interface One of the four possible transmission alternatives involves the construction of a direct current (d/c) transmission line and the remaining three involve upgrades to the existing alternating current (a/c) network. In evaluating the three upgrade alternatives, LAI considered recent advances in conductor technology and their feasibility for the particular upgrades.

Traditionally, upgrading a circuit requires replacing existing conductors with larger more heat-resistant ones, which usually requires reinforcements to existing towers or installing new towers, an expensive proposition. In this regard, LAI considered the use of new conductor 56 designs that can increase the circuit capacity without needing to reinforce or replace towers.

Retirement with Empire Connection Market Transmission Response Several years ago, Conjunction LLC announced the development of the 140 mile Empire Connection Transmission project that would connect upstate New York, i.e. Zone F, the 56 Among the new technologies LA! considered include the Aluminum Composite Conductor Reinforced cable and the Aluminum Conductor Composite Core cable. These conductors are designed to double the electrical transmission capacity of conventional conductors of the same diameter without reinforcing or replacing towers, making the new conductor designs economical in many situations. The Aluminum Composite Conductor Reinforced conductor was recently installed in its first 345 kV commercial application, while the Aluminum Conductor Composite Core cable has had some recent installations at 230 kV but none at the 345 kV level.

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Capitol District around Albany, to the downstate grid, i.e. Zone J, New York City. The plan called for two physically separate d/c cable circuits to be buried underground along the existing Hudson River railroad right-of-way, with some portions mounted on poles above ground. Each of the +/- 500 kV circuits would be controllable and able to transmit 1,000 MW for a total of 2,000 MW. Circuit 1 would interconnect from a new substation near the existing Leeds substation, along the Leeds/Gilboa 345 kV line, to Con Edison's Rainey 345 kV substation. Circuit 2 would interconnect from a new substation near the existing New Scotland substation, along the New Scotland/Alps 345 kV line, to Con Edison's West 49 th Street 345 k V substation.

The project's Article VII Application to the NYPSC was originally filed on November 18, 2003. On August 5, 2004, Conjunction filed a supplement to the Application, which is under consideration by the NYPSC. The project's System Reliability Impact Study was approved by the NYISO on March 18, 2004. The study results showed that the performance of the New York bulk power system is not degraded by the project's interconnection. However, the project held an open season solicitation offering transmission capacity to market participants that was unsuccessful, rendering the Empire Connection project unlikely to be developed under current market conditions.

Empire Connection in and of itself would not provide replacement capacity for IP2&3. While it would provide a transmission pathway from the Capitol District to New York City, additional generation would have to be installed in Zone F to replace IP2&3 to maintain the statewide 18% reserve margin requirement. According to the Article VII filing, Empire Connection would cost about $750 million, equivalent to $375/kW for 2,000 MW, but detailed cost estimates were not provided. Based on the project's high cost, the inability to achieve certain development milestones, and the necessity of also adding new generation, Empire Connection is not a viable option in the 2008-2010 time frame.

LAI contemplated a modified Empire Connection project to take advantage of the 2,000 MW transmission pathway from Westchester to New York City that would be made available by retiring IP. This would reduce the project's cost by utilizing IP's existing terminal equipment at the Buchanan substation that would become available, and the cost of extending Empire Connection over the last few miles into Zone J would be avoided 57 While this modification would reduce the project's capital cost, doing so would deprive the project owner, Conjunction, with an important revenue source - the ability to arbitrage energy price differentials between Zone F and Zone J. Therefore we have not pursued this modified Empire Connection project as a viable option.

Retirement with Upstate New York Market Transmission Response A second transmission alternative would be to upgrade the existing 345 kV New Scotland-Leeds circuits and the 345 kV Leeds-Pleasant Valley circuits, and construct a new 345 kV 57 A new Article VII filing would need to be made and a revised System Reliability Impact Study submitted for this modification because this alters the original configuration.

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line from New Scotland to Pleasant Valley. This would increase the UPNY-SENY interface transfer capability (see Figure 3 above) by approximately 600 MW. As with other transmission alternatives, 600 MW of new generating capacity would have to be added in Zone F to take advantage of the increased transfer capability. The cost for upgrading the Leeds-Pleasant Valley circuits was estimated at $40 million plus $27 million to upgrade the New Scotland-Leeds circuits 58 LAI estimated the cost for constructing a new 345 kV line from New Scotland to Pleasant Valley. The resulting total cost is approximately $177 million, equivalent to $295/kW. This cost would outweigh the savings of building a combined cycle plant in Zone F as opposed to Zones G, H, or 1. Therefore LAI did not pursue this option for this assignment.

Retirement with Western New York Market Transmission Response There have been a number of studies to increase the transmission interface limit across the Central-East interface to transmit more power from western New York. The most recent plan would be to convert the existing single 345 kV Marcy-New Scotland circuit to a double circuit and to rebuild the New Scotland station to a breaker-and-a-half design. This would increase the Central-East transfer capability by approximately 650 MW and increase the transmission capacity into Zone J by approximately 450 MW. We estimated the cost of this alternative at $143 million, equivalent to $220/kW. Even though this option is less expensive than the upstate New York option, the cost would still outweigh any savings of constructing a combined cycle plant in Zones A-E. Therefore LAI did not pursue this transmission option for this assignment.

Retirement with P JM via Ramapo Market Transmission Response The fourth transmission alternative involves transmitting power from the PJM system into NYISO. The two systems are connected in a number of locations, including a 500 kV line from the P JM Branchburg substation to the NYISO Ramapo substation. P JM is approximately three times the size of NYISO, with a considerably higher percentage of coal and nuclear generation. LAI examined two options to increase the power flow to Buchanan:

re-conductor the existing transmission paths from Ramapo to Buchanan, and construct a new dedicated (overhead or underground) transmission line from Ramapo to Buchanan. Either option would require extensive additional studies to satisfy reliability and environmental requirements, which are beyond the scope of this assessment.

The capacity of the Ramapo-Buchanan route could be increased significantly, conservatively estimated at 1,000 MW and perhaps as much as by 2,000 MW if both options are pursued.

However, total power flows between eastern PJM and NYISO are governed by the Total East transfer capability, a simultaneous transfer limit that incorporates five interface locations and that takes into account single and multiple contingency events. Our investigation reveals that this alternative probably would not increase the Total East transfer capability significantly 58 Cost provided in Power Alert III, New York's Energy Future, a report by the NYISO.

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because of the simultaneous nature of the Total East limit. Therefore LAI did not pursue this transmission option for this assignment.

3.7. ENTERGY GAs-FIRED REPLACEMENT GENERATION AT IP SITE One generation replacement option would be for Entergy or another developer to build and operate a gas-fired simple cycle or combined cycle power plant at the IP site. The feasibility of this option is supported by Entergy's Preliminary Scoping Statement filed with the NYPSC on March 18, 2002 to construct a 330 MW simple cycle plant 59 The plant was originally to be comprised of eight 45 MW aero-derivative gas turbines, later amended to two 165 MW GE 7F A industrial frame gas turbines 60 The plant was to utilize a 5 acre parcel on the IP site outside of the "protected area" that houses the reactors. The plant would have tied into the Buchanan electric substation, less than 2,000 feet to the northeast. The principal components would have been the two gas turbines and generators in a main generator building, two 90 foot tall exhaust stacks, an electrical switchyard, a water demineralization system, and a control building.

NOx emissions would have been controlled by using dry low NOx combustors and through a selective catalytic reduction system. Natural gas for the plant would have been obtained from Algonquin, the interstate pipeline that traverses the IP property less than 1,000 feet away.

While the existing Algonquin mainline may be adequate for a simple cycle plant that would operate in peaking mode during the summer season, we believe that substantial pipeline upgrades would be required to supply natural gas to a combined cycle plant throughout the winter heating season, November - March.

Entergy's Preliminary Scoping Statement indicated that the simple cycle project would have benefited the local community in a number of ways:

  • The project would add to the local tax base.
  • The project would improve utilization of the IP site.
  • Construction would create 200-250 jobs during a one year period.
  • Operation would require 3-4 full-time staff.
  • The project would improve electric reliability, particularly during peak demand periods.

59 Case No. 02-F-0342.

60 Aero-derivative gas turbines are similar to jet aircraft engines and are designed to start up and shut down quickly and frequently, ideal for peaking operation. Industrial frame gas turbines utilize similar technology on a larger scale and are more often utilized in a combined cycle arrangement, better suited for intennediate and base load operation. Aero-derivative gas turbines typically range from 5MW - 50MW, while industrial frame units typically range from 80 MW - 265 MW.

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Site Suitability Entergy abandoned the project and withdrew the Preliminary Scoping Statement prior to filing a more definitive Application for Article X approval. However, the IP site appears to be well-suited for replacement capacity, based on four key attributes - size, fuel supply, transmission connection, and water supply:

  • Size - According to Entergy's Preliminary Scoping Statement, the IP site has land outside of the IP2&3 "protected area" that is vacant and used for temporary storage.

The ISFSI under construction is not located on this vacant land. With careful planning, we believe that Entergy could utilize this land to site replacement generation, perhaps as much as 1,000 MW of combined cycle capacity61 However, if IP is converted to a closed-cycle cooling system, the cooling towers will probably use up most of the vacant land and preclude Entergy's ability to use the site for replacement generation.

  • Fuel Supply - According to the Preliminary Scoping Statement, the Algonquin 26" and 30" gas pipelines traverse the IP site, and the gas interconnection would extend less than 1,000 feet. Entergy planned to obtain interruptible or seasonal secondary firm transportation on Algonquin. More recently, the Millennium pipeline project announced Phase 1 plans to construct a major gas pipeline from the Empire State Pipeline in Corning, New York to the Algonquin system in Ramapo, New York.

Additional supplies from Western Canada, coupled with system reinforcements on the Algonquin mainline from Ramapo to Connecticut, would facilitate a gas-fired replacement plant on the IP site. Expensive upgrades on Algonquin would surely be required to provide firm year-round service to the site without denigrating the service rights of other Algonquin customers in New York and Connecticut 62 The extent to which such upgrades could be reduced for "quasi-firm" service that allows for some delivery interruptions is unknown.

  • Transmission Connection - The retirement of IP will provide a transmission pathway for 2,000 MW of on-site replacement capacity. Retiring IP would also free up terminal space at the Buchanan substation for any replacement capacity on the IP site.

The Preliminary Scoping Statement suggests that the transmission lines would be less than 2,000 feet, a very short distance compared to other merchant project locations.

  • Water - Peaking plants require relatively little water, and the Preliminary Scoping Statement stated that water would be required for inlet fogging (to improve hot weather performance) and turbine washing. Water was not anticipated for NOx control. Entergy intended to use water from the Buchanan municipal system, rather 61 The County will have to discuss site capacity with Entergy at the appropriate time.

62 Quantifying pipeline service adequacy and upgrade costs were beyond the scope of this assigmnent. During the course of our analysis, no discussions were held with Algonquin, or its parent, Duke Energy, regarding gas delivery capacity to IF.

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than the Hudson River. A large combined cycle plant might require more water, although the exact amount depends on the cooling technology utilized. We believe that the cooling technology adopted at the Athens plant, a wet/dry compromise that minimizes water consumption and plume formation, may be appropriate for the IP site.

Combined Cycle Replacement Generation If IP was retired and cooling towers were not constructed, an on-site gas-fired combined cycle plant would be an appropriate replacement technology63 Since IP operates as a base-load resource, a combined cycle plant is better suited for base-load operation than the simple cycle plant proposed by Entergy. Both plant types are designed around gas turbine technology. In light of concerns regarding greenhouse gas emissions and the need for significant transportation infrastructure, it is doubtful that a coal-fired plant could be sited in Westchester County. An on-site combined cycle replacement plant would offer Entergy, the County, and the State a number of benefits:

  • The site is already zoned for a power plant and has useful infrastructure in place. The Buchanan substation would allow up to 2,000 MW of replacement generation to be connected into the high voltage transmission system at virtually no cost to NYISO or Entergy. A replacement plant that would become operational at the time the IP units were retired would assure NYISO and State ratepayers of system reliability. Locating a site for a new power plant elsewhere in Westchester would be difficult and costly due to land costs, governmental considerations, and the need for the supporting infrastructure. Thus, the IP site has substantial value for replacement generation because zoning, infrastructure, and community acceptance all are favorable, conditions not easily duplicated elsewhere.
  • Algonquin traverses the site and could deliver gas to the replacement plant. If Phase 1 of the Millennium project is completed in time and Algonquin expands its mainline, gas supplies should be available at IP throughout the non-heating season without significant facility additions. If the on-site replacement plant required firm year-round transportation service, Algonquin would likely require substantial and costly upgrades.

However, if Entergy could obtain an air permit that would allow the plant to utilize distillate oil as a back-up fuel for up to 30 days per year, less costly upgrades might be sufficient to render non-firm service. Many plants have such permit conditions that allow the gas to be shifted to core loads, such as residential consumers who are 64 entirely reliant on gas Back-up fuel oil capability that ensures uninterrupted winter 63 Evaluating the potential of other conventional and renewable power plant technologies was outside the scope of this assignment.

64 For example, the Bowline 3 project listed on page 31 had an air permit that permitted fuel oil use with restrictions. The Wawayanda project had a gas-only air permit. SCS Astoria, a combined cycle project in New York City, can burn distillate fuel oil for 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> (30 days) per year Many other plants that have recently commenced operation are also pennitted to burn distillate fuel or some other oil product, with restrictions.

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65 time operation would also be looked upon favorably by the NYISO. Entergy would have to install above-ground storage tanks on-site to store some quantity of back-up fuel oil.

  • The capital cost of a combined cycle plant is significant. Based on generic cost data, we estimate that a 1,000 MW (nominal rating) combined cycle plant would cost approximately $0.8 billion (2012 dollars), including all development, permitting, engineering, procurement, construction, and start-up costs 66 Utilizing the IP site would reduce the capital cost somewhat.
  • An on-site combined cycle plant would provide construction jobs for a period of time that we estimate at two-to-three years, longer than would be required for a simple cycle plant. While the permanent staffing level of the combine cycle plant would be less than for a nuclear facility, there would be continuing staff requirements to provide site security, maintain safety, and restore the former nuclear facility site.
  • An on-site combined cycle plant would preserve some level of PILOT payments for the local communities, especially the Hendrick Hudson School District. While the level of PILOT would be subject to negotiations, we note that a report we conducted for NYISO last year indicated property taxes would average about $17.60/kW-yr in 2005. At this tax rate, property taxes (not necessarily as PILOT) for a 1,000 MW combined cycle plant, one-half of the IP capacity, would be $17.6 million in 2005, almost as much as IP's current PILOT.

Entergy actively pursued non-nuclear merchant power opportunities (i.e. non-utility power plants using fossil-fuel technologies such as a gas-fired plant at the IP site) up until two-to-three years ago. Deteriorating economics of merchant power projects caused Entergy to discontinue project development and either sell off plants or record charges due to value impairment for a sizeable portion of its domestic and international portfolio. Entergy also sold a number of gas turbines that had been ordered for new power plant projects to a special-purpose entity in 200 l.

While Entergy's interest in developing a gas-fired simple cycle or combined cycle plant may have waned, an on-site replacement plant appears to have some advantages compared to other sites. Entergy could capture that value and thus benefit financially through a number of business arrangements. For example, Entergy could develop and own the on-site replacement plant, or could be a partner in which case it could contribute the site in lieu of cash, among other potential transaction structures.

65 Absent finn transportation on Algonquin, there may not be sufficient pipeline capacity during the heating season to provide adequate natural gas service once the 30 days of pennitted oil use has been fully utilized.

66 We assumed that the site could accommodate 1,000 MW of combined cycle capacity. While 2,000 MW may be possible at the IF site, such large plants at one site are very unusual. For example, the four merchant combined cycle plants described in section 3.5 range from 500 MW to 1,000 MW (nominal ratings).

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3.8. CONVERSION OF IP TO NATURAL GAS One of the options that LAI was asked to investigate was the conversion of the IP from a nuclear plant to a non-nuclear plant. A conversion would require installing new gas turbines and heat recovery steam generators to produce steam that would be utilized in the existing IP2&3 steam turbines and generators, i. e. a gas-fired combined cycle plant. Over fifteen years ago, one nuclear plant, then under construction, was converted to a gas-fired combined cycle plant, the Midland Cogeneration Project. The conversion of the Midland plant had unique features that render it irrelevant in the present context:

  • The Midland nuclear plant was never completed and never had radioactive fuel on site.
  • The Midland nuclear plant was owned by a utility, Consumers Power. Its conversion allowed Consumers Power to place a large portion of the nuclear expenditures for the abandoned nuclear plant into rate base. The business arrangement, sanctioned by the state utility commission, gave the utility a strong economic incentive to transfer as much of the expensive nuclear plant costs into the non-nuclear plant, regardless of technical merits.
  • Combining new gas turbines with the existing steam turbines was not as efficient as a new combined cycle plant.
  • The Midland combined cycle plant was located near many pipelines that had access to domestic and Canadian gas supplies. The IP site would have difficulty obtaining winter gas deliveries absent significant and expensive pipeline upgrades.

Another nuclear plant, Rancho Seco, was owned and operated by the Sacramento Municipal Utility District until it was retired in 1989. Rancho Seco was not converted to gas, but was replaced by conservation, cogeneration, and alternative energy sources through an aggressive program.

Other, more general reasons that we do not believe conversion ofIP is feasible are as follows:

  • The steam conditions exiting the heat recovery steam generators would not match the conditions required in the steam turbines, depressing total plant efficiency.
  • Back-fitling new gas turbines and steam generators with existing steam turbines would not permit the overall combined cycle efficiency to be optimized.
  • New combined cycle plants constructed under a turnkey contract typically have complete repair/replacement warranties and performance guaranties. Contractors cannot offer such warranties and guaranties for a converted plant.
  • Utilizing the equipment would expose the new plant investors and lenders to nuclear plant-type risks (ex. soil contamination) that investors would ordinarily avoid.

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3.9. ALTERNATIVE ENERGY SOURCES An evaluation of the potential of alternative energy sources to replace IP capacity was not part of the assignment given to LA!. Nevertheless, we are aware of certain state and federal initiatives to encourage alternative energy sources that may influence the County's strategy towards IP.

Last September the NYPSC adopted a Renewable Portfolio Standard requirement for utilities and other load-serving entities that requires them to increase their procurement of renewable energy to 24% of their total requirements by 2013. The NYPSC anticipates that voluntary purchases of renewable energy will increase the total to 25%. Currently, about 19% of the State's energy requirements are supplied by renewable sources, mostly hydroelectric in the western region. The NYPSC's order implements a program whereby the New York State Energy Research and Development Authority (NYSERDA) will subsidize developers of new renewable facilities, selected via auction, to increase the state's renewable portfolio. We expect the largest source of incremental renewable energy to be wind projects, but it is not certain how much could be developed in the downstate region that would help replace IP capacity.

The DOE has been directed by Congress to perform an assessment of alternatives to IP for meeting energy needs in New York. DOE was directed to use the National Research Council for this study. According to the Council's web site, a committee was established to identify and assess options for replacing IP energy, and then compare them to the continued operation of IP. The alternatives may include coal- or natural-gas-fired power generation, renewable-energy-based options, energy imports, and energy efficiency measures. In assessing the alternatives, the committee may consider such factors as economic costs and benefits, emissions, infrastructure barriers (e.g. fuel supply, compatibility with the transmission grid),

health and safety, reliability of supply, and other factors. The committee will not recommend options or the future of IP. Rather, it will provide a menu of options with a sufficiently detailed description of the full impacts of choosing those options for policymakers to understand the implications of their potential decisions. The work is scheduled to be completed at the end of the year.

3.10. COUNTY / COWPUSA ALTERNATIVES Westchester County and COWPUSA have a limited number of potential business strategies to encourage Entergy to shut down IP and construct replacement generation at the site. One strategy would be for the County to purchase unused land at the IP site that is in free release condition (described later on in this report) as a financial incentive. This land could then be leased to a developer for on-site replacement generation. Another strategy would be to expand COWPUSA's role to allow it to purchase wholesale power and sell retail power to Westchester residents. NYP A or Con Edison, which both have large retail customer bases, could better serve in this role. Purchasing wholesale power from Entergy under a PP A could encourage replacement capacity at the IP site or at another location.

Westchester County has encouraged cost-effective conservation, load management, and renewable energy sources and should continue to do so whether or not IP continues to 43 OAGI0000197_070

operate. Recommending specific alternative energy sources is outside of the scope of this assignment. However, there are many institutions active in this area as well as existing programs that could support Westchester's efforts:

  • NYSERDA actively supports the development of conservation and load management programs that could be expanded throughout Westchester.
  • NYISO has instituted market mechanisms to encourage load management, i.e. shifting or curtailing load that can be reliably called upon.

The merchant generation environment is highly competitive, demanding sophisticated energy bidding and fuel procurement strategies, efficient plant O&M practices, lean administration, and significant financial strength. We do not believe that COWPUSA should consider owning and operating replacement generation without a base of relevant experience. Many merchant plant owners that are not part of a large and diversified corporate structure are currently in financial distress.

We note that COWPUSA's ability to provide retail service III Westchester and compete against Con Edison is limited by two factors. First, the NYPSC's recent decision to differentiate MAC will lower Con Edison's retail rates in Westchester, taking a potential cost advantage away from COWPUSA. Previously MAC charges had the effect of increasing Con Edison's charges to Westchester customers (even though the underlying energy cost is lower than in New York City) while lowering Con Edison's charges to New York City customers.

While the County is to be commended for its efforts in prompting NYPSC to phase out the imbalance, the MAC change results in lower Con Edison rates in Westchester, thus making it harder for COWPUSA to compete. Second, we investigated whether COWPUSA could avoid transmission charges by purchasing power directly from the on-site replacement plant and transmitting that power directly to the Westchester distribution system. However, doing so would require additional capital costs to design and construct the plant switchyard, and the plant's location in Buchanan would not allow COWPUSA to serve a large percentage of the County's potential load.

44 OAGI0000197_071

4. PLANT VALUATION 4.1. INTRODUCTION LAI estimated the value of IP at various points in time and under different scenarios in order to guide the County regarding the potential acquisition of the plant as well as possible negotiations with Entergy to voluntarily shut down the plant. Compensation estimates using the Cost Approach, Comparable Sales Approach, and Capitalized Income or Earnings Approach are addressed in this section. This section also includes detailed discussions of LAI's forecast of plant revenues and expenses, as well as the discount rate appropriate for a merchant nuclear power plant, that are required for the Earnings Approach, the preferred valuation method for income-producing assets such as IP.

4.2. COST ApPROACH The Cost Approach involves a determination of value based upon the cost of duplicating IP, plus a consideration of any changes in standards and conditions if necessary67 Entergy acquired IP3 in November 2000 and IP2 in September 2001. These transactions are recent enough to utilize as a check against the Earnings Approach valuation.

IP3 was sold by NYPA to Entergy, along with the FitzPatrick station, in November 2000.

Under the terms of the Purchase and Sale Agreement, Entergy agreed to a purchase price of

$967 million allocated as follows: $636 million for the two plants plus $171 million for fuel and other inventory. This transaction was sufficiently recent to be considered in the valuation of IP3. In addition to the purchase prices in the Purchase and Sale Agreement, the parties executed a PPA, a Facilities Agreement, and a Value Sharing Agreement that convey value between the parties and should be considered in valuation. Each of these valuation components are discussed below.

Entergy is making purchase price payments over an eight year period following the closing date. According to the Purchase and Sale Agreement, the $637 million price for the plants is being paid as an initial payment of $50 million on the closing date and then seven annual installment payments of $83.715 million. Allocating the purchase prices among the plants can be accomplished based on plant size. Since IP3 was rated at 980 MW and FitzPatrick was rated at 825 MW, IP3 represented 54.3% of the combined plant capacities and, thus, is allocated $346 million for plant and $93 million for fuel.

At the time IP3 was sold the parties also executed a PP A under which NYP A agreed to purchase IP3's capacity, energy, and ancillary services through 2004 at a set price of

$36/MWh. The parties had the option but did not extend the PP A beyond the initial term.

LAI is not aware of any reason to believe that the PP A prices were set above or below then-67 Appraisers also refer to this approach as "Replacement Cost New" or "Reproduction Cost New" OAGI0000197_072

prevailing market expectations about market energy prices; therefore no adjustment to the purchase price is required.

The Value Sharing Agreement ensures that NYP A will benefit from power sale revenues in the event that actual market energy prices exceeded specified target prices from 2005 to 2014.

The target prices are set at $42.26/MWh in 2005 and rise gradually to $57.77/MWh in 2014.

Forecasted energy prices applicable to IP3 are $59.04/MWh in 2005 to $68.04/MWh in 2014.

The expected positive difference will be shared equally between Entergy and NYP A, thereby reducing IP3's valuation to Entergy through 2014. Based on our forecast of market energy prices, LAI estimates that NYP A will receive an average of $37.3 million per year under the Value Sharing Agreement.

The parties also executed a Facilities Agreement for Entergy to make additional payments to NYPA in the event Entergy acquired additional nuclear generating units in New York. The provision for Entergy's ownership of IP2 requires Entergy to pay NYPA $10 million annually, commencing in September 2003, the second anniversary of the date IP2 is acquired, and continuing to the earlier of December 31, 2015, the eleventh anniversary of the IP2 acquisition date, or the date when either IP2 or IP3 is retired. Assuming that IP2&3 are operated though the end of their respective NRC licenses, Entergy would make ten payments (2003-2012) of $10 million. Our valuation estimate includes payments made under both the Value Sharing Agreement and Facilities Agreement.

IP 1&2 were sold by Con Edison to Entergy in September 2001. Under the Purchase and Sale Agreement, the purchase price was $502 million for the nuclear generating plants and associated facilities, plus approximately $107 million for fuel inventory.68 The parties also executed a PPA under which Con Edison purchased IP2's output through 2004. LAI is not aware of any reason to believe that the PP A prices were set above or below then-prevailing market energy prices, which would require an adjustment to the purchase price. Since IPI was shut down in 1974 and is in safe storage, the entire purchase price is allocated to IP2.

The PSA called for the purchase price to be paid in full at closing. There is only one provision of the PSA that may result in a significant financial transfer related to the sale of IP2 following the closing. The agreement stipulates that if decommissioning of IP occurs by any means other than decontamination (e.g., by safe storage or entombment), then half of the amount by which the decommissioning funds exceed the decommissioning cost shall be paid to Con Ed. Unlike the sale of IP3, there are no other related agreements for sharing value with Con Edison after the closing.

A breakdown of IP's purchase prices is provided in Table 9, including the discounted value of the ten payments under the IP3 Facilities Agreement.

68 The sale also included IFI, three gas turbine units with a combined capacity of about 45 MW and the Toddville Training Center.

46 OAGI0000197_073

Table 9 - Indian Point Purchase Prices

($ millions)

IP2 IP3 Power Plant $502 $345 Fuel Inventory69 $107 $ 93 Facilities Agr't ~ $ 87 Total $609 $525 Cost Approach Considerations In considering the changes in standards and conditions since Entergy acquired IP, there have been a number of changes in the power market over the past four years, as follows:

  • Regulation - The New York wholesale power market has been deregulated since November 1999. There have not been any significant changes in federal nuclear power regulations since that time. Entergy acquired IP3 in November, 2000 and IP2 in September, 200l. Thus LAI believes that IP's Cost Approach value has not been materially affected by regulatory changes.
  • Physical Depreciation - There may have been some physical wear and tear of the IP assets since the Entergy purchase, but LAI is not aware of any significant depreciation (e.g. major equipment failure) that would cause the original purchase price to not be a cost-based indicator of market value. Moreover, NRC regulations require nuclear plants be maintained to a very high standard, so that IP's cost-based market value has not been materially affected by physical depreciation.
  • Functional Depreciation - The technology utilized at IP has not been made obsolete and does not prevent IP from providing energy and capacity into the market. IP' s cost-based market value has not been materially affected by functional depreciation.
  • Economic Depreciation - Economic depreciation includes changes in the value of the plant's output, which in this case is energy, capacity, and other ancillary services.

Since Entergy purchased the IP assets, market energy prices in New York have increased about 25%, thus raising IP's cost-based market value. At the same time, IP has fewer operating years left under the NRC licenses. When they were purchased, IP2 had 12 years left to operate and IP3 had 15 years left. The remaining operating period under the existing NRC licenses is 9 years and 11 years for IP2 and IP3, respectively, a reduction of 26%. Thus the improvement in market energy prices is largely offset by the reduction in operating lives.

69 Estimated book value of the nuclear fuel and fuel oil inventories at the time of closing.

47 OAGI0000197_074

Since the improvement in market energy prices is largely offset by the reduction in IP2&3 operating lives, there is no net impact of these adjustments. LAI inflated the original purchase prices by inflation, i.e. Gross Domestic Product Implicit Price Deflator, to a January 1, 2005 valuation date. The combined adjusted purchase price is $l.2 billion, broken down as shown in Table 10 below, a useful FMV indicator under the Cost Approach:

Table 10 - Cost-Based Valuation

($ millions, excluding fuel inventory, including adjustments)

IP2 IP3 Purchase Date September, 2001 November, 2000 Original Purchase Price $609 $525 Quarters to Jan 1, 2005 13 l7 Escalation Factor70 l.047 l.067 Adjusted Purchase Price $638 $560 4.3. COMPARABLE SALES ApPROACH Prior to the sale of the first IP unit, IP3, there were eight sales of equity interests in nuclear power plants in 1998 and 1999. All of these sales were at low prices when considered on a

$/MW basis as sellers and regulatory commissions tended to view these nuclear assets as liabilities, and there were few qualified and interested buyers.

Beginning with the sale of IP3 and FitzPatrick in November 2000, prices increased significantly as buyers considered these plants as profitable enterprises once they were incorporated into a nuclear fleet with the prospect of improved performance. Capacity-weighted nuclear sales prices, expressed in beginning of year 2005 dollars, averaged about

$24/kW from 1999 until just prior to the IP3 and FitzPatrick sale, and have since averaged over $500/kW. The value of nuclear plants selling into the competitive market was also enhanced by the rise in market energy prices, particularly in NYISO, New England (ISO-NE),

and P JM. Given the dramatic shift in nuclear plant transaction values, LAI considered only those nuclear plant transactions that occurred since November 2000. Each transaction is briefly described below. All prices are in then-current dollars.

  • Millstone 1, 2, & 3 - Northeast Utilities sold its 100% interest in units 1 and 2, and its 93.5% interest in unit 3 in March 2001 to Dominion Resources for $l.19 billion plus

$105 million for fuel inventory71 The parties did not enter into a PP A. The selling price was allocated as shown below. Since Millstone 1 had already been shut down, we did not include the nominal $1 million price or capacity in our comparable sale analysis.

70 Inflation in 2004, 2003, 2002 and 2001 was 1.2%, 1.3%, 1.6% and 1.8%, respectively. We assume that long-tenn inflation will be 3% beginning in 2005.

71 Millstone I was subsequently shut down.

48 OAGI0000197_075

Millstone 1 Millstone 2 Millstone 3 Plant $1 million $402 million $790 million Fuel 0 $42 million $63 million

  • Seabrook - Co-owners Northeast Utilities, United Illuminating, BayCorp, National Grid, NSTAR, and New Hampshire Electric Coop sold their combined 88.2% interest in late 2002 to FPL Group for $749.1 million plus $61.9 million for fuel and $25.6 million for parts. The parties did not enter into a PP A. The selling price was allocated as follows:

Plant $749 million Fuel $ 62 million Parts $ 26 million

  • Vermont Yankee - Vermont Yankee sold its 100% interest in July 2002 to Entergy for a total selling price of $180 million. The parties executed a ten year PP A that called for Entergy to sell 100% of the plant's output power to the prior owners. The selling price was allocated as follows:

Plant $145 million Fuel $ 35 million

  • Nine Mile Point 1&2 - Niagara Mohawk sold its 100% interest in Nine Mile Point I, and NiMo, NYSEG, RG&E, and CHG&E sold their combined 82% interests in Nine Mile Point 2 in November 2001 to Constellation Energy Group for $675 million plus

$134 million in interest charges and $87 million for fuel inventory. The parties executed a ten year PP A under which Constellation would sell approximately 90% of the plants' output. The selling price was allocated as follows:

Plant $809 million Fuel $ 87 million

  • Peach Bottom 2&3, Hope Creek, Salem 1&2 - Conectiv sold its 7.5% equity interest in Peach Bottom to Exelon in January 2001 for $5.2 million and its 5% equity interest in Hope Creek plus its 7.4% equity interest in Salem to PSEG in October 2001 for

$17.3 million 72 The fuel inventory was sold for an estimated $50 million. The selling price was allocated as follows:

Plant $ 22 million Fuel $ 50 million

  • Ginna - Rochester Gas & Electric (RG&E, part of Energy East Corporation) sold its 100% interest in the Robert E. Ginna plant to Constellation in June 2004 for $422.6 72 Operational problems at the Peach Bottom units contributed to the low sales price.

49 OAGI0000197_076

million. The transaction also includes a ten year PP A under which Constellation is selling 90% of the plant's energy and capacity to RG&E. The $837/kW sale price is the highest price to date for a nuclear plant sale.

Plant $ 423 million Fuel $ 22 million

  • Kewaunee - Wisconsin Public Service Corporation and Wisconsin Power & Light have agreed to sell their combined 100% interest in the Kewaunee nuclear plant to Dominion Resources for $220 million. The sale was approved by the NRC and the FERC but was denied by the Wisconsin Public Service Commission.

The plant sizes and plant sales prices for these nuclear transactions have been escalated to Q I 2005 prices and are shown in Figure 4 below. The Peach Bottom/Hope Creek/Salem sale was excluded from the following figures, because the sales price was unduly influenced by several operational problems at Peach Bottom 2&3:

Figure 4 - Nuclear Plant Sales - Plant Size and Purchase Price 1.400

________________________________________________M~II~t~~e_~______________ _

1.200 1.000

~

~ 800 Seabrook

  • Nine Mile Point Indian Point 3 E

600

_____________________________________ ~_____F~t~~~i~.___________________ _

Indian POi~2 Ginna 400 ------------~-------------------------------------------------------

Kewaunee 200 ---------------~-----------------------------------------------------

Vennont Yankee

  • 500 1.000 1.500 2.000 2.500 MW Figure 5 below indicates the nuclear plant sale prices per unit of capacity over time, beginning with the IP3 transaction:

50 OAGI0000197_077

Figure 5 - Nuclear Plaut Sales - Transaction Date aud Price 900 Ginna 800 Seabrook 700 Millstone 2,3 600 Nine Mile Point 1,2 Indian Point 2 500

~ 400 Kewaunee Indian Point 3 Fitzpatrick

______________________V!!~m_oQtY~l!..k§'e_______________________________________ _

300 200 100 Mar-OO Oct-OO Apr-01 Nov-01 May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 4.4. EARNINGS ApPROACH LAI believes that the Earnings Approach, also referred to as Capitalized Income Approach, provides the best basis for estimating the value of IP2&3. This approach is forward-looking and can account for the possible extension of the NRC license term. It is also the approach recommended and utilized by ORPS in its appraisal of IP. The Earnings Approach requires forecasting the revenues, operating expenses, net income, and net cash flow that Entergy would earn over the forecast horizon. The net cash flow is then discounted to a present value using a discount rate appropriate for the asset. LAI calculated IP values at various points in time assuming either that IP would be retired at the end of their current existing license periods in 2013115, or alternatively at the end of twenty year license extensions in 2033/35.

4.5. REVENUES LAI forecasted the energy revenues for IP2&3 using the MarketSym chronological dispatch simulation model that simulates the hourly operation of the NYISO energy market. All generators submit bids to NYISO to provide energy on a day-ahead basis. The generators' energy bids typically are based on their variable operating costs, e.g. fuel, and may include a premium to recover fixed costs, e.g. labor, property taxes, capital cost recovery, as well.

NYISO seeks to dispatch plants with the lowest bids possible, consistent with a safe and 73 reliable system Under the current market rules, the highest bid accepted in any hour sets 73 New York State is divided into 11 zones that may have differing market energy prices due to transmission constraints. A zone may have a relatively high market energy price if more expensive bids must be accepted to assure reliable energy supply in zones that have limited transmission import capacity. For example, (cant' d) 51 OAGI0000197_078

the market energy price paid to all generators operating in that hour. When system demand is low, the most expensive generator might be a coal-fired steam unit with low variable operating costs, therefore setting a low market energy price. When system demand is high, more expensive peaker plants are dispatched, setting a high market energy price. The MarketSym model takes into account the full range of variables that determine market energy prices 74 These variables include:

  • Load by zone based on historical hourly data and growing over time using NYISO forecasts.
  • Supply based on the current mix and location of generators, known near-term supply additions and retirements, and forecasted long-term additions required to maintain the State's reliability requirement.
  • The fuel type, efficiency (heat rate), availability, and other operational characteristics of each generator.
  • Price forecasts for natural gas, distillate oil, residual oil, coal, uranium, and other fuel types.
  • Transmission capacities and constraints within New York and with the surrounding markets ofISO-NE, PJM, Quebec, and Ontario A nuclear plant such as IP has low variable operating costs and therefore operates mostly at full load whenever it is available, characteristic of base-load plants. Because IP operates as a base-load plant, it is "infra-marginal," meaning it is a price-taker, not a price-setter, in daily wholesale energy markets. The value of the energy is the cumulative value of the individual hourly market prices during each hour IP2&3 operate, multiplied by the net output delivered to NYISO. This approach implicitly values the contract prices in the PP As that Entergy recently negotiated with Con Edison and NYP A at market prices.

A graph of LAI's forecast of average market energy prices for the years 2005-2015 for the Base Case in which IP is retired in 2013115 is shown in Figure 6. These market energy prices are for the combined Zones G, H, and I (as defined by NYISO) that include Westchester and other counties to the north (as depicted in Figure 2). Market energy prices are relatively high by historical standards due to the high cost of gas and oil, the fuels used by generators that often set market energy prices during peak hours. The currently high energy prices have enhanced the bottom line for many base-load coal, uranium, or hydroelectric generators.

New York City (Zone 1), and Long Island (Zone K), generally have much higher market energy prices than the rest of New York State. Our simulation modeling captures Ioeational differences, and forecasts the appropriate market energy price for Westchester County.

74 Our forecast of market energy prices do not incorporate potential second-order effects attributable to increased gas volatility throughout the winter if the gas-fired replacement generators do not have firm transportation rights.

Generators are not required to have finn year-round transportation, and lacking such rights, we would expect more frequent pipeline congestion events.

52 OAGI0000197_079

Figure 6 - Base Case (Retirement in 2013/15) Forecast of Market Energy Prices 80 70 ------------------------------------------------------------------

~--

60  ::::---.'=-:::-;,:;.::,;;.;;;.~;;::,;;;;?-~="'="=-:::"--- ~-

50 ------------------------------------------------------------------

~

- Zones GHI Time Weighted 40 -Zones GHI Load Weighted 30 ------------------------------------------------------------------

20 ------------------------------------------------------------------

10 ------------------------------------------------------------------

en

'"oo CD o

o t-o o

00 o

o o

o  ;;  ;;  ;;  ;;  ;;

N N N N N N N N N N Year IP had PP As to sell both capacity and energy to Con Edison and NYP A that expired on December 31,2004. Both Con Edison and NYPA executed new PPAs with Entergy, and it is reasonable to assume that the PP A prices correspond to expected market energy prices.

Buyers and sellers rationally set prices for multi-year bilateral contracts based on the prevailing outlook for wholesale power by location. Hence, buyers ordinarily do not pay more for contract energy than they could otherwise purchase in the competitive bulk power market. Generators likewise mark-to-market the value of energy, thereby setting price based 75 on opportunity costs Thus LAI's forecast of market energy prices is the principal determinant of the Earnings Approach value ofIP2&3.

In addition to revenues derived from energy sales, generators in New York earn capacity revenues for being available for dispatch, regardless of the actual level of plant operation.

Capacity prices are also location-based, reflecting the value of being located inside or outside of transmission-constrained zones. NYISO conducts auctions for capacity, matching bids from buyers with those from generators 76 Whereas buyers may obtain part or all of their required capacity through PP As, LAI believes that it is reasonable to assume that contractual 75 While PPAs do reduce the volatility of market prices, this benefits both buyers and generators, so the effect is relatively neutral.

76 NYISO also administers markets for ancillary services (e.g. spinning and non-spinning reserves), that are required from generators to assure the safe and reliable operation of the bulk power system. Revenues from such ancillary services are not material for IP.

53 OAGI0000197_080

capacity rates tend to follow market capacity rates. We forecast market capacity prices using proprietary in-house models that simulate NYISO's demand curve mechanism.

Figure 7 - Base Case (Retirement in 2013/15) Forecast of Market Capacity Prices 120 100 80

"'l'

~

60 40 20 en o

'"oo CD o

o t-o o

00 o

o o

o  ;:;  ;:;

N N N N N N N N N N Year Although IP has strong transmiSSIOn ties into New York City, market capacity rates are currently low for all generators outside of New York City and Long Island due to excess capacity above the State's 18% reserve margin target. These capacity rates are expected to rise as demand increases over time and the market "tightens up", as shown in Figure 7. Our expectation of timely and sufficient replacement generation would result in an 18% reserve margin in each year, and would leave market capacity prices unchanged. If there is any lag in the timing of replacement generation that leaves the State short of its 18% target, market capacity prices would rise, attracting investment but raising customer rates in the short-run until new generation restored the supply / demand balance.

Given our assumption of an 85% capacity factor, we forecast that IP will be entitled to roughly $100-$150 million of capacity revenues per year through the term of the existing operating licenses. Table 11 summarize IP's revenue outlook through the term of the existing operating licenses. Note that gross energy revenue is adjusted by the provisions of the Value Sharing Agreement applicable to IP3 generation.

54 OAGI0000197_081

Table 11- Base Case (Retirement in 2013/15) Energy and Capacity Revenues

($ millions)

Value Gross Energy Capacity Year Sharing Total Revenue Revenue Adjustment 2005 $ 886.0 $(59.1) $ 29.2 $ 856.2 2006 $ 866.1 $ (49.0) $ 25.8 $ 842.9 2007 $ 860.0 $ (4l.4) $ 43.2 $ 861.7 2008 $ 854.4 $ (33.8) $ 125.6 $ 946.2 2009 $ 860.2 $ (28.8) $ 150.5 $ 98l.8 2010 $ 889.6 $ (29.6) $ 183.1 $1,043.2 2011 $ 896.5 $ (24.4) $ 197.7 $1,069.9 2012 $ 930.0 $ (25.7) $ 200.1 $1,104.4 2013 $ 882.1 $ (37.6) $ 186.3 $1,030.8 2014 $ 537.3 $(43.7) $ 109.4 $ 603.0 2015 $ 495.8 $ 0.0 $ 102.7 $ 598.5 Figure 8 - Life Extension Case Revenue Forecast w/ 20-year License Extension 3,000 I _Capacity 2,500 I I c::JV,'"' Sh,,, Adj,,'m," I

_Energy

-Total

2,000

~

g 1,500

~

'"'iI, 1,000

~ 500 (500)

If Entergy is successful in extending the IP license tenus for twenty years, IP' s energy and capacity revenues are forecast to increase over time as shown in 55 OAGI0000197_082

Figure 8. Note that revenues drop off in 2013 and 2015 as the units are converted to a closed-cycle cooling system. Energy revenues appear to increase rapidly as inflation and real gas costs put upward pressure on market energy prices. In the last two years shown, revenues drop by one-half once IP2 is retired in 2033.

4.6. OPERATING EXPENSES In order to forecast IP's expected operating expenses and CapEx, LAI relied principally on data from an NEI study prepared for Entergy, "Economic Benefits of Indian Point Energy 77 Center" that was published in April 2004 Entergy is not required to file as much data for IP, a non-utility merchant plant, than for a utility plant in rate base. We have supplemented this NEI data with relevant industry data and our own in-house data including that of other PWR nuclear plants. We are confident that our assumptions regarding operating expenses and CapEx are reasonable, and have documented the foundations for these assumptions in this section of our report. The total Base Case operating expenses are summarized in Figure 9 below.

Figure 9 - Estimated Base Case (Retirement in 2013/15) Operating Expenses

$600 II NYPA IP2 Payment

$500 IIISFSI Costs

$400

  • Staffing DFixedO&M i
  • Fuel Expense
i $300

$200

$100

$0 2005 2007 2009 2011 2013 2015 2017 2019 2021 77 Operating expenses are deductible for income tax purposes in the year incurred. CapEx is added to the asset base and then depreciated for income tax purposes over the useful life of the expenditure.

56 OAGI0000197_083

Non-Fuel Operating Expenses IP operating expenses, excluding fuel and PILOT, can be divided into four key components -

personnel, maintenance, administrative expenses, and taxes, which for 2002 totaled $453.8 million according to the NEI Study. If IP continues to operate beyond the current license term, operating expenses are projected to be much higher due to more frequent repairs and replacement of equipment, consistent with current industry experience.

Personnel - Labor is a large expense at IP. According to the NEI Study, there were 1,683 78 employees at IP and the Entergy Nuclear Northeast office in White Plains as of 2002 Westchester's Planning Department lists IP employment at 1,550 as of 2001 and the current IP "Factsheet" (which may be out-of-date) lists 1,500 employees, which we assume excludes the White Plains office. An article in the Westchester County Business Journal indicates that total employment decreased to 1,355, plus 160 at the White Plains office, as of mid-2004 79 We have assumed this latest employment figure.

Entergy has announced its intention to reduce IP's staff from 1,500 to between 1,000 and 1,100 to improve profitability 80 We assume this reduction excludes the White Plains staff, and have assumed that IP employment will decline over the next three years, reaching a mid-point value of 1,050 as of 2007.

81 According to the NEI Study, IP personnel had average earnings of $95,000 in 2002 Assuming average annual increases equivalent to the inflation rate, the average earnings in 2005 would be $100,312 as shown in the first line of Table 12 below 82 We have assumed that average earnings will continue to increase at roughly the rate of inflation, and that plant operating staff receive higher compensation than security personnel. Total personnel expenses for the years 2005-2015 are listed in the second-to-Iast column of Table 12 below.

We also include estimated decommissioning staff, although those costs can be recovered from the decommissioning funds and are therefore not a cost per se.

  • Base Case Scenario without License Extension - If IP2 is retired at the end of the current NRC license term, operating personnel levels will begin to decline as each unit ceases operating while SNF and decommissioning personnel will increase. When IP3 is retired we estimate that SNF personnel will increase to 400 and site security staff 78 Entergy Nuclear Northeast provides management and administrative services for Entergy's fleet of five non-utility nuclear plants.

79 Westchester County Business Journal, April 26, 2004, "Industry group touts impact of indian point", by Alex Philippi dis.

80 Alex Philippidis. Westchester County Business Journal, September 2,2002. "Indian Pt. building designed/or

/ewerjobs" 81 The actual data provided in the NEI Study indicates average earnings of $96,000; the discrepancy may be due to the fact that White Plains personnel have higher earnings than IP staff.

82 We assume that pay raises in excess of inflation for existing employees will be offset by the lower starting salaries of new employees.

57 OAGI0000197_084

requirements will decrease slightly. SNF and decommissioning activities should be completed by 2025, at which time the site could be closed or sold.

  • Entergy will be responsible for all of the operating, security, and SNF costs. The costs for decommissioning personnel, shown in the last column in Table 12, should be recoverable from the decommissioning funds, and are therefore not included as a cost in our valuation 83 However, the decommissioning personnel costs are significant and are included in our consideration oflocal and State-wide economic impacts.

Table 12 - Estimated Personnel Levels and Expenses with 2013/15 Retirement Operating Security SNF Expenses Year Decommissioning Staff Personnel Personnel (millions) 2005 1,180 70 0 $ 125.2 0 2006 1,080 70 0 $ 118.5 0 2007 980 70 0 $ 111.2 0 2008 980 70 0 $ 114.6 0 2009 980 70 0 $ 118.0 20 2010 980 70 0 $ 121.5 60 2011 980 70 0 $ 125.2 100 2012 980 70 0 $ 128.9 160 2013 980 70 0 $ 132.8 240 2014 490 50 250 $ 103.0 340 2015 490 50 250 $ 106.1 420 2016 0 50 400 $ 61.3 480 2017 0 50 400 $ 63.2 500 2018 0 50 400 $ 65.0 500 2019 0 50 400 $ 67.0 500 2020 0 50 400 $ 69.0 500 2021 0 50 0 $ 5.6 500 2022 0 50 0 $ 5.8 500 2023 0 50 0 $ 6.0 500 2024 0 50 0 $ 6.2 500 2025 0 50 0 $ 6.3 500

  • License Extension Scenario - If Entergy is successful in extending the NRC licenses, there will be a number of changes to the personnel assumptions and expenses listed in the table above. Operating personnel will be maintained at the 1,050 level as proposed by Entergy, SNF management will still be required as the wet storage pools are filled and SNF is loaded into dry storage casks, and decommissioning activities will be delayed until retirement in 2033/2035.

83 Up to 4% of the Decommissioning Funds can be used for studies and other decommissioning preparations.

58 OAGI0000197_085

  • Retirement in 2005 - In the unrealistic event that IP would have been retired on January 1, 2005, we expect that the entire personnel shift from operations to SNF and decommissioning functions will occur quickly, and that the duration of SNF and decommissioning will not change significantly.
  • Retirement in 2008 - If IP were to be retired in 2008 we expect that the entire personnel shift from operating to SNF and decommissioning functions will occur gradually as in the Base Case, with the same duration of activities.

Maintenance Expense - According to the NEI report, total 2002 expenditures for IP and Entergy's administrative office in White Plains were $448.9 million. Ignoring personnel compensation of $16l.2 million and fuel expenses of $30.2 million leaves total maintenance expenditures of $257.5 million. In order to divide these expenditures between IP and White Plains, we have assumed a 75% / 25% split for certain activity categories, as well as the fact that IP would require fewer administrative and overhead-type services than White Plains on a per-employee basis. The resulting expenditure estimates are shown in Table 13 below.

Table 13 - Estimated Breakdown of IP Maintenance Expensess4 (2002; $ millions)

Activity NEI Study IP White Plains Maintenance & Repair $ 57.5 $ 57.5 Mgt and Consul Svcs $ 35.4 $ 26.6 $ 8.8 Eng & Arch Services $ 16.0 $ 16.0 Electric Utilities $ 12.7 $ 9.5 $ 3.2 F ed'l Gov't Enterprises $ 10.6 $ 8.0 $ 2.7 Computer & Data Proc $ 10.4 $ 7.8 $ 2.6 Motors & Generators $ 10.2 $ 10.2 Building Services $ 9.7 $ 9.7 Insurance Agents $ 8.9 $ 8.9 Other $ 86.2 $ 64.6 $2l.5 Total $257.5 $209.8 $47.7 IP's maintenance expenses should increase with inflation over the next decade. However, if the IP operating licenses are extended, we estimate that maintenance expenses will increase an additional $10 million/year (2004 dollars) for each unit due to the added costs of maintaining the closed-cycle cooling system and more equipment requiring repair and replacement due to aging (as discussed below).

84 Source: NEI Study 59 OAGI0000197_086

Figure 10 - Industry Average Non-Fuel O&M Costs (1981-2003)

(2003 cents per kWh) 20219321522!221224?.0719920219Y 174113 169 '""

~R#~~~####~~#~##~~~###~#

'"t..EI LAI confirmed the reasonableness of our persoIlllel and maintenance expense data tabulated above by comparing it to industry data reported by NEI. The average non-fuel O&M costs for all domestic nuclear plants has been declining over time and was reported to be as shown in Figure 10. In order to compare the 2003 industry average cost of 1.28¢ikVVh to actual IP costs, we first assume an IP staff level of 1,050 ("right-sized" per Entergy's annOllllced plans) at an average compensation of $96,235 (reported 2002 compensation plus one year of inflation). The resulting persoIlllel cost is $101.0 million. Second, we add the IP maintenance expenditures of $209.8 from Table 13 above. Third, we divide the total non-fuel O&M expenditures by IP generation. According to NEI statistics, IP2 generated 8,375 G% in 2003, and IP3 generated 7,607 G%. The resulting O&M costs using IP data are provided in Table 14 below and appear to be higher than the nuclear industry plant average, even at the reduced staffing level. The higher operating expenditures may be explained by the higher cost of living in the area arOlllld IP, and the additional costs of keeping IPI in SAFSTOR condition.

Table 14- Estimated Non-Fuel O&M Expenditures (2002 $ millions except as noted)

PersoIlllel $101.0 Maintenance $209.8 Total $310.8 Generation 13982 GWh Average Cost 2.22¢IkWh License Renewal - The costs and schedule for preparing and pursuing a license renewal varies, depending on the status of the plant llllder consideration. According to a study 60 OAGI0000197 087

prepared by the EIA, the estimated cost to prepare a license extension application and for NRC review was $17.5 million in 1999 85 These costs are in line with the Xcel Energy 2004 Resource Plan, which estimates $19 million for the relicensing costs associated with Prairie Island, a two unit Westinghouse PWR similar to IP. These estimates only include the costs associated with the development, preparation, submittal and subsequent NRC review of the application, and exclude any hardware upgrades at the site 86 The overall schedule for a license extension decision from the NRC is approximately four years. That schedule includes an initial two year period for the development and submittal of the application, plus another two years for the NRC review and approval.

SPDES Escrow Payment - Under the terms of the draft State Pollution Discharge Elimination System (SPDES) permit, Entergy will be required to contribute $24 million per year into an escrow account from the time the final SPDES permit is issued to the time that construction on the cooling towers commences. Under the License Extension scenario, we anticipate that construction will take four years and will be completed in 2013. Thus Entergy would have to make escrow payments from 2006 through 2009. Under the Base Case scenario without license extension, Entergy would have to make escrow payments from 2006 though 2015. In the scenarios in which IP is retired in 2005 or 2008, we do not expect that Entergy would have to make further escrow payments.

Fuel Expenses According to the NEI Study, IP purchased $30.2 million of uranium fuel in 2002 for one refueling. When IP's fuel expense is divided by IP generation for that same year, the resulting value is 0.19¢/kWh. In order to confirm the reasonableness of this expense we compared it to the 2003 industry average of 0.44¢/kWh as shown in Figure 11 below, provided by NEI. The U.S. nuclear fleet has plants that have refueling cycles that vary from as short as 12 months to as long as 24 months. Assuming an average of 18 months, the 0.44¢/kWh industry average should be adjusted to 0.33¢/kWh for plants, such as IP2&3, which are on a 24 month cycle. While IP's value is less than the adjusted industry average, it appears reasonable for a single refueling outage. In addition, IP's cost would be higher and closer to the industry average if the plant operated at an 85% capacity factor as we anticipate for the long-term.

85 Appendix E-3, Nuclear Power Plant Analysis of Annual Energy Outlook 1999, prepared by the EIA for the DOE.

86 These costs do not include the cost to convert to closed-cycle cooling and other CapEx items discussed below.

61 OAGI0000197_088

Figure 11- Industry Average Fuel Costs (1981-2003)

(2003 cents per kWh) 150 125 100 '" 092 Capital Expenditures Maintaining nuclear power plants requires significant CapEx to replace primary equipment components. In order to accurately estimate future CapEx requirements at IP, we have divided CapEx into the following principal changes (major modifications):

  • Fuel Storage Building Gantry Crane
  • Spent Fuel Pool Re-Racking or Dry Spent Fuel Storage
  • Reactor Vessel Head Replacement
  • Pressurizer Replacement and! or Repairs
  • Closed-Cycle with Cooling Towers If IP operates beyond 2013/15, we estimate that Entergy will spend over $1 billion, principally to convert the existing once-through cooling system to a hybrid cooling tower design. Other CapEx requirements are discussed below. In addition, we estimate that CapEx generally will increase $10 million/year for each unit over IP's remaining life, and maintenance expenses will also increase by $10 million/year for each unit, both due to plant aging. We calculate that license extension would be cost-effective in relation to the value of capacity and energy from the units over the anticipated twenty years of extended plant life.

However, Entergy may be less inclined to pursue license extension if the CapEx requirement is higher than our estimate or if market power prices are lower than we forecasted. In either case, postulated compensation amOllllts to Entergy would be lower.

62 OAGI0000197 089

Fuel Storage Building Gantry Crane - On December 29, 2003 Entergy gave notice to the NRC of their plans to construct an ISFSI at IP to store SNF. Entergy is planning on using the Holtec International HI-STORM 100 Cask System with the HI-TRAC 100 spent fuel transfer cask, which requires a single-failure-proof gantry crane and hoist to be installed in both IP2&3. The existing 40-ton overhead cranes in IP2&3 are not single-failure-proof and do not have sufficient capacity to handle the Holtec HI-TRAC 100 spent fuel transfer cask.

However, they will remain in place and will be utilized for other load handling activities in the FSB.

Per Entergy's June 16, 2004 submittal to the NRC, a new gantry crane with a design rated load capacity of 110 tons will be installed in the IP2 fuel storage building. The crane will be used to move dry cask storage equipment into and out of the spent fuel pool. The crane design and associated handling equipment must conform to:

  • NUREG-0554, Single-Failure-ProofCranes for Nuclear Power Plants
  • NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, for heavy load lifts over the spent fuel pit The estimated cost per plant installation is $7 million, which would equal approximately $14 million for both units.

Spent Fuel Pool Re- Racking or Dry Spent Fuel Storage - Nuclear plants typically replace a third of the fuel (approximately 65 fuel assemblies) at each refueling cycle. As with all domestic nuclear plants, SNF is placed in storage pools on site for several years following discharge where the SNF cools off. These storage pools are made more effective by adding boron, which absorbs neutrons from the SNF and allow more SNF to be stored in the pools.

IP2&3 uses Boraflex, a metallic material that provides for the nonproductive absorption of neutrons and therefore permits SNF assemblies to be stored more densely.

IP2 had problems with Boraflex degradation as documented in a Licensee Event Report to the NRC in 2000. Because of Boraflex degradation, IP2 will not have full core offload capacity after 2006 and IP3 will not have full core offload capacity after 2009. The immediate cause of the degradation was dissolution of the boron from the Boraflex matrix. Boraflex, a neutron-absorbing material, consists of about 50% (by weight) boron carbide, and about 50%

polymer matrix that contains the boron carbide. In the spent fuel storage pool, the Boraflex is exposed to the aqueous pool environment and high gamma radiation. Under these service conditions, the physical and chemical properties of Boraflex change, including shrinkage, gap formation, and Boraflex dissolution (the boron carbide dissolving into the water).

In the short term, this issue restricts the operational flexibility in IP's spent fuel pools since the SNF must to be stored in a "checkerboard" fuel distribution pattern in the racks. Fuel assemblies to be stored in the different defined regions of the spent fuel pool are identified or qualified based on burn-up, enrichment, and cooling times. A schematic diagram of the IP2 Spent Fuel Pool is provided below in Figure 12. The different regions denoted in the spent fuel pool schematic relate to the characteristics of the SNF that can be stored on those regions.

63 OAGI0000197_090

Figure 12 - Schematic Diagram of IP2 Spent Fuel Pool J

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[--1 PERIPHERAL CELL 40 42 44 46 48 5153 55 57 59 61 6364 IP2 needs a dry SNF storage management program in order to remain operational through the existing plant life. Re-racking is not an efficient option, and IP2 has already performed a re-racking in the 1990/91 timeframe. A dry storage program requires the following:

  • Procure a SNF management solution/technology
  • Design/construction of an ISFSI
  • Implement a dry fuel storage loading campaign on-site The technical aspects of a dry fuel storage management program are addressed in the Decommissioning and Spent Fuel Management section of this report. It is expected that Entergy will subcontract the work of establishing an ISFSI and loading the fuel into the dry casks. We estimate the total cost to be $70 million (all 2004 $) to design, license, and construct the ISFSI, $10 million to install rigging / ancillary equipment, and $40 million (i. e.

16 casks at $2.5 million/cask) to remove the SNF from wet storage, load in casks, and transport onto the ISFSI pad over the next ten years. We estimate that about $30 million has been spent prior to 2005 and is therefore not included in our analysis. A second, larger ISFSI will be required to accommodate additional SNF soon after the current NRC licenses expire.

64 OAGI0000197 091

The estimated CapEx for the larger ISFSI is $70 million (all 2004 $) to design, license, and install the pad in 2015-2017 (which represents a cost savings over the first ISFSI), plus $1.25 million/cask (again incorporating a cost savings compared to the first ISFSI) to remove the SNF and store an additional 91 casks in a major campaign in the 2018-2021 period assuming retirement at the end of the existing license terms.

Reactor Pressure Vessel Head InspectioIL Repair and Replacement - The reactor pressure vessel eRPV) heads of PWRs have penetrations for control rod drive mechanisms and instnnnentation systems. Nickel-based alloys (e.g. Alloy 600) were conunonly used in the penetration nozzles and related welds. Primary coolant water and the operating conditions of P"VVR plants can cause cracking of these nickel-based alloys through a process called primary water stress corrosion cracking. The susceptibility of RPV head penetrations to corrosion cracking appears to be strongly linked to plant operating time and the temperature of the RPV head. Problems have therefore increased as plants have operated for longer periods of time.

An example of such corrosion cracking fOlmd at the Davis-Besse plant is shown below.

Figure 13 - Example of Reactor Vessel Head Cracking Reactor Pressure Vessel Head Degradation Location This issue is a concern for both IP units. IP3 must follow NRC inspection requirements for a moderate category plant, which requires RPV head inspections at least once over the course of every 2 refueling outages. The RPV head inspection frequency for IP2 is assumed to be the same as IP3. Both IP2&3 are operating on 24-month fuel cycles; therefore inspections would be performed at least once every 4 years. As of February 2004, 32 P"VVRs out of 69 in operation have or are proceeding with RPV head replacements. Thus RPV head replacement is likely at IP2&3. According to NEI, estimated inspection and repair costs are:

65 OAGI0000197 092

  • $l.5 million per outage for the average RPV head inspections and stand-by repair capability.
  • Repairs are estimated to cost approximately $1 million per nozzle. There are approximately 70 nozzles per RPV head.

Per recent industry experience, the costs for inspections and repair at other PWRs were:

  • $5.5 million for NRC Mandated NDE Inspections per unit (Florida Power and Light Company).
  • The cost of inspection and repair services at St. Lucie Unit 2 (Florida Power and Light Company) was approximately $11 million and lengthened the outage by 14 days.
  • Approximately $7 million for RPV head inspections per unit at Prairie Island.

Based on this data, the industry estimate for RPV head replacements that would be applicable at IP2&3 are:

  • NEI - $20 to $25 million
  • Davis-Besse nuclear plant - $55 to $75 million 87
  • Forbes Magazine - $60 million
  • General industry experience - $40 to $50 million The costs to replace both IP2&3 RPV heads are estimated to range from $50 million (per NEI) to $150 million (per Davis-Besse). Given these data, and the significant number of PWR units that have or are proceeding with RPV head replacements, we estimate the cost at

$100 million (2004 $) for both IP units. This CapEx might be required prior to their current license expiration, but we have made the reasonable assumption that this work would be conducted at the same time the cooling system is converted to a closed-cycle to minimize the plant outage time.

Steam Generators - All of the IP steam generators, in which heat produced in the reactor vessel is transferred to a secondary steam loops, have been replaced since the units originally became operational. The four steam generators in IP3 were replaced in 1989, and the four steam generators in IP2 were replaced in 2000 as a result of a generator tube rupture on February 15th of that year. The steam generators currently in service at IP2&3 should not need to be replaced again for the remainder of the current NRC license. If steam generators were required to be replaced prior to the current license termination date, it probably would not be economically prudent unless license extensions were being requested. If the NRC license is extended, the steam generators could require replacement again.

87 u.s. Reactor Repairs Seen Topping $1 Billion. Forbes Magazine. December 12, 2002 66 OAGI0000197_093

Pressurizer - Pressurizers are vessels that contain a mixture of steam and water for pressure control in the primary system. Operating experience, both domestic and foreign, has demonstrated that metals and welds (particularly Alloy 821182/600) in PWR pressurizers are susceptible to primary water stress corrosion cracking (PWSCC).88 Most recent leakage events were the result of axially-oriented PWSCC of the pressure boundary portion of pressurizer heater sleeves. Recent non-destructive examination results on heater sleeves have demonstrated that circumferentially-oriented PWSCC can occur in the non-pressure boundary portion of these components.

The NRC issued Bulletin 2004-01 on May 28, 2004 requiring all holders of operating licenses to evaluate their plants for this condition. On July 26, 2004 Entergy Nuclear Northeast responded that the pressurizers at IP2&3 do not contain Alloy 82/182/600 components.

While no further action is required, IP2&3 will continue to monitor industry experience relative to cracking of these components and will enhance the applicable inspection programs in the future if warranted. 89 Closed-Cycle with Cooling Towers - As mentioned previously, the DEC has issued a draft SPDES permit for IP. The draft permit effectively requires IP to replace its once-through cooling system that uses Hudson River water with a closed-cycle system utilizing cooling towers that will minimize environmental impacts. Closed-cycle cooling recirculates cooling water in a closed system; the only need for additional cooling water would be to make up water lost due to evaporation and water extracted from the closed system to flush out contaminants.

Entergy's analysis showed that the construction of hybrid cooling towers is generally feasible.

Converting to a closed system is expected to require that each unit be out of service for nine months. Entergy may take advantage of this lengthy shut-down period to undertake some of the repairs 1 replacements 1 enhancements discussed above, or other CapEx, e.g. new steam turbines with improved efficiencies.

Entergy's projected capital cost to construct hybrid cooling towers for IP2&3 is approximately $740 million (2004 $), with additional O&M expenses of $145 million projected over the life of the plant (assuming each unit receives a 20-year life extension). We interpret this expense estimate to include the reduction in plant output as well as the additional O&M expenses for the cooling towers. As explained in Attachment I, we estimate that output 88 Extensive operational experience with PWSCC in Alloy 821182/600 materials used in the fabrication of pressurizer penetrations and stearn space piping connections is not surprising. The initiation and growth of PWSCC flaws is known to be strongly dependent on the temperature of the primary system water to which the Alloy 821182/600 materials are exposed and the length of the exposure. At the pressurizer, the reactor coolant system environment operates at a temperature of about 650 C F (343 c C), so PWSCC should be expected to occur in these materials and an effective degradation management program is warranted.

89 A similar example occurred recently at San Onofre Unit 3, where cracks were discovered in the water heaters attached to the pressurizers during a scheduled refueling outage. Replacing the heaters was expected to extend the outage from just under 2 months to 31i months, at an estimated cost of close to $7 million excluding the cost of replacement energy. At some point the stearn generators will need to be replaced as well, at an estimated cost of $600 million.

67 OAGI0000197_094

would be reduced by 3%-5% due to pumping requirements and poorer condenser performance.

The estimated cost of the cooling towers may be a conservative value because IP will be required to have an emergency service cooling water system. In case of a failure in the cooling tower system, IP2&3 will need an alternative source of cooling water, referred to as an "Ultimate Heat Sink". Entergy may be able to use the existing Hudson River intake structure for this purpose, or may need to design and construct some other water source to address emergency conditions. We do not know if this additional cost will be significant and if it is included in Entergy's $740 million estimate.

In spite of the considerable CapEx to convert to cooling towers, LAI believes this will be cost-effective for Entergy because of the high market values for energy and capacity from IP2&3 over the anticipated twenty year extended plant life. However, if the CapEx requirement is higher than our $1 billion estimate, if the NRC approval is for less than twenty years, or if power prices retreat from the high values we forecast, Entergy may be less inclined to pursue license extension.

4.7. DISCOUNT RATE In order to estimate the present value of prospective IP earnings it is necessary to discount future IP after-tax unleveraged net cash flows to a financially equivalent lump sum as of a defined valuation date. We have used discount rates that reflect the after-tax weighted average cost of capital (W ACC) for a merchant nuclear power plant owner/operator. The discount rate is tantamount to the "hurdle rate" or threshold internal rate of return (IRR) that a company would find acceptable in committing discretionary capital to a nuclear plant, whose revenues are market-based. A W ACC may consist of both equity and debt components in proportion to the capital structure of the investment. The required return on equity (ROE) and the cost of debt (adjusted for tax-deductibility) comprise the W ACC, provided that both the ROE and debt interest rate fully reflect the risks of a merchant nuclear plant rather than the lower risks of an integrated energy company such as Entergy90 Discount Rates and Risk - Nuclear plants are considered to be risky relative to other power generation technologies (as explained below). Merchant plants, such as IP, have additional risk compared to utility plants that have the assurance of recovering operating and capital costs through rates. LAI reviewed two documents published by Standard & Poor's (S&P), a major rating agency that provides information to financial investors and institutions. These documents, summarized below, describe the unique risks faced by owners of nuclear power plants. Entergy itself recognizes the unique risks of merchant nuclear plants and IP in particular. In its 2003 Annual Report, under the section titled "Management's Financial Discussion and Analysis" Entergy addressed the risks of owning and operating utility and non-utility nuclear plants. After one paragraph that briefly describes the various nuclear risks, 90 The discount rate for the County of Westchester was assumed to be 4.0%, roughly equivalent to the estimated cost of GO tax-exempt debt as described on page 21.

68 OAGI0000197_095

Entergy devoted the remaining four paragraphs to safety-related issues surrounding IP; no other individual plant was mentioned.

S&P issued a report in 2003, Time for a New Start for u.s. Nuclear Energy? that addressed the future of nuclear power in light of then-current federal Energy Bill legislation designed to support nuclear investment. The S&P Report, provided as Attachment 5, highlighted the unique risks that investors face, divided into four categories:

  • Pre-construction risks of cost growth, permitting delays, public opposition, and scope changes.
  • Construction risks of cost growth, public opposItion, regulatory changes, scope changes, construction delays, procurement delays, finance delays, and permitting /

licensing delays.

  • Operating risks of public opposition, regulatory changes, permitting / licensing delays, latent technical defects, market risk, fuel disposal, "mishap" repair costs, forced outages, and replacement power obligations.
  • Decommissioning risks of regulatory changes, permitting changes, public opposition, disposal costs, and land reclamation costs.

While not all of these risks apply to IP, even nuclear plants beyond the permlttmg and construction stage expose owners to significant risks. The S&P Report states that:

" ... an electric utility with a nuclear plant exposure has weaker credit than one without and can expect to pay more on the margin for credit. Federal support of construction costs will do little to change that reality. Therefore, were a utility to embark on a new or expanded nuclear endeavor, Standard & Poor's would likely revisit its rating on the utility."

91 IP has the additional risk of being a merchant plant and not entitled to rate base treatment The S&P Report states that:

"Clearly buying and selling electricity in a competitive environment comes with its risks, both market and political.. .. These events (popularly referred to as the California "meltdown"), combined with the credit crunch that has hit many other utilities and energy merchants, have understandably moved public utility commissioners and capital providers into more risk-adverse postures.

Absent these problems, nuclear power would still be challenged to attract new capital; in this environment, however, the task is all the more difficult."

91 The S&P Report makes the point that not even rate-base treatment protects investors. For example, the $400 million estimated cost to repair the Davis-Besse plant, not including replacement power, is unrecoverable from ratepayers, leaving shareholders to shoulder the cost.

69 OAGI0000197_096

Although S&P did not quantify a risk premium or minimum IRR, the Report concluded:

"Investors, particularly lenders who rarely see any upside potential in cutting-edge technology investments, including energy, will likely find the potential downside credit risk on an advanced, nuclear power plant too much to bear unless a third party can cover some of the risks. An Energy Bill that covers advanced design nuclear plant construction risk may go a long way toward allaying those concerns, but if operational and decommissioning risks remain uncovered, look for lenders to sit this opportunity out."

In September 2004 S&P published a Commentary, Evaluating Risks Associated with Unregulated Nuclear Power Generation, provided as Attachment 6, which focused on the various risks faced by owners of merchant nuclear power plants:

  • Environmental and safety compliance risks
  • Risks associated with the storage of spent nuclear fuel
  • Decommissioning risk
  • Operational performance While the companies that own and operate these plants have been successful, S&P states that "some element of event risk will always remain with this business strategy, which could ultimately impinge on credit quality." S&P explains:

"In Standard & Poor's view, these nonregulated nuclear operations have higher risk than those plants that reside in a regulated utility business. Mostly, nonregulated plants lack the safety net afforded to those plants that are part of a regulated utility. The absence of this protection presents uncertainty regarding the ability to recover certain costs. Also, decommissioning risk is greater because underfunding cannot be recovered through the regulatory process."

Together, these two S&P documents demonstrate that merchant nuclear plants are viewed as much riskier than non-nuclear or utility-owned power plants.

Discount Rate Values - LAI researched available public sources of discount rates appropriate for merchant nuclear power plants as summarized below 92 In our judgment, a 14%-20%

discount rate is a reasonable range for our valuation analysis based on the following sources:

92 The FERC used to prepare benchmark returns on equity to establish a common basis for rate-setting purposes that would have been useful for our purposes, but no longer does so. FERC does not set rates for merchant plants.

70 OAGI0000197_097

  • Public Utilities Fortnightly - supports a 15% discount rate
  • Conference Paper on New Nuclear Plants - supports a 20% equity hurdle rate
  • State Regulatory Decisions - supports a 14%-22% discount rate
  • LAI Experience - supports a 14%-20% discount rate
  • Bodington & Company Study - supports a 18. 5% discount rate Public Utilities Fortnightly - Triggering Nuclear Development An article in the May 2004 issue of Public Utilities Fortnightly by Geoffrey Rothwell, Associate Director of the Public Policy Program and a senior lecturer at Stanford University, addressed how generating companies should evaluate the risks of investing in new nuclear 93 power plants In his analysis Dr. Rothwell derived a 12% risk-adjusted real discount rate for nuclear power plant net revenues using a real options approach to estimate the risk premium above the real cost of capital. Dr. Rothwell's approach is based on estimates of specific sources of variability in nuclear power plant net revenues electric energy prices - energy prices, output, and operating costs. While this approach was applied to a potential new nuclear power plant investment, it could be applied to the valuation of an existing nuclear generation asset as well, since the uncertainty variables modeled by Rothwell would have identical or similar distributions for either a new plant or an existing plant.

A real risk-adjusted discount rate of 12% would be equivalent to a nominal discount rate of about 15%, assuming the 3% general inflation rate used herein.

Conference Paper - The Business Case for Building a New Nuclear Plant in the U.S.

J. Redding of GE Nuclear Energy, C. Muench of Black & Veatch, and R. Graber of Energy Path presented a paper at the 2003 International Conference on Advances in Nuclear Power Plants on the economics of new nuclear power plants in the u.S 94 The three authors evaluated the economics, risks, and investment issues associated with building a new merchant nuclear power plant. The authors recognized that nuclear power plants are more risky than other technologies, and state that "Most CEOs and business development managers with whom we have discussed this issue talk in terms of20% return on equity (versus 16% for combined cycle)." The authors blend this ROE with debt in a 50/50 ratio to obtain a 12%

discount rate, implying an 8% debt interest rate. However, the authors do not indicate whether this interest rate is appropriate for a merchant nuclear plant. LAI believes that the interest rate is reflective of an integrated energy company, thus benefiting from other business 93 Rothwell, G.S., Triggering Nuclear Development, Public Utilities Forinightly, May 2004, pp. 46-51, provided as Attachment 7. Dr. Rothwell also prepared What Construction Cost Might Trigger New Nuclear Power Plant Orders? SEIPR Discussion Paper No. 03-19, Stanford Institute for Economic Policy Research, Stanford University, Stanford, CA, March 2004.

94 Proceedings ofICAPP '03, Cordoba, Spain, May 4-7, 2003, Paper 3188, provided as Attachment 8.

71 OAGI0000197_098

activities that diversify the company's risks. The cost of debt for merchant nuclear plants would likely be much higher. Moreover, it is not certain that lenders would provide non-recourse debt to a company entirely invested in merchant nuclear power.

State Regulatory Decisions LAI researched the regulatory history of the nuclear plant sales listed in the Plant Valuation section of this report and found only one document in which a state commission utilized a discount rate that reflects the risks of a merchant nuclear plant in a deregulated competitive generation market. The Connecticut Department of Public Utility Control (DPUC) issued a decision in Docket No. 99-02-05 regarding CL&P's Application to recover stranded costs associated with the sale of its equity interests in Millstone 2 (81 % of 870 MW), Millstone 3 (53% of ll54 MW), and Seabrook (4% of ll50 MW). In its introduction to the July 7,1999 decision, DPUC summarizes the purpose and the need to prepare a valuation of Millstone:

"Section 8 of Public Act 98-28 requires each electric company to submit an application for recovery of stranded costs that may be collected through the Competitive Transition Assessment (CTA) commencing on January 1, 2000. . ... This proceeding sought to quantify the potential stranded costs by determining the projected market valuations of The Connecticut Light and Power's (CL&P) various generation assets and power contracts. Critical to this process is the establishment of a market price forecast (MPF) for both energy and capacity from which the Department can then estimate the amount ofCL&P's projected costs that are above market, and, therefore, stranded. The MPF is used in this Decision to estimate 1) the stranded costs associated with the purchased power contracts either retained by the Distribution Company or bought out; 2) the minimum bids for the nuclear units; 3) an estimate of nuclear stranded costs over the remainder of the nuclear plants' useful life, and, 4) an estimate of nuclear cost recovery from January 1, 2000, until the nuclear assets are sold."

There were two expert witnesses who utilized discount rates in their calculation of market valuations. Both witnesses agreed that the market for nuclear power plants (at that time) was new and had few precedents upon which to base a conclusion. CL&P's witness, Mr.

O'Flynn, recommended a 20% discount rate based on his experience in transacting nuclear power plants. Mr. O'Flynn testified that:

  • Merchant fossil power plants had return on equity requirements of 12%-16%.
  • Nuclear plants are riskier due to complexity and uncertainty of NRC approval, unforeseen decommissioning costs, and uncertainty of planned outages.
  • A 20% discount rate is appropriate for nuclear plants.

The Office of Consumer Council witness, Mr. Rothschild, utilized a 9.84% discount rate based on the capital structure of a BBB-rated generation-only utility, reflecting a 7.19% debt 72 OAGI0000197_099

rate and an equity premium of 0.49% to 0.87% above the return granted a distribution-only utility 95 The DPUC considered both discount rate estimates and concluded "that a 14% discount rate is appropriate for a future sale on the nuclear plants by 2004":

"While the Department concurs with the Company that the risk of nuclear power exceeds that of fossil generating plants, the record also supports the use of a discount rate less than the 20% rate proffered by O'Flynn, which is inflated by an assumed 11 % - 12% benchmark ROE for regulated utilities.

Moreover, the Department concludes that by 2004, the high discount rate recommended by O'Flynn would likely drop as more sales are transacted, as the merchant nuclear plant market matures, and as buyers add successive plants to their portfolios. Although no particular capital structure is implied, the 14% discount rate allows for the possibility that a portion of the value of a nuclear plant asset could be purchased with debt financing."

Table 15 - Market Values of CL&P's Nuclear Assets

($/kW)

Discount Rate Millstone 2 Millstone 3 Seabrook 20% $ -ll $ 227 $ 179 17% $ 6 $ 292 $ 236 14% $ 35 $ 387 $ 323 Despite its conclusion that a 14% discount rate was appropriate, the DPUC selected estimated plant values that corresponded to higher discount rates. Assuming linear interpolation and extrapolation of the values in the table above, the DPUC effectively utilized discount rates of 15%-22% as shown below 96 The average discount rate, weighted by CL&P's effective ownership shares in the three plants, was 18.3%.

  • $25/kW for Millstone 2 - corresponds to 15%.
  • $185/kW for Millstone 3 - corresponds to 22%.
  • $185/kW for Seabrook - corresponds to 20%.

95 LAI does not believe that Mr. Rothschild fully considered the risks of merchant nuclear power plants in determining the equity premium and resulting discount rate.

96 The market values may not be linearly correlated to discount rates. However, for the purpose of this assignment, LAI believes that assuming a linear relationship is reasonable.

73 OAGI0000197_100

LAI Experience The proposed discount rate range of 14% - 20% is consistent with LAI's experience. We have worked on a number of relevant plant valuation and investment matters in which the discount rates we used are consistent with the range in this assignment. In one case, LAI was retained by a utility investor that was considering purchasing an equity interest in a nuclear power plant that would be exposed to market risk. The purchaser conducted an evaluation of the plant's operating data and decided to pursue the purchase based upon estimated IRRs at the upper end of the range used in this assignment. As more accurate O&M data became available and the estimated IRR fell below the range used in this assignment, the investor withdrew its offer. LAI confirmed the reasonableness of the purchaser's decision to cancel the transaction.

Bodington & Company Report LAI commissioned Bodington & Company, a firm specializing in energy industry investments, to review the literature and recent market transactions and to develop an independent estimate of the appropriate W ACC for a merchant nuclear entity 97 Bodington found that most recent nuclear transactions and merchant power asset transactions have not been "pure plays", that is, an entity with publicly traded securities engaged solely in the merchant generation business.

Bodington applied the Capital Asset Pricing Model (CAPM) to several publicly traded firms (e.g., AES, Calpine, and Reliant) that are engaged primarily in merchant power generation to estimate a market-based cost of equity and found a range from l7.l5% to 19.60%, built up from a risk-free return rate of 4.90%, a general market risk premium of 7.00%, and company Betas of l.75 to 2.10. These companies have very high debt levels, reflective ofa time when (fossil) merchant plants could be highly leveraged. Rather than use the current debt levels, Bodington imputed debt costs based on each company's S&P rating - all were in the B/C range, resulting in marginal debt cost of 12.0% pre-tax. Given that the selected firms are not "true plays", Bodington suggests that leverage should be decreased to 30%. Based on a Beta of2.00, this approach yields a WACC of 15.39%.

As an independent approach, Bodington analyzed the sale of merchant assets from Duke Energy to KGen Partners in 2004. The resulting entity was financed with $425 million in cash equity and $50 million in a note to Duke at LIB OR plus 14.5%. The note establishes an upper range for merchant power debt cost at 16.95% and a lower bound on equity cost. Citing a typical risk premium of equity cost over debt of 6%, the cost of equity was estimated at 22.95%. With the leverage ratio of 11 % implied in the transaction, the W ACC was calculated at 2l.54%.

Using both the CAPM and KGen approaches, Bodington concludes that a reasonable W ACC for the envisioned IP transaction would be 18.5%.

97 The Bodington report is provided as Attachment 9.

74 OAGI0000197_ 101

Entergy's Non-Utility Nuclear Assets LAI analyzed the financial statements of four integrated electric companies that have significant portfolios of merchant nuclear power plants: Entergy, Exelon, Constellation Energy, and Dominion Resources. Only Entergy provides separate financial data for their non-utility nuclear business that provides us with historical IRR and ROE data that is useful in calculating a discount rate appropriate for merchant nuclear power plants.

LAI reviewed Entergy's financial data provided in filings to the Securities and Exchange Commission (SEC) and in various documents for investors in order to estimate the actual ROE or IRR for their merchant nuclear power investments 98 Entergy operates primarily through three business segments, U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services, and provides useful data for each. The most recent key financial indicators for these business segments are provided in Table 16. The Non-Utility Nuclear segment owns and operates five nuclear power plants - Pilgrim, FitzPatrick, IP2, IP3, and Vermont Yankee -

and is an important and very profitable part of Entergy's overall business activities.

According to these indicators, the Non-Utility Nuclear business segment accounted for less than 15% of Entergy's total assets, but yields almost one-third of Entergy's net income.

Table 16 - 2003 Key Indicators of Entergy's Business Segments

($ millions)

Non-Utility Nuclear Energy Entergy u.S. Utility (and % of total) Commodity Consolidated Operating Revenues $ 7,585 $ 1,275 13.9% $ 185 $ 9,195 Net Income $ 493 $ 301 31.7% $ 180 $ 950 Total Assets $22,429 $ 4,l71 14.6% $ 2,077 $28,554 Shareholder's Equity $ 5,448 $ 1,949 22.4% $ 1,615 $ 8,704 Every year Entergy prepares an Investors Guide and Statistical Report designed to support investors understanding of Entergy's businesses. The report provides profitability measures for the Non-Utility Nuclear business segment over the years 2001 - 2003 that is summarized in Table 17 below.

98 2004 data was not available in time to be included in this report.

75 OAGI0000197_102

Table 17 - Reported Profitability of Non-Vtility Nuclear Business Segment (based on net income) 2003 2002 2001 Average Return on Invested Capital As Reported 12.7% 11.8% 10.0% 11.5%

_________<?p~~~t!~,!-~l__________ ~:~~~ ______ !!._8_'l::o______ !~*9::? ______ I_~-}::? __ _

Return on Equity As Reported 17.3% 16.4% 20.7% 18.1%

Operational Il.l% 16.4% 20.7% 16.1%

Return on Invested Capital (ROIC) is defined as net income plus after-tax interest expense divided by the average level of invested capital (equity plus long-term debt). ROE is defined as net income divided by the average level of common equity. The ROIC and ROE data differ due to interest expense and the amount of debt included in the business segment's capitalization. The amount of debt attributed to the Non-Utility Nuclear business segment has fallen from 48% as of year-end 2001 (hence the large difference between the ROIC and ROE data) to 24% as of year-end 2003 (resulting in a smaller difference). The reported profitability is presented on an "As Reported" basis per GAAP reporting requirements and on an "Operational" basis that excludes the impact of special items. Special items only affected the 2003 data, when an accounting change provided Entergy with a one-time increase in net

. 99 IUcome.

While ROIC or ROE are single year measures of return, the fact that net income includes the effects of depreciation, amortization, and decommissioning accruals as expenses makes it an indicator of return over the life of the various investments included in the operating segment.

Over the life of an investment, the average of annual ROIC or ROE measures should approximate the corresponding DCF internal rate of return. Of course, in the case of an ongoing, multi-asset concern, there are no clear beginning and ending points to test this hypothesis. Since Entergy's Non-Utility Nuclear business segment relies on parent company debt that does not reflect the specific risks of merchant nuclear plants, we believe that the ROE data is a more reliable indicator of W ACC and supports our range of discount rates.

99 According to Entergy's 2003 Annual Report, SFAS 143, Accounting for Asset Retirement Obligations required Entergy to (i) record the fair value of asset retirement obligations, i.e. nuclear plant decommissioning, (ii) measure the obligations assuming a third party performs the work, and (iii) discount future obligations using a credit-adjusted risk-free rate. The net effect for the Non-Utility Nuclear business segment was a one-time increase in net income of $155 million. Other non-operational items resulted in a combined adjustment to income of $1 04 million.

76 OAGI0000197_103

Table 18 - Estimated Profitability of Entergy Non-Utility Nuclear Business Segment (based on cash flow; $ millions) 2003 2002 2001 Average Cash Flow Provided by Operations $ 183 $ 282 $ 263 Average Shareholders' Eguity $1,654 $1,165 $ 798 Return on Equity - high case 11.0% 24.2% 33.0% 22.7%

Cash Flow Provided by Operations $ 183 $ 282 $ 263 Average Shareholders' Eguity $1,654 $1,165 $1,005 Return on Equity - low case 11.0% 24.2% 26.2% 20.5%

Entergy's Investors Guide and Statistical Report provides perfonnance data based on net income. However, the discount rate LAI intends to utilize will be applied to a forecast of IP cash flow. Therefore we have estimated similar financial performance measures based on the reported after-tax cash flow data provided in Entergy's 2003 Fonn 10-K. LAI divided the Non-Utility Nuclear business segment's cash flow provided by operations 100 by the average shareholder's equity (averaged between beginning-of-year and end-of-year) to estimate the cash flow-based profitability101 Over the period 2001-2003, Entergy's Non-Utility Nuclear business segment averaged about a 20.5%-22.7% ROE on an after-tax cash basis as illustrated in Table 18 102 These measures of return based on cash flow are generally higher than the corresponding measures based on net income, because non-cash expenses such as depreciation are "added back" to obtain cash flow from operations.

It would be possible to derive a cash flow measure for return on invested capital by adding interest paid to cash flow from operations, before dividing by the average level of invested capital. This measure would have a similar relationship to its income-based counterpart. We believe that the ROE estimates shown above also support our range of reasonable discount rates.

4.8. VALUATION / COMPENSATION RESULTS Using the revenue and cost forecasts described above, LAI developed a pro forma cash flow model for IP. The cash flow model uses the forecasts of revenues and operating costs to calculate earnings before interest, taxes, depreciation, and amortization (EBITDA), then estimates the unleveraged after-tax net cash flow (Net Cash Flow) for an infonned, willing buyer of the IP units as a going concern. The purchase price that results in a net present value 100 Cash flow provided by operating activities is essentially net income adjusted for non-cash items (depreciation, amortization, and decommissioning allowances and deferred taxes) included in income and for changes in working capital accounts. It does not include cash flows used in or provided by investing and financing activities.

101 The SEC Fonn IO-Ks provided all of the data required to complete this calculation except for the shareholder's equity at the beginning of 2001.

102 These ROE calculations are based on Entergy's book value of equity, while our derivation of discount rates is based on market values of equity.

77 OAGI0000197_104

of zero using the buyer's W ACC as a discount rate is the FMV of the generating units. The development of EBITDA and the calculations for determining FMV are discussed in subsections below.

LAI estimated EBITDA for the original license term and for a license renewal period, based on the revenues and operating costs discussed above, as shown in Figure 14 and Figure 15, respectively. During the original license term EBITDA varies from $400 million to $600 million per year through 2012, and then drops off as the units are retired in 2013 and 2015.

The values shown for 2016 and 2017 are typical of the years after shutdown, with negative EBITDA attributable to ongoing expenses for SNF management. If Entergy (or a hypothetical buyer) is successful in obtaining NRC license extensions and undertakes the CapEx for the cooling towers and other improvements, Entergy would begin investing capital as early as 2010. The negative EBITDA value in 2013 shown in Figure 15 reflects the CapEx spending and extended outage of IP2 prior to operation under the new license. The negative EBITDA in 2015 reflects the extended outage for IP3, partially offset by the operation ofIP2.

Figure 14 - Original License Term EBITDA 1,400,000 .-------------------~

= NYPA IP2 Payment 1,200,000

-SPDESCost 1,000,000

=ISFSI Cost 800,000

-Labor Cost 600,000 o

a

. 400,000 +.........1'1-'" - Fixed O&M, etc .

"iii 200,000 c:::J Variable cost w

=Value Sharing Adj (200,000) -Capacity Revenue (400,000) -Energy Revenue (Net)

-EBITDA (600,000)

(800,000) .1..-_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _--1 78 OAGI0000197_105

Figure 15 - License Renewal Tenn EBITDA 3,000,000 ,-

-SPDESCost

=ISFSI Cost 2,500,000 -Labor cost

=PILOT

- Fixed O&M, etc.

2,000,000 -Variable cost

-Capacity Revenue

-Energy Revenue (Net) 1,500,000 -EBITDA c

c

~ 1,000,000

(500)

(1,000) .. *

(I ,500) -t.............................................................................................................................................................................................................................................................................................................................................................

1 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 ll8 OAGI0000197_145

6.13. TOTAL COSTS AND RATE / ECONOMIC IMPACTS LAI has calculated the total direct and indirect costs and rate / economic impacts to the County and other stakeholders, assuming no on-site replacement generation, by combining the direct costs and impacts of (i) estimated compensation due Entergy, (ii) electric rate impacts, and (iii) economic impacts, as well as the indirect impacts using economic multipliers. Under the acquisition option in which the County or the State would commence condemnation proceedings immediately, and would complete the acquisition and shut down IP on January 1, 2008, we estimate the compensation due Entergy at $l.75 - $2.74 billion, plus $241 million for SNF management, expressed in present value terms as of January 1,2008. This cost could be shared among the County, State, NYPA, and other stakeholders such as Con Edison, New York City, etc. When indirect impacts are included using a l.75 multiplier, the total cost to the stakeholders increases to $2.99 - $4.48 billion, as seen in Table 33 and Table 34.

Table 32 - Direct and Total Costs - 2008 Acquisition by Condemnation (2008 $ millions; impacts relative to 2013115 retirement; no replacement generation)

Costs Shared by Stakeholders Direct Cost Direct and Indirect Entergy Compensation $1,754 - $2,744 $2,631 - $4, ll6 Spent Nuclear Fuel $ 241 $ 362 Total $1,995 - $2,985 $2,993 - $4,478 If IP is acquired through a condenmation proceeding, the County would bear a large proportion of the economic impacts due to lost PILOT, reduced employment, etc. The present value of the economic impacts on the County as of 2008 is $ll6 million; the figure would be over $330 million ifnot for assigning 10% of the value for the improved health of the Hudson River fisheries. When including the impact of the electricity market prices, the total direct impact increases to $214 million ($434 million excluding the fisheries).

To account for indirect effects on the County, we employed a County-specific multiplier of l.5x. The present value of the direct and indirect impacts on the County is $320 million, excluding any share of compensation paid to Entergy.

ll9 OAGI0000197_146

Table 33 - Direct and Total County Impacts - 2008 Acquisition by Condemnation (2008 $ millions; impacts relative to 2013115 retirement; no replacement generation)

Rate / Economic Impacts on County Direct Direct and Indirect Electric Market Impact $ 216 $ 324 Economic Impacts (benefits in parenthesis)

Property Taxes $ 143 $ 215 Employment $ 123 $ 185 Local Spending $ 89 $ 134 Community Support $ 6 $ 9 County Emergency Planning ($ 35) ($ 53)

Corporate Income Tax $ 8 $ 12 Hudson River Fisheries ($ 220) ($ 330)

Air Emissions ~ ~

Sub-Total $ ll6 $ 174 Totals $ 332 $ 498 While the rest of the State would bear some of the same types of economic and rate impacts of retiring IP, it would receive the lion's share of the improved fisheries health benefit.

Higher electricity prices would also impact the State, raising the total cost estimate.

Table 34 - Direct & Total State Impacts - 2008 Acquisition by Condemnation (2008 $ millions; impacts relative to 2013115 retirement; no replacement generation)

Rate / Economic Impacts on State Direct Direct and Indirect Electric Market Impact $ 1,742 $ 3,048 Economic Impacts (benefits in parenthesis)

Property Taxes $ 143 $ 250 Employment $ 820 $ 1,435 Local Spending $ 341 $ 597 Community Support $ 6 $ II County Emergency Planning ($ 35) ($ 61)

Corporate Income Tax $ 167 $ 292 Hudson River Fisheries ($ 2,198) ($ 3,847)

Air Emissions ~ ~

Sub-Total LL.m.2 (U,lID Totals $ 1,027 $ 1,798 A voluntary retirement through a consensual agreement with Entergy would allow the County to avoid the costs and risks of an acquisition, keep in place Entergy's operation and management resources, provide Westchester with significant flexibility to arrange a compensation package that could include on-site replacement generation, and allow the State and other stakeholders to participate in the negotiations. We have assumed that the County 120 OAGI0000197_147

would enter into a consensual agreement to retire IP at the end of the existing license terms with Entergy and other stakeholders by January 1, 2011. In this option, the only cost the County would incur is its share of compensation due Entergy, since all of the electric market and economic impacts would be identical to our base case assumption of IP retirement in 2013/15. In effect, the County and other stakeholders would be buying out Entergy's option to extend IP's licenses. We estimate compensation due Entergy at $0.49 - $1.38 billion in l36 present value terms as of January 1,2011, much less expensive than the acquisition option As before, the compensation range is due to the uncertainty of an appropriate discount rate.

When indirect impacts are included, the value rises to $0.87 - $2.42 billion.

Table 35 - Total Direct and Indirect County Costs - 2013/15 Voluntary Retirement (2008 $ millions; impacts relative to 2013115 retirement; no replacement generation)

Costs Shared by Direct and Direct Cost Stakeholders Indirect Entergy Compensation $495 - $1,376 $866 - $2,415 SNF Costs Total $495 - $1,376 $866 - $2,415 6.14. RATE IMPACTS The impact of IP retirement on market energy prices, discussed earlier, can be translated into impacts that would be felt by residential ratepayers. A typical household in Westchester paid approximately $84.60 per month last summer and $90.59 last winter, or $1,051 per year, based on the Con Edison's 2004 retail rates. Con Edison resets its rates every six months to include necessary modifications to the market supply (i.e., energy and capacity) and market adjustment charges. The principal components of each bill for the current winter and the past summer are depicted in the table below based on a typical household usage of 500 kWh/month. 137 136 In 2005 dollars, the cost is equivalent to $0.4 - $1.2 billion for the County, assuming a 4.0% discount rate.

137 Source: NYPSC utility bill data. NYPSC uses 500 kWh/month as a standard average consumption value; actual average consumption may be materially higher in Westchester.

121 OAGI0000197_148

Table 36 - 2004 Monthly Con Edison Westchester Electric Bills (based on 500 kWh/month)

Component Summer '04 Winter '04-'05 Delivery Charge $ 9.71 $ 9.71 Distribution Charge $22.16 $19.97 Transmission Charge $ 3.92 $ 3.62 System Benefits Charge $ 0.80 $ 0.80 Taxes $ 2.61 $ 2.56 Market Supply $30.99 $34.98 Monthly Adjustment Charge $20.40 $12.96 Total $90.59 $84.60 Only one component of the residential bill would be affected by the retirement of IP: Market Supply, which combines the cost of both energy and capacity procured by Con Edison on behalf of its customers. In the past, MAC would also have been impacted by IP retirement, but is currently being phased out as discussed below.

Monthly Adjustment Charge Prior to the development of competitive electric markets in New York, the NYPSC investigated but, at that time, found no substantial cost differences to warrant charging Con Edison's Westchester customers (Zones H&I) a different rate than Con Edison's New York City customers (Zone J).138 In 2000, Con Edison unbundled its services and instituted a MAC to recover its stranded generation costs in a manner that equalized Con Edison's customer rates across Zones H (i.e. Westchester County) and J (i.e. New York City).139 Since underlying electricity costs were higher in New York City, Westchester customers were burdened with a higher MAC to equalize Con Edison's rates between the two service areas.

In fact, according to testimony filed by the County, Westchester ratepayers were paying over one-half of Con Edison's stranded costs but only account for 12% of Con Edison's total electricity consumption.

In December, 1999, the NYISO took control of the electricity markets and began its bid-based pricing mechanisms. Shortly thereafter, it became clear that the underlying costs for electricity products (i. e. energy and capacity) were significantly different among the NYISO zones. As the NYPSC implemented Con Edison's proposed MAC, Westchester raised concerns of unfair cost allocation. Although the NYPSC allowed Con Edison's MAC mechanism, it decided to examine Westchester's concerns about this issue and initiated a 138 Case 28157. Consolidated Edison Company of New York. Inc. - Order Determining Iliat a Geograpliical Classification of Customers is Unnecessary. 22 NYPSC 1428 (1982).

139 Case 96-E-0897. Consolidated Edison Company of New York. Inc. - Rate Restructuring Proceeding. Order Concerning Retail Access Implementation Plan - Pliase 3 (2/28/2000).

122 OAGI0000197_149

proceeding. 140 The NYPSC staff submitted a proposal to establish equal MAC rates over a three year phase-in period that would lower rates in Westchester and raise them in New York City. The case continued contentiously over the next two years. In its Order Adopting Staff Proposal, the NYPSC noted that the case presented a unique situation "where the utility company straddles two ISO zones that have substantially different commodity costs." In November 2003, the NYPSC decided to equalize the MAC over the three-year period, which would cause Con Edison's full service rates in Westchester to become lower than rates for New York City, thereby furthering economic efficiency goals 141 Although New York City filed a Petition for Rehearing, the NYPSC denied the Petition in April 2004. Thus LAI expects that Con Edison rates for Westchester ratepayers will be lower than for Con Edison ratepayers in New York City starting this year. 142 While achieving a change in the MAC was a substantial victory for Westchester County and succeeded in lowering retail energy prices in the County, the MAC change also eliminates some ability for COWPUSA to compete against Con Edison in the retail service market.

Energy Price Forecast LAI prepared a Base Case forecast of market energy prices assuming that IP' s operating licenses would not be renewed, as well as forecasts for the alternative scenarios in which IP is retired immediately, retired in 2008, and the licenses are extended for twenty years. In general, we project electricity bills to increase rapidly in all cases. This is due in large part to the natural effects of inflation (set at 3% in our financial models), as well as the expected increase in real fuel commodity costs, particularly natural gas, that sets the market energy price during many on-peak hours of the year. Since the NYISO sets the market price for energy based on the cost of the last, or "marginal," unit to meet demand, hours when the marginal unit is a gas-fired facility will raise market energy prices for all generators. 143 Over time, this effect will increase due to the additional use of gas in power plants and load growth in the region. As load increases, particularly during off-peak hours, natural gas is likely to set the market price in an increasing number of hours. Currently, lower cost coal and hydro units set the price for many of the off-peak (night-time and weekend) hours of the year.

But because these resources are not growing in size, regardless of Westchester's actions related to IP, increases in off-peak load require higher cost units such as natural gas-fired 144 facilities to increasingly operate and thus set the market price. Under this system, more expensive units would be dispatched more frequently, including the gas-fired combined cycle 140 Case 00-E-1208, Consolidated Edison Company of New York, Inc. - Electric Rates, Order Instituting Proceeding (7/20/2000).

141 Case 00-E-1208, Consolidated Edison Company of New York, Inc. - Electric Rates, Order Adopting Staff Proposal (11/25/2003).

142 The J\1AC is reset and trued up every six months, but not simultaneously. For purposes of our analysis, we assumed the MAC is eliminated on January I, 2005.

143 In the short-run, utilities can hedge against market energy prices by executing PPAs with generators.

144 Increased reliance on gas-fired generation may expose New York ratepayers to increased price volatility as periodic gas price spikes during the winter months directly affect market energy prices. Our gas price forecast incorporates average expected gas prices and does not focus on short-tenn price volatility.

123 OAGI0000197_150

units that we expect would replace IP. The following table describes changes to regional spot market energy prices that LAI forecasted using MarketSym if IP is retired immediately in 2005, in 2008, or has its licenses extended 145 Values represent percentage changes against the Base Case ofIP retirement in 2013/15.

Table 37 - Average Change in Market Energy Prices 2005 2008 License Region NYISO Zone(s)

Retirement Retirement Extension Westchester County GHI 11.3% 84% -7.5%

New York City 4.5% 3.8% -2.9%

Albany F 7.6% 6.5% -3.7%

Western NY A-E 0.1% 0.6% -0.2%

Long Island K 4.3% 3.9% -3.1%

  • If IP is retired immediately and replacement generation is not installed, an unrealistic scenario, market energy prices in Westchester are projected to increase by 1l.3% on average through 2015.
  • If IP is retired in 2008 and developers have sufficient notice to install replacement generation, market energy prices in Westchester are projected to increase by 8.4% on average through 2015. Market energy prices in New York City are projected to increase by 3.8% on average. Unlike the Immediate Retirement scenario, the 2008 Retirement scenario allows for a reasonably orderly market-based transition. In this scenario, we presume three years represents adequate time for developers to build new replacement generation so that the IP2&3 shutdown does not result in a shortage in generating capacity.
  • If the IP licenses are extended so that 2,000 MW of replacement generation is not required, market energy prices in Westchester are projected to decrease 7.5% on average from 2013 through the term of the license extension.

Average market energy prices for the County and surrounding regions are depicted in Figure

30. These values are considered "time-weighted" or averaged across all hours of the year.

145 Importantly, as referenced above, not all energy procured is indexed to market prices. We estimate that approximately 50% of the energy consumed in New York State is under long-term or cost-based agreements that will not be impacted by IF's retirement.

124 OAGI0000197_ 151

Figure 30 - Forecast of Market Energy Prices in Westchester 95.00

~Base Case

____ Inunediate Retirement

~ 2008 Retirement 80.00 Licens e Extension 65.00 50.00 2005 2008 2011 2014 2017 2020 Ratepayer Impacts LAI forecasted the expected impacts on with residential customer electricity bills. As described earlier, ratepayers would only be exposed to changes in market energy prices for the share of their utility's supply not purchased through long-term PPAs. We have estimated that Con Edison ratepayers in Westchester and in New York City would be 50% affected by higher market energy prices. The results can be summarized as follows:

  • In the unrealistic case that IP is retired immediately and replacement generation is not installed, the typical residential ratepayer will pay $4.20/month more in that year, and

$3.76/month on average through 2015.

  • If IP is retired in 2008, the typical residential ratepayer will pay $2.42/month more in electricity charges in that year, and $1.55/month more on average in electricity charges though 2015.
  • If the IP licenses are extended so that 2,000 MW of replacement generation is not required, the typical residential ratepayer will pay $1.65/month less for electricity charges in the first full year to be impacted by the license extension, 2016, and approximately $2.05/month on average from 2013 through the duration of the license extension period.

In the following figure, we show total bills for years 2005 and 2008 for the Base Case in which IP is retired in 2013/15, Immediate Retirement, and 2008 Retirement scenarios.

125 OAGI0000197_152

Figure 31- Comparison of Residential Bills by Scenario: 2005,2008 85.-------------------------------------------------,

s 80

=

~

~ 75

~

iii 70 "0

~ 65 60 2005 2008 DBase Case .Immediate Retirement o 2008 Retirement Residential bills under the License Renewal scenario are identical to the Base Case without license renewal for the years 2005 and 2008 and were not included in Figure 3l. License renewal does affect long-tenn prices, as shown in the following figure with typical bills under all four cases through 2018.

Figure 32 - Long-Term Trends of Monthly Bills by Scenario 110

c

==

= 100

~ 90

~

80

'~"

! 70

~ ~:~ ~

60 2005 2007 2009 2011 2013 2015 2017

~Base Case ~Immediate Retirement -L\-2008 Retirement License Renewal 126 OAGI0000197_153

ATTACHMENTS:

1. PERFORMANCE EFFECTS OF COOLING TOWERS
2. NEW YORK EMINENT DOMAIN PROCESS TrMELINE
3. CHAPTER 875 OF THE WESTCHESTER COUNTY CHARTER
4. ENTERGY ZONING VARIANCE
5. TIME FORA NEW START FOR U.S. NUCLEAR ENERGY?
6. EVALUATING RISKS ASSOCIATED WITH UNREGULATED NUCLEAR POWER GENERATION
7. TRIGGERING NUCLEAR DEVELOPMENT
8. THE BUSINESS CASE FOR BUILDING A NEW NUCLEAR PLANT IN THE U.S.
9. REpORT OF BODINGTON & COMPANY REGARDING DISCOUNT RATE 1o. FAIR MARKET VALUE CALCULATIONS
11. GAO REpORT: NUCLEAR REGULATION (EXCERPT)

OAGI0000197_154 OAGI0000197_155

Attachment 1 PERFORMANCE EFFECTS OF COOLING TOWER BACKFITS The most significant modification to IP2&3 as part of the relicensing process, in terms of performance as well as cost, is likely to be the replacement of the once-through circulating water system with closed-loop cooling towers. This modification will reduce the net output of each unit by about 3% to 5% due to a combination of increased auxiliary power requirements and reduced steam cycle thermal efficiency.

Heat Rejection Requirements All thermal power plants receive heat energy from a high temperature source and rej ect heat energy to a lower temperature sink. Generally, the greater the difference between source and sink temperature, the more work (i. e. electric energy) can be extracted and the higher the thermal efficiency of the thermal cycle will be. 1 The amount of heat that must be rejected is proportional to (1- thermal efficiency) of the cycle? At a 33.3% thermal efficiency, then, the roughly 3,000 MW'of thermal energy from each reactor results in 1,000 MW of electric generation and 2,000 MW thermal (appro)(imately 6,800 MMBtulh) of condenser heat rejection.

The condensers are very large heat exchangers, consisting of a shell into which the steam turbines exhaust the spent steam, and which is traversed by thousands of tubes carrying cooling water. As the steam contacts the tubes, it is condensed, and the heat released by condensation is conducted through the tube walls and carried off by the cooling water.

Condensate accumulates at the bottom of the shell and is pumped back through the cycle.

The temperature at which condensation occurs is determined by the amount and condition of the steam entering the condenser (i.e. the duty), the amount of surface area supplied by the tubes, the heat transfer coefficient determined by the material and wall thickness of the tubes, their cleanliness, and the velocity of the water flowing through them, and the total flow and the inlet temperature of the cooling water. For a given duty and surface area, the temperature will be higher as water flow decreases and/or inlet water temperature increases. A higher condensing temperature means a higher condenser pressure and a less efficient thermal cycle?

Existing Indian Point Heat Rejection Design IP2&3 were designed to use the Hudson River as their "sink" to dissipate the cycle heat.

Pumps push large volumes of water (estimated at 840,000 gallons per minute for each unit 1 Tbis comes from the Second Law of Thermodynamics, wbich requires that entropy of a system increase. For work to be created from thermal energy, energy must flow "down hill" to a lower temperature, an irreversible process.

2 From the First Law of Thermo dynarnics , total energy is conserved.

3 The saturation temperature (boiling or condensing temperature) of water is a function of pressure. At atmospheric temperature, water boils or steam condenses at 212 OF. At a vacuum of28 inches of mercury (about 1 psi absolute), steam condenses at 101°F.

OAGI0000197 _156

from the river, through the condensers, and back to the river heated by about 17 of. Steam flowing through the plant's turbines exhausts into the condensers at pressures as low as 1 psi absolute, or a vacuum of about 28 inches of mercury. Inlet water temperatures from the Hudson River presumably range from close to 32 of in the winter to about 75 of in the summer, with minimal fluctuations during a typical day.

The circulating water pumps are designed to handle a large flow at relatively low "head" or pressure differential. Since the water is discharged at river level, there is no significant net elevation head to overcome, so the pumps need only overcome friction losses. This results in relatively low power requirements for the pumps.

Cooling Tower Backfit Design Options If a conversion to closed-loop cooling is required as part of the relicensing process for IF 2 &

3, the owner will have several design decisions to make:

~ Location of the cooling towers

~ The type of cooling tower o Natural draft or mechanical draft o Cross flow or counter flow o Wet (evaporative) only, or hybrid wet/dry

~ Condenser modifications o Maintain current flow (and temperature rise) or decrease flow (increase rise) o Maintain current condenser envelope or replace with optimized design (longer tubes, different materials)

~ Hydraulic design o Hot- or cold-side pumping o High water pressure operation or hydraulic recovery turbine The crowded nature of the IF site at the main plant grade will probably preclude locating cooling towers at close to the same elevation as the condensers. One option that has been considered is locating them on a bluff about 100 feet above the main plant grade. The retrofitted circulating water system would have to allow for the head to the bluff level plus about 50 feet to the top of the tower fill.

Several nuclear power plants in the Northeast use natural draft cooling towers with their large (400 to 500 ft high) hyperbolic concrete stack shells. While more capital intensive than mechanical draft towers, they eliminate the parasitic load and noise of cooling tower fans, and the higher discharge elevations reduce fogging and icing problems. On the other hand, they have high visual impact and require a long construction period. Cross-flow and counter-flow designs are available in both natural and mechanical draft, and they offer trade-offs in pumping head, land requirements, control under extreme cold conditions, and fill design.

Hybrid wet/dry cooling towers have seen limited applications for plume control and water conservation.

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It may be possible to design a closed loop system around the existing condenser, but several concerns make this an unlikely choice. First, the condenser is designed for relatively low maximum inlet temperature, high circulating water flow (and correspondingly low temperature rise), and low water-side pressures. Maintaining the low temperature rise will result in a relatively expensive cooling tower and require high pumping power. If circulating water pumps are placed on the cold-water side of the condenser (normal practice), then the pressure on the water boxes and tubesheets will be significantly higher than in the once-through arrangement. If the pumps are placed on the hot-water side, pressure might still be an issue if the cooling tower is located on the bluff instead of at plant grade. To the extent possible within turbine building constraints, a new condenser with optimized dimensions might be more economicaL It would probably have a longer effective tube length, achieved by pushing out the water boxes and circulating water piping or creating multiple passes. This would allow for lower circulating water flows and a higher temperature rise. Tubes might be of different material and diameter to optimize available space and minimize performance impacts.

In conjunction with condenser reconfiguration, the entire circulating water piping system will require reconfiguration. As indicated previously, the circulating water pumps might be on either side of the condenser. With a high elevation for the cooling tower relative to the condenser, some form of hydraulic recovery turbine may be appropriate to recover potential energy in water flowing down from the cooling tower basin to a plant level reservoir.

Cooling Tower Performance All evaporative cooling towers are limited by an approach to the ambient wet bulb temperature. 4 If a tower is designed to cool a specific water flow rate from 112 OF to 95 OF when the wet bulb temperature is 80 OF, it is said to have a design approach of 15 OF (= 95° -

80°) and a range of 17 OF (=112° - 95°). Cooling tower range is equal to condenser rise. At the same duty (flow and range) this tower will have a somewhat higher approach at a lower wet bulb, so water temperature does not drop degree for degree with wet bulb. If range (duty with constant flow) is decreased, the approach will be lower at a given wet bulb temperature.

This design condition is relatively severe. Achieving the same approach with less flow and a higher range (same duty) would require less cooling tower capacity.

While Hudson River temperature is quite stable day to day and follows a relatively predicable seasonal pattern, the temperature of water from a cooling tower will vary significantly with ambient conditions. The temperature of river water approaches seasonal average wet bulb temperature quite closely. Cooling tower water approaches hourly wet bulb with a significant differentiaL Plant Performance Effects 4 Wet bulb temperature is an indication of the amount of moisture in air at a given "dry bulb" temperature. At 100% relative humidity, the wet bulb temperature equals the dry bulb temperature. At low relative humidity and high dry bulb temperature, wet bulb temperature is significantly less than dry bulb temperature. Wet bulb temperature can be measured by covering the bulb of a thermometer with a water-soaked wick and spinning the thermometer through the air.

\\sgp\My Documents\COWPUSA\Report\Attaclrrnents\Heat Rejection Effects pIc 3Dec04.doc 3 12/3/043:24 PM OAGI0000197 _158

Regardless of which design options might be chosen, retrofitting to closed-loop cooling will result in a loss of net output from IP 2 & 3, particularly in the summer when wet-bulb temperatures are high. The loss of net output will consist of two components - reduced gross generation and increased auxiliary power load. For a natural draft tower, the auxiliary power would be almost entirely for pumping circulating water. With a mechanical draft tower, there would also be fan power to consider.

On a peak summer day, condenser inlet water temperature would increase by at least 10 OF, (i.e. the approach of the cooling tower). If the condenser rise is maintained at 17 OF, then condenser outlet temperature would increase by 10°F and condensing temperature would increase by roughly the same amount. This could have a 1% or greater impact on generation, depending on turbine design parameters. If rise is increased (circulating water flow decreased) to control the size and cost ofthe cooling tower and reduce pumping requirements, there would be a larger increase in condensing temperature, unless surface area and/or heat transfer rates are increased.

Pumping power will increase substantially if flow is maintained at current levels. With up to 100 feet of additional head, power requirements would increase by up to 25 MW per unit, or 2.5% of output. s Based on these estimates and on earlier IP studies, net electric output from the facility might be reduced by at least 3% to perhaps as much as 5%.

5 Pump kW = [Flow (gpm) x Head (ft) ] / 3960 / Pump efficiency / Motor efficiency

  • 0.746 Assume that pump efficiency is 75% and motor efficiency is 95%.

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OAGI0000197_159 OAGI0000197_160

New York Eminent Domain Process Owners must be Condemnor served must serve Parties can Condemnor has up to with notice of appeal to 3 years to commence notice of acquisition Appellate action from later of hearing on Owner Divison for publication of within 20 once order limited determination; entry of Decide to Conduct Offer days of and map review fmal order or judicial acquire public made Tp."lP.UT hearing are filed property hearing to Condemnor public makes public Owner has up to notice on determination Condemnor 3 years to file hearing andfmdings files petition consecutive claim for Offer dee-med with days in paper damages if it rejected if not Westchester roperty doesn't believe accepted by Supreme appraised monetary offer is Owner within Court to by sufficient 90 days acquire o Condemnor property

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OAGI0000197_162

Chapter 875 PUBLIC UTILITY SERVIC:E; AGENCY Sec. 875.01. Legislative findings and declaration of purpose.

Sec. 875.11. Dennitions.

Sec. 875.21. Agl'lncy created; commissioners.

Sec. 875.31. Powers and duties.

Sec. 875.41. Method of operation; rate setting.

Sec. 875.51. Paymenfu :iIi lieu oftaxes.

Sec. 875.61. Annual audit.

Sec. 875;71. Tennination.

Sec. 875.81. Separability.

Sec. 875.01. Legislative findings and decla~ Sec. 875.~1. Defmitions.

ratio~ of purpose.

As ).lsed or referred to* in this chapter, unless a different meaning clea:r1y appearsfrolll the con-It is hereby found and declared: text: .

(1) The County of Westchester has been con- Agency shall mean the County of Westchester cemed for some time with the high cost of Public Utility Service Agency cre~ted by section electric power in the Con Edison Service . 875.21 of this chapter. .

) Area of the. county and .the effect of such Cliqirman shall :mean the Chairman of' the costs on the economic growth and well- .. Cbuntyof Westchester Public Utility Service being ofthe. cOlInty. Agency,

. (2) It is essential for the county to take the Commissioner of Finance shall mean the Com-necessary steps to obtain and maintaip. an missiqner ():f.FiIl~~e:9f:Westchester County.

adequate and reliable supply of less ex- Con Edison shallmean the Consolidated Edison pensive electric pow.er. Company of New York, Inc.

(3) By referenr;lum held on March 30, 1982, Con Edison Service Area of the county* shall the .voters of the county ove:rwhelIDinglY , mean that. territory within Westchester County approved a proposition authorizing the where the Consolidated Edison Company of New county to* establish a Public Utility Ser- York, Inc; now or hereafter is franchised* to fur-vice Agency to construct, lease, purchase, nish electrical utility service, own, acquire, use andlor operate a public County shall me~ the County of Westchester, electric utility service.

County Board shall mean the Board of Legis-(4) The creation of a County Public Utility lators of the County of Westchester as the said Service Agency will enable the county to board now exists or may hereafter be constituted.

contract for or otherwise purchase or ac- County Executive shall mean the Chief Execu-quire lower cost electri,c energy in the tive and Administrative Officer o{ the County of form of hydroelectric power and other Westchester. -

economical forms of electricity from the State of New York or from any state Executive Director shall mean the Executive agency, municipal, public or private cor- Director 'of the County of Westchester Public poration. Utility Service Agency appointed pursuant to (L.L. No. 11-1982, § 1) section 875.31 of this chapter.

page 875:1 OAGI0000197_163

§ 875.11 WESTCtIESTER COUNTY Fiscal year shall mean tb,e- p.erio-d. beg#.ming the three coininissioners appointed upon the ree-with the first d~y:. of J anual'y and- ending with the oinmendation of* the Chairman of the.. CO'!lhty 31st day of Dec;embe).". in each* year. Board from a list of not less than four nor more thim six, one shall serVe a four-year term, One

. PubZi<; electric utility service shall mean any shall serve a three'-year term, and.one shall serVe electric service authorize-dto be furnished by any a two-year term.

public utility company pursuant to Article4 bfthe Public Service Law ~d shall include- works, struc~ (c) Vacancies shalLbe filled .in the same man-tures; poles! lines, wires, conduits, mains, sys- ner as original appoiniJ:n.ents; provided, however, tems, waterpower and any and all other real and that in the event of, a vacitncy in. a position personal property used or necessary for,. con- originally filled upon therecomniendation of the nected with or relating to. *the furnishing of such Chairman of. the CountY* Board, the appointment electric utility service.* shall be made by the County Executive from a*

(L.L. No. 11~1982, § n ~tten list of not less than two nor more than three persons recom:Q1ended by the Chair~an of Sec. 875.21. Agency cre.ated; commission- the County Board. Vacancies occurring by .otqer ers. than expiration* of term. shall be filled for the balance*of the unexpiretiterm; provided, however, (a) Thex:e is* hereby created a County of that. an* appointment for a term shorlelied:by Westchester Fublic Utility Semee Agency.* The reason ofapredecessor's holding over after expi-agency. shall consist of seven commissio.ners to he ration of a term shall be for the balance .of that appointed *by the County Executive with the con- term.

firmation of the* County Board. Three of the (d) The County Exec~tive may suspend with commissioners shall be se-lectedand appointed b~ ..

the approval of the County* Board and may re-the County Executive froll:).a list of not less than

.move any commissioner for ineffl,ciency,. negle~Gt of four nor more than six persons recommended by duty, misconduct in office or any other reasons.

the Ch.a,irman of the County Board. Th~ Chab:-

lll~r.t :~f.t¥ ..a~.e.~(;y .. sl?-.~ll pe Aes~gn.:9-t.e<i l:lY the (e) Neither the Chairman nor any other com-County Executive from amongst the*seven com- missioner shall receive a salary. Eachcommis-missioners. All coIDmissioners. shall be residents sioner, including the 'Chairman, shali be entitled of th~*Con* Edison Service Ar~a of the county at to reimbursement of actual and necessary ex-the time of their appointment and during their: . pensesincurred in* the performance of that

. term of office. 1'0 the. extent practicable, the com, commissioner's official duties. A majority of the missioners selected shall' have experience hi. one whole number' of commissioners of the agency, or more of the following disciplines: public utility which is four; shall constitute a quorum; and the

  • nianagemeni;, finance/accounting, law, engineer- transaction. of any business or the exercise of.any ing, labor, consumeraflhlrs. At least four coinmis~ power of the. agency requires four* affirmative ,.

sioners s.J:!all have expertise or qualifications. in at . votes.* * .

least one of among the; fullowing disciplines:Jaw, (LL. No. 1l~1982, § 1; amended by LL~ No.

engineering,finance/accountingandpublic utility 1$-1~86) management.

Sec. 875.31. Powers and. duties.

(b) Commissi~ners of the. agency shan be ap-pointed for a term of four years except that, of (a) General powers and duties. The agency, .on those first appointed, three commissioners, includ;' behalf of the county, shall.havethe power to ingthe Chairman, shall. he appointed for a term of establish, construct, lease, purchase, own, ac-four* years, two commissioners shall b~ appointed* quire, .useand/or operate. a public electric utility for a teJ;mofthreeyears, and two commissioners service within and/or-without the i;errltoriallim-shall be appointed for a term of two years. The. its of the county for the .purp.ose of furnishing to County Executive shall designate the terms to be . the county or for compensation: to inhabitants of served by the fuitial commissioners, e;)Ccept that of the Gon Edison Service Area of thec.ounty any page 875:2 OAGI0000197 _164

PuBLIC UTILITY SERVICE AGENCY § 875.31 elEictric service similar to that furnished by any mend that the County Board authorize public utility company specified in Article 4 of the the purchase or construction oisuch facil-Public Service Law and to purchase electrical ities or improvements, where the Agency energy from thE) State of New York or from any determines that same wouid be desirable state agency, or other municipal corporation, or and in the interest of the county, provided from any private or public corporation or other that the agency shall not construct and/or sources_ purchase such facilities or improvements without the approval of the COt,illty BOl:JId.

. (b) Specific powers and dutie.s .. :m discharging its powers and duties, the agency: (4) May appoint an Executive Director, who (1) Shall have the atitl:lority to contract for or . shall be a person experienced in electric otherwise purchase' or' ~cquire low-cost utility operations, to be responsible for hydroelectric power or such other econom- the administration and day-to-day opera-ical forms of adequ.ate* and reUable elec-. tioI1$ of the Agency. The Executive Direc-tricity from the State of New York, any tor, who shall not be a member of the agency of the State of New York, any other Agency, shall hold office at the pleasure of mun.lcipal corpo~ation, PI' any pnvate or the agency and shall be paid a salary to be public corporation, or other sources, as £ixed. by the agency. The Agency shall be shall be availabie for the . Can Edison empowered to delegate anyone or more of Service Area of the county. ; its operational and administrative func-tions or powers to the. Executive Director; (2) Shall have the authority to negotiate with provided, however, that the agency shall Con Edison and! or other utility compa- delegate to the Executive Director such nies for the use, by lease andlor by con- functions and powers, including without tract, of such portion of the appropriate limitation, that of appointment, discipline distribution., substation and transmission and removal of employees, as are neces-facilities necessary to transmit to . the sary for the' Executive Director to dis-

. , ,countY:_Qr_for compens;ltiontp mhabjtants charge his responsibilities .

of the coun,ty in the Con Edison Service Area of the county such quantities of (5) Consistent'with applicable law, shall have power as may be acquired by the Agency; the al;lthority to make and alter bylaws andlor to sell such power to Can Edison for its organization and internal manage-for resale to its customers inhabiting the ment and to make rules and regulations Can Edison Service Area of the county. governing the use of its property and Contracts andlor leases entered. into by facilities, which bylaws, rules and regula-the agE)ncy with electric utilities for dis- tions shall be filed with the Clerk of the tribution of power purchased by the agency . County Board.

shall include a provision that the net savings associated with such energy or on (6) Shall have the authority to enter into taxes shall be passed along to customers contracts, leases and other instruments in the Con Edison Service Area of the and to acquire, hold and dispose ofreal or county and shown separately on their personal property necessary and conve-bills as a credit. nient to the exercise of its powers_

(3) Shall have the authority to determine (7) Shall have ~he authority to appoint, fix what, if any, additional facilities and inci- the compensation of and, consistent with dental improvements would have to be section 297.31 of the Laws of Westchester constructed and/or purchased in connec- County, provide for the indemnification of tion with the use, by lease audior con- such qfficers and employees as it may tract, of the foregoing facilities, to project require for the performance of its duties the estimated cost thereof, and to recom- and to retain or employ consultants or page 875:3 OAGI0000197 _165

§ 875.31 WESTCHESTER COUNTY . .. /I~--"

acivisors on a contract basis or otherwise dun~s established by the agency..Monies of the for rehdering professiQI1al {)l' technical ser- ag¢ncy.shall be paid out on checkEl signed by the vices and adviee. Chairman of the agency or such other officer or (8) Shall have the authority to arrange for employee as the ag~ncy shali so authorize. The temporary financing prior to the receipt of agericy inl:1.Y in. its di~ctetion elect to utilize the

. revenUes 'sufficiel+tto meet cllttent costs fiscal services of the. Commissioner .of Finance, or. expeli$es by obtaining such at;lvances ahd it). such event the Commissioner of Finance frOlll the Commissioner of Finance as may shall provide such fiSC;ll servic~s as are requested be authorized by the County Board. Loans by the. ageQ.cy; Monies of the agency t;leposited obtained in this manner shall be repaid as .. with the Commissioner Qf Finance shall he sub-soon as the agency-sball possess a suffi- ject to requisition by the Chairman of the agency cient excess of cash over current obliga- . or of such other officer or employee as the agency tions to permit suC;h repayment. shall authorize to make such requisition. All monies of the agency deposited with the Commis-(9) Shall have the authority to initiate and . sioner of Fin,ance shall be maintained in a sepa-prosecute all mquiries, llvestigations, sur- rate bank account or accounts and,' except for veys;' and . studies which it may deem investment purposes; shall not** be commingled necessary or desirable for the effectuation with any other monies. All deposits of monies of the powers and duties conferred upon it with th~ Commissioner of Finance shall, if re~

by this chapter. quired by the Commissioner of Finance or the (10) . Shall have the authority to exercise such agency, be secured by obligations of either the other powers granted under law that are United States or the State of New York or its necessary or convenient to carry out and municipalities or' a market value equal. at all

.effectuate the purposes and provisions of times to the amount of the deposits .

this chapter.

. (f) The agency, within 90 days after the end of (11) Shall have the authority to study and its fiscal year"shall annually submit to the County

.rec(m-1m~:p;(;:Lj:.o .the.. Cpp.nty. Board .the de~ - *Executive and the County Board a complete and velopment of alternative energy sources detailed. repm:Lsemng. forth, .In. ..addition to the for local needs or conservation purposes. financial statements required by section 875.61 of (c) Nothing herein should be construed as au- this chapter, the operations and accomplishments thorization for the county or th~.agency OIl behalf of the agency during such year and *its legislative of the county to exercise any power 'of condemna~ recommendations in furtherance of the purposes tion orto establish generation, distriQution, andlor of the agency, .

transmission* facilities . separate from the Can (L.L. No. 11-1982, § 1)

Edisongeneration,distribution., and/or transmis-sion system iIi. the Con Edison Service .Area qf the Sec. 875.41. Method,. ofopel"ationj rate .set-cQunty.. . tinge .

(d)" Those provisions oithe Laws of Westchester County pertaining to the award and execution of The method of operation of the rates, rentals contracts' and leases shall apply to the agency;' . and charges for public electric utility service and '

provided, however, that the' agency, at a public the procedure for their collection shall be fixed by meeting, is: hereby empowered to adopt its own the County Board in accordance with law. The rules and regulations, consistent with law, regard- agency shall recommend to t1).e County :Board the ing*theaward and execution of agency contracts establishment of a system of cop.sum,er electric and leases. rates, the inten,t of which shall be to enable the public electric utility service to be self-liquidat-(e) All monies of the agency shall he managed. ing, and shall impose and collect the rates estab-MQ. used by the agency :fpr the purposes of the lished in a manner consistent with law.

agency in accordance with sound financial proce- (L.L. No. 11-1982, § 1) page 875:4 OAGI0000197 _166

PUBLIC UTILITY SERVICE AGENCY § 875.81 Sec. 875.51. Payments in lieu of taxes. Sec. 875.81. Separability.

With respect to any property the agency may If any section, subdivision, paragraph, sen-acquire within the county from any private utility tence, clause or provision of this chapter shall be company, inducting Can Edison, the agency shall unconstitutional or be ineffective in whole or in make payments in lieu of taxes to the appropriate part, to the extent that it is not unconstitutional municipalities or districts in an !llnount equal to or ineffective, it shall be valid and effective, and the amount that would have been paid in real no other section, subdivision, paragraph, sen-estate or franchise taxes had such privat~ utility tence, clause or provision shall on account thereof continued to own such property. be deemed invalid or ineffective. .

(L.L. No. 11-1982, § 1) . (L.L. No. 11-1982; § 1)

Sec. 875.61. Annual audit.

The agency shall maintain books of record and account. with respect to its operations in accor-dance with generally accepted accounting princi- ...

pIes consistently applied. Within 90 days after the ..

end of the. agency's fiscal year, the agency sh~

deliver to the County Executive and the County Board its financial statements at the end of such*

year and for the year then ended, prepared in accordance with generally accepted accounting principles and accomJ)anied by the report thereon, by a. firm of independent ac.countants of recog-

.nized national standing selected after consulting with the Commissioner of Finance and the County Budget Director by the*. agency, .based upon an audit using. generally .accepted auditing stan~ .

dards.

CL.L. No. 11-1982, § 1)

Sec. 875.71. Termination.

The agency's eristenceshall continue until terminated by law; provided, however, that no such law shall take effect so long as the agency shall have obligations outstanding. The terms of the commissioners of the agency shall expire upon the enactment of a law terminating the :;tgency's existence, and the County Board shall constitute the agency rlntil the effective date of the agency's expiration. Upon termination of the existence of the agency, all its rights and properties shall pass to and be vested in the couni-y. No law terminat-ing the existence of the agency shall be enacted except upon an affinnative two-thirds vote of all the members of the County Board.

I. (L.L. No. 11-1982, § 1; amended by L.L. No.

.r 13-1986) page 875:5 OAGI0000197 _167 OAGI0000197_168

VILLAGE OF BUCHANAN ZONING BOARD OF APPEALS Westchester County, New York DECISION & ORDER Petitioner(s): Entergy Nuclear Northeast File No.: 3-02*BZ Address: 295 Broadway, Buchanan, NY Public Hearing Date(s); 5/8,6/12,7/10/02 Property Location: 295 Broadway, Buchanan, NY 10511 Tax Map Designation: Section: Block: Lot:

Present Zoning District: M*2 Nature of Petition:

[ 1Use Variance [X 1 Area Variance

[ 1Special Permit [1 Interpretation 1 Other Describe Specific Request:

Area Variance with respect to maximum building height dimensions to allow for the proposed Generation Support Building on the above property.

The above referred to Petition, having been duly advertised in The .Journal News the official newspaper of the Village of Buchanan, and the matter having duly come to be heard before a duly convened meeting oflhe Board on the above dates, at the Municipal Building, 236 Tate Avenue, Buchanan, New York, and all of the facts, matters and evidence produced by the Petitioner(s), by Village officials and by interested parties baving been duly beard, received and cdnsidered, and due deliberation having been had thereon, the following Decision and Order is hereby made by this Board:

The Zoning Board of Appeals has taken into consideration the benefit to the applicant if the variance is granted as weighed against tbe detriment to the health, safety and welfare of the neighborhood or community by such grant. In making s'uch determination, the Board makes the following findings:

1. There is no undesirable change in the character of the neighborhood or a detriment to nearby properties' created by the granting of the area variance;
2. The benefit sought by the applicant cannot be achieved by some method, feasible for the applicant to pursue, other than an area variance;
3. The requested area variance is not substantial;
4. The proposed variance will have no adverse effect or impact on the physical or environmental conditions in the neighborhood or district; and
5. The alleged difficulty is not self-created.

Applicant is GRANTED the following Area Variance:

1. A Variance in the maXimum building height from 35 feet to 59 feet to allow for the proposed Generation Support Building on the above property, plus an ildditional 10' high roof scraen is permitted to conceal roof mechanicals from ground view.

NOW, THEREFORE, the Petition herein is granted and it is further ordered that in all other respects Petitioner(s) comply with all of ttie rules, regulations and ordinances of the Village of Buchanan, the Building Dep~artmeI, the Village Engineer, and all other agencies having jurisdiction thereof. . ~

Date Filed: July 10, 2002 _ J£ H. ~ ____

NICOLAS HAR Chairman, oning oard of Appeals OAGI0000197_169 OAGI0000197_170

)ublication date: 04-Jun-2003Credit

~eprinted from RatingsDirect Time for a New Start for U"S. Nuclear Energy?

.l1alyst: Peter Rigby, New York (1) 212-438-2085 Since its beginnings, commercia! nuclear energy has offered the tantalizing pmmise of clean, reliable, secure, safe, and cheap energy for a modem wOl"id dependent upon electricity. No one did more than lewis Strauss, chairman of the U.S. Atomic Energy Commission, to define expedations for the industry when he declared in 1954 that nuclear energy would one day be "too cheap to meter." But the record proved far different. Nuciear energy became the most expensive form of generating electricity and the most controversial following accidents at Three Mile

~sland and ChemobyL And today's electricity industry's credit problems of too much debt and too many power plants will do little to invite new interest in an advanced design nuclear power plant Yet energy bnls circulating through the U.S. Senate and House of Representatives hope to change that perception and perhaps lower the credit risk sufficient enough to attract new capital. Wi!! Washington, D.C.'s new energy initiatives lower the barriers to new nuclear construction? Many would like to think so, but it wm be an uphm battle.

The House vemion oUhe Energy BiU modestly Of . . . sets the stage 101" building new nuclear reactors by reauthorizing Price-Anderson .... " Since 1957, the Price-Anderson Act has indemnified the private sector's liability if a major nucle31r accident happens on the premise that no private insur31nce c31rriers could provide such coverage 011 commercial terms. Without Price-Anderson, it is difficult to envision how nucle31r pl31nts could operate commerci31l1y, now or in the future. The more ambitious Senate version of the Energy lBili seeks to jump-start new nudear plants in tile U.S. by providing measurable financi311 resources for new projects. According to the latest version of the Senate Energy IBm, the Secretary of Energy could provide fin31ncia! assist31nce to supplement private sector financing if the proposed new nuclear plant contributes to energy security, fuel, or technology diversity or cle31n air 31Uainment goals. The bill would limit financial 31ssistance to 50% of the projed costs with financial assistance being defined 31S 31 line of credit, secured 1031n, loan guarantee, purchase agreement, or some combin31tion of these 31ssistance pl31ns.

OAGI0000197 _171

Time for a New Start for U.S. Nuclear Energy?

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in ligh~ o~ how well U.S. nuclear plaln~s have generally been opera~ing recently and with promising new ~echno~ogy on the horizon, nuclear energy would seem to have a future. CurrenUy, abou~ 20% of the na~ion's eiectricity comes from nuclear power plants (see chart be~ow),

The intmdudion of compe@on and deregu!ation in the U.S. has helped drive the nudear fleet into achieving record availabilities and load factors, as independent owners have taken ownership from utilities that divested generation. Even utiiities that did not divest their nuclear plants have experienced greatly impmved performance across the board.

loday's nuc!earpowerplant operation and maintenance and fuel costs are remarkably low compared with many fossil fuel plants--as low as 1.68 cents per kWh according to the Nuclear Energy Institute. Although

~he high-pm~ile accidents at Three Mile Island and Chernobyl greatly raised the threshold for safer operations, operating success stories may ovei'State what may be achievable with new designs. Nuclear operators in the U.S. have had a few decades to work out operational problems, and with original debt paid off, mme cash resources have been dedicated to impmving performance. Providers of new capital for advanced, nudear energy will want some comfort that credit and operating risks are covered. But the industry's legacy of cost growth, technology problems, cumbersome political and regulatory oversight, and the newer risks brought about by competition and terrorism concerns may keep credit risk too high for even the Senate bill to overcome.

Hi$i@ric [FU~k~ wm P@r~6~t A nuclear power p~anrs life cycle exposes capital 'OrDviders to four distinct periods of credit risk that history has shown will persist These periods are pre-construction, construction, operations, and decommissioning (see chart below). The risks tend to be asymmetrical with an enormous downside bias against credit providers and HWe or no upside benems. 1'0 aUract new capital, future developers will have to demonstrate that the risks no longer exist or that the provisions of the

!Energy Bm can effectively mitigate the risks.

(2 of 10)

OAGI0000197 _172

Time for a New Start for U.S. Nuclear Energy?

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During a nudear plan~'s pre-colilstrudion phase, lenders, as they do with other projects, face the risks of cost growth and delay. When nuclear engineers encountered technology problems during the planning stages in the ~960s and ~970s, solutions ineVitably resulted in scope changes or re-designs, or both. A 1979 Rand Corp. study for ~he U.S. Dept of Energy stii~ serves as a warning to hwestors in new, untested nuclear teclmo!ogy. The study found ~hat cos~ budget estimates grew on average 114% over first estimates and that final actual costs exceeded those estimates by 141 %. Half of the plants in the study never reached commercial operations. An extreme example of de~ays and cost overrUIllS, which remains fresh in investors' minds, is Long island Lighting Co.'s Shoreham nuclear power station. Begun in ~965 at an initial cost estimate of $65 mimon-$75 million, Shoreham endured 20 years of construction delays and design changes due to lega! baWes, iocal opposition, regulatory and political intervei1tion, and technical problems that pushed the final cost to almost $6 biliion. ~n the end, a compiete and fully licensed power plant never went operaHonal, and ratepayers, investors, and taxpayers are still footing the bill. Another example is TXU Corp.'s 2,300 MW Comanche Peak Units 1 and 2, which took longer than any nuclear plant to build and saw costs mushroom to nearly $ t2 billion by the time full operations began in 1993.

That 1'10 new nuclear plant construction has begun in the U.S. for over 20 years suggests that a new one would be susceptible to cost growth risk, as engineers incorporate advances in control and power systems, fuel systems, safety and regulatory requirements (which could become more onerous during the years of deSign and construction), material sciences, and information technology. Even prromising new designs, such as the OAGI0000197_173

Time for a New Start for U.S. Nuclear Energy?

pebb~e bed reactor (P!BR) design that ESKom Holdillgs Ud. of South Africa plans to build soon, would like!y risk desigll1 chall1ges all1d attendant cost growth if built ill1 the U.S. Cost growth alld delay call also arise from desigll and scope changes due to the efforts of effective inteI'Veners, such as the antl-ill.Jciear citizen activist groups that successfully de~ayed Shoreham alld u!timately prevented it from going commercial.

History also suggests that the cOllstruction and start-up phases of new Iluclear power will lik.ely encounter problems that will result in illcreased costs and delays. Licensing delays, cOllstruction mallagement problems, procurement holdups, troubles with new technologies and construction defects, among other problems extended construction beyond i 0 years for some U.S. nuclear power plallts. U would be overly heroic to assume that the first nuclear plant to be built ill more than two decades would escape the industry's legacy of construction problems. For 81 debt-fillallced COllstruction elldeavor, likely to cost hundreds of millions of doilars (possibly into the billioll dollar plus range), these problems, or even the possibmty of such problems, wi!! likely drive risk-averse lenders to demand 81 significallt risk premium unless 81 third party assumes completion and delay risks. In the world of cost-of-sel'Vice, rate-of-retum ellvironments, utilities couid, and did, pass these costs on to ratepayers to 81 certain extent The bankruptcies of EI Paso Electric Co. and Public Service Company of New Hampshire in ~he i 980s, however, aUest to the limits of ratepayers' capaci~y ~o absorb construction risk.

Today, no utility or illdependellt power producer or their capital providers wiH want ~o take ufflImiiigated construction risk, particularly if it is difficun to quantify. ~n additioll, given the possibility that much of the construction risk of 81 new fflIuciear piallt may lay outside of the engineering, procurement, alld constructioffll contractor's cOffllkol, 110 contractor will want to risk its balance sheet to provide the fixed-price, date-certain, turnkey construction cOfflliracts that have given great certainty to ~he cos~

of today's new fossil-fueled power pian~s. Because of the 10llg iead-time historically associated wi~h nuclear power, securing i 00% financing upfront, as the indus~ry has become accustomed to, may be difficu~t That couid introduce financing risks if projects encounter problems during construction; delays ill securing final fillancing WOUld, among other prob~ems! drive up capitalized interest costs duriffllg cOllstruction and ultimate!y the projects cost While U.S. Iluclear power plants have operated wiUllout major mishap 110r over 20 years, unexpected costs during ~he operational phase of a nuclear plant can be subs~antiaL And it is unclear whether and if proposed government programs wm be able, or wiWng, to offset the risk of ~hese costs. Still, today's opera~ors have demollstrated that they call safely operate oider nuclear power plallts. Yet the potential that incidents, such as last year's wholly ullanticipated corrosion problem at FirstEnergy Corp.'s Davis !Besse 900 MW plant, are not unique, one-time affairs will keep credit risk high for m.!clear plallt owners. In addition, investors wW remember that the Davis Besse repair costs of abou~ $400 million, not illcluding replacemen~ power, are unrecoverable from.

ratepayers, leaving il"westors to shoulder the costs. ~ncidentaily, had ~he outage occurred during 81 period of high power prices and tight supply, (4 of 10)

OAGI0000197 _174

Time for a New Start for U.S. Nuclear Energy?

as was the case two years ago, the cost to investol'S would have been much higher.

Decommissioning costs, which entaii the considerable expense of tearing down a plant and sa1fe~y disposing or storing the radioactive waste, remain uncertain at best given how few U.S. nuclear plants have undergone decommissioning. Progress toward creating a permanent disposai site for nuclear waste at the government's Yucca Mountain site in Nevada wili help miUgate decommissioning risk, as wei! as spent fue~

disposai costs. Again, it is not clear who wm bear decommissioning cosh., but if lenders foresee any lender liabmty risk, they wm steer dear of new nuclear investments or require steep compensation. 1'hat, as a point aside, may be one of the reasons so many plants have been granted Hcense extensions. Refurbishing a depreciated nuclear power piant costs far less than decommissioning one.

Finally, for many of the reasons described above and an else being equal, Standard .& Poor's Ratings Services has found that an electric utiiity with a nuclear exposure has weaker credit than one Without and can expect to pay more on the margin for credit. Federal support of constn.Hdion costs will do little to change that reality. Therefore, were a utility to embark on a new or expanded nuclear endeavor, Standard &.

Poor's would likely revisit its rating on the utility.

CQ)M[pJtiti@1ri ~lritr@d\UJ~$ ~@W ~!~~~ 1!@fi' ~a.g~~@~fl' leUll@[J~31 As electricity deregulation and industry reform have progressed, capital providers to the nuciear power sedor face some of the same risks as capi~al providers to o~her power generation technoiogies. Again, if policymakers want to aUrad capital to the industry, lenders in particular wililike!y have to be convinced that at least some of the risks are covered or mitigated. The sheer size of most new nuclear investments suggests that downside risk for ienders could be considerable indeed 0 Clearly, buying and selling eledricity in a competitive environment comes with its risks, both market and political. The wake of Califomia's eledricity reform problems forced one utility into bamkruptcy and brought another to the brink of bankruptcy. independent power producers are resisting efforts by California and its Department of Water Resources to abrogate or renegotiate recently executed power sales agreements.

These events, combined with the credit crunch that has hit many other lltiliUes and energy merchants, have understandably moved public uWity commissioners and capital providers into more risk-averse postures.

Absent these problems, nuclear power would sW! be challenged to attract new capital; in this environment, however, the task is aU the more difficult. Competition has dramatically shifted risks from ratepayers to lenders atnd other ilJwestors; that is not likely to change.

In a competitive wholesale power environment, nuclear plants would likely sell power as a base load generator behind hydroelectric atnd ahead of coal and gas. Capital costs would be higher than coal plants and much higher than natural gas plants, but marginal operating costs would be very low, as they are now. Nonetheless, an owner of a new nuclear plant would like!y want a iong-term--20 years or more--power (50nO)

OAGI0000197_175

Time for a New Start for U.S. Nuclear Energy?

cOill~rac~ with a credi~worthy u~ility to eillsure tha~ fixed ailld variable cos~§ are covered iill order to aUrad the massive amount of capital needed for construction. AI~ematively, a utility that wants ~o add a new nuclear plaillt to its portfolio would need regu!atory assurances from its public utility commission tha~ the en~ire cost of the plant would be recoverable from its rate base. In the firs~ iillstance, few utilities, or their regulators, want such long-term contract obligations, especiaUy in an environment of excess genemtion that can be purchased on the cheap. That gas costs and clean-air compliance costs could be on the rise migh~ offset some of those concems. For some of the same reasons, public utility commissioners may not be so forthcoming with their authority to grant rate-based trea~ment of a new nudear plant, especiaHy in ~he pre-construction period if cost groW1lh risk remains uncovered. For many commissioners, ithe ail-in costs of altemative genera~ion wi!! likely seem more predictable and cheaper than a new nuclear plant The curren~ backlash against regulatory reform and open markets in parts of the country could also put a new nudear plant at risk. A large, new nudear plan~ will typically need access to a large electrical network with a geographically dispersed cl.llStomer group--the network that a wen-structured regional tmnsmission organization, as envisioned by FERC, could provide. However, if transmission access is limited or if states have chosen to main~ain barriers to eledrici~y ~rading and marketing, physical or o~herwise, as many have, a new nuclear power plan~ may find itself operating wi~hin a much smaller system, a si~uation that could raise its credit risk, all else being equaL One obvious mitigant to this risk would be to build much smaller nuclear plants, such as the 100-MW modular PIBR designs.

Whether a new nuclear plant is financed directly from the waliets of captive ratepayers or with long-term contrads, a large nuclear plant's size relative to its market raises outage-cost risk. A nuclear plant with a long-term power contl'8lct will likely contain provisions to provide replacement power, or the financial equivalent, if the plant becomes temporarily unavaiiable. Given nuclear power's vulnerability to rare, but extended forced outages, replacement power costs for 1,000-2,000 MW of base load power could be considerable, which would factor into credit risk. Similarly, a utmw that owns a large nuclear station could find itself spending hundreds of millions of dollars to cover its short position whHe its station was down without assurances of recovery from ratepayers.

Again, smaller PIBRs would mitigate this risk.

Some of the preliminary proVisions of the Sena~e Energy IBm contemplate some of these risks. A long-term power contrad, for example, with the federal govemment that covers 50% of the planfs costs might mitigate some of concems of operating in a competitive environment Similarly, loan guarantees or lines of credit could also offset the cos~s. However, if gas- and coa!-fired plants can be built for much less (e.g., 50% less) and the operational risk of extended nuclear plant outages remains uncovered, a government program could fall short of relieving investors' credit concerns. Moreover,as with allY govemmentsubsidy program, lenders would invariably fador U.S.

government counterparty risk in the form of subsidy re-authorization (6 of 10)

OAGI0000197 _176

Time for a New Start for U.S. Nuc\ear Energy?

I.mcertail"lty. Would the programs el"lvisiol"led by the Sel"late bill last through the capital recovery period? Maybe. Maybe not A new risk for I"lucleal' el"lergy that has caught everyol"le's aUentiol"l is terrorism. Because of the dal"lgers that nuclear energy bril"lgs, security and il"lS!..!l'"al"lce costs for I"ludear facilities--I"lew al"ld old--are much higher thal"l for fossil or rel"lewable power plal"lts. Therefore, il"l a compemive power el"lvirol"lment, stakeholders il"l power gel"leratiol"l may be rehJdal"lt to assume I"lew risks that cost more to mitigate. Again, if a govemmel"lt subsidy can put security costs for I"lew I"luclear p!al"lts Ol"l al"l even playil"lg fieid with convel"ltiol"lal power gel"leration, the il"ldustry could aUract new capitaL However, most new programs el"lvisiol"led by Washington only address the construction risk.

As a I"lote aside, some power generators and uWities may oppose enorts to support new U.S. nuclear generation capacity beyond existing subsidies, sllch as Price-Andersel"l, if they are heavily il"lvested in coa~

and gas. New I"luclear el"lergy's low variable operatil"lg costs would likely displace existil"lg coal-fired and gas-fired gel"leratiol"l units in today's el"lvironmel"lt It will do little, however, to displace oil-fired gel"leratiol"l or lower U.S. oj! imports because so little electricity, about 2% ofthe U.S.

load, is actually gel"lerated by oil and much of that is for peak ioad, which I"luciear energy would I"lot serve anyway. !But for stakeholders--investors, state politiciam; al"ld regulators, lenders, customers--the risk that new nuclear gel"leratiol"l could stral"ld investment il"l conventiol"lai fos§i!-~uel fired generation may be unacceptable unless the govemment provides final"lcial compel"lsation. Al"ld for a govemmel"lt tryil"lg to contain fedieral spel"lding, those costs could be prohibitively expel"lsive.

(7 of 10)

OAGI0000197_177

Time for a New Start for U.S. Nuclear Energy?

An En~rgy sm Could Mmtrng)©lt@ th~ Risk~

To a\ttmct rlew capi~al to build the next generation of nuclear power plants in the U.S., developers will rleed to cOrlvince capital providers U'lat the foilowing risks are not materially greater than for fossil fuel power plants:

@ The expense of cost growth, scope change, techrloiogy risk arlO start-up delay.

@ The costs of urlforeseen design problems ~hat manifest themseives wel~ after commercial ,)perations begin.

@ The costs resulting from the activities of effective interveners.

@ The costs resultirlg from regula~ory changes, including growth in oversight arld compliance costs.

@ The costs arising from forced outages in a competitive whoiesa~e erlvironment.

@ The costs of replacirlg credit counterparties who are unwilling or unable to honor obligations or commitments upon which a nuclear plant's firlancing decisions were made.

@ The added and uncertain expense of providing insurance and terrorism protection that nuclear plants need and that would disadvantage a nuclear piarlt operating in a competitive (8 of 10)

OAGI0000197_178

Time for a New Start for U.S. Nuclear Energy?

wnoiesa!e market The versions of the Energy Bill circulating around Capitol Hill may indeed mitigate enough of the risks that woukl otherwise dissuade ilwestors from finamcing new nuclear capacity. The key drivers will be not so much in the broad generalities of the authorizing legislation, but in the details of the enabUng regulations promulgated by the Department of Energy. That could take some time to draft. However, the Senate mark-up of the bill appears to recognize the issues. Absent an affordable alternative, if Price-Anderson is not re-authorized, existing nuclear power plants could be forced to close because of the potential liability olf an accident that could run into the bimons of dollars. Beyond Price-Anderson, however, considerable government Ifinancial support will likely be needed to aUract capital, given tne perceived credit risks.

The proposed Energy Act's subtitle section, the "Nuclear Energy Finance Act of 2003," provides support 101' "advanced reador designs" that covers reactors that enhance salfety, efficiency, prolilferation resistance, or waste reduction compared with existing commercial nuclear reactors in the U.S. In addition, financial support would consider "eligible costs" tha~ would cover cos~s incurred by a project developer to develop and construct a nuclear piant, including costs arising from regulatory and licensing delays. Financiai assisial1lce may take the Iform of a loan guarantee olf principal al1ld interest, a power purchase agreement, or some combination olf both.

The governmel1lfs proposed support of new l1Iuciear construdion will come wi~h limits. The objective is to cover the risks of new nuclear gel1leratiolrl technology and construdion until capital providers gain confidence that a new generation of nuclear power plants is commerciaUy sustainable. The ad would limit support to 50% of eiigib!e project costs and to the firs~ 8,400 MW of l1Iew Irluciear generation. The 50% limit would certainly control the governmenfs exposure, as well as mitigate the risks of moral hazard that a complete guarantee would invite. However, as the ilrldustry has learned, some of the costs that could undermine new nuclear power are not those of construdion and design, but are the operational ones that could arise after govemmel1lt assistance has elrlded. !n addition, given the risk of cost growth and the likely high capital costs. of a new nuclear plant, a 50% level of financia!

assistance may not be enough to entice a developer comparing uncertain estimates of$1 ,500-$2,000 per kW capital cost olf a new generation nuclear plant with more certain $500 per kW combined-cycle gas turbine or $1,000 per kW coal plant capital costs.

Whether or not the nuclear energy provisions or the Senate's versiol1l of the El1Iergy Bill are good economic 01' energy policy is beyond the scope or intent o~ this article. New nuclear energy has compelling aUributes, such as supporting energy diversity, replacing an aging U.S. nuclear f!eet, offseUing rising natural gas prices, and reducing greenhouse gases and NOx, SOx, and particu~ate airborne pollutants. Once the capital costs are sunk, the variable operating costs can indeed be quite low. However, nuclear power tends to raise credit risk: cOlrlcems during construction and well after construction. Investors, particularly lenders (9 of 10)

OAGI0000197_179

Time for a New Start for U.S. Nuclear Energy?

who rarely see any upside po~ential in cuUing-edge technology investmer!~s, including energy, will likely find the potentia~ downside credit risk of an advanced, nuclear power plant too much to bear un!ess a third party can cover some of the risks. An Energy IBHi that covers advanced design nuclear plant construction risk may go a long way toward allaying those concerns, but if operationa~ and decommissioning risks remain uncovered, look for lenders ~o si~ this opportuni~y out Add t@ My 1R@~©HF~I1Click ~he Add buUon below to save this article in your My Research folder.

This report was reproduced from Standard & Poor's RatingsDirect, the premier source of real-time, Web-based credit ratings and research from an organization that has been a leader in objective credit analysis for more than 140 years. To preview this dynamic on-line product, visit our RatingsDirect Web site at www.standardandpoors.com/ratingsdirect. Standard & Poor's.

Setting The Standard.

S~&~~ iZ A~~~~

Published by Standard & Poor's, a Division of The McGraw-Hili Companies, Inc.

Executive offices: 1221 Avenue of the Americas, New York, NY 10020. Editorial offices: 55 Water Street, New York, NY 10041. Subscriber services: (1) 212-438-7280.

Copyright 2002 by The McGraw-Hill Companies, Inc. Reproduction in whole or in part prohibited except by permission. All rights reserved. Information has been obtained by Standard & Poor's from sources believed to be reliable. However, because of the possibility of human or mechanical error by our sources, Standard & Poor's or others, Standard & Poor's does not guarantee the accuracy, adequacy, or completeness of any information and is not responsible for any errors or omissions or the result obtained from the use of such.information. Ratings are statements of opinion, not statements of fact or recommendations to buy, hold, or sell any securities.

(10 of 10)

OAGI0000197_180 OAGI0000197_181

[09-Sep-2004] Evaluating Risks Associated With Unregulated Nuclear Power Generation Page 1 of2 STANDARD RAT:I N G S D f R. E GT

(~.POOl~S Return to Regular Format Research:

Evaluating Risks Associated With Unregulated Nuclear Power Generation Publication date: 09-Sep-2004 Credit Analyst: John Kennedy, New York (1) 212-438-7670 Competitive nuclear generation presents an added risk factor to a firm's business profile, given the inability to recover unexpected cost~ through a regulatory process. To date, those operating non regulated generation have had success by mitigating risk through enhanced operating performance (higher capacity factors, shorter outage interjlals), expertise in managing nuclear assets, and the ability to sufficiently fund decommissioning costs. Stil\, some element of event risk will always remain with this business strategy, which could ultimately impinge on credit quality.

In the late 1990s, several firms decided that nonregulated nuclear generation was their growth platform (see table). To date, those with nonregulated nuclear generation exposure have performed well, despite greater business risk related to fuel procurement and storage, asset concentration, and the potential need of replacement power. In Standard & Poor's view, these nonregulated nuclear operations have higher risk than those plants that reside in a regulated utility business. Mostly, nonregulated plants lack the safety net afforded to those plants that are part of a regulated utility. The absence of this protection presents uncertainty regarding the ability to recover certain costs. Also, decommissioning risk is greater because underfunding cannot be recovered through a regulatory process.

Top Nonregulated Nuclear Plant Owners Company MW Exelon Corp. 16,959 Dominion Resources Inc. 5,468 Entergy Corp.' 4,670 Constellation Energy Group Inc. 3,825 FirstEnergy Corp. 3,796

'Includes operating contract for the Cooper Plant.

Some examples of the risks that these nonregulated nuclear operators may face include:

  • Environmental and safety compliance risk;
  • Risks associated with the storage of spent nuclear fuel;
  • Decommissioning risk; and
  • Operational performance.

~ Environmental and Safety Compliance Risk Given the safety, health, and environmental concerns surrounding nuclear generation, compliance standards play an important role in credit quality for firms owning merchant nuclear generation for a number of reasons.

First and foremost, noncompliance can cause plants to shut down until certain standards are met. This prevents them from generating power and collecting revenue. Because these plants are nonregulated (not in rate base) an owner has no recourse for reimbursement of any lost revenue. Also, regulators such as the Nuclear Regulatory Commission (NRC) can influence outages and capital expenditures related to other oversight issues. Again, without the ability to recoup these costs through a regulatorY http://www.ratingsdirect.com!Apps/RD/controllerlArticle ?id=3 94717 &type=&outputType... 9/13/2004 OAGI0000197 _182

[09-Sep-2004] Evaluating Risks Associated With Unregulated Nuclear Power Generation Page 2 of2 process, this could create an additional burden on merchant nuclear plants. Furthermore, repeated compliance problems, coupled with political pressures, could permanently close a plant or disallow a license renewal, leaving an owner with an unrecoverable stranded investment.

~ Spent-Fuel Storage The question of where to store spent nuclear fuel is a key environmental issue. The Department of Energy is more than 10 years behind schedule in building a centralized repository. This creates a burden on nuclear plant owners as on-site storage capacity begins to dissipate.

Here again, the owners of nonregulated nuclear generation are responsible for paying for the process.

For the most part, rates that a generator would charge incorporate storage costs. However, these owners could incur unexpected capital outlays and have no recourse for recovery. Some of these I "J concerns are being mitigated by recent government actions. A recent settlement with Exelon Corp. will give the company $80 million for incurred storage costs, and it is likely that other firms will receive similar compensation.

~ Decommissioning Risk A higher level of risk for nonrate-based nuclear plants arises in part from the uncertainty regarding a firm's ability to fund the requisite decommissioning costs. Given that decommissioning is a legal obligation for a nuclear plant operator, any funding shortfall would create a financial obligation on that firm's behalf. Unlike many of their peers who own nuclear plants in rate base, owners of nuclear power plants not in rate base neither collect decommissioning costs in rates, nor do they have recourse to the local regulator for relief. Therefore, the funding responsibility falls squarely on the owners of nonrate-based nuclear plants. Standard & Poor's views this obligation to be debt-like, similar to underfunded pension benefit obligations, and may incorporate any shortfall into computing credit metrics.

. .; Operational Performance Risk

. Given the competitive nature of nonregulated plants, Standard & Poor's considers operating efficiency as an important factor in credit quality. Generally, the incentive to purchase nonregulated nuclear power plants is the ability to produce power at costs lower than coal- or gas-fired counterparts. Also, many sale prices incorporate a purchaser's ability to increase operating margins through efficiency and cost savings. To generate the expected return on investment commensurate with the associated risk, new owners need expertise in budgeting and cost containment, operating know-how, and experienced personnel.

Unplanned or prolonged maintenance outages that reduce capacity factors and unexpected repair costs can be hurdles to achieving an appropriate operating margin. Again, the lack of a regulatory safety net deprives new owners of the ability to recover all or some of these unexpected capital expenditures. Furthermore, unplanned outages could create an obligation to provide replacement power, which could be at a higher (and unrecoverable) cost.

!!!@ Summary

. Standard & Poor's will closely monitor the issues surrounding a firm's ability to manage these issues, and continue to assess the need for adjusting financials in light of any obligations arising for these types

r'Ifof concerns.

Copyright © 1994-2004 Standard & Poor's, a division of The McGraw-Hili Companies.

  • All Rights Reserved. Privacy P o l i c y '

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http://www.ratingsdirect.com/Apps/RD/controller/Article?id=3"94 717 &type=&outputType... 9113/2004 OAGI0000197_183 OAGI0000197_184

OAGI0000197_185 lectricity generation deregulation has opened u.s. whole- FIG. 1 MONTHLY TEXAS ELECTRICITY AND NATURAL GAS PRICES, 1990-2003 E sale electricity markets to unregulated power producers.

In this uncertain environment, how should a generating company evaluate the risk of investing in new capacity?!

Building upon the calculations in the sidebar (seep. 51) we can calculate the price trigger for new nuclear power capacity

=lE

~

10 9

8 7

6 Natural Gas 1l by considering the option of building an advanced boiling § 5 water reactor (ABWR) in Texas coming into commercial oper-ation in 2010.2 This article: (1) provides a technique for esti-i:

mating the mean and variance of net revenues from the power 1 ..............- ... ---.... ---........--.. - ......- ...........----.-...................--.....-

plant; (2) calculates the variance of net revenues; (3) deter- o .--........- ...-----.--..- ...... ---,...------.. -......._ ....---._-.....-- .-.-.-.....

1990 1992 1994 1996 1998 2000 2002 2004 mines a price trigger, or K*, that might trigger new orders for the current generation of nuclear power plants; and (4) dis-FIG. 2 A SIMULATION OF ANNUAL COMPETITIVE MARKET PRICES IN ERCOT cusses how to mitigate net revenue uncertainties in the form of controlling price risk, output risk, and cost risk.

$45

$40 ABWR Construction, Investment,

$35 Price, Output, and Cost $30 ,...1. __ .* _ ."'~_" *..**.. _.

As an application of the real options approach to evaluating =lE $25 -}--,..... -~.+-- ""-, . . -.~-- ..... ~

~

new nuclear power plants, public data is available to estimate $20 -.. ---.;-... *f- --f--P(~:$1-~:63*;O~58P~=1*i* . l-construction cost, electricity prices, megawatt-hours gener- $15 -- --~- ..... -i.- ; Std Dev of Residential = $1.69 ~ ..

$10 ....'." L. -": ..1 Mean Price = $40.13/MWh

.~ _____ ..".~ _________. ___._... _"J i-ated, and operating costs for an ABWR in Texas. First, Table 1
:

$5 ...' ." ... , ... -- ._----- ...._- .

-.~~

(see p. 50) presents the average construction capital cost of a $0 -;---.. *-r***---T---*~- .. ~---* '+--"~'--I _ .. r"--: ... -~ -*-**-*-,.---~***r-****-**T* .. **-* "

dual-unit ABWR built in the United States. 3 The following 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 20402045 2050 summarizes the reactor supplier's statement regarding Table 1:

"The ABWR plant can be constructed in just four years for FIG. 3 CAPACITY FACTORS AT DUAL-UNIT BWRs IN US AND ABWR IN JAPAN US$1,600/kWe and suppliers are willing to undertake a proj-' 100 ect on a fixed price, flXed schedule basis. As a result, the ABWR nuclear plant has proven itself in Japan and Chinese Taipei to 80 ~ .

be economically competitive with other power generation BWR2 OLS Trend .....

60 options and estimates mdicate that it can be economic in other countries as well." 40 Let the construction cost (K) of theABWR be $1,600/kWe 20 ...................... -.... ........ . ......... .......- ..

(including financing charges) for a dual-unit 2,800-MW (gross) capacity plant (with 2,700 MW net). The plant could generate 23.65 M MWh each year at full capacity. The total 1990 1992 1994 1996 1998 2000 2002 investment, 1, would be about $4,500 million (M).

Second, to forecast electricity prices over the life of the FIG. 4 ASIM LATION OF CAPACITY FACTOR FOR A DUAL-UNIT ABWR plant, consider energy sold in the Texas electricity market. The Texas market is unique in the u.s. because of its separation 100%

from the rest of the country into its own reliability region, 80%

known as ERCOT, the Electric Reliability Council of Texas.

(Although all of ERCOT is in Texas, not all of Texas is in ~ 60%

ERCOT.) Figure 1 shows Texas monthly electricity prices and 40% _... ____ .~ CF =87.56-16.~8 [1/~Year-1989)]! ...

natural gas prices from 1990 to 2003. Since the price spikes in f Std Oev of ReSidential 5.72 1 =

2000, the price of electricity (for example, "Type B Electric 20% *----*****-*-------***1 I __

Mean of Lifetime CF =86.23% 1

,_.....-_ _...,...,.-.-._,~___~. . . . . _,r -

Energy" in ERCOT) has been higher and is likely to remain 0% :---;-----1'-----*,**----'T'*-----;----'------l-------

higher for the foreseeable future.

2010 2015) 2020 2025 2030 2035 2040 2045 2050 Figure 2 presents prices from 1990 to 2003 and simulated www.fortnightly.com MAY 2004 PUBLIC UTIlITIES FORTNIGHTLY 47 OAGI0000197_186

FIG. 5 ANNUAL AVERAGE VARIABLE EXPENSES (C) AT 100% CAPACITY FACTOR i prices from 2004 to 2050. These simulated prices represent 25 .--.---------..--.--... --.- -..-------------..-.----------.- "--"--'---"--- lone of 1,000 Monte Carlo trials. In these trials, average price fQ~ follows the parameters given in Figure 2. For each year there 20 15 ------.---i.-.--------

OlS Trend BWR2----------- - - - . - - i

-- is a random draw from a normal distribution that adds vari-ance to electricity prices. (The standard deviation of this nor-

-- mal distribution is $1.69.) In the particular simulation presented in Figure 2 the mean electricity price was $40.13 10 and the standard deviation was $1.62.

5 Third, during the 1980s and 1990s, capacity factors at U.S. nuclear power units improved dramatically. Figure 3 presents capacity factors from 1990 to 2002 at: (1) dual-unit 1990 1992 1994 1996 1998 2000 BWRs in the U.S: that came into commercial operation after g 1982; and (2) the Japanese ABWR that came into full com-FIG. G A SIMULATION OF ANNUAL VARIABLE PRODUCTION COST (C)

~ mercial operation in 1997. Data for General Electric BWRs 25 -------.----.------.- ---"-'--'--- -..---.. --....-.........---... - .----

i larger than 1, 100 MW are used to simulate capacity fa~tors

~ at ABWRs operating in the United States. Ordinary Least

~1!- Squares parameters were estimated with this sample of capac-

" ity factors. The estimated trend line is identified in Figure 3.

~

~

Assuming ABWRs follow the same trend, the expected life-10 Q=16.49 + 6.05 [1/(Year-1989)] f---- time capacity factor would be about 86 percent. Using esti-Std Dev of Residential =$1.49 Mean of Q=$16.38/MWh mated parameters, a Monte Carlo simulation of capacity factors for a dual-unit ABWR is presented in Figure 4. (This is from the same simulation as in Figure 2.)

2010 2015 2020 2025 2030 2035 2040 2045 2050 Fourth, Figure 5 presents C (operating cost at full capac-ity) for dual-unit BWRs in commercial operation in the FIG. 7 A SIMULATION Of ANNUAL REVENUES i United States after 1982 for the years 1990 to 2000 (inflated 600 I. to mid-2001 dollars). Assuming ABWRs follow the same

~ trend, Figure 6 presents a Monte Carlo simulation of variable I expenses. In this simulation, the mean Cis $16.38, with i a standard deviation of $1.58. To summarize, expected net f revenues might be (R is at the mean of the 1,000 Monte Carlo

trials)

R =: (($40.l31MWh . 86%) - $16.38IMWh) . 23.65M MWh/year =:

$430Mlyear.

2010 2015 2020 2025 2030 2035 2040 2045 2050 The Value of a Dual-Unit ABWR in Texas FIG. 8 1,000 SIMULATIONS Of NET PRESENT VALUE With a real discount rate of7 percent, the capital recovery 300 -.... -----.-... -.-............------.- .. ------.- .. ---- ------..--.---- ... -- -.. -..

factor (8) is 0.0772 for 40 years. The NPV in 2010 (assum-ing both units are completed in 2010) is 250 - -____________________ r-J.lean [et Re_\I!lI!l!~~_::~~ll_'\jL __

'" 200 -.-.----.. --..--.------'_____---.----.---.-.---.-----.-.- NPV = (R/ 8)-1 =($430M/0.0772) -$4,500M = $1,100 M.

ill

! 150 ---------------lIl-.f--II------**-..- .. -----* ..*-------- --.. -

The NPV is positive, so the investor-generator would build the ABWR under traditional investment criteria.

However, net revenues are uncertain. Simulations of the electricity prices, generation output, and input costs can be o 888 00 00 combined to determine the probability distribution of net

'" M revenues. Figure 7 presents a simulation of revenues for>>

48 PUBLIC UTILITIES FORTNIGHTLY MAY 2004 wwwfnrtninhtlv r.nm OAGI0000197 _187

A REAL-OPTIONS ApPROACH By GEOFFREY ROTHWELL per kilowatt at 1*. For aplant ofW kilowatts-U nder standard investm.ent criteria, the nal cost is closer to 10%), the capital recov-investor-generator would invest in ery factor ( 8) is 0.0772 over a 40-year life, electric, K* = /* / w. To summarize:

new power capacity if the Net Pre- and the NPV of annual net revenues (R/ 8) K* =(1/>10) *(P*CF -f)* (MWill4R/W) sent Value (NPV) of the project were positive. is $5,700M (ignoring taxes).2 =(l/>lo)*(p*CF-f)* 8.760, Net Present Value equals the discounted Discounted net revenues can be calcu- where the final term is equal to the number value of (1) the power plant's net revenues lated, but each of the three variables (P, CF, of hours in ayear divided by 1,000 (the num-(R) per year (in millions of dollars) minus (2) and C) is uncertain, because future electric- ber of kilowatts in a megawatt). What is the total construction cost ( f) including financ- ity prices, generation output, and operating value of K* (the total construction cost per ing costs (e.g., interest during construction): costs are unknown. Therefore, net revenues kWe) that might trigger new power plant NPV=R/o -1>0 => R > 0'/, are uncertain and the NPV is uncertain. The orders? In the text (assuming I/> = 1), if K*

where 8 is the capital recovery factor.' Under traditional NPV analysis does not have acon- = $1 ,980 kWe, investors would be indiffer-NPV investment criteria, the generator sensus method for evaluating NPV probabil- ent between ordering new plants and wait-invests if net revenues are greater than the ity distributions. 3 ing for new information.

levelized cost of construction: R > 8 ./.

Let R* be the "net revenue trigger value," Real Options Analysis of Endnotes:

Nuke Investment 1. The capital recovery factor, 8, is equal to [e'T (er -1)]1 such that if expected present value of net (erT -1), where r is the generator's cost of capital and revenues is greater than R*, the investor Traditional NPV analysis assumes that all T is the economic life of the plant Qgnoring tax effects, would order new power capacity. Under NPV uncertainty is reflected in the risk premium see next).

analysis, R* =0 ./. If net revenue is less associated with the cost of capital. How is 2. Neglecting income taxes is not likely to influence the thanR*, the investor-generator waits (does this risk premium determined? The "real primary conclusions of this paper under competitive market conditions, low corporate income tax rates, not invest). options" approach provides one answer, and the use of accelerated depreciation. However, the Net revenues are based on an evaluation of the probability dis- error will increase with increases in the cost of capital.

R=(P* CF - f) *MWYEAR, tribution of net revenues. 3. Consider Robert Brealey and Stewart Myers, Princi-where (1) P is the market price of elec- Two assumptions must be made to eval- ples of Corporate Finance (2000, Irwin/McGraw-HilO; tricity in dollars per MWh (megawatt- uate this probability distribution with the real p. 275): "Finally, it is very difficult to interpret a distri-hours), bution of NPVs. Since the risk-free rate is notthe oppor-options approach. First, assume that per-tunty cost of capital, there is no economic rationale (2) CF is the capacity factor equal to total centage changes in net revenue follow apro- for the discounting process. Because the whole edi-electricity generated per year divided by portional Brownian motion with anormal dis- fice is arbitrary, managers can only be told to stare at the maximum dependable capacity per tribution. Second, assume that uncertain net the distribution until inspiration dawns. No one can tell year, revenues are perfectly correlated with aport- them how to decide or what to do if inspiration never dawns." Hopefully, this analysis will provide some inspi-(3) f is average production cost at full folio oftradable assets (both real and finan-ration for identifying sources of risk and how to miti-capacity (i.e., total production cost divid- cial).4 gate them. It also provides a method for calculating ed by maximum output), and Under these assumptions the net rev- the risk premium.

(4) MINYEAR is the maximum depend- enue trigger value, R*, is 4. Avinash Dixit and Robert Pindyck, Investment Under able capacity (in megawatt-hours) per R* = (1/I{>>. 8*/*. Uncertainty(1994, Princeton University Press): pp. 65 year. where I{> represents an investor's discount of and 148.

For example, if P = $40 per MWh, the NPV of uncertain net revenues. s From 5. Here, 1> equals [( y-1)/y] where y= 112* {I +

[1 + (8 /) / (J') ] In}, see Rothwell (2004, Appendix.

CF = 90%, and f = $16/MWh, with Equation (3), the trigger value for total con- 2). This formula for yassumes that financial markets MWYE4R = 22M (million) MWh/year, then struction cost, f~ can be found: price risk conSistently across assets, including assets Rt =[($40* 90%) -$16]* 22M = $440Mlyear. /*=( 8/I{>>R* in a portfolio that is perfec~y correlated with ("spans")

With a real cost of capital of 7% (the nomi- Finally, let K* be the construction cost net revenues for new power plants.

www.fortniahtlv.r.nm M6Y ?nn4 PIIRIlr.IITIlJTI~~ FnRTNIGHTLY 49 OAGI0000197_188

Mitigating the Risks of Nuclear Investment Three risks were considered: price risk, output (capacity factor) risk, and cost risk. This section exam-ines the sensitivity of the trigger J(i' to mitigating each of these risks and what nuclear power plant owner-operators might be willing to pay for real and financial assets to mitigate each of these risks.

To examine the sensitivity of K*, each risk can be suppressed in the Monte Carlo simulation. For example, if the owner-operator could contract with a buyer to guarantee the price of all output at $40/MWh (real) for 40 years, the standard deviation of the price could be reduced to zero and the trigger price (K") would rise. Each of the three risks can be held to zero; two of the three can be held to zero; or all three can be held to zero.

each year from 2010 to 2050, based on the particular simula- As a benchmark, with the assumptions and simulations tion in Figures 2, 4, and 6. Figure 8 presents a histogram of described in this paper, holding most revenue-related risk to 1,000 simulations ofNPV: Average NPV is $740M with a zero, the nuclear power plant supplier could sell new nuclear standard deviation of $160M. Underlying this NPV are aver- power plants on a fixed-construction cost basis for a breakeven age net revenues of $430M per year. How might an investor- price of $1 ,980/kWe including IDC (see Table 2, p. 51). Con-generator evaluate this probability distribution for NPV? trolling output and cost risk, price risk alone reduces K" by Following the real options analysis, the variance of percent- $200/kWe. Controlling output and price risk, cost risk alone age changes in net revenues was 4.2 percent in the 1,000 sim- reduces K* by $320/kWe. Controlling both price and cost ulations represented in Figure 8. With a variance of 4.2 risk, output risk alone reduces K* by $380/kWe.

percent, cp = 60%.4 So, TIIBLE 1 AVERAGE CAPITAL COST OF A DUAL-UNIT ABWR BUILT IN THE U.S.

J* =( cp/8) R* = (60% I 0.0772) $430M =$3,340M and Direct costs (per 1,400-MW unit)

~

g Structures and improvements $400 ~

K" = ($3,340M I 2,800MW) . (1,000 MWIkWe) = $1,200/kWe. Reactor plant $500 ~

Turbine plant $250 Electrical plant $150 Alternatively, the capital recovery factor could be adjusted to Miscellaneous plant (e.g., cooling) $100 reflect the Wlcertainty in NPV; i.e., (81<1>> = 0.1287, inferring Total direct costs (per unit) $1,400 a real discoWlt rate of 12 percent, or a risk premium of 5 per- Total indirect costs (per unit) $400 cent. (A 12 percent cost of capital yields a 12.87 percent capi- Base (Overnight) Construction Cost $1,800 Contingency (per unit) $165 tal recovery factor for a 40-year life.) This represents a decrease DC at 7% (4-year lead time per unit) $275 of about 25 percent from construction cost in Table 1. There- Total Cost (per 1,400-MW unit) $2,240 fore, if investors implicidy discoWlt nuclear power because of Total Cost (for two units, 2,800 MW)=I $4,480 Plant Cost per kW (gross)=K $1,600 these uncertainties, new nuclear power deployment requires (in millions of 2001 dollars) lower construction cost.

50 PUBLIC UTILITIES FORTNIGHTLY MAY 2004 OAGI0000197 _189

Further, controlling output risk, price plus cost risk TABLE 2 DECOMPOSITION OF REVENUE VARIANCE together reduce K* by $500/kWe. (Because of the slight corre- iii Source of cr' I "Price" of  !!

lation between price risk and cost risk in the simulations, there* Variance Control g ro is an economy of risk reduction, compared to controlling price ~

Almost none 0.0001 $1,980/kW $0 and cost risk separately for the equivalent of $ 520/kWe.) The influence of each pair of risks onK* can be calculated (see Table Price 0.009 $1,780/kW $200/kW Cost 0.014 $1,660/kW $320/kW 2). Finally, to trigger sales with no risk mitigation (output, 0.017 $1,600/kW $380/kW Output price, or cost risk), K* is about $780/kWe lower than the benchmark, i.e., $1,200/kWe (as found above). Price + Cost 0.024 $1,480/kW $500/kW Price + Output 0.026 $1,450/kW $530/kW These values for mitigating risk give an opportunity to con- Cost + Output 0.032 $1,360/kW $620/kW sider bargaining among nuclear power industry participants P+ Cost + Output 0.042 $1,200/kW $780/kW to share risk and returns from new nuclear power plants. For Note: There are differences due to rounding.

example, the owner-operator might be willing to reduce the price of firm power below the expected spot market price to encourage very long-term contracts. According to the assump- Three risks influence annual net revenues (revenues before tions here, the owner-operator might be willing to pay up to payments on construction expenditures) from operating the equivalent of $200/kWe to eliminate price risk. (This is a nuclear plants: output risk, price risk, and cost risk. Currently price per megawatt-hour difference of about 10 percent, hold- operating nuclear power plants were built under rate-of-return ing all else equal.) regulation. Future nuclear power plants likely will be built in Under electric utility rate-of-return regulation, price risk deregulated environments. These environments put competi-was reduced by giving electric utilities price increases to cover tive pressure on nuclear power plant suppliers to lower new increases in reasonable costs of operation and capital. In dereg- nuclear power plant construction cost and to develop a new ulated markets, price risk is shared between the owner-opera- business model for new plants. Future research should exam-tor and the electricity consumer. Further research should ine risk-mitigating components of this new business model.

determine the willingness-to-pay of electricity consumers for Until a new business model is created and implemented, it is fum power under very long-term contracts. unlikely that there will be new orders for nuclear power plants A related question concerns output risk (because risk-miti- in Texas (or anywhere in the United States). [ii gating measures to control price risk require the delivery of firm power). The owner-operator must backup committed Geoffrey Rothwell is senior lecturer in the Department of output with either: (1) financial instruments or contracts for Economics and the associate director of the Public Policy purchases on the spot market; or (2) physical assets, such as Program, Stanford University. He is also working for the u.s.

natural gas peaking units. The owner-operator should be will- Department of Energy on the economics of new nuclear power.

ing to pay up to ~500/kWe to eliminate both output and price However, the analysis here is independent research. Contact him risk. Future research should consider alternative real asset and at rothwell@stanford.edu.

financial portfolios to best mitigate these two forms of risk simultaneously for new nuclear power plants. Endnotes The remaining risk to the investor is cost risk, which could 1. A more detailed explanation of the techniques used here can be found in Geoffrey Rothwell, What Construction Cost Might Trigger New be eliminated through contracting. For example, nuclear fuel Nuclear Power Plant Orders?" (March 2004) at (which has an asset life of decades) could be leased at a fixed http://siepr.stanJordeduipapers. On deregulated electricity markets, see price for a finite period and returned to the lessor. Also, an Geoffrey Rothwell and Tomas Gomez, Electricity Economics: Regulation operations management company could operate the plant and Deregulation (2003, IEEE Press with John Wiley).

under contract. But the transaction cost of monitoring an 2. Two ABWRs have been operating in Japan since 1997 and four units are under construction inJapan and Chinese Taipei. The ABWR operating contract is likely to be prohibitive. Therefore, cost has been certified by the u.s. Nuclear Regulatory Commission for risk should be assigned to the party best able to mitigate cost construction in the United States.

risk on a day-to-day basis-the owner-operator. Future 3. See Nuclear Energy Agency. Reduction ofCapital Costs in Nuclear Power research should consider how much cost risk can be mitigated Plants (2000, Paris: OECD): pp. 96-99. In their 2003 edition Brealey and Myers dropped their discussion of "Misusing Simulations" (part and how much equity in the project might be required of the of which is quoted here) and added a new section, "Real Options owner-operator to create optimal incentives to deliver cheap, and Decision Trees."

reliable, and safe electricity. 4. Here Y= 1/2' {l+[l+(8*0.077/0.042)]1I2} = 2.5 and rf> = (y-l)ly= 0.60 www.fortnightly.com MAY 2004 PUBLIC UTILITIES FORTNIGHTLY 51 OAGI0000197_190 OAGI0000197 _191

Proceedings ofICAPP '03 Cordoba, Spain, May 4-7, 2003 Paper 3188 The Business Case for Building a New Nuclear Plant in the U.S.

John Redding GE Nuclear Energy 175 Curtner Avenue, San Jose California 95125 Tel: (408) 925-2978, Fax: (408) 925-6472, Email: John.Redding@gene.ge.com Cheryl Muench Black & Veatch Corporation 11401 Lamar Overland Park, KS 66211 Tel: (913) 458-2813, Fax: (913) 458-293, Email: MuenchCL@bv.com Rob Graber EnergyPath Corporation 5526 Radell Drive SE Salem, OR 97301 Tel: (503) 851-5376, Fax: (503) 371-7024, Email: robgraber@nrgpath.com Abstract - Sustained economic performance by a nuclear plant generates a significant amount of cash for its owner.

This cash becomes available for other investments including additional power generating assets. What better investment can a successful nuclear utility make than in a new nuclear plant? Of course, one must make the corresponding business case. A pro forma is developed and this provides a forecast of revenue, costs, the resulting cash flow, and, more importantly, the positive effect on the value of the owner's company as reflected in its stock price. The capital cost of the plant represents not only the single biggest cost but also a significant outflow of cash. Central to establishing the business justification then is the capital cost and how the resulting pro forma compares with that of other investments.

1. INTRODUCTION for example, recently adopted a RPS that requires utilities to increase their total amount of eligible The ability to operate a nuclear plant safely year-in and renewable resources by at least one percent per year, year-out with a capacity factor of 90% is certainly a until 20 percent of its retail sales are procured from pre-requisite for moving ahead with a new plant. So is renewables. If only nuclear plants were considered an the ability to consistently maintain production costs at eligible renewable resource ... )

or near 1.0 cent per kwhr. The performances of many U.S. nuclear power plants already fall into this category Because these options are to varying degrees attractive of excellence, demonstrating that U.S. nuclear utilities and because a nuclear plant has not been ordered in the have the management skills to safely and profitably U.S in nearly three decades, the CEO and Board of operate nuclear plants. Directors are going to look long and hard at the nuclear option. To get their approval to build a new nuclear Sustained economic performance by a nuclear plant plant means that someone must make an unassailable generates a significant amount of cash for its owner. business case for it.

This cash becomes available for other investments including additional power generating assets. What It is commonly assumed that a new nuclear plant will better investment can a successful nuclear utility make be a .:nerchant plant built by a utility or consortium of than in a new nuclear plant? utilities in a state whose wholesale electricity market has been de-regulated. We don't think this is II. REGULATION OR DEREGULATION? necessarily the case. Because of the unfortunate experience with deregulation in California, many states The obvious answer is that a utility has several have put a halt to or slowed down their own potentially attractive options including additional deregulation plans. So it is conceivable that the next combined cycle plants, advanced clean coal plants and nuclear plant in the U.S., the one that will break the a range of renewable technologies. Indeed, some states logjam so to speak, will be built by a regulated utility have adopted Renewable Portfolio Standards that with the approval and perhaps the encouragement of its mandate the build-out of renewable plants. (California, Public Utilities Commission.

The Business Case for Building a. Page 1 of6 New Nuclear Plant in the U.S OAGI0000197_192

Proceedings ofICAPP '03 Cordoba, Spain, May 4-7,2003 Paper 3188 In fact, there are many advantages to building a nuclear III. IF A NUCLEAR PLANT WAS ORDERED plant in a regulated environment, that is, on a cost-of- TODAY service basis. The utility has a higher degree of In order to answer that question, a project pro forma assurance that it will recover its costs and eam an 11 to has been developed. Since the pro forma is in the form 12% return on those costs. If the plant suppliers provide of a spreadsheet, it can be used to determine the 2 or 3 the utility with firm priced contracts for the plant's key elements upon which the success or failure of the construction, it would seem almost a certainty that these project depends by performing several "what if' cases.

costs will be deemed prudent by the PUC. There is, in other words, significantly less risk to the utility.

So let's begin by assuming that a nuclear plant is (Utilities building a $2B merchant plant nuclear plant ordered today. Imagine a newspaper report along the could be putting themselves in a situation often lines of that in Figure 1. The cost is reported to be described as "betting the company.")

$1445lkw and that this will be shared by more than one utility (it isn't clear if GE is to be an investor, but this Currently, there IS no straightforward* market could be read into the announcement.) The most telltale mechanism for capturing the value of new nuclear part of the report is that investors were lukewarm about capacity in terms of fuel diversity and reducing the news. Why might that be?

pollutants. However, policy makers at the state level could and, in our opinion, should take these issues into First Nuclear Plant in U.S. Ordered consideration when planning new capacity. Thus state Reuters decision makers might very well decide that their May4,2003 utilities are "long" on natural gas capacity and direct them to build new nuclear in order to diversify their SAN JOSE, CA (Reuters) - GE, Black& Veatch, and a generating portfolio and reduce C02 emissions. consortium of utilities announced today that they have signed an agreement to proceed with the construction of Of course, many policy makers and PUCs at the state an ABWR nuclear power plant. Stock prices of all

, level have biases against nuclear power and it would be companies remained unchanged as investors reacted difficult, to say the least, to surmount the ideological with caution to the announcement. The plant, estimated to cost $1445/kw, will be built in California and sell into and political hurdles that stand in the way of getting that state's wholesale markets. An excited Gov. Gray approval for new nuclear capacity. Although public Davis told reporters ...

support is always important, let's face it, a non-regulated utility or a developer can build a merchant (continued on back page) nuclear plant without it (we are assuming, of course, that the plant is licensed and complies with all safety Figure 1: A purely fictitious newspaper report.

and environmental requirements.)

Since investors and analysts are pretty smart people, It is able to do so because it takes on the risk that is they know that this project will not create additional otherwise borne by the ratepayers. As we have written value for the firm. They base this upon an analysis, elsewhere (1), that risk is extensive and must be using the data in Table 1 that indicates the net present carefully managed. As we all know, more risk must be value of this project is zero.

offset by a higher return on investment. Most CEOs and business development managers with whom we have Table 1:

discussed this issue talk in terms of 20% return on Capital cost $ 14451kw (overnight value) equity (vs. 16% for combined cycle.) This translates Fuel cost $0.50 cents per kwhr into a 12% weighted cost of capital, otherwise known O&M cost $0.60 cents per kwhr as the discount rate. Equity 50%

Discount rate 12% (the weighted cost of capital)

So, the question to which we will now turn is this: can a Gas prices $4.00IMBTU for 4() years nuclear plant be built as a merchant plant and achieve financial success where We will measure such success To say the same thing in a different way, the Internal as achieving at least a 12% Internal Rate of Return. Rate of Return (IRR) for this project is 12.0%. Since This is equivalent to a zero Net Present Value. If this is the discount rate or weighted cost of capital for the achieved, the minimal expectations of the owner will be utility is also 12.0%, no value is created or destroyed.

met. We say minimal because it is in line with the company's other business returns but it does not exceed Weare assuming that natural gas prices determine the them and thereby increase the value of the company. cost of electricity in the marketplace since combined The Business Case for Building a. Page 2 of6 New Nuclear Plant in the U.S OAGI0000197 _193

Proceedings ofICAPP '03 Cordoba, Spain, May 4-7, 2003 Paper 3188 cycle plants have been "on the margin" more than half With this in mind, the GE engineering team has the time in most major markets and in some markets identified a number of design changes that would 80% of the time or more. A gas price of $4 per MBTU reduce capital cost by about this amount and is translates into electricity prices of about $501MWhr currently evaluating these for implementation into the when the average heat rate for the system is 8000 ABWR and ESBWR designs.

MBTUlkwhr.

If two units were built at the same site and a year apart, Some discussion of the capital cost used here is in then the capital cost of the second ABWR unit would order. GE and B&V spent a good deal of time and be $1180/kw. This is a cost reduction of 18% or effort in 2002 in the performance of a bottoms-up $2401kw. The IRR for a two-unit project would estimate of the capital cost of the ABWR. This estimate therefore be larger, in fact,* a full percentage point was based upon the quantities and vendor costs that higher.

were compiled in the POWRTRAK 1m database during the delivery of the Lungmen ABWRs in Taiwan. GE Another obvious thing to do is sell the output of the and B&V's scope on this project was the Nuclear Island plant at a higher price. This is not as facetious as it may and so the accuracy of this portion of the plant is quite seem on the surface. The location of the plant site has a high Labor costs and productivity figures were taken significant influence on the price it receives for its from B&V's proprietary database for U.S. power plant electricity. Power pools such as PJM use locational projects. The Turbine Island costs are based upon a new marginal pricing (LMP) and others such as California turbine-generator design that GE and B&V are use zonal pricing. Those interested in such things can developing and is an estimate as opposed to an actual find hourly spot prices for PJM at cost The radwaste building and yard area are included http://www.pjm.com!). The prices vary significantly by in the scope of the estimate. node or zone. For example, the PJM website indicates that the spot price on January 21,2003 at Deer Creek 1 The cost figure of $ 1445/kw includes everything except is $39.40 MWhr and is $60.70 per MWHR at Seneca.

inflation and financing (both of which are, of course, included in the financial analysis used to determine the IRR.) It includes the EPC (Engineering, Procure, and Construct) cost, supplier's profits, the owner's cost, If two units were built on the same site and a year licensing and development costs, and a contingency. apart, then the capital cost of the second ABWR Even the cost of engineering the new turbine-generator unit would be $1180Ikw, a savings of 18% or and turbine island is included. It is as solid a number as $2401kw compared to the cost ofa single unit.

one can get and the team of GE and B&V stand behind it.

It is important to note that this is an estimate for a Wholesale prices are difficult to project since these are single unit. The GE plan to commercialize the ABWR determined by the cost of natural gas, how many new in the U.S. does not rely upon the simultaneous plants are brought On line, and the demand. Nodal construction of 6 or 8 ABWR units.

prices are even more difficult to predict over the long term since load centers and the grid itself change over IV. MAKING NUCLEAR A BETTER INVESTMENT time. No one can safely predict what electricity prices will be six years from now when the nuclear plant goes We need to get investors more excited about a new into commercial operation.

nuclear project and we do that by improving the IRR. It is also important to reduce the negative cash flows It would be wise therefore to sell most of the plant's during the construction period since these would dilute output through long term bi-Iateral contracts. Since the the utility's overall earnings and diminish the value of cost of producing nuclear electricity is stable and the utility as an investment. This is not a good career predictable over time,)t is possible to offer industrial path for those responsible for managing the utility.

customers fixed prices for electricity (the energy as IVA. The Obvious Ways opposed to the T&D portion). Given the volatility of gas prices and the subsequent up-and-down of Reducing the capital cost of the plant is an obvious way wholesale prices, industrialcllstomers will find this to improve the financial attractiveness of the plant. In attractive. Indeed when TVO, a Finnish utility, fact, reducing the capital cost from $1445/kw to announced its decision to build a new nuclear plant,

$13 OO/kw increases the IRR by a full percentage point.

The Business Case for Building a. Page 3 of6 New Nuclear Plant in the U.S OAGI0000197 _194

Proceedings ofICAPP '03 Cordoba, Spain, May 4-7, 2003 Paper 3188 they were contacted by over 50 industrial consumers Production Tax Credit (pTC), in the same way that interested in purchasing some portion of the output of owner's of wind energy facilities are given a 1.8 cents the plant at a fixed rate. A nice mix would be to have per kwhr PTe. A nuclear PTC of just 0.5 cents per 90% of the nuclear plant's output under long~term kwhr for 10 years-just 113 the value of the wind PTC--

contract and the remaining 10% available to be sold in would be sufficient to increase the IRR by 0.9%.

the spot market in order to take advantage of the IV.D. Investment Tax Credit periodic price spikes that do occur. The significance of selling most of the plant's output on a long-term basis, Past economic stimulus packages created by Congress particularly if that means 10-year strips or longer, is have contained provisions for tax credits given to that the risk associated with the utility's generating capital investments that create jobs and improve the portfolio is reduced. Moreover, if industrial consumers economy. An investment tax credit (ITC) on capital are offered an attractive long-term contract in exchange expenditures (equity portion only) made during the for some commitment in advance of project start, as construction of the plant would have dual effect of was the case with TVO, then the risk associated with increasing the project returns and mitigating the impact the project is significantly reduced. of negative cash flow during this time. A 10% ITC would increase the IRR by 0.45% and reduce the IV.B. Accelerated Depreciation negative cash flow by nearly $50M during the peak Because a nuclear project is capital intensive, year of construction.

accelerated depreciation of the plant's asset value will IV.E. Leverage reduce the amount of income tax owed and thereby increase cash flows. The latter directly increases. the Not so long ago, developers were building merchant IRR. If the accounting rules permitted 7-year MACRS power plants with highly leveraged project financing, (Modified Accelerated Cost Recovery) instead of the that is, with debt of about 80%. As a result of the Enron usual 40 year, straight-line depreciation, the IRRwould debacle and the downturn of the wholesale market, increase by 0.65%. lenders are wary and require substantially more equity from developers. For our analysis we used 50% debt There is justification for this change. MACRS is and 50% equity in keeping with the current realities and allowed for renewable energy projects as a way to the higher risk associated wlth nuclear construction.

encourage its use. Wind energy projects, for example, are eligible for 5-year MACRS. For the same reason--to It may be possible to reduce the equity requirements by encourage the use of an important source of energy--we demonstrating to lenders that risks are properly would like to see legislation that would permit MACRS managed. We have written extensively on this subject to be used for new nuclear capacity, new plants as well (Reference 1) and believe that selection of a well-as power uprates. managed engineering and construction team that has experience building advanced plants assures investors Better technology and lower costs, MACRS and a that capital cost projections will not be exceeded and Production Tax Credit have succeeded in bringing that the plant will be free oftechnical problems. GE and about a proliferation of new wind projects in recent B&V bring this kind of experience to a proj ect by virtue years. This strikes us as a good blueprint to follow of having built two ABWRs in Japan and two more in when it comes to new nuclear plants. Taiwan.

IV.C. Production Tax Credit Let's say this kind of experience and risk management is worth a 5% reduction in equity requirements so that Since we brought up the Production Tax Credit for the debt to equity ratio is now 55-45. The discount rate wind energy projects, let us propose that there be a PTC would fall and the NPV would increase by an amount for nuclear plants as well. This would be in recognition equivalent to 0.5% rise in IRR.

of the fact that increases in output from current nuclear plants account for 2/3 of all emission free generation in Table 2 summarizes all of these changes:

the U.S. in recent years. Sound environmental policy Table 2: Our Game Plan IRR must recognize the value of nuclear plants in terms of Base case 12.00%

reducing NOx, SOx and C02. There is no way, for Reduce capital costs +1.00 example, for the U.S. to comply with the intent of the Accelerated depreciation +0.65 Kyoto treaty without the expanded use of nuclear power Production tax credit +0.90 plants to meet future increases in demand.

Investment tax credit +0.45 It makes policy sense to encourage the construction and Risk management +0.5%

use of new nuclear plants by providing owner's with a 15.50%

The Business Case for Building a. Page 4 of6 New Nuclear Plant in the U.S OAGI0000197_195

Proceedings ofICAPP '03 Cordoba, Spain, May 4-7, 2003 Paper 3188 These numbers should be sufficient to get investors and analyses by 2.5 percentage points, equivalent to about a analysts excited about owning stock in this utility. $300lkw reduction in overnight costs.

In light of the Bush administration's stated goal of Merchant companies like Calpine are certainly having a new nuclear plant in commercial operation by concerned about gas price uncertainty and the 2010, we think those changes that require legislative or possibility of a sustained increase in prices. They can regulatory approvals are politically achievable. With and do protect themselves by hedging and by these changes, owners and suppliers can clear the final purchasing their own supply of gas. However, these are economic hurdle standing in the way of a new u.s. limited means of coping and gas price increases can nuclear plant. We look forward to seeing the following have unfavorable consequences as the article report in our newspapers: reproduced below clearly indicates. Most merchant companies do not, however, diversify (except for a bit First. Nuclear Plant. in U.S. Ordered of renewables) because their business model calls for Reuters focusing on one technology that in the case of Calpine May 4,2003 is advanced combined cycle.

SAN JOSE, CA (Reuters) - GE, Black & Veatch, and Integrated utilities, many of which are still subject to a consortium of utilities announced today that they have signed an agreement to proceed with the construction of regulation, do diversify and in fact know what mix of an ABWR nuclear power plant. Stock prices of all capacity (baseload, intermediate, peaking) and fuel companies climbed in heavy trading as investors (gas, coal, nuclear, renewable) is optimal for their reacted positively to the announcement. bus.iness conditions. A representative mix is 60%

baseload, 20% intermediate, and 20% peaking although This action by GE and utilities follows enactment last week of the Energy Policy Act of 2003. A key element of certainly not all utilities follow this recipe.

this legislation is the use of tax credits and accounting changes to stimulate the construction of new, advanced Technologies that use gas are not suitable for baseload nuclear plants. purposes on a sustained basis not only for technical reasons but because they have trouble competing with The ABWR plant, estimated to cost $1300/kw, will be existing coal and nuclear plants which get dispatched built in California and sell into that state's wholesale markets. An excited Gov. Gray Davis told reporters first. During the recent "boom" years utilities ordered "This solves all of our problems .... or built significant amounts of new gas fired plants to the point that the actual mix strayed pretty far from the (continued on back page) desired mix. It was for exactly this reason that many utilities began considering their baseload options Figure 2: Another purely fictitious newspaper report but one that we would love to see. Calpine's Profit Falls 50% As Its Fuel Costs Skyrocket DOW JONES NEWSWIRES V. WHAT ABOUT GAS PRICES? November 5, 2002 As far as gas prices are concerned, we are likely to SAN JOSE -- Calpine Corp.'s net slumped 50% in the enter uncharted waters in the very near future, and this third-quarter net income amid higher costs for fuel and will accrue to the benefit of the ABWR. The dramatic for project under development as well as a decline in decline in gas drilling productivity over the last three prices.

years, and over 200,000 MW of new natural gas power The energy concern on Tuesday posted net income of plants in the next two years could quite possibly be the $161.3 million, or 36 cents a share, down from 320.8 start or a long tern1 increase in gas prices. In the short million, or 88 cents a share, a year earlier.

term, aggravated by a colder-than-expected winter in The latest results included a gain of $12.9 million, or the East, short-term prices could easily exceed the three cents a share, from the sale of discontinued nearly $8.70/mmbtu gas experienced in January 2001. operations. The company also booked charges totaling The California Energy Commission forecasts that gas five cents a share, including severance and other prices in California will be between $4 and $4.50 per costs, deferred project-cost write-offs and a loss on the MBTU for the next five years, climbing to $5 per sale of turbines.

MBTU by the end of this decade. (Reference 2) Excluding these items, the company said it posted recurring earnings of $170.9 million, or 38 cents a As gas is increasingly on the margin even current share, below its August guidance for earnings between nuclear owners will benefit. A $1 per MBTU increase 40 cents and 55 cents a share. Revenue, meanwhile, in gas prices would increase the IRR determined in this slipped 1% to $2.5 billion from $2.52 billion.

Fuel expenses jumped 60% to $525.5 million, and project development costs more than quadrupled The Business Case for Building a. Page 5 of6 to $23.9 million.

New Nuclear Plant in the U.S OAGI0000197_196

Proceedings ofICAPP '03 Cordoba, Spain, May 4-7,2003 Paper 3188 including clean coal and nuclear. The sense of urgency financially attractive. These would hasten the diminished as soon as we entered the current "bust" introduction of advanced nuclear technology in the years but new baseload capacity, including nuclear U.S., something we feel is desirable on many levels. 0 capacity, is still being actively considered.

VII. REFERENCES Better technology and lower costs, a short MA CRS and a Production Tax Credit have 1. lR. Redding, Cost, Schedule and Risk succeeded in bringing about a proliferation of Management: The Building Blocks of a u.s.

new wind projects in recent years. This strikes us Nuclear Project, Proceedings of PowerGen as a good blueprint to follow when it comes to International Conference, Orlando Florida, new nuclear plants. December, 2002.

2. California Energy Commission, "Comparative There are signs already that a recovery* is anticipated. Cost of California Central Station Electricity Consider this revealing report from the February 3, Generation Technologies", Staff Draft Report, 2003 edition of Power Week: February 13, 2003. Available on the Internet at http://www.energy.ca.gov/energypolicy/docu "PacifiCorp said last week it will need more than 4,000 MW mentsI2003-02-25+26 _workshop/2003 of additional generation capacity by 2014 to meet a projected 11 lOO-03-001SD.PDF load growth rate of about 2% per year across its six state service area. Including long-term power purchases and new capacity additions, PacifiCorp's energy resource portfolio would increase about 40% over current levels, according to the company's 162-page Integrated Resource Plan 2003 submitted state regulatory commissions The plan takes into account retirement of aging plants and supply contracts.

The plan calls for diversification resources, including wind, geothermal, gas, coal and demand-side management.

PacifiCorp said it thoroughly analyzed energy resource options various scenarios that accountedfor possible changes in weather, electricity use, fluctuations in fuel costs, plant performance and other considerations.

The result is a plan for 2,100 MW new baseload capacity, 1,200 MW of peaking generation, 700 MW load shaping contracts and other resources, 1,400 MW of renewable energy, and up to 450 average MW load to be avoided through demand-side management programs. "

To reinforce the points made in this paper, we note that:

  • the Plan calls for resource diversification
  • half of the additionai capacity is new baseload.

We think that the best way to meet these two needs is the addition of new nuclear capacity.

VI.

SUMMARY

There is an important role for nuclear power to play in meeting the needs of U.S. utilities whether in a regulated setting or in deregulated markets. The risks associated with building the first few nuclear plants in a deregulated market will require higher than normal returns. We have advanced several proposals that would make invest~ng in a new nuclear power plant more The Business Case for Building a. Page 6 of6 New Nuclear Plant in the U.S OAGI0000197_197 OAGI0000197_198

BODINGTON & COMPANY 50 California Street, Suite 630 December 17, 2004 San Francisco, CA 94111 Telephone (415) 391*3280 Mr. Seth Parker Facsimile (415) 391*7220 Principal Levitan & Associates, Inc.

100 Summer St. #3200 Boston, MA 0211 0 Re: Discount Rate for Valuation ofIndian Point

Dear Mr. Parker:

In this memorandum we present the basis for a discount rate to calculate the value of Indian Point. Indian Point is a nuclear power plant that is not utility rate-based property and is therefore exposed to merchant risks.

In sum, there are no "pure play" merchant transactions or existing literature from which to draw a discount rate. Accordingly, we considered business and [mancial risks, and then employed the capital asset pricing model ("CAPM") and data on KGen's recent acquisition of gas-fIred merchant projects to make two independent estimates of a valuation discount rate appropriate for Indian Point. The data and methods corroborate each other and together support a discount rate of approximately 18.5%.

Please note that this work reflects an initial review of literature and data. More detailed reviews and analyses may be necessary to support thorough explanations and testimony in the future.

First, the value of Indian Point may be estimated using several different measures of income and each measure of income has its own appropriate discount rate. For this evaluation, we have estimated the rate to be applied to debt-free after-tax net cash flow ("ATNCF").

For valuation of un-levered ATNCF, the appropriate discount rate is the weighted average cost of capital ("WACC") for a potential buyer of Indian Point.!

Debt-free ATNCF is a measure of net cash flow including income tax benefIts and costs but excluding all considerations of potential debt financing.

Tax rates assumed are a 35.0% maximum marginal Federal rate and an 8.5% maximum marginal New York State rate, for a combined rate of 40.5%?

Valuation date is January 1,2005.

I. Review of Transactions and Literature A detailed review of power project transactions and related discount rate literature is beyond the scope of this Exhibit. Subject to that qualifIcation, examples of project sales and published comments concerning related discount rates are addressed below.

1 Note that WACC is not the same thing as internal rate of return ("IRR"). WACC is the expected cost of capital, IRR is a measure of expected or actual return on capital. In capital budgeting theory, IRR should exceed WACC for a prudent investment.

20.35*(1-0.085)+0.085=0.4053 Member: NASD, SIPC OAGI0000197_199

Drawing from a log of sales of power projects during the last several years, the following tables presents examples of both nuclear and non-nuclear merchant project transactions.

Examples of Recent Nuclear and Merchant Project Sales Buyer Seller Project Year Nuclear Projects Entergy Yankee owners Yankee 2002 Exelon British Energy Clinton, TMIl. Oyster Creek 2003 FPL Energy Seabrook owners Seabrook 2002 Texas Genco et al AEP South Texas 2004 Non-Nuclear Merchants Brascan Reliant Orion Portfolio 2004 Calpine NRG Bank Group Brazos Valley 2004 Centric PLC FPL/EI Paso Bastrop 2004 KGen Duke SE Portfolio 2004 In addition to the nuclear transactions noted above, Dominion agreed to purchase the Kewaunee facility in Wisconsin during late 2003. The Wisconsin Public Service Commission recently rejected an application for a change in ownership. While this and the transactions noted above do show that there is a market for nuclear and merchant facilities, none of the buyers is a stand-alone or "pure play" nuclear merchant entity with its own publicly-traded securities. Accordingly, none of the deals done to date provide a direct observation ofWACC for the buyer of a nuclear merchant.

Discount rates for nuclear generation have been addressed in several recent publications.

Standard & Poors ("S&P"): In "Time for a New Start for U.S. Nuclear Energy?" and "Evaluating Risks Associated with Nuclear Power Generation" S&P reviewed many issues concerning nuclear power but did not estimate WACC.

Geoffrey Rothwell: "Triggering Nuclear Development" presents a real options approach to estimating a discounting rate and more information on the methodology appears in "What Construction Cost Might Trigger New Nuclear Power Plant Orders?" 3 Rothwell focuses on the cost uncertainties associated with nuclear generation and calculates a real discount rate of 12% for nuclear generation using a real options approach. He applies this rate to "net revenue", a measure he defines as pre-tax operating income. These papers are primarily silent on the incremental risks associated with merchant operations. Accordingly, this rate is not a WACC for application to Indian Point's merchant ATNCF. In addition, real discount rates cannot be easily adjusted for application to nominal ATNCF because depreciation is fixed at a point in time and then affects income taxes for many years in the future regardless of inflation.

Messrs Redding, Muench and Graber: Thes", authors with GE Nuclear Energy, Black & Veatch and Energy Path presented "The Business Case for Building a New Nuclear Plant in the U.S." during 2003 in Spain.4 They describe a 12% IRR as a minimum expectation and do address income taxes, financing and merchant risks. They also cite discussions with CEOs to support the assertion that investors expect a 20% return on equity for nuclear and 16% for natural-gas-fired combined cycle 3 Rothwell, Geoffrey, "Triggering Nuclear Development", Public Utilities Fortnightly, May 2004, pp 47-51, see page 50. Rothwell, Geoffrey, "What Construction Cost Might Trigger New Nuclear Power Plant Orders?", Stanford Institute For Economic Policy Research, March 31 2004,26 pages, see page 6 and the appendix defmition of net revenue.

4 Proceedings ofICAPP 03', Cordoba, Spain, May 4-7 2003, Paper 3188, see page 2.

OAGI0000197_200

investments, a nuclear risk-premium of 4%. However, the basis for 12% is not presented in detail and several oftheir calculations appear contrary to accepted fmancial theory.

Finally, Entergy purchased Fitzpatrick and Indian Point Unit 3 from the New York Power Authority in November 2000 and Indian Point Unit 2 from Consolidated Edison in September 2001. Entergy publishes some business-segment-specific data and does provide selected information on these projects and its nuclear business unit. 5 According to these data, the nuclear unit's return on average invested capital has been 8.S% to 12.2%, return on common equity has been 16.4% to 27%. The capital structure has been 23.S% to 4S%, averaging approximately 30%, debt. Entergy holds a Note to the New York Power Authority relating to the purchase of Fitzpatrick and Indian Point. Entergy's forecast of interest payments on this Note implies an interest rate between 6% and 7%. While this cost of capital data does concern the subject property, the data are not reflective of terms for a merchant nuclear project as of January 200S. Those terms and financial performance instead reflect what are now embedded costs and a seller-financing Note negotiated between Entergy and a seller during 2000.

II. CAPM-BasedEstimate ofWACC We first employ the CAPM to estimate the cost of equity and then combine that with an estimate of the cost of debt and a reasonable capital structure to calculate W ACC. CAPM requires estimates of the risk free return, beta, and the equity risk premium.

We selected companies that have substantial merchant power generation business units and obtained the most recent Value Line and S&P data on these companies. All the data are dated during December or Fall 2004.

Risk-free return is the yield on 20 year Treasuries as of early December 2004.

Beta is estimated by and taken from the most recent Value Line analysis of each company.

Market risk premium is 7.0% and taken from recent Ibbottsen Associates publications. This represents an average of the full-period income and total asset returns estimated by Ibbottsen.

Actual current cost of debt does not reflect the current marginal cost of debt capital because it may include existing fixed rate debt. Accordingly, we obtained the S&P rating for each company's debt and have employed the current market-based yield for each rating. Reuters publishes yield spreads for issues of different quality.

Capital structures are also based on data published by Value Line and S&P.

5 www.entergy.comJInvestor/Financiallassual.asp See 2002 Investor Guide, pages 49-51.

OAGI0000197_201

CALCULATION OF WACC Material Merchant EXl!osure Nuclear Company AES Calpine Duke FPL Group Reliant Dominion Entergy COST OF EQillTY CS symbol AES CPN DUK FPL RRl D ETR Risk free rate 4.90 4.90 4.90 Beta 1.85 2.10 1.75 Market risk premium 7.00 7.00 7.00 CAPMresult 17.85 19.60 17.15 COST OF DEBT S&P Rating, range B+/CCC B/CCC B+/B-Marginal cost ofB/C debt 12.00 12.00 12.00 WACC Combined tax rate 40 40 40 Capital Structure Common Equity 2 40 44 51 40 53 Preferred Equity 2 Debt 92 98 60 56 49 60 45 Result 8.03 7.50 12.23 Several facts must guide interpretation of the data above.

None of the companies are "pure play" merchants. While DUK, FPL, D and ETR do have merchant exposure they also have substantial regulated assets and thus we omit their cost of capital data from the table above. AES, CPN and RRI have more merchant exposure but do also own contracted assets.

The high leverage of AES and CPN is an artifact of the late 1990s and early 2000s when debt fmancing was more available for merchant projects and equity valuations were high. Little debt, at any price, is now available for merchant fmancings. The figures represent the so-called "embedded" capital structure not the marginal structure required to finance a new merchant acquisition.

Accordingly, the data above do support a beta of approximately 2.00 and a corresponding cost of equity of approximately 19%. They also show that the cost of debt should be consistent with current yields on sub-investment-grade B and C rated issues. The estimated average current yield on B/C-rated debt is approximately 12%. Further, the likely capital structure involves less than 50% debt. Entergy's nuclear unit capital structure implies that reasonable leverage is less than 30%.

ill. KGen Cost of Capital Duke Energy sold a portfolio of merchant projects to KGen Partners during 2004, and several aspects of the financing provide valuable information on the potential cost of capital for a buyer of Indian Point.

Duke Energy North America ("DENA") developed numerous merchant projects and had a portfolio of eight projects in four states located within the in the Southeast Electric Reliability Council ("SERC"). As DENA's heavy investment in merchant generation failed to yield current earnings, asset sales began.

Lackluster bids forced Duke to write down the value of the plants three times and the portfolio was ultimately sold to KGen Partners ("KGgen"). KGen is owned by MatlinPatterson and the firm previously purchased interests in NRG.

Duke's southeast merchant portfolio included three combined cycle projects and five peakers. Combined cycle projects accounted for 2,360 MW of the 5,280 MW total, all are natural-gas fired, all went into service during 2002, and after a multiple round auction the acquisition closed on August 5 2004 with KGen.

OAGI0000197_202

The transaction had three key components; cash, a high-yield note and a power purchase agreement.

Total cash was $425.tvfM. Regarding the high-yield note, Duke holds a $50 J\1M receivable from KGen.

This note bears interest at LIBOR +14.5% and is secured by a fourth lien on KGen's owner. Interest compounds quarterly and both interest and principal are due in a balloon payment after 7.5 years. Finally, the transaction included a seven-year power sales agreement between KGen and Georgia Power concerning the Murray combined cycle facility. Duke also operates this project under a long-term operations and maintenance agreement.

The terms for the high-yield note establish a lower bound on the cost of equity, an upper bound on the cost of debt and also show an example of capital structure.

As of mid-December 2004 LIBOR is approximately 2.45% hence the full rate of KGen's note is approximately 16.95%.

That rate is a lower bound on the cost of equity. Based on Ibbottson, Brigham & Houston, business risks and financial risks, a reasonable equity risk premium over the debt rate is approximately 6%.

CALCULATION OF WACC Company KGen COST OF EQUITY Sub debt rate 16.95 Premium 6.00 Result 22.95 COST OF DEBT S&P Rating, range Unrated KGen High Yield Note 16.95 WACC Combined tax rate 40.00 Capital Structure Equity 89 Debt 11 Result 21.54 IV. W ACC for Indian Point Building on the CAPM and KGen estimates of WACC presented above, in thisSection IV we now estimate a reasonable discount rate for valuing Indian Point's potential un-levered ATNCF.

KGen data were presented above and are repeated below.

The market-traded companies with substantial merchant exposure noted above included AES, CPN and RRI. Cost of equity and debt data based on these companies appears below. Regarding capital structure, all three have more embedded leverage than appears realistic in today's markets. The 70:30 ratio below is both lower than embedded leverage and based on the actual leverage for Indian Point shown in Entergy's financial statements.

OAGI0000197_203

CALCULATION OF WACC Market-Traded Indian Point Company KGen Merchants Estimate COST OF EQUITY Sub deat rate 16.95 Preumium 6.00 Risk free rate 4.90 Beta 2.00 Market risk premium 7.00 Result 22.95 18.90 20.93 COST OF DEBT S&P Rating, range unrated B/C B/C Yield 16.95 12.00 14.48 WACC Combined tax rate 40.00 40.00 40.00 Capital Structure Co=on Equity 89 70 80 Debt 11 30 20 Result 21.54 15.39 18.48 The 18.5% W ACC for Indian Point calculated above is based on an average of KGen and the Market-Traded Merchants. While many issues are important and many variations could be considered, this result is broadly consistent with market data.

A cost of equity of approximately 21 % is similar to Messrs Redding, Muench and Graber findings about investors expecting a 20% return on equity. This cost of equity is also implied by a beta of approximately 2.40, and such a beta is consistent current perceptions of the material non-diversifiable risks associated with merchant and nuclear operations.

A 15% cost of debt is and should be both above the cost of more-secure issues and below the cost of KGen's subordinated note secured by only a fourth lien.

The spread between 21 % and 15%, approximately 6%, is consistent with the spreads found by Ibbottson and Brigham & Houston for the difference between the costs of equity and debt.

An 80:20 capital structure is consistent with both difficult financing conditions for merchant projects and Indian Point's marginal costs and location in a market less troubled than SERC.

OAGI0000197 _204 0

OAGI0000197_205

Attachment 10 Formula for Fair Market Value Basic Equation Fair market value (FMV) of a business is derived from the unleveraged after-tax net cash flow (ATNCFu) that a willing, informed buyer would expect from its purchase. ATNCFu is a string of cash flows consisting of the purchase price as a negative (outward) cash flow, earnings before interest, taxes, depreciation, and amortization (EBITDA) less associated income taxes, and the tax shield provided by depreciation of the purchase price over the life of the business. FMV is the purchase price that makes the present value of the ATNCFu stream zero when discounted at the appropriate weighted average cost of capital (WACC):

0= PV(ATNCFu) = - FMV + PV(EBITDA)*(l-TR) + PV(Dep ofFMV)*TR TR = Effective income tax rate PV ( ) = Present* value of a string of cash flows at discount rate of WACC Dep ofFMV = String of annual depreciation charges on FMV as a purchase cost The equation above requires iteration on an estimate of FMV. The iteration can be avoided in this instance by using a depreciation factor in each year (the ratio of the depreciation charge to the amount being depreciated) in the present value term, and rearrangmg:

FMV = PV(EBITDA) * (1 - TR) / { 1 - TR

  • PV(DepFac) }

FMV ofLicense Renewal Option Ownership of IP 2&3 carries with it an implicit option to re-license the units for operation beyond their current license expiry dates. To exercise the option, the owner must make substantial capital investments. A decision to proceed with license renewal would be based on the owner's perception of future revenues and expenses (EBITDA) relative to the investment required. If the present value of the ATNCFu associated with license renewal is positive, the owner would be inclined to proceed. A positive present value would increase the price a buyer might be willing to pay for the facility, after adjusting for the perceived probability of renewal application approval and the tax treatment ofthe amortization ')f any premium paid for the option.

Vtotal = Original License Term FMV + License Renewal Option FMV

= VOLT + VLRO VOLT = PV(EBITDAoLT) * (1 - TR) / { 1 - TR

  • PV(DepFacOLT) }

1 OAGI0000197_206

Attachment 10 VLRO = Papproval * [PV(EBITDALRo) * (1- TR) - PV(CapExLRO) *

{l - TR

  • PV(DepFacLRO) } ] / {l - TR
  • PV(DepFacLRO) }

EBITDAOLT = EBITDA for original license tenn DepFacoLT = depreciation factor for VOLT Papproval = probability of approval of renewal application EBITDALRO = EBITDA for license renewal period CapExLRO = capital expenditure to achieve renewal DebFacLRo = depreciation factor series for VLRO and CapExLRO 2

OAGI0000197_207 1

OAGI0000197 _208

United States General Accounting Office GAO Report to the Honorable Edward J.

Markey, House of Representatives October 2003 NUCLEAR REGULATION NRC Needs More Effective Analysis to Ensure Accumulation of Funds to Decommission Nuclear Power Plants GAO Accountability

  • Integrity
  • Reliability GAO-04-32 OAGI0000197_209

October 2003 NUCLEAR REGULATION NRC Needs More Effective Analysis to Ensure Accumulation of Funds to Decommission Nuclear Power Plants What-GAO Found Although the collective status of the owners' decommissioning fund accounts has improved considerably since GAO's last report, some individual owners are not on track to accumulate sufficient funds for decommissioning. Based on our analysis and most likely economic assumptions, the combined value of the nuclear power plant owners' decommissioning fund accounts in 2000-about $26.9 billion-was about 47 percent greater than needed at that point to ensure that sufficient funds will be available to cover the approximately $33 billion in estimated deCOmmissioning costs when the plants are permanently shutdown. This value contrasts with GAO's prior fmding that 1997 account balances were collectively 3 percent below what Was needed. However, overall industry results can be misleading. Because funds are generally not transferable from funds that have more than sufficient reserves to those with insufficient reserves, each individual owner must ensure that enough funds are available for decommissioning its particular plants. We found that 33 owners with ownership interests in a total of 42 plants had accumulated fewer funds than needed through 2000 to be on track to pay for eventual decommissioning. In addition, 20 owners with ownership interests in a total of 31 plants recently conttibute_d less to their trust funds than we estimate they needed to put them on track to meet their decommissioning obligations.

NRC's analysis of the owners' 2001 biennial reports was not effective in identifying owners that might not be accumulating sufficient funds to cover their eventual decommissioning costs. In reviewing the 2001 reports, NRC reported that all owners appeared to be on track to have sufficient funds for decommissioning. In reaching this conclusion, NRC relied on the owners' future plans for fully funding their decommissioning obligations. However, based on the owners' recent actual contributions, and using a different method, GAO found that several owners could be at risk of not meeting their financial obligations for decommissioning when these plants stop operating.

In addition, for plants with more than one owner, NRC did not separately assess the status of each co-owner's trust funds against each co-owner's contractual obligation to fund decommissioning. Instead, NRC assessed whether the combined value of the trust funds for the plant as a whole was reasonable. Such an assessment for determining whether owners are accumulating sufficient funds can produce misleading results because owners with more than sufficient funds can appear to balance out owners with less than sufficient funds even, though funds are generally not transferable among owners. Moreover, NRC has not established criteria for taking action if it determines that an owner is not accumulating sufficient funds.

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Contents Letter 1 Results in Brief 2 Background 4 Despite Industry-wide Improvement, Some Owners of Nuclear Power Plants Are Not Accumulating Sufficient Decommissioning F\unds 6 NRC's Analysis Did Not Effectively Determine Whether Each Owner Was Accumulating Sufficient Decommissioning F\unds 11 Conclusions 15 Recommendations for Executive Action 16 Agency Comments and Our Evaluation 16 Appendixes Appendix I: Scope and Methodology of Our Analysis of the Decommissioning Trust Funds 19 Appendix II: Detailed Results of Our Analysis of the Decommissioning Trust Funds 28 Appendix III: Comments from the Nuclear Regulatory Commission 42 GAO Comments 47 Appendix IV: GAO Contact and Staff Acknowledgments 52 GAO Contact 52 Acknowledgments 52 Tables Table 1: Status of Individual Owners' Trust F\und Balances through 2000, Compared with Benchmark Trust F\und Balances, under Most Likely Assumptions 9 Table 2: Status of Individual Owners' Recent Trust F\und Contributions, Compared with Benchmark Trust Fund Contributions, under Most Likely Assumptions 10 Table 3: Status of Combined Trust F\unds Compared with Benchmarks for Balances and Contributions (by Percentage above or below Benchmarks) 28 Table 4: Owners with More, or Less, Than Benchmark Trust Fund Balances and Contributions, under Most Likely Assumptions (by Percentage above or below Benchmarks) 29 Page i GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197 _211

Contents Table 5: Selected Owners with More, or Less, Than Benchmark Trust Fund Balances and Contributions, under Optimistic Assumptions (by Percentage above or below Benchmarks) 37 Table 6: Selected Owners with More, or Less, Than Benchmark Trust Fund Balances and Contributions, under Pessimistic Assumptions (by Percentage above or below Benchmarks) 39 Abbreviations FERC Federal Energy Regulatory Commission GDP Gross Domestic Product NRC Nuclear Regulatory Commission SAFSTOR Safe Storage This is a work of the U.S. government and is not subject to copyright protection in the United States. It may be reproduced and distributed in its entirety without further permission from GAO. However, because this work may contain copyrighted images or other material, permission from the copyright holder may be necessary if you wish to reproduce this material separately.

Page ii GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197 _212

Contents Table 5: Selected Owners with More, or Less, Than Benchmark Trust Fund Balances and Contributions, under Optimistic Assumptions (by Percentage above or below Benchmarks) 37 Table 6: Selected Owners with More, or Less, Than Benchmark Trust Fund Balances and Contributions, under Pessimistic Assumptions (by Percentage above or below Benchmarks) 39 Abbreviations FERC Federal Energy Regulatory Commission GDP Gross Domestic Product NRC Nuclear Regulatory Commission SAFSTOR Safe Storage This is a work of the U.S. government and is not subject to copyright protection in the United States. It may be reproduced and distributed in its entirety without further permission from GAO. However, because this work may contain copyrighted images or other material, permission from the copyright holder may be necessary if you wish to reproduce this material separately.

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GAO Accountability

  • Integrity
  • Reliability United States General Accounting Office Washington, D.C. 20548 October 30,2003 The Honorable Edward J. Markey House of Representatives

Dear Mr. Markey:

Following the retirement of a nuclear power plant and removal of the plant's spent or used fuel, a significant radioactive waste hazard remains until the waste is removed and disposed of, and the plant site decommissioned. l Decommissioning of existing plants is expected to cost nuclear power plant owners about $33 billion dollars. 2 The Nuclear Regulatory Commission (NRC), which licenses nuclear power plants, requires plant owners to submit biennial reports on decommissioning funding that, among other things, provide financial assurance that enough funding will be available when the power plants are retired.

In 1999, we reported that the combined value of the owners' decommissioning trust fund accounts (as of the end of 1997) was 3 percent less than needed to ensure that enough funds would be available when the plants are retired. 3 In addition, we found that NRC had not established criteria for responding to unacceptable levels of financial assurance. In December 2001, we reported that transfers of plant licenses among companies stemming from economic deregulation and the restructuring of the electricity industry had, in many cases, increased assurances that new plant owners would have sufficient decommissioning funds when their plants are retired. 4 Nevertheless, in some instances, NRC's evaluation of the adequacy of funding arrangements was not rigorous enough to ensure that decommissioning funds would be adequate.

lRetirement means the permanent cessation of a plant's operation.

2Costs in 2000 present value dollars and are for decommissioning the plant site only and exclude costs for cleaning up nonradiological hazards and storing spent fuel.

3U.S. General Accounting Office, Nuclear Regulation: Better Oversight Needed to Ensure Accumulation oj Funds to Decommission Nuclear Power Plants, GAOIRCED-99-75 (Washington, D.C.: May 3, 1999).

4u.S. General Accounting Office, Nuclear Regulation: NRC's Assurances oj Decommissioning Funding during Utility Restructuring Could Be Improved, GAO-02-48 (Washington, D.C.: Dec. 3, 2001).

P,\ge 1 GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197 _214

In this context, you asked us to update our earlier findings on the adequacy of owners' decommissioning funds. Specifically, this report (1) assesses the extent to which nuclear plant owners are accumulating funds at sufficient rates to pay decommissioning costs when their plants' licenses expire and (2) evaluates NRC's analysis of the owners' 2001 biennial reports and its process for acting on reports that show unacceptable levels of financial assurance.

As part of our review, we collected data from the 2001 biennial reports on estimated decommissioning costs and actual decommissioning trust fund balances, generally as of December 31, 2000, for 122 nuclear power plants licensed by NRC. In addition, we surveyed the owners of the plants to determine how the trust fund balances were invested in 2000 and to identify the annual amounts that the owners had contributed to the trust funds in recent years. Eighty-two percent of the owners responded to our survey.5 Using an approach similar to that used for our 1999 report,6 we analyzed both the combined efforts of all owners to accumulate funds to decommission all of the nuclear plants and each individual owner's efforts to accumulate funds for decommissioning each of its plants. For our analysis, we estimated the most likely future values of key assumptions, such as decommissioning costs, earnings on the decommissioning funds' assets, and the operating life of each plant. To address the inherent uncertainty associated with forecasting outcomes many years into the future, we also analyzed the effect of using pessimistic and optimistic values for these key assumptions. To evaluate NRC's analysis of the biennial reports and its process for acting on reports that have not satisfied decommissioning funding assurance requirements, we reviewed NRC's guidelines and policies for analyzing these reports and interviewed NRC's officials about how they conducted their analysis. Appendix I provides more detail on the scope and methodology of our review.

Results in Brief Although the collective status of the owners' decommissioning fund accounts has improved since our last report, some individual owners are not on track to accumulate sufficient funds for decommissioning. Using 5We administered the survey to 110 owners. Since then, the ownership of some plants has changed and as a result, the total number of owners has declined. Our analysis assesses 222 trust funds held by 99 owners.

6GAOIRCED-99-75.

Page 2 GAO-04-32 Deconunissioning Nuclear Power Plants OAGI0000197 _215

our most likely economic assumptions, the combined value of the nuclear plant owners' trust funds in 2000-about $26.9 billion-was about 47 percent greater than needed at that point to ensure that sufficient funds will be available to cover the approximately $33 billion in estimated decommissioning costs when the plants are retired. This value contrasts with account balances that collectively were 3 percent below what was needed by the end of 1997. Overall industry results can be misleading, however. Because NRC does not allow owners to transfer funds from a trust fund with sufficient reserves to one without sufficient reserves, each individual owner must ensure that enough funds are available for decommissioning its particular plants. We found that 33 owners of all or parts of 42 different plants had accumulated less funds than we estimated they needed to have through 2000 to be on track to pay for eventual decommissioning. Under our most likely assumptions, these owners will have to increase the rates at which they accumulate funds to meet their future decommissioning obligations. Of the 33 owners, 26 provided contributions information for our survey. Of these 26 owners, only 8 appeared to be making up their shortfalls with recent increases in contributions to their trust funds.

NRC's analysis of the owners' 2001 biennial reports was not effective in identifying owners that might not be accumulating sufficient funds to cover their eventual decommissioning costs. In reviewing the 2001 reports, NRC reported that all owners appeared to be on track to have sufficient funds for decommissioning. In reaching this conclusion, NRC relied on the owners' future plans for fully funding their decommissioning obligations.

However, based on the actual contributions the owners recently made to their trust funds, we found that several owners could risk not meeting their financial obligations for decommissioning when these plants are retired. In addition, for the plants with more than one owner, NRC did not separately assess the status of each co-owner's trust funds against the co-owner's contractual obligation to fund decommissioning. Instead, NRC assessed whether the combined value of the trust funds for each plant as a whole was reasonable. Such an assessment for determining whether own 3rs are accumulating sufficient funds can produce misleading results because owners with more than sufficient funds can appear to balance out owners with less than sufficient funds, even though funds are generally not transferable among owners. Furthermore, NRC has not established criteria for responding to any unacceptable levels of financial assurance.

Accordingly, we are recommending that NRC develop and use an effective method for determining whether owners are accumulating funds at Page 3 GAO-04-3'; Decommissioning Nuclear Power Plants OAGI0000197 _216

sufficient rates and establish criteria for responding to unacceptable levels of financial assurance.

Background NRC's primary mission is to protect the public health and safety, and the environment, from the effects of radiation from nuclear plants, materials, and waste facilities. Because decommissioning a nuclear power plant is a safety issue, NRC has authority to ensure that owners are financially qualified to decommission these plants.

Of the 125 nuclear power plants that have been licensed to operate in the United States since 1959, 3 have been completely decommissioned. Of the remaining 122 plants, 104 currently have operating licenses (although 1 has not operated since 1985), 11 plants are in safe storage (SAFSTOR) awaiting active decommissiOning,7 and 7 plants are being decommissioned. At the time of our analysis, 43 plants were co-owned by different owners.

NRC regulations limit commercial nuclear power plant licenses to an initial 40 years of operation but also permit such licenses to be renewed for additional 20 years if NRC determines that the plant can be operated safely over the extended period. NRC has approved license renewals for 16 plants (as of August 20,2003).

In 1988, NRC began requiring owners to (1) certify that sufficient financial resOurces would be available when needed to decommission their nuclear power plants and (2) require them to make specific financial provisions for decommissioning. s In 1998, NRC revised its rules to require plant owners to report to the NRC by March 31, 1999, and at least once every 2 years thereafter on the status of decommissioning funding for each plant or proportional share of a plant they own. 9 Under NRC requirements, the 7SAFSTOR involves placing the stabilized and defueled facility in storage for a time followed by final decontamination and dismantlement, and license termination.

BNRC licenses include all co-owners as co-licensees; in general, one owner is authorized to operate the facility while the others are authorized only to h,we an ownership interest. Co-owners generally divide costs and output from their power plants by using a contractually defmed pro rata share standard. .

9u.S. Nuclear Regulatory Corrunission, Financial As.surance Requirements (Sept. 22, 1998),

63 Fed. Reg. 50465.

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owners can choose from one or more methods, including the following, to provide decommissioning fInancial assurance:

  • prepayment of cash or liquid assets into an account segregated from the owner's assets and outside the owner's administrative control;
  • establishment of an external sinking fund maintained through periodic deposit of funds into an account segregated from the owner's assets and outside the owner's administrative control;
  • use of a surety method (Le., surety bond, letter of credit, or line of credit payable to a decommissioning trust account), insurance, or other method that guarantees that decommissioning costs will be paid; and
  • for federal licensees, a statement of intent that decommissioning funds will be supplied when necessary.

In September 1998, NRC amended its regulations to restrict the use of the external sinking fund method in deregulated electricity markets. Prior to this time, essentially all nuclear plant owners chose this method for accumulating decommissioning funds. However, under the amended regulations, owners may rely on periodic deposits only to the extent that those deposits are guaranteed through regulated rates charged to consumers.

In conjunction with its amended regulations, NRC issued internal guidance, describing the process for reviewing the adequacy of a prospective owner's financial qualifIcations to safely operate and maintain its plant(s) and the owner's proposed methodes) for ensuring the availability of funds to eventually decommission the plant(s).lD The guidance outlines a method for evaluating the owner's fInancial plans for fully funding decommissioning costs. In addition, the guidance states that, except under certain conditions, the NRC reviewer should, when plants have multiple owners, separately evaluate each co-owner's funding schedule -for meeting its share of the plant's decommissioning costs.l1 IOU.S. Nuclear Regulatory Commission, Standard Review Plan on Power Reactor Licensee Financial Qualifications and Decommissioning Funding Assurance, NUREG 1577, Rev.

1, March 1999.

llUnder NRC's guidance, co-owners trust funds can be collectively evaluated when the lead licensee agrees to coordinate funding documentation and reporting for all the co-owners.

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Despite Industry-wide Using our most likely economic assumptions, the combined value of the nuclear power plant owners' decommissioning trust funds was about 47 Improvement, Some percent higher at the end of 2000 than necessary to ensure accumulation of Owners of Nuclear sufficient funds by the time the plants' licenses expire. This situation contrCl$ts favorably with the findings in our 1999 report, which indicated Power Plants Are Not that the industry was about 3 percent below where it needed to be at the Accumulating end of 1997 to ensure that enougl} funds would be available. However, Sufficient because owners are not allowed to transfer funds from a trust fund with sufficient reserves to one without sufficient reserves, overall industry Decommissioning sufficiency can be misleading. When we individually analyzed the owners' Funds trust funds, we found that 33 owners for several different plants had not accumulated funds at a rate that would be sufficient for eventual decommissioning.

Collectively the Nuclear Through 2000, the owners of 122 operating and retired nuclear power Power Industry Is on Pace plants collectively had accumulated about 47 percent more funds than would have been sufficient for eventually decommissioning, using our most to Accumulate More Than likely economic assumptions. Specifically, the owners had accumulated Sufficient Funds for about $26.9 billion-about $8.6 billion more than we estimate they needed Decommissioning at that point to ensure sufficient funds. This situation contrasts with the fmdings in our 1999 report, which indicated that the industry had accumulated about 3 percent less than the amount we estimated it should have accumulated by the end of 1997.

Using alternative economic assumptions changes these results. For example, under higher decommissioning costs and other more pessimistic assumptions, the analysis shows that the combined value of the owners' accounts would be only about 0.2 percent above the amount we estimate the industry should have collected by the end of 2000. (See app. II for our results using more optimistic assumptions.)

Page 6 GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197 _219

The collective improvement in the status of the owners' trust funds (under most likely assumptions) since our last report is due to three main factors.

First, all or parts of the estimated decommissioning costs were prepaid for 15 plants when they were sold to new owners. For example, the seller prepaid $396 million when the Pilgrim 1 nuclear plant was sold in 1998 for the plant's scheduled decommissioning in 2012. Second, for 16 other plants, NRC approved 20-year license renewals, which will provide additional time for the owners to make contributions and for the earnings to accumulate on the decommissioning fund balances. Third, owners earned a higher rate of return on their trust fund accounts than we projected in our 1999 report. For example, the average return onthe trust funds of owners who responded to our survey was about 8.5 percent12 (after-tax nominal return) per year, from 1998 through 2000, instead of the approximately 6.25 percent per year we had assumed. The higher return was a result of the stronger than expected performance of financial markets in the late 1990s. 13 Since that time, however, the economy has slowed and financial markets-equities in particular-have generally performed poorly.

Several Owners Are Not In contrast to the encouraging industry-wide results, when we analyzed the Accumulating Sufficient O"wners' trust fund accounts individually, we found that several owners Funds for Decommissioning were not accumulating funds at rates that would be sufficient to pay for decommissioning if continued until their plants are retired. Each owner has Their Plants a trust fund for each plant that it owns in whole or in part. For example, the Exelon Generation Company owns all or part of 20 different plants. For this analysis, we assessed the status of 222 trust funds for 122 plants owned in whole or part by 99 owners. As shown in table 1, using our most likely assumptions, 33 owners of all or parts of 42 different plants (50 trust funds) had accumulated less funds than needed through 2000 to be on track to pay for eventual decommissioning (see app. II for details).14 Thirteen of these 12Based on 72 owners who provided after-tax rates of return for 1998, 199b, and 2000. These owners' trust funds accounted for about 71 percent of the total trust funds in 2000.

13For 2000 (the only year for which we have data on fund allocations), on average, owners allocated their funds rather evenly between equities and fixed income assets (see app. I for details). Investment plans such as pension funds that invested more heavily in equities may have earned a greater overall return during this period.

14Some owners whom we estimate are below the benchmark have a parent company guarantee or other method to support financial assurance obligations. However, we did not evaluate the adequacy ofthese provisions. See app. II, table 4.

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plants were shut down before sufficient funds had been accumulated for decommissioning. Although the remaining 78 owners of all or parts of 93 plants (172 trust funds) had accumulated more funds than we estimate they needed to have at the end of 2000, funds are generally not transferable from owners who have more than sufficient reserves to other owners who have insufficient reserves. Under our most likely assumptions, the owners whom we estimate to be behind will have to increase the rates at which they accumulate funds to meet their eventual decommissioning f"mancial obligations.

For our analysis, we compared the trust fund balance that individual owners had accumulated for each plant by the end of 2000 with a "benchmark" amount of funds that we estimate they should have accumulated by that date. In setting the benchmark, we assumed that the owners would contribute increasing (but constant present-value) amounts annually to cover eventual decommissioning costs. 15 For example, at the end of 2000, an owner's decommissioning fund for a plant that had operated one-half of a 40-year license period (begun in 1980) should contain one-half of the present value of the estimated cost to decommission the owner's share of that plant in 2020. Although this benchmark is not the only wayan owner could accrue enough funds to pay future decommissioning costs, it provides both a common standard for comparisons among owners and, from an equity perspective among ratepayers in different years, a financially reasonable growing current-dollar funding stream overtime. Appehdix I describes our methodology in more detail.

150ur analysis simulates that the owners will increase their yearly future funding at the assumed after-tax rate of return on the investments of the funds, and that once in the fund, these yearly contributions will grow at this same rate. See appendix I for a discussion of our methodology.

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Table 1: Status of Individual Owners' Trust Fund Balances through 2000, Compared with Benchmark Trust Fund Balances, under Most Likely Assumptions' Plants currently Plants shut Status Trust funds Owners operating down Above benchmark balance 172 78 88 5 Below benchmark balance 50 33 29 13 b b Total 222

'Source: GAO analysis.

aMost likely assumptions include 20-year license renewals that have been approved by NRC for 16 plants as of August 20, 2003.

bNot applicable.

The status of each owner's fund balance at the end of 2000 is not, by itself, the only indicator of whether an owner will have enough funds for decommissioning. Whether the owner will accumulate the necessary funds also depends on the rate at which the owner contributes funds over the remaining operating life of the plant; by increasing their contribution rates, owners whose trust fund balances were below the benchmark level could still accumUlate the needed funds. Consequently, for the owners who provided contributions information to us, we also analyzed whether their recent contribution rates would put them on track to meet their decommissioning obligations. For this second analysis, we compared the average of the amounts contributed in 1999 and 2000 (cost-adjusted to 2000) with a benchmark amount equivalent tb the average yearly present value of the amounts the owners would have to accumUlate each year over the remaining life of their share of the plants to have enough decommissioning funds.

As table 2 shows, 28 owners with ownership shares in 44 different plants (50 trust funds) contributed less than the amounts we estimate they will need to meet their decommissioning obligations, under 0ur most likely assumptions.

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Table 2: Status of Individual Owners' Recent Trust Fund Contributions, Compared with Benchmark Trust Fund Contributions, under Most Likely Assumptions' Trust Plants currently Plants shut Status funds Owners operating down Above benchmark t::ontributions 122 58 76 5 Below benchmark contributions 50 28 34 10 c c Total 172b Source: GAO analysis.

"Most likely assumptions include 20-year license renewals that have been approved by NRC for 16 plants as of August 20, 2003.

bContributions not available for 50 other trust funds.

CNot applicable.

We compared the owners in table 1 with those in table 2 to see whether owners who are behind in balances were making up their shortfalls with recent increases in contributions. Of the 33 owners who we estimate had less than the benchmark balances through 2000, 26 owners of all or parts of 38 plants provided contributions information. Of these owners, only 8 owners of all or parts of 9 plants appeared to be making up their shortfalls with recent increases in contributions. By contrast, 20 owners with ownership interests in 31 plants recently contributed less to their trust funds than we estimate they needed to put them on track to meet their decommissioning obligations. 16 These results would change under alternative economic assumptions. For example, if economic cOhditions improve to those assumed in our optimistic scenario, of the 20 owners who were below the benchmark under most likely assumptions on both balances and contributions, 12 owners would still be below the benchmark in both categories, even under optimistic assumptions.

However, if economic conditions worsen to those in our pessimistic scenario, 34 owners who were above the benchmark under most likely assumptions on either balances or contributions would be below either of 16Some of these owners were also making up their shortfalls on other plants.

Page 10 GAO-04-32 Deconunissioning Nuclear Power Plants OAGI0000197 _223

these benchmarks under pessimistic assumptions. (See app. II for detailed r" results.)

NRC's Analysis Did Not NRC's analysis of the 2001 biennial decommissioning status reports was not effective in identifying owners that might not be accumulating funds at Effectively Determine sufficient rates to pay for decommissioning costs when their plants are Whether Each Owner permanently shut down. Although the NRC reported in 2001 that all owners Was Accumulating appeared to be on track to have sufficient funds for decommissioning,17 our analysis indicated that several owners might not be able to meet financial Sufficient obligations for decommissioning. NRC's analysis was not effective for two Decommissioning reasons. First, NRC overly relied on the owners' future funding plans, or on rate-setting authority decisions, in concluding that the owners were on Funds track to fully fund decommissioning. However, as discussed earlier, based on actual contributions the owners had recently made to their trust funds, several owners are at risk of not accumulating enough funds to pay for decommissioning. Second, for the plants with more than one owner, NRC did not separately assess the status of each co-owner's trust funds relative to the co-owner's contractual obligation to fund a certain portion of decommissioning. Instead, NRC combined funds on a plant-wide basis and assessed whether the combined trust funds would be sufficientfor decommissioning. Such an assessment method can produce misleading results because the owners with more than sufficient trust funds can appear to balance out those with insufficient trust funds. Furthermore, if NRC had identified an owner with unacceptable levels of financial assurance, it would not have had an explicit basis for acting to remedy potential funding deficiencies because it has not established criteria for responding to unacceptable levels of financial assurances.

NRC officials said that their oversight of the owners' decommissioning funds is an evolving process and that they intend to learn from their review of prior biennial reports and make changes to improve their evaluation of the 2003 biennial reports. However, they also said that any specific changes they are considering are pre decisional, and final decisions have not yet been made.

I7Summary oj Decommissioning Trust Funding Status Reports For Power Reactors, SECY-Ol:.o197, Nuclear Regulatory Commission, November 5,2001.

Page 11 GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197_224

NRC's Review Relied on According to NRC officials, in reviewing the 2001 biennial reports, they Owners' Future Plans for used a "straight-line" method to establish a screening criterion for Making Contributions assessing whether owners were accumulating decommissioning funds at sufficient rates. Specifically, NRC compared the amount of funds accumulated through 2000 (expressed as a percentage of the total estimated cost as of 2000 to decommission the plant) to the expended plant life (expressed as a percentage of the total number of years the plant will operate). Under this method, the owner of a plant that has operated for one-half of its operating life would be expected to have accumulated at least one-half ofthe plant's estimated decommissioning costs (that is, it would be collecting at or above the straight-line rate). NRC found that the owners of 64 out of 104 plants currently licensed to operate were collecting at the above a straight-line rate, and that the owners of the remaining 40 plants were collecting at the less than a straight-line rate. is On a plant-wide basis, NRC then reviewed the owners' "amortization" schedules for making future payments to fully fund decommissioning. The schedules, required as part of the biennial reports, consist of the remaining funds that the owners expect to collect each year over the remaining operating life of the plants. In estimating the funds to be collected, the owners may factor in the earnings expected from their trust fund investments. To account for such earnings, NRC regulations allow an owner to increase its trust fund balance by up to 2 percent per year (net of estimated cost escalation), or higher, if approved by its regulatory rate-setting authority, such as a state public utility commission. Because these owners' amortization schedules identified sufficient future funds to enable them to reach the target funding levels, NRC concluded that all licensees appear to be on track to fund decommissioning when their plants are retired.

However, relying on amortization schedules is problematic, in part because the actual amounts the owners contribute to their funds in the future could differ (that is, worsen) from their planned amounts if economic conditions or other factors change. NRC officials said that owners are not required by regulation to report their recent actual contributions to the trust funds, and NRC does not directly monitor whether the owners' actual contributions match their planned contributions. Consequently, NRC relies on the owners' amortization schedules as reported in the biennial reports.

IBO ne plant-Browns Ferry I-has a license but is currently not operating.

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Such reliance is also problematic because in developing their amortization schedules, the owners could use widely varying rates of return to project the earnings on their trust fund investments. For example, each of the three co-owners of the Duane Arnold Energy Center nuclear plant assumed a different rate, ranging from 2 to 7 percent (net of estimated cost escalation). Other factors being equal, the owners using the higher rates would need to collect fewer funds than the owner using the lower rate of return. While the return that each owner actually earns on its investments may be higher or lower than these rates, by relying on the owners' amortization schedules, NRC effectively used a different set of assumptions to evaluate the reasonableness of the trust funds accumulated by each owner. Consequently, NRC did not use a consistent "benchmark" in assessing the owners' trust funds. By contrast, we used historical trends and economic forecasts to develop assumptions about rates of earnings and other economic variables, applied the same assumptions in evaluating the adequacy of each owner's trust fund, and based expected future contributions on actual amounts contributed in recent years.

NRC's Analysis Focused on NRC's internal guidance for evaluating the biennial reports states that for the Adequacy of Trust plants having more than one owner, except in certain circumstances, each Funds on a Plant-by-Plant owner's amortization schedule should be separately assessed for its share of the plant's decommissioning costS. 19 For those plants that have co-Basis owners, NRC used the total amount of funds accumulated for the plant as a whole in its analysis. However, as we demonstrated with our industry-wide analysis, such an assessment for determining whether owners are accumulating sufficient funds can produce misleading results because owners with more than sufficient funds can appear to balance out owners with less than sufficient funds, even though funds are generally not transferable among owners.

19Requirement is waived if lead owner has agreed to coordinate funding documentation and reporting for all co-owners. In such cases, the guidance does not require a separate evaluation of each co-owner's amortization schedule.

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In explaining their approach, NRC officials said that the section of the guidance that calls for a separate evaluation of each owner's amortization schedule for its share of the plant is not compulsory. In addition, they said that they consider each owner's schedule to determine the total funds for the plant as a whole, but they believe that the same level of effort is not required for each individual trust fund balance unless there is a manifest reason to do so. They also stated that NRC's regulations do not prohibit each co-owner from being held responsible for decommissioning costs, even if these costs are more than the co-owner's individual ownership share. However, assessing the adequacy of decommissioning costs on a plant-wide basis is not consistent with the industry view, held by most plant owners, that each co-owner's responsibility should be limited to its pro rata share of decommissioning expenses and that NRC should not look to one owner to "bail out" another owner by imposing joint and several liability on all co-owners. 20 NRC has implicitly accepted this view and has incorporated it into policy to continue it. In a policy statement on deregulation,21 NRC stated that it will not impose decommissioning costs on co-owners in a manner inconsistent with their agreed-upon shares,22 except in highly unusual circumstances when required by public health and safety considerations and that it would not seek more than the pro rata shares from co-owners with de minimis ownership. Nevertheless, unless NRC separately evaluates each co-owner's trust fund, NRC might eventually need to look to require some owners to pay more than their share.

NRC Has Not Established While the NRC has conducted two reviews of the owners' biennial reports Criteria for Responding to to date,it has not established specific criteria for responding to any Unacceptable Levels of unacceptable levels of financial assurances that it fmds in its reviews of the owners' biennial reports. As we noted in our 1999 report, without such Financial Assurance criteria, NRC will not have a logical, coherent, and predictable plan of action if and when it encounters owners whose plants have inadequate financial assurance. NRC officials said that their oversight of the owners' 20Joint and several liability refers to the legal doctrine, which would allow holcling all or any one of the co-owners financially responsible for th8 default of arty co-owner.

21Final Policy Statement on the Restructuring and Economic Deregulation of the Electric Utility Industry, 62 Fed. Reg. 44071 (Aug. 19, 1997).

22Co-owners generally divide costs from their facilities using a contractually defined pro rata share.

l'age 14 GAO-04-32 Deconunissioning Nuclear Power Plants OAGI0000197_227

decommissioning funds is an evolving process, and they are learning from their prior reviews. However, they also said that any specific changes they are considering are predecisional and fmal decisions have not yet been made.

The absence of any specific criteria for acting on owners' decommissioning financial reports contrasts with the agency's practices for overseeing safety activities at nuclear power plants. According to NRC, its safety assessment process allows it to integrate information relevant to licensee safety performance, make objective conclusions regarding the information, take actions based on these conclusions in a predictable manner, and effectively communicate these actions to the licensees and to the public. Its oversight approach uses criteria for identifying and responding to levels of concern for nuclear plant performance. In determining its regulatory response, NRC uses an "Action Matrix" that provides for a range of actions commensurate with the significance of inspection findings and performance indicators. If the findings indicate that a plant is operating in a way that has little or no impact on safety, then NRC implements only its baseline inspection program. However, if the findings indicate that a plant is operating in a way that implies a greater degree of safety significance, NRC performs additional inspections and initiates other actions commensurate with the significance of the safety issues. A similar approach in the area of financial assurance for decommissioning would appear to offer the same benefits of objectivity and predictability that NRC has established in its safety oversight.

Conclusions Ensuring that nuclear power plant owners will have sufficient funds to clean up the radioactive waste hazard left behind when these plants are retired is essential for public health and safety. As our analysis identified, some owners may be at risk of not accumulating sufficient trust fUnds to pay for their share of decommissioning. NRC's analysis was not effective in identifying such owners because it relied too heavily on the owners' future funding plans without confirming that the plans were consistent with recent contributions. Moreover, it aggregated the owners' trust funds plant-wide instead of assessing whether each individual owner was on track to accumulate sufficient funds to pay for its share of decommissioning costs.

In addition, NRC has not explained to the owners and the public what it intends to do if and when it determines an owner is not accumulating sufficient trust funds. Without a more effective method for evaluating oWners' decommissioning trust funds, and without criteria for responding Page 15 GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197_228

to any unacceptable levels of financial assurance, NRC will not be able to effectively ensure that sufficient funds will be available when needed.

Recommendations for To ensure that owners are accumulating sufficient funds to decommission their nuclear power plants, we recommend that the Chairman, NRC, Executive Action develop an effective method for deterrn:in:ing whether owners are accumulating funds at sufficient rates to pay for decommissioning. For plants having more than one owner, this method ,should include separately evaluating whether each owner is accumulating funds at sufficient rates to pay for its share of decommissioning. We further recommend that the Chairman, NRC, establish criteria for taking action when NRC determines that an owner or co-owner is not accumulating decommissioning funds at a sufficient rate to pay for its share of the cost of decommissioning.

Agency Comments and We provided a draft of this report to NRC for its review and comment.

NRC's written comments, which are reproduced in appendix III, expressed Our Evaluation three main concerns regarding our report. First, NRC disagreed with our observation that its analyses of funding levels of the co-owners of a nuclear plant are inconsistent with its internal guidance. We revised the report to remove any inferences that NRC was not complying with its own guidance.

While clarifying this point, we remained convinced that NRC needs to do more to develop an effective method for assessing the adequacy of nuclear power plant owner's trust funds for decommissioning. NRC's current practice is to combine the trust funds for all co-owners of a nuclear plant, then assess whether the combined value of the trust funds is sufficient.

However, as our analysis indicates, NRC's practice of combining the trust funds of several owners for its assessment can produce misleading results because co-owners with more than sufficient funds can appear to balance .

out those with less than sufficient funds. As a practical matter, owners have a contractual agreement to pay their share of decommissioning costs, and owners generally cannot transfer funds from a trust fund with sufficient reserves to one without sufficient reserves. While NRC recognizes that private contractual arrangements among co-owners exist, the agency stated that it reserves the right, in highly unusual situations where adequate protection of public health and safety would be compromised if such action were not taken, to consider imposing joint and several liability on co-owners for decommissioning funding when one or more co-owners have d~faulted. Nonetheless, we believe that NRC should take a proactive approach, rather than simply wait until one or more co-Page 16 GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197_229

owners default on their decommissioning payment expenses, to ensure that sufficient funds will be available for decommissioning and that the adequate protection of public health and safety is not compromised. Such an approach, we believe, would involve developing an effective method that, among other things, separately evaluates the adequacy of each co-owner's trust fund.

Second, NRC disagreed with our view that some owners are not on track to accumulate sufficient funds for decommissioning. NRC's position is that it has a method for assessing the reasonableness of the owners' trust funds and that our method has not been reviewed and accepted by NRC. VVhile we recognize that NRC has neither reviewed nor accepted our method, our report identifies several limitations in NRC'smethod that raise doubts about whether the agency's method can effectively identify owners who might be at risk of not having sufficient funds for decommissioning. A particularly problematic aspect of this method is NRC's reliance on the owners' future funding plans to make up any shortfalls without verifying whether those plans are consistent with the owners' recent contributions.

We found some owners' actual contributions in 2001 were much less than what they stated in their 2001 biennial reports to NRC that they planned to contribute. For example, one owner contributed about $1.5 million (or 39 percent) less than the amount they told NRC that they planned to contribute. In addition, based on our analysis using actual contributions the owners had recently made to their trust funds, we found that 28 owners with ownership shares in 44 different plants contributed less than the amounts we estimate they will need to make over the remaining operating life of their plants to meet their decommissioning obligations. Therefore, we continue to believe that some owners are not on track to accumulate sufficient funds to pay for decommissioning.

Finally, NRC disagreed with our view that it should establish criteria for responding to owners with unacceptable levels of financial assurance. NRC stated that its practice is to review the owners' plans on a case-by-case basis, engage in discussions with state regul'ltors, and issue orders as necessary and appropriate. Since NRC has never identified an owner with unacceptable levels of fInancial assurance, it has never implemented this practice. We believe that NRC should take a more proactive approach to providing owners and the public with a more complete understanding of NRC's expectations of how it will hold owners who are not accumulating sufficient funds accountable. As stated in our draft report, this lack of criteria is in contrast to NRC's practices in overseeing safety issues at nuclear plants, where the NRC uses an "Action Matrix" that provides for a Page 17 GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197_230

range of actions commensurate with the significance of safety inspection findings and performance indicators. In the area of financial assurance, a similar approach could involve monitoring the trust fund deposits of those owners who NRC determines are accumulating insufficient funds to verify that the deposits are consistent with the owners' funding plans.

We conducted our review from June 2001 to September 2003 in accordance with generally accepted goverrunent auditing standards. Unless you publicly announce the contents of this report earlier, we plan no further distribllttQn until 30 days from the report date. At that time, we will send copies of this report to the appropriate congressional committees; the Chairman, NRC; Director, Office of Management and Budget; and other interested parties. We will also make copies available to others upon request. In addition, this report will be available at no charge on the GAO Web site at http://www.gao.gov. If you or your staff have any questions, please call me at (202) 512-6877. Key contributors to this report are listed in appendix IV.

Sincerely yours, Jim Wells Director, Natural Resources and Envirorunent Page 18 GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197 _231

Appendix II Detailed Results of Our Analysis of the Decommissioning 'Irust Funds (Continued From Previous Page)

Baseline (most likely) scenario Ownership Adequacy of trust Adequacy of recent share of plant fund balances as of trust fund Plant name Owner (percent) end of 2000 contributions*

C Farley 2 Alabama Power Co. 100 ++ ++++

Fermi 1d Detroit Edison Co. 100 Fermi 2 Detroit Edison Co. 100 +++ ++++

FitzPatrick Entergy Nuclear Operations, Inc. 100 +++ ++ ++e Fort Calhoun h Omaha Public Power District 100 + ++++

Ginnah Rochester Gas & Electric Corp. 100 Grand Gulf 1 South Mississippi Electric Power 10 Grand Gulf 1 System Energy Resources, Inc. 90 + ++++

Haddam Nec~ Connecticut Yankee Atomic Power 100 + ++++e Co.

Harris 1 North Carolina Eastern Municipal* 16.17 +

Harris 1 Progress Energy Carolinas, Inc. 83.83 + +

Hatch 1b e", 9 City of Dalton (Georgia) 2.2 ++++

Hatch 1b Georgia Power Co. 50.1 +++ ++++

Hatch 1b Municipal Electric Authority of 17.7 +++ ++++

Georgia Hatch 1b Oglethorpe Power Co. 30 +++ ++++

Hatch 2b e,f!

City of Dalton (Georgia) 2.2 ++++

Hatch 2b Georgia Power Co. 50.1 ++++ ++++

Hatch 2b Municipal Electric Authority of 17.7 ++++ ++++

Georgia Hatch 2b Oglethorpe Power Co. 30 +++ ++

Hope Creek 1 PSEG Nuclear, LLC 100 ++++i Humboldt Bay 3d Pacific Gas & Electric Co. 100 + ++++e Indian Point 1d, f Entergy Nuclear Operations, Inc. 100 Indian Point 2 Entergy Nuclear Operations, Inc. 100 + ++++

Indian Point 3 Entergy Nuclear Operations, Inc. 100 +++ ++++e Kewaunee Wisconsin Power & Light 41 ++++ ++++e Kewaunee Wisconsin Public Service 59 ++++i + + + +e,i Corporation LaCrossed, f Dairyland Power Cooperative 100 LaSalle County 1 Exelon Generation Co., LLC 100 +++

LaSalle County 2 Exelon Generation Co., LLC 100 +++ +++

Limerick 1i Exelon Generation Co., LLC 100 Limerick 2i Exelon Generation Co., LLC 100 Maine Yankeed Maine Yankee Atomic Power Co. 100 Page 31 GAO-04-32 Decommissioning Nuclear Power Plants OAGI0000197_232

Appendix II Detailed Results of Our Analysis of the Decommissioning Trust Funds (Continued From Previous Page)

Baseline (most likely) scenario Ownership Adequacy of trust Adequacy of recent share of plant fund balances as of trust fund Plant name Owner (percent) end of 2000 contributions' Vogtle 2 Oglethorpe Power Co. 30 Waterford 3 Entergy Louisiana, Inc. 100 +

Watts Bar 1 Tennessee Valley Authority 100 ++++

Wolf Creek 1 Kansas City Power & Light Co. 47 +

Wolf Creek 1 Kansas Electric Power 6 Cooperative Wolf Creek 1 Kansas Gas & Electric Co. 47 + +

Yankee Rowed Yankee Atomic Electric Co. 100 ++++

Zion 1d Exelon Generation Co., LLC 100 Exelon Generation Co., LLC 100 Legend

+ means that fund balance/recent contributions were 0 to 25 percent more than benchmark.

++ means that fund balance/recent contributions were 26 to 50 percent more than benchmark.

+++ means that fund balancelrecent contributions were 51 to 100 percent more than benchmark.

++++ means that fund balancelrecent contributions were 101 percent or more than benchmark.

_ means that fund balancelrecent contributions were 0.1 to 25 percent less than benchmark.

__ means that fund balance/recent contributions were 26 to 50 percent less than benchmark.

___ means that fund balance/recent contributions were 51 to 100 perce[1t less than benchmark.

Source: GAO analysis, "Adequacy of recent contributions is based on responses to our survey. The percentages are more, or less, than the benchmark, meaning the owner has contributed more, or less, on average for 1999 and 2000 (cost adjusted to 2000) than the annual average of the present value amounts required in each subsequent year until its plant is retired.

bPlant's operating license extended for 20 years, "Plants whose owners are expected to apply for 20-year license renewals by December 2003.

dPlant has permanently shut down.

"Trust fund balance exceeds present value of estimated decommissioning costs.

fO wner has, as of March 31, 2003, an additional method to support financial assurance obligations (e.g., parent company guarantee, statement of intent).

gContributions data are not available.

hPlants whose owners have applied for 20-year license renewals, as of August 20, 2003.

lncludes balances and/or contributions from a previous owner's biennial report and/or responses to our survey.

iO wner had, as of March 31, 2001, an additional method to support financial assurance obligations (e.g., parent company guarantee, statement of intent).

kUability is for decommissioning share and not ownership share.

Page 36 GAO.04-32 Deco~issioning Nuclear Power Plants OAGI0000197 233

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