ML021210645

Corporation - 2001 Annual Financial Report

ML021210645
Person / Time
Site:	Vermont Yankee
Issue date:	04/29/2002
From:	Sen G Vermont Yankee
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
-RFPFR, BVY 02-28
Download: ML021210645 (33)

Text

VERMONT YANKEE NUCLEAR POWER CORPORATION 185 OLD FERRY ROAD, PO BOX 7002, BRATYLEBORO, VT 05302-7002 (802) 257-5271 April 29, 2002 BVY 02-28 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555

Subject:

Vermont Yankee Nuclear Power Station License No. DPR-28 (Docket No. 50-271)

Vermont Yankee Nuclear Power Corporation - 2001 Annual Financial Report In accordance with IOCFR50.71(b), attached is a copy of Vermont Yankee Nuclear Power Corporation's 2001 annual financial report including certified financial statements.

We trust that the information provided is adequate; however, should you have questions or require additional information, please contact Mr. John J. Boguslawski at (802) 258-4136.

Sincerely, VERMONT YANKEE NUCLEAR POWER CORPORATION 7Ž21 Licensing Manager Attachment cc: USNRC Region I Administrator USNRC Resident Inspector - VYNPS USNRC Project Manager - VYNPS Vermont Department of Public Service 0

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SUMMARY

OF VERMONT YANKEE COMMITMENTS BVY NO.: 02-28 Vermont Yankee Nuclear Power Corporation - 2001 Annual Financial Report The following table identifies commitments made in this document by Vermont Yankee.

Any other actions discussed in the submittal represent intended or planned actions by Vermont Yankee. They are described to the NRC for the NRC's information and are not regulatory commitments. Please notify the Licensing Manager of any questions regarding this document or any associated commitments.

COMMITMENT COMMITTED DATE OR "OUTAGE" None N/A

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Vermont Yankee Nuclear Power Corporation 2001 Annual Report I

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Vermont Yankee 2001 Annual Report Table of Contents President's Letter 2 Description of Business 3 Comparative Highlights 4 Common Stock Ownership 4 Financial Review 5 Report of Independent Public Accountants 6 Statements of Income and Retained Earnings 7 Balance Sheets Assets 8 Capitalization and Liabilities 9 Statements of Cash Flows 10 Notes to Financial Statements 11 Board of Directors 29 Officers 29 Vermont Yankee Nuclear Power Corporation 185 Old Ferry Road P. 0. Box 7002 Brattleboro, Vermont 05302-7002 www.vermontyankee.com

President's Letter Vermont Yankee began the year 2001 in a maelstrom of sale activity. In February, after having spent much of the previous year hearing testimony on the proposed

$23.5 million sale to AmerGen, the Vermont Public Service Board formally rejected the AmerGen sale proposal as being too low. Following an auction process adminis tered by JPMorgan, Vermont Yankee and the Entergy Nuclear Corporation signed a purchase agreement to sell the plant for $180 million on August 15. During the auction process, news teams from The New York Times, The Washington Post, Chicago Tribune, ABC "World News" and others focused on Vermont Yankee as a prime example of a well-run nuclear plant aggressively being sought for acquisition by several major nuclear operators.

On April 27, Vermont Yankee shut down for a scheduled refueling outage, concluding the most productive cycle in the company's history, having generated more than 6.3 billion kilowatt hours and achieving a 101.8% cycle reliability. At the beginning of the outage, VY performed a noble metals chemical injection as the first phase of a hydrogen water chemistry project. The project is an important factor in the long-term operating strategy of the plant. Other significant outage projects included turbine valve inspections and refurbishing, repairs to the #2 feedwater heaters, a comprehensive internal inspection of the main and auxiliary transformers, and successful refueling. When VY rejoined the New England power grid on May 20, it concluded the best refueling/maintenance outage in company history - 23 days, 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, 1 minute - shorter by 11 days than any similar outage. Focus on integrated planning and scheduling was a major contributor to the accomplishment.

VY's commitment to safety and quality was reflected in achievement of all six outage goals encompassing safety, quality, duration, radiation exposure and cost.

Throughout the auction process, successful negotiation of a three-year union contract, the tragic events of September 11 and the heightened security that fol lowed, VY employees remained focused on the safe, efficient operation of the plant.

The plant's year-end capacity factor was the best ever for a year with a refueling outage and its fifth best overall. The plant was available 93% of the time and a new maximum generation record for a year with a refueling outage was set by generat ing 4,171,120 net megawatts electric. In addition, a new record was set for the lowest average personnel radiation exposure in a year with a refueling outage. All in all, 2001 was a banner year for Vermont Yankee.

On a personal note, 2001 was my last full year at Vermont Yankee. Although I will continue to serve as president and chief executive officer through the expected closing of the Entergy sale in July, I formally retired as a Vermont Yankee employee effective March 15, 2002. I have greatly enjoyed the past six years, and it has truly been a privilege to work with VY's board of directors and the men and women whose dedication to excellence has made Vermont Yankee one of the finest plants in the U.S. nuclear fleet. We have accomplished a lot together since 1996 and I will always have great memories of my years here in Vermont. I wish all of you the very best in the years to come.

Ross P Barkhurst

Description of Business Vermont Yankee Nuclear Power remaining owners), eight of which are Corporation ("the Company") was the Sponsoring utilities that are entitled incorporated under the laws of the State and obligated to purchase the output of of Vermont on August 4, 1966. The the Plant.

Company was formed by a group of New England utilities to construct and Under the terms of certain Power operate a nuclear-powered generating Contracts and Additional Power Con plant ("the Plant"). tracts (collectively, the "Power Con tracts"), each Sponsor is obligated to pay The Plant commenced commercial Vermont Yankee monthly, regardless of operation on November 30, 1972, and the Plant's operating level, or whether except during maintenance and refuel or not it is operating, an amount equal to ing outages, has been in full operation its entitlement percentage of Vermont since that time. The Plant is licensed by Yankee's total fuel costs, operating the Nuclear Regulatory Commission to expenses, decommissioning costs and an operate until March 21, 2012. allowed return on equity. Also, under the terms of the Capital Funds Agree Located on the west bank of the ments, the Sponsors are committed to Connecticut River in Vernon, Vermont, make funds available for changes or the facility has a gross maximum de replacements needed to maintain or pendable capacity of approximately 535 restore operation of the Plant or to megawatts. The common stock of obtain or maintain licenses necessary for Vermont Yankee is owned by twelve its operation. The names of the Spon utilities (on January 16, 2002, the Com sors and their respective entitlement pany repurchased the shares of the four percentages of Vermont Yankee's non-Sponsor owners, leaving eight capacity and output are as follows:

Entitlement Sponsor Percentage Central Vermont Public Service Corporation 35.0%

New England Power Company 22.5 Green Mountain Power Corporation 20.0 The Connecticut Light and Power Company 9.5 Central Maine Power Company 4.0 Public Service Company of New Hampshire 4.0 Cambridge Electric Light Company 2.5 Western Massachusetts Electric Company 2.5 100.0%

See Note I to the Financial Statements for discussion on the possible sale of the Plant and related assets and liabilities.

Comparative Highlights 2001 2000  % Change Financial (Dollars in millions):

Operating revenues $178.8 $178.3 0.3 Net income 6.1 6.6 (7.0)

Total assets 723.8 707.0 2.4 Average number of shares of common stock outstanding (thousands) 392.5 392.5 0.0 Per Share of Common Stock:

Basic earnings per common share $15.59 $16.77 (7.0)

Dividends paid per common share 15.96 15.77 1.2 Book value per common share (year-end) 138.03 138.40 (0.3)

Operating:

Kilowatt-hour sales (billions) 4.17 4.55 (8.3)

Cost per kilowatt-hour (cents) 4.29 3.92 9.4 Connnon Stock Ownershlip at 12/31/01 Percentage Shares Stock Owner Owned Owned Central Vermont Public Service Corporation 31.30% 122,653 New England Power Company 22.5 88,203 Green Mountain Power Corporation 17.9 70,088 The Connecticut Light and Power Company 9.5 37,242 Central Maine Power Company 4.0 15,681 Public Service Company of New Hampshire 4.0 15,681 Burlington Electric Department* 3.6 14,301 Cambridge Electric Light Company 2.5 9,801 Western Massachusetts Electric Company 2.5 9,800 Vermont Electric Cooperative, Inc.* 1.0 4,213 Washington Electric Cooperative, Inc.* 0.6 2,431 Village of Lyndonville Electric Department* 0.6 2,387 100.0% 392,481

• On JanuarNy 16, 2002, the Company repurchased the shares of these non-Sponsor owners.

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Financial Review Operating revenues of the Company Operating revenues increased in are billed and received from its Spon 2001 from 2000 by $0.5 million, or 0.3%,

sors based on the terms of the Power primarily due to higher maintenance Contracts. Under those contracts, the and other operating expenses associated Sponsors are severally required to pay with the refueling and maintenance the Company an amount equal to their outage in 2001. There was no refueling respective entitlement share of the and maintenance shutdown in 2000.

Company's total fuel and operating Several other items largely offset the expenses, return on net unit investment impact of the 2001 cost of the refueling and an amount designated to meet and maintenance shutdown.

anticipated decommissioning costs at the end of the nuclear electric generat Nuclear fuel expense decreased by ing plant's useful life. $3.4 million in 2001 from 2000 as a result of less generation in 2001 due to the The Company continued its run of refueling outage, and a favorable sales operating success in 2001. The plant tax decision involving nuclear fuel.

produced 4,171,120 net megawatt hours Decommissioning expense decreased by of electricity during the year corre $4.5 million as a result of a revised sponding to an overall capacity factor collection schedule included in a settle of 93.4% (net maximum design capabil ment agreement approved by the ity). Both results are records for a year Federal Energy Regulatory Commission with a refueling outage. This perfor (FERC) in 2001. The FERC approved mance comes on the heels of the record settlement agreement also included a setting performance for a year without provision allowing the deferral of costs a refueling outage in 2000 when the associated with the potential sale of the plant produced a record 4,548,065 net plant. While all costs incurred during megawatt hours of electricity corre 2001 related to the sale were deferred, sponding to a record capacity factor of operating costs for 2000 included 101.5%. approximately $3.0 million of sale related expenditures.

The plant shuts down to refuel approximately every 18 months. The Other income, net of associated last refueling prior to 2001 was com income tax, increased by $1.1 million in pleted in December 1999. When the 2001 from 2000 due to higher after-tax plant shutdown to refuel in April 2001, earnings on the fixed income invest it marked the end of the most produc ments in the Spent Fuel Disposal Trust.

tive operating cycle in the company's Total interest expense decreased by $2.6 history with more than 6.3 billion million in 2001 from 2000 as a result of kilowatt hours of electricity produced the lower prevailing interest rates in and cycle reliability in excess of 100%. 2001. This is particularly noteworthy for the DOE spent fuel disposal obligation The refueling outage itself was where the applicable interest rate record setting. The well planned and dropped from 6.257% at the end of 2000 executed outage lasted a total of just to 2.364% at the end of 2001.

over 23 days, or about 11 days shorter than the prior best for a similar outage. Net income, computed in accordance It was also the lowest cost outage in with the Company's formula rate more than 15 years, finishing nearly $3 approved by the Federal Energy Regula million under budget. tory Commission ("FERC") decreased by approximately $0.5 million in 2001 from 2000.

Report of Independent Publie Accountants Thie Stockholders and Board of Directors of Vermont Xankee Nuclear Power Corporation:

We have audited the accompanying balance sheets of Vermont Yankee Nuclear Power Corporation as of December 31, 2001 and 2000, and the related statements of income and retained earnings and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Vermont Yankee Nuclear Power Corpora tion as of December 31, 2001 and 2000, and the results of its operations and cash flows for each of the three years in the period ended December 31, 2001, in confor mity with generally accepted accounting principles in the United States.

Arthur Andersen L.L.P.

Boston, Massachusetts January 24, 2002 Statements of Income and Retained Earnings Years ended December 31, 2001 2000 1999 (In thousands except per share data)

Operating revenues $178,840 $178,294 $208,812 Operating expenses:

Nuclear fuel expense (NOTES 5 and 9) 17,527 20,907 18,834 Other operating expense 79,699 79,565 94,694 Maintenance expense 32,180 19,724 40,232 Depreciation and amortization expense 14,751 14,349 15,973 Decommissioning expense (NOTES 3 and 4) 11,764 16,245 12,559 Taxes on income (NOTE 10) 2,227 2,031 1,903 Property and other taxes 8,709 9,329 9,685 Total operating expenses 166,857 162,150 193,880 Operating income 11,983 16,144 14,932 Other income (expense):

Net earnings on decommissioning trust (NOTES 4 and 6) 28,704 11,271 8,864 Decommissioning expense (NOTE 4) (28,704) (11,271) (8,864)

Earnings on spent fuel disposal trust (NOTE 6) 8,214 6,255 4,748 Taxes on other income (NOTE 10) (2,839) (2,257) (1,669)

Other, net (447) (169) (116)

Total other income 4,928 3,829 2,963 Income before interest expense 16,911 19,973 17,895 Interest expense:

Interest on long-term debt 6,330 6,835 6,736 Interest on spent fuel disposal fee obligation (NOTE 9) 4,717 6,577 4,953 Allowance for borrowed funds used during construction (255) (22) (265)

Total interest expense 10,792 13,390 11,424 Net income 6,119 6,583 6,471 Retained earnings at beginning of year 1,224 830 1,546 7,343 7,413 8,017 Dividends declared 6,265 6,189 7,187 Retained earnings at end of year $1,078 $1,224 $830 Average number of shares outstanding 392 392 392 Net income per share of common stock outstanding $15.59 $16.77 $16.49 Dividends per share of common stock outstanding $15.96 $15.77 $18.31 See accompanying notes to financial statements.

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Balance Sheets Assets

])eceinber 31, 2001 2000 (Dollars in thousands)

Utility plant:

Electric plant, at cost (NOTE 7): $430,020 S420,640 Less atcumulated depreci ation 308,302 295,773 121,718 124,867 Construc tion work in progress 5,034 8,121 Net electric plant 126,752 132,988 Nuclear fuel, at cost:

Assemblies in reactor 69,148 69,016 Assemblies in process 708 12,914 Spent fuel 386,030 372,101 455,886 454,031 Less atumrnulated amortization of burned nuclear fuel 425,961 414,532 29,925 39,499 Less act umulated amortization of final core nuclear fuel 12,773 11,888 Net nutclear fuel 17,152 27,611 Net utility plant 143,904 160,599 Long-term investments, at fair market value:

Decommnissioning trust (NOTES 4, 6, 8 and 15) 297,059 281,704 Spent fuel disposal trust (NOTES 6, 8 and 9) 116,514 109,239 Total long-term investments 413,573 390,943 Current assets:

Cash and cash equivalents 4 775 Accounts retceivable from sponsors 13,848 16,074 Other atcounts receivable 2,022 1,729 Materials and supplies, net of amortization 16,421 15,762 Prepaid expenses 3,049 2,847 Total cucrent assets 35,344 37,187 Deferred charges:

Deferred decommissioning costs (NOTES 4 and 15) 31,811 25,407 Deferred low-level waste facility expenses (NOTES 5 and 14) 25,673 25,830 Accuimulated deferred income taxes (NOTE 10) 41,307 37,012 Deferred design basis dotCumentation costs (NOTE 5) 16,395 17,807 Deferred DOE enrichment site decontamination and decommissioning fee (NOTE 5) 7,409 8,473 Net unamortized loss on reacquired debt 1,425 1,606 Other deferred charges (NOTES 3, 5 and 6) 6,974 2,120 Total deferred charges 130,994 118,255

$723,815 $706,984 See accoipaii *wnuotes to f!iaoicial state)'icits.

Balance Sheets Capitalization and Liabilities Deceiber 31, 2001 2000 (Dollars in thousands)

Capitalization:

Common stock equity:

Common stock, $100 par value; authorized 400,100 shares; issued 400,014 shares of which 7,533 are held in Treasury $40,001 $40,001 Additional paid-in capital 14,226 14,226 Treasury stock (7,533 shares at cost) (1,130) (1,130)

Retained earnings 1,078 1,224 Total common stock equity 54,175 54,321 Long-term obligations, net (NOTES 7 and 8) 54,173 59,591 Total capitalization 108,348 113,912 Commitments and contingencies (NOTES 4, 13 and 14)

Spent fuel disposal fee and accrued interest (NOTES 8 and 9) 120,068 115,351 Current liabilities:

Accounts payable 2,086 3,185 Accrued expenses (Note 2) 10,728 13,403 Accrued low-level waste expenses (NOTES 3 and 14) 4,541 4,858 Accrued taxes 1,629 2,360 Accrued interest 1,419 2,218 Current maturities of long-term debt (NOTE 7) 5,418 36,393 Revolving credit agreement debt (NOTE 7) 27,540 Other current liabilities 10,721 9,739 Total current liabilities 64,082 72,156 Deferred credits and other liabilities:

Accrued decommissioning costs (NOTE 4) 349,903 321,409 Accumulated deferred income taxes (NOTE 10) 34,023 36,561 Accrued low-level waste facility expenses (NOTES 5 and 14) 23,070 23,226 Accrued DOE enrichment site decontamination and decommissioning fee (NOTE 5) 5,157 6,280 Accrued employee benefits (NOTE 12) 12,654 10,885 Net regulatory tax liability (NOTE 10) 3,641 3,982 Accumulated deferred investment tax credits 2,869 3,222 Total deferred credits and other liabilities 431,317 405,565

$723,815 $706,984 See accompanying notes to financial statements.

Statements of Cash Flows Yicar ended I)ceinicir 31, 2001 2000 1999 (Dollars in thousands)

Cash flows from operating activities:

Net income $6,119 S6,583 $6,471 Adjustments to reconcile net in ome to net Cash provided by operating attivities:

Amortiiation of nuclear fuel 13,753 15,423 13,845 Depreciation and amortization 14,751 14,349 15,973 DeCoimissioning expense 11,764 16,245 12,559 Deferred Lax expense (7,175) (8,692) (6,424)

Amortliation of deferred investment tax credits (353) (666) (545)

Nuclear fuel disposal fee interest accrual 4,717 6,577 4,953 Interest and dividends on spent fuel disposal trust (7,275) (7,714) (3,383)

(Increase) decrease in accounts receivable 1,933 150 (1,090)

(Increase) decrease in prepaid expense (203) 311 683 (Increase) decrease in materials and supplies inventory (659) 981 (593)

Increase (decrease) in accounts payable and accrued liabilities (3,109) (12,526) 15,347 Intrease (decrease) in interest and taxes payable (1,529) 1,403 (710)

Other 5,851 2,596 (1,728)

Total adjustments 32,466 28,437 48,887 Net cash provided by operating activities 38,585 35,020 55,358 Cash flows from investing activities:

Elettrit plant additions and retirements (6,923) (5,292) (10,686)

Nuclear fuel additions (3,294) (12,914) (20,785)

Payments to decommissioning trust (14,022) (16,454) (12,898)

Net tash used for investing activities (24,239) (34,660) (44,369)

Cash flows from financing activities:

Dividend payments (6,264) (6,189) (7,187)

Series I Bonds Sinking Fund Payments (5,418) (5,418) (5,418)

Payments of long-term obligations (423,709) (323,050) (328,000)

Borrowings under long-term agreements 420,274 327,102 337,493 Net tash used for financing activities (15,117) (7,555) (3,112)

Net increase (decrease) in cash and cash equivalents (771) (7,195) 7,877 Cash and tash equivalents at beginning of year 775 7,970 93 Cash and (ash equivalents at end of year $4 $775 $7,970 See accoloIjoaliyilgnotes to financial statemtn'ts.

Notes to Financial Statements NOTE 1. Nature of Bushiess and Possible Sale of Assets Vermont Yankee Nuclear Power Corporation ("the Company") was incorporated under the laws of the State of Vermont on August 4, 1966. The Company was formed by a group of New England utilities for the purpose of constructing and operating a nuclear-powered electric generating plant ("the Plant"). As of December 31, 2001, the Company's common stock was owned by twelve utilities, eight of which are the Sponsoring utilities that are entitled and obligated to purchase the output of the Plant. On January 16, 2002, the Company repurchased the shares of the four non-Sponsor owners. Under the terms of certain Power Contracts and Additional Power Contracts (collectively, the "Power Contracts"), each Sponsor is obligated to pay Vermont Yankee monthly, regardless of the Plant's operating level, or whether or not it is operating, an amount equal to its entitlement percentage of Vermont Yankee's total fuel costs, operating expenses, decommissioning costs and an allowed return on equity. Also, under the terms of the Capital Funds Agreements, the Sponsors are committed to make funds available for changes or replacements needed to maintain or restore operation of the Plant or to obtain or maintain licenses necessary for its operation.

The names of the sponsoring utilities and their respective entitlement percentages of Vermont Yankee's capacity and output are as follows: Central Vermont Public Service Corporation with 35.0%, New En gland Power Company with 22.5%, Green Mountain Power Corporation with 20.0%, The Connecticut Light and Power Company with 9.5%, Central Maine Power Company with 4.0%, Public Service Com pany of New Hampshire with 4.0%, Cambridge Electric Light Company with 2.5%, and Western Massa chusetts Electric Company with 2.5% ("the Sponsors").

The Plant commenced commercial operation on November 30, 1972, and except during maintenance and refueling outages, has been in full operation since that time. The Plant has a gross maximum depend able capacity of approximately 535 megawatts and is licensed by the Nuclear Regulatory Commission to operate until March 21, 2012, though there is no assurance that it will do so. Other nuclear plants, includ ing some in the Northeast with similar ownership structures, have been shut down prior to the end of their license life for economic reasons. The Federal Energy Regulatory Commission, which regulates the rates charged by the Company under the Power Contracts, has allowed plants that are shut down prema turely for economic reasons to recover the as yet unrecovered costs at the time of the shut down, if it is determined that the decision to shut down was prudent. These unrecovered costs include undepreciated plant and unfunded nuclear decommissioning costs. The Company prepares periodic economic studies.

Study results to date have determined that it is economical to continue to operate the plant.

In November 1999 the Company had executed an agreement to sell the Plant and related assets and liabilities, including the liability to decommission the Plant, to AmerGen Energy Company, LLC (AmerGen). The agreement was subject to several conditions including approvals or specific rulings by various federal and state regulatory and tax authorities.

On February 14, 2001, the Vermont Public Service Board (PSB) ruled against the sale to AmerGen. The ruling to dismiss the petition stated that the dismissal would benefit ratepayers and promote the general good of the state and that the proposed sale was of less value than is otherwise available on the market today. The decision was based in part on the fact that, during PSB proceedings in 2000, three other parties expressed interest in buying the plant. One of the three submitted a bid to the PSB, backed by a bond, with terms that were better than those of the AmerGen agreement and the other two asked to participate if an auction of the Plant were conducted.

On August 15, 2001, following an auction process conducted by J.P. Morgan Securities, Inc. as agent for the Company, a Purchase and Sale Agreement (PSA) was executed with Entergy Nuclear Vermont Yankee, LLC (ENVY). Under the PSA, ENVY will pay a purchase price of $180 million, subject to closing adjustments, and will assume the Company's obligation to operate and decommission the Plant in exchange for the transfer of ownership of the Plant and related assets (including the decommissioning fund) and liabilities to ENVY. The PSA also contemplates that the Company will purchase from ENVY 100% of the output of the Plant (based on the Plant's current capacity) after closing through March 21, 2012 pursuant to a Power Purchase Agreement (PPA) with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour. The PPA prices are subject to a "low market adjuster" beginning in 2005 that would provide for lower power purchase prices if the market price of power is significantly less than the PPA price. The Company will resell power purchased under the PPA to the sponsoring utilities pursuant to the Power Contracts (as amended for this arrangement).

The above agreements are subject to several conditions, including approvals or specific rulings by the Nuclear Regulatory Commission, the Federal Energy Regulatory Commission, the PSB and the Internal Revenue Service. As such, execution of the Agreements does not provide assurance that the sale will occur.

If the sale does occur, proceeds are expec ted to be sufficient to retire all of the Company's current debt including, its First Mortgage Bonds and borrowings under its Secured Credit Agreement. No material gain or loss is expected to be realized as a result of the sale. The Company expects that if there is a loss on the sale, it will be recorded as a regulatory asset recoverable from the Sponsors over the current remaining license life of the plant under the Power Contracts as amended.

Due to the threat of a possible terrorist attack on important infrastructure sites within the United States following the events of September 11, 2001, nuclear plants, including the nuclear plant owned by the Company, have operated under a heightened level of security. This has resulted in a marginal increase in the plant's operating costs which may continue for the foreseeable future. The Company does not believe that the additional costs will have an adverse effect on the results of operations due to its current and future ability to recover costs from the Sponsors.

NOTE 2. Suunniary of Signifieant Aecounting Policies (a) Regulations and Operations The Company is subject to regulations prescribed by the Federal Energy Regulatory Commission ("FERC"),

and the Public Service Board of the State of Vermont with respect to accounting and other matters. The Company is also subject to regulation by' the Nuclear Regulatory Commission ("NRC") for nuclear plant licensing and safety, and by federal and state agencies for environmental matters such as air quality, water quality and land use.

The Company recognizes revenue pursuant to the terms of the Power Contracts and Additional Power Contrac ts filed with the FERC. The Sponsors, a group of eight New England utilities, are severally obligated to pay the Company each month their entitlement percentage of amounts equal to the Company's total fuel costs and operating expenses, plus an allowed return on equity (11.0% since August 1, 1994). Such contracts also obligate the Sponsors to make decommissioning payments through the end of the Plant's service life and completion of the decommissioning of the Plant. All Sponsors are commit ted to such payments regardless of the Plant's operating level or whether the Plant is out of service during the period.

Under the terms of the Capital Funds Agreements, the Sponsors are committed, subject to obtaining necessary regulatory authorizatiions, to make funds available to obtain or maintain licenses necessary to keep the Plant in operation.

(b) Depreciation and Maintenance Electric plant is being depreciated on the straight-line method at rates designed to fully depreciate all depreciable properties over the lesser of estimated useful lives or the Plant's remaining NRC license life, which extends to March 21, 2012. Depreciation expense was equivalent to overall effective rates of 3.08%,

3.08% and 3.59% for the years 2001, 2000 and 1999, respectively.

The cost of additions, including replacements and betterments of units of property, is charged to electric plant. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property are charged to maintenance expense. The cost of property retired, plus removal or disposal costs, less salvage, is charged to accumulated depreciation.

(c) Amortization of Nuclear Fuel The cost of nuclear fuel is amortized to expense based on the rate of burn-up of the individual assem blies comprising the total core. The Company also provides for the costs of disposing of spent nuclear fuel at rates specified by the United States Department of Energy ("DOE") under a contract for disposal between the Company and DOE.

In conformity with rates authorized by the FERC, the Company amortizes to expense on a straight-line basis the estimated costs of the final unspent nuclear fuel core, which is expected to be in place at the expiration of the Plant's operating license.

(d) Amortization of Materials and Supplies The Company amortizes to expense a formula amount designed to fully amortize the cost of the material and supplies inventory that is expected to be on hand at the expiration of the Plant's operating license.

(e) Long-term Funds The Company accounts for its investments in long-term funds at fair value as required by Statement of Financial Accounting Standards No. 115. See NOTE 6 for further discussion of this accounting method.

(f) Amortization of Loss on Reacquired Debt The difference between the amount paid upon reacquisition of any debt security and the face value thereof, adjusted for any unamortized premium or discount, related unamortized debt expense and reacquisition costs, applicable to the reacquired debt, is deferred by the Company and amortized to expense on a straight-line basis over the remaining life of the new debt issuance consistent with the rate treatment authorized by the FERC.

(g) Allowance for Funds Used During Construction Allowance for funds used during construction ("AFUDC") is the estimated cost of funds used to finance the Company's construction work in progress and nuclear fuel in-process which is not recovered from the Sponsors through current revenues. The allowance is not realized in cash currently, but under the Power Contracts, the allowance is recovered in cash over the Plant's service life or as nuclear fuel is used through higher revenues associated with higher depreciation and amortization expense.

AFUDC was capitalized at overall effective rates of 2.45%, 6.29% and 6.29%, for 2001, 2000 and 1999, respectively, using the gross rate method.

(h) Decommissioning The Company is accruing the estimated costs of decommissioning its Plant over the Plant's remaining NRC license life. Any amendments to these estimated costs are accounted for prospectively. See NOTE 4 for further detail.

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(i) Taxes on Income The Company accounts for taxes on income under the liability method. See NOTE 10 for a further discussion of the accounting for taxes on other income.

Investment tax credits have been deferred and are being amortized to income over the lives of the related assets.

(j) Cash Equivalents For purposes of the Statements of Cash Flows, the Company considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents.

(k) Accrued Expenses Accrued Expenses represents the Company's best estimate of costs incurred for which no invoice has been received by, the Balance Sheet date. The amount shown for 2001 includes 51.4 million in capital project costs and 59.3 million in operating and maintenance costs. The comparable amounts for 2000 were

$1.9 million and 511.5 million, respectivelv.

(1) Reclassifications The Company makes reclassifications of information presented in prior period financial statements to conform with the current period when considered significant.

(m)Earnings per Common Share Basic earnings per common share have been computed by dividing earnings available to common stock bx' the weighted average number of shares outstanding during the year. Diluted earnings per conmman share have not been disclosed as they do not differ from basic earnings per share.

(n) Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

NOTIEI 3. FEIiC Rate Case Matters On June 22, 2000, a group of muinic ipal utilities that purchase power produced by the Plant from certain of the Sponsors filed a complaint at the FERC seeking refunds of amounts they had paid in the past for decommissioning and challenging the Company's immediate recovery of costs associated with net oitiiting and documenting a proposed sale to AmerGen, claiming that those costs should be absorbed by the Company or deferred for reco very through amortization. The FERC set the complaint for investiga tion and hearing. A settlement agreement was filed with the FERC on June 25, 2001, in which the parties agreed that: (1) Vermont Yankee would make refunds, with interest, to the Sponsors and certain wholesale customers of the Sponsors, for transaction costs associated with the proposed sale of the Plant to AmerGen; (2) Vermont Yankee and affected Sponsors could recover such refunds through amortization, with a return; (3) Vermont Yankee was authorized to rectover transaction costs associated with future pursuits to sell the Plant through amortization, with a return; (4) Vermont Yankee would prospectively reduce its annual decommissioning charges to 511.4 million annually until the financial closing of any new sale transaction or the implementation of superseding rates; and (5) Vermont Yankee would no longer reserve for certain low-level radioactive waste disposal costs through its formula rates, instead those costs would be recovered on an as-incurred basis or as decommissioning casts. The FERC approved the settlement agreement effec tive August 1, 2001. In accordance with the provisions of the settlement agreement, Vermont Yankee made refunds of sale costs, as account credits, totaling S0.8 million.

NOTE 1. Deeoimnissionhig The Company accrues estimated decommissioning costs for its nuclear plant over its remaining NRC licensed life. The accrual is currently based on a 1994 site study by an independent engineering firm and a settlement agreement approved by the FERC for rates effective July 1, 2001. The study assumes decom missioning will be accomplished by the prompt removal and dismantling method (DECON) which requires that radioactive materials be removed from the plant site and all buildings and facilities be dismantled immediately after shutdown. The study estimates that approximately seven years would be required to dismantle the Plant at shutdown, remove non-fuel wastes and restore the site, and that spent fuel would be stored on-site in a dry fuel storage facility until 2025. The FERC approved settlement agreement allowed $312.7 million, in 1993 dollars, as the estimated decommissioning cost. This allowed amount is used to compute the Company's liability and billings to the Sponsors. Based on the agreement's assumed cost escalation rate of 5.4% per annum through 2000 and 4.25% thereafter, the estimated current cost of decommissioning is $471.1 million and, at the expiration of the Plant's operating license in March 2012, is approximately $721.8 million. The present value of the pro rata portion of decommissioning costs recorded to date is $349.9 million. The actual decommissioning costs could vary from the above estimates because of changes in the assumed date of decommissioning, changes in regula tory requirements, changes in technology, and changes in labor, materials and equipment.

On August 15, 2001, the Company executed a Purchase and Sale Agreement (PSA) with the intent to sell the Plant and related assets and liabilities, including the liability to decommission the Plant, to Entergy Nuclear Vermont Yankee, LLC (ENVY). The sale of the plant, as contemplated, would result in the transfer of responsibility for decommissioning the plant to the new owner and may make future decommissioning collections unnecessary after the dosing under the PSA. See NOTE 1 for further discussion.

Billings to Sponsors for estimated decommissioning costs commenced during 1983, at which time the Company recorded a deferred charge for the present value of decommissioning costs applicable to operations of the Plant for prior periods. Current period decommissioning costs not funded through billings to Sponsors or earnings on decommissioning trust assets are also deferred. At December 31, 2001, deferred decommissioning costs were $31.8 million. These deferred costs are amortized to expense as they are funded over the remaining life of the Company's operating license.

Cash received from Sponsors for plant decommissioning costs is deposited directly into the Vermont Yankee Decommissioning Trust in either the Qualified Fund (i.e., amounts currently deductible pursuant to the IRS regulations) or the Nonqualified Fund (i.e., collections pursuant to FERC authorization which are not currently deductible). Earnings on the Decommissioning Trust assets are recorded in other income, with an equal and offsetting amount representing the current period decommissioning cost funded by such earnings reflected as decommissioning expense. On December 31, 2001, the fair market value of the Decommissioning Trust was $297.1 million including pre-tax unrealized appreciation of $28.2 million, and funds held by the Trust were primarily invested in corporate bonds, government securities and equities. See NOTE 6 for further detail.

The staff of the Securities and Exchange Commission has questioned certain current accounting practices of the electric utility industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board ("FASB") has issued SFAS 143, which establishes accounting and disclosure for asset retirement costs, including the decommissioning of nuclear power plants. The Company is currently evaluating the effects of the new standard. However, when the Company's current accounting practice is changed as required by the new standard in 2003, the present value of the full estimated cost of decommissioning will be recorded as a liability (rather than a pro rata portion), with an increase in the recorded cost of the Plant. The Company does not believe the changes would have an adverse effect on the results of operations due to its current and future ability to recover costs from the Sponsors.

NOTE 5. I)eferred Charges, Credits and Other Liabilities In October 1992, Congress passed the Energy Policy Act of 1992. The Act requires, among other Lhings, that certain utilities help pay for the cleanup of DOE's enrichment facilities over a fifteen year period. The Company's annual fee is based on its historical share of enrichment services provided by DOE and is indexed to inflation. The fees are not adjusted for subsequent business as DOE's cost of sales now includes a decontamination and decommissioning component. The Act stipulates that the annual fee shall be fully recoverable in rates in the same manner as other fuel costs.

In 2001, the Company paid the tenth of the fifteen annual charges. As of December 31, 2001, the Company had recognized a current accrued liability of $1.3 million for the fee payment expected to be made in 2002, a non-current liability of S55.2 million for the expected four annual fee payments that are due subsequent to 2002, and a corresponding regulatory asset of 87.4 million which represents the total amount to be included in future billings to the Sponsors under the Power Contracts.

In 1994, the states of Vermont, Maine and Texas each ratified legislation to join a low-level radioactive waste disposal tompact for the purpose of disposing of lowl-hevl radioactive waste in the state of Texas.

The Company has recorded a non-current liability of 523.1 million to recognize the $27.5 million compact fund requirements less amounts on deposit with the State of Vermont and a torresponding deferred debit of $25.7 million which represents the total amount to be included in future billings to the Sponsors under the Power Contracts. The Compact was ratified by the U.S. Congress in 1998, however to date, no site has been licensed. See NOTE 14 for further detail.

During 2001, Vermont Yankee completed Design Basis Documentation, a project undertaken to incorporate all design documentation into a tentralized system. The objective was to ensure that Vermont Yankee maintains its safety margins in connection with any plant modifications. The project created a set of design basis documents which enable more efficient systematic problem solving, maintenance, and system overview in support of the safe, tost effective, long term operation of the Plant. The Company received FERC approval in 1996 to recognize deferred charges for these unrecovered study costs and amortize the Costs through billings to Sponsors over the remaining license life of the Plant. As of Decem ber 31, 2001, the Company had recorded deferred charges of 816.4 million, net of amortization related to this initiative.

In 2001, FERC approved a settlement agreement between the Company and intervening parties that included, among other things, a settlement on the regulatory treatment of costs incurred in conjunction with initiatives to sell the plant and related assets and liabilities. The agreement provided for the refund of a portion of the costs incurred in pursuit of the then terminated AmerGen transaction, and the authori zaLion for the Company and the affected Sponsors to retover this refund through amortization, with a return. In addition, the settlement agreement provided for the deferral of all costs associated with the pursuit of a new agreement for the sale of the plant, and for the ret overy of these costs, through amortiza tion with a return, commencing with the financial closing of the new transaction. If no new transaction is consummated, the Company will have to apply to the FERC for the recovery of such costs. As of Decem ber 31, 2001, the Company had recorded deferred charges of $3.6 million, net of amortization relative to the sale initiatives.

NOTE 6. Liong-term tIvestinents The Company accounts for its investments in certain debt or equity' securities by classifying each such security as either trading, available-for-sale or held-to-maturity. Both trading and available-for-sale securities mtist be reflected on the balance sheet at their aggregate fair values. Held-to-maturity securi ties are reflected on the balance sheet at amortized cost.

The Company tclassifies securities in the Decommissioning Trust as available-for-sale. As of Decem ber 31, 2001, the Decommissioning Trust had net unrealized gains of $28.2 million which reduce deferred decommissioning costs because the Company will not realize the gains, rather, the gains will be used to reduce future billings to Sponsors.

The Company also classifies securities held in the Spent Fuel Disposal Trust as available-for-sale. As of December 31, 2001, the reported Trust balance includes net unrealized gains of $1.7 million with a corre sponding adjustment reflected in Other Deferred Charges.

The cost and estimated market value of long-term investments at December 31, are as follows (Dollars in thousands):

2001 2000 Market Market Cost Value Cost Value Decommissioning Trust:

US Treasury obligations $107,319 $112,064 $108,400 $113,753 Municipal obligations 57,853 58,902 36,068 37,044 Corporate bonds 32,776 33,244 31,139 31,208 Stocks 64,647 86,634 40,639 80,870 Accrued interest and money market funds 6,215 6,215 18,829 18,829 268,810 297,059 235,075 281,704 Spent Fuel Disposal Trust:

US Treasury obligations 43,193 44,186 81,827 82,517 Municipal obligations 51,297 51,646 8,911 8,994 Corporate bonds 17,455 17,786 14,245 14,496 Accrued interest and money market funds 2,896 2,896 3,232 3,232 114,841 116,514 108,215 109,239 Total long-term investments $383,651 $413,573 $343,290 $390,943 Pursuant to the Company's arrangements with its Sponsors, the difference between market value and cost of the Decommissioning Trust has been recorded as a decrease to deferred decommissioning costs.

The Company's Power Contracts with its Sponsors provide for full recovery of decommissioning costs and any excess or shortage in the fund, including those resulting from investment performance, will be refunded to or collected from Sponsors.

The Company has entered into certain derivative contracts to hedge the total return on its nuclear decommissioning trust fund. As required by SFAS 133, these derivative instruments are recorded at fair value on the balance sheet with any change in the value recorded as an increase or decrease to deferred decommissioning costs, consistent with the treatment of all gains and losses on the decommissioning trust fund. Unrealized gains recorded as reductions to deferred decommissioning costs as of December 31, 2001 and 2000 were $28.2 million and $46.6 million, respectively.

The securities included in the Spent Fuel Disposal Trust represent funds invested by the Company for which the earnings and principal will be used to pay the DOE fee for spent fuel discharged prior to April 7, 1983. See NOTE 9 for further details. Although the Company collected this fee from its Sponsors in rates, it has elected to defer payment as permitted by the contract with DOE. Since any realized gains (losses) have the effect of reducing (increasing) billing to customers, the Company has included the difference between cost and market value of the Spent Fuel Disposal Trust as a decrease to Other Deferred Charges.

At December 31, gross unrealized gains and losses pertaining to the long-term investment securnties in the Decommissioning Trust and the Spent Fuel Disposal Trust were as follows (Dollars in thousands):

2001 2000 Unrealized gains on US Treasury obligations $5,738 $6,209 Unrealized losses on US Treasury obligations - (166)

Unrealized gains on municipal obligations 1,398 1,221 Unrealized losses on municipal obligations (162)

Unrealized gains on corporate bonds 863 469 Unrealized losses on corporate bonds (64) (149)

Unrealized gains on stocks 22,706 40,575 Unrealized losses on stocks (719) (344)

$29,922 $47,653 For the years ended December 31, gross realized gains and losses pertaining to the long-term invest ment securities were as follows (Dollars in thousands):

2001 2001 2000 2000 Total Sale Gross Realized Total Sale Gross Realized Proceeds Gain Loss Proceeds Gain Loss Decommissioning $255,941 $22,358 $(1,600) S202,879 $4,555 $(3,702)

Spent fuel disposal $169,746 $2,259 $(1,230) 5188,061 5591 $(409)

Maturities of short-term obligations, bonds and notes (face amount) at December 31, are as follows (Dollars in thousands):

2001 2001 2000 2000 Decommissioning Disposal Fee Decommissioning Disposal Fee Trust Defeasance Trust Trust Defeasance Trust Within one year $ 1,814 $33,680 S $37,255 One to five years 52,688 61,155 36,963 52,631 Five to ten years 65,983 9,489 49,443 4,346 Over ten years 73,481 5,509 85,85() 15,908

$193,966 $109,833 $172,256 $110,140 NOTE 7. I)ebt Obligations A summary of debt obligations at December 31, is as follows (Dollars in thousands):

2001 2000 Current maturities of long-term debt:

First mortgage bonds: Series I sinking fund requirement $ 5,418 S 5,418 Commercial Paper - Eurodollar Credit Agreement - 30,975 Total debt maturing within one year $5,418 $36,393 Long-term obligations (excluding current maturities):

First mortgage bonds: Series I 6.48% due 2009 $54,173 $559,591 The first mortgage bonds are issued under, have the terms and provisions set forth in, and are secured by an Indenture of Mortgage dated as of October 1, 1970 between the Company and the Trustee, as modified and supplemented by thirteen supplemental indentures. All bonds are secured by a first lien on

-is-

utility plant, exclusive of nuclear fuel, and a pledge of the Power Contracts and the Additional Power Contracts (except for fuel payments) and the Capital Funds Agreements with Sponsors.

In November 1993, the Company issued $75.8 million of Series 1, first mortgage bonds stated to mature on November 1, 2009. The Company applied the proceeds of the bond issuance principally to retire the remaining Series D, Series E, Series F, Series G and Series H first mortgage bonds including call premiums totaling $3.7 million. Annual cash sinking fund requirements for the Series I first mortgage bonds of $5.4 million began in November 1999. The Company has classified the sinking fund require ments of November 2002 as a current liability at December 31, 2001.

The Company's $75.0 million Eurodollar Credit Agreement expired on August 13, 2001 and was not renewed. In its place, the Company signed a one-year $50.0 million Secured Credit Agreement which expires on August 12, 2002. Under this agreement, payment is secured by a pledge of nuclear fuel pay ments under the Power Contracts and Capital Funds Agreements and by a second mortgage on the Company's generating facility. The Company expects that, if necessary, either the current agreement will be extended or another credit agreement will be put in place by the expiration date. Since neither has occurred by the issuance of these financial statements, the Company has classified this debt as a current liability at December 31, 2001. The Company issued commercial paper under the Eurodollar Credit Agreement with weighted average interest rates of 5.24% for 2001 and 6.39% for 2000 and borrowed funds under the Secured Credit Agreement with a weighted average interest rate of 3.81% for 2001.

Borrowings under the Secured Credit Agreement were $27.0 million at December 31, 2001 and were $31.0 million under the Eurodollar Credit Agreement at December 31, 2000.

The Company also had available lines of credit of $5.5 million at December 31, 2001 and $3.0 million at December 31, 2000. The maximum amount of short-term borrowings outstanding at any month-end was approximately $3.0 million for 2001 and $3.0 million for 2000. The average daily amount of short-term borrowings outstanding was approximately $0.5 million for 2001 and $0.3 million for 2000 with weighted average interest rates of 6.88% in 2001 and 7.93% in 2000. The Company had borrowings of $0.5 million under the line of credit as of December 31, 2001.

NOTE S. Diselosuwes About the Fair Value of Finaneial Instrinnents The carrying amounts for cash and temporary investments, trade receivables, accounts receivable from Sponsors, accounts payable, accrued liabilities and debt maturing within one year approximate their fair values because of the short maturity of these instruments. Long term funds are carried at fair market value which are estimated based on quoted market prices for these or similar investments. The fair values of each of the Company's long-term debt instruments are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities.

The estimated fair value of the Company's financial instruments as of December 31, are summarized as follows (Dollars in thousands):

2001 2000 Cost Estimated Cost Estimated Amount Fair Value Amount Fair Value Decommissioning Trust $268,810 $297,059 $235,075 $281,704 Spent Fuel Disposal Trust 114,841 116,514 108,215 109,239 Long-term debt 54,173 54,647 59,591 57,261 Spent fuel disposal fee and accrued interest 120,068 120,068 115,351 115,351 Fair value estimates are made at a specific point in time, based on relevant market information and information about the financial instrument. These estimates are subjective in nature and involve uncer tainties and matters of significant judgment and therefore cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

N)TiE 9. spent Fuel I)isposal Under the Nuclear Waste Policy Act of 1982, 1)OE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. The Company, as required by that Act, has signed a contract with 1)O1' to provide for the disposal of spent nuclear fuel and high-level radioactive waste from its nuclear generation station beginning no later than January 31, 1998.

'This delivery schedule has not been met and is expected to be delayed significantly. It is not certain when DOE w ill accept spent nuclear fuel and high-level radioactive waste from the Company and other owners of nuclear power plants, although DOE has stated that the earliest would be 2010. These delays by DOE have caused the Company to consider other costly alternatives for storing high-level waste.

The Company has primary responsibility for the interim storage of its spent nuclear fuel. The plant is currently able to operate with the ability to discharge the entire reactor core to the spent fuel storage pool through the year 2008 refueling outage. The Company is also investigating other options for additional storage capacity beyond the year 2008.

Various legal proceedings have been filed by the owners and operators of nu,clear power plants and by states and state regulatoiy agencies against DOE and the federal government to enforce the DOE's obligation to dispose of spent nuclear fuel and seeking damages resulting from DOE's breach of those obligations. In addition, legislation has been introduced in Congress over the past several years to assure that DOE carries out its obligations and to protect the funds paid to the government by utilities and their customers that were intended to pay for the disposal of utilities' spent nuclear fuel.

In Jul, 1996, the U.S. Court of Appeals for the IDistrict of Columbia Circuit ruled that DOE had an unconditional obligation to begin disposing of the utilities' spent nuclear fuel by January 31, 1998, and that the absence of a DOE interim storage facility did not excuse DOE from that obligation. In November, 1997, the same Court in ruling on a petition briought by thirty six utilities, including the Company reaf firmed the 1996 ruling but declined to order DOE to accept spent nuclear fuel, saving that the utilities had another potentially adequate remedyciunder their D101 contracts.

After the January 1998 deadline passed Without compliance by DOE' with its contractual and statutory obliaation, forty one utilities, including the Company, and sixty states and state regulatory commissions, petitioned the same Court to compel DOE1to act. In orders issued in May 1998 and July 1998, the Court declined to order DOE to act and again directed the utilities to pursue relief in accordance with their DOE contracts. In November 1998, the U.S. Supreme Court denied petitions by the Government and by the states and state agencies to review the lower Court's decisions.

Beginning in February 1998, a series of lawsurits have been filed with the U.S. Court of Federal Claims seeking damages from the Government for DOE's breach of its obligation to begin disposing of the utilities' spent fuel by the 1998 deadline. In October and November 1998, the Court granted summary judgment in favor of Yankee Atomic Electric Company, Connecticut Yankee Power Company and Maine Yankee Atomic Power Company (collectively "Yankee") as to DOE's liability for its breach of the 1998 obligation- The Court rejected the Government's argu ment that the utilities must first bring claims for damages to the DOE Contracting Officer. In April 1999, another judge of the U.S. Court of Federal Claims, in a case brought by Northern States Power Company, reached the opposite conclusion, ruling that the utility could not sue for breach of contract damages in the Court but must rather submit a claim for equitable adjustment with the DOE Contracting Officer.

On August 31, 2000, the U.S. Court of Appeals for the Federal Circuit decided appeals from both Yankee and Northern States cases, ruling that the utilities were entitled to sue in the U.S. Court of Federal Claims for breach of contract damages and need not first submit equitable adjustment claims to the DOE Contracting Officer.

A "discovery judge" has been designated in all except the Yankee cases and one other case and discovery is underway in all except the latter case, although the discovery judge suspended discovery in November 2001, and then revoked the suspension in January 2002. The Government has moved to reinstate the suspension.

In all the cases, the Government has filed motions for partial summary judgment regarding the rate of spent nuclear fuel acceptance and on the issue of Greater Than Class C Radioactive Waste. The Govern ment has also filed motions to dismiss takings and illegal exaction claims in those cases which include such claims. In the Yankee cases, the Government is currently obligated to submit its pretrial filings by February 8, 2002. The Yankee plaintiffs submitted their pretrial filings in June 1999.

On July 19, 2000, DOE entered into a settlement agreement with PECO Energy Company ("PECO")

allowing PECO to take credits against payments into the Nuclear Waste Fund to offset certain spent fuel storage costs which PECO had incurred because of DOE's failure to meet its 1998 obligation. Alabama Power Company and a number of other utilities have initiated a challenge in the U.S. Court of Appeals for the Eleventh Circuit to DOE's attempt to use Nuclear Waste Fund credits to offset potential spent fuel damages claims.

The DOE contract obligates the Company to pay a one-time fee of approximately $39.3 million for disposal costs for all spent fuel discharged through April 6, 1983, and a fee payable quarterly equal to one mill per kilowatt-hour of nuclear generated and sold electricity after April 6, 1983. Although the $39.3 million for the one-time fee has been collected from the Sponsors in rates, the Company has elected to defer payment to DOE as permitted by the DOE contract. The fee plus accrued interest must be paid no later than the first delivery of spent fuel to DOE. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly. Through 2001, the Company has accumu lated $116.5 million in an irrevocable trust to be used exclusively for meeting this obligation ($120.1 million including accrued interest) at some future date, provided the DOE complies with the terms of the aforementioned contract.

NOTE 10. Taxes on Income The Company uses the liability method of accounting for income taxes. The liability method accounts for deferred income taxes by applying enacted statutory rates in effect at the balance sheet date to differ ences between the book basis and the tax basis of assets and liabilities ("temporary differences").

For certain items, the Company's allowed rates have recognized income tax expense on a different method. As a result, the Company has recognized net liabilities to Sponsors of $3.6 million as of Decem ber 31, 2001 and $4.0 million as of December 31, 2000 representing taxes collected from them in excess of amounts that would have been recorded under the liability method. These amounts will be systematically returned to Sponsors by reducing future power bills.

The components of income tax expense for the years ended December 31, are as follows (Dollars in thousands):

2001 2000 1999 Taxes on operating income:

Current federal income tax $7,358 $8,740 56,841 Deferred federal income tax (6,421) (8,099) (5,494)

Current state income tax 2,397 2,649 2,031 Deferred state income tax (754) (593) (930)

Investment tax credit adjustment (353) (666) (545) 2,227 2,031 1,903 Taxes on other income:

Current federal income tax 2,389 2,104 1,606 Current state income tax 450 153 63 2,839 2,257 1,669 Total income taxes $5,066 $4,288 $3,572 The Company's effective income tax rates differed from the federal statutory rate of 35% for the years ended Dec ember 31, as foll ows:

2001 2000 1999 Federal statutory rate 35.0% 35.0% 35.0%

State incomne taxes, net of federal income tax benefit 12.2 13.2 7.5 Investment credit (3.2) (6.1) (5.4)

Book depreciLation in excess of tax basis 1.3 1.3 2.1 Flowback of excess deferred taxes (2.0) (2.1) (2.6)

Other 2.0 (1.9) (1.0) 45.3% 39.4% 35.6%

The significant components of deferred tax expense for the years ended December 31, are as follows (Dollars in thousands):

2001 2000 1999 Decomnis.sioning expense not currently deductible $ (6,120) 5(3,233) S(1,844)

Tax depreciation (under) over financial statement depreciation (2,503) (2,157) (3,226)

Asset sale 1 ost deduction over (under) financmial sttemenlt expense 2,612 (810) (1,388)

Tax fuel amortization (under) over financial statement amortization (1,221) (936) 1,038 Tax loss on reacquisition of debt (under) over financial staLement expense (75) (75) (75)

Pension expense deducLion (under) over financial statement expense (375) (252) (627)

Postemployment benefits deduction over (under) financial a statement expense 111 23 99 Materials and supplies deduction over (under) financial statement expense 81 (227) (124)

Low-level waste deduction over (under) financial statement expense 135 (156) 327 Flowback and other change in excess deferred taxes (230) (223) (264)

Other, net 410 (646) (340)

$(7,175) $(8,692) S(6,424)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, are presented below (Dollars in thousands):

2001 2000 Deferred tax assets:

Accumulated amortization of final nuclear core $5,280 $4,914 Nuclear decommissioning liability 24,173 16,944 2,565 2,830 Regulatory liabilities 1,186 1,332 Accumulated deferred investment credit 3,316 3,127 Accumulated amortization of materials and supplies 5,590 5,326 Pension and retiree benefit liabilities 1,877 2,012 Accrued low-level waste disposal costs 2,968 4,755 Other Total gross deferred tax assets 46,955 41,240 Less valuation allowance (5,648) (4,228)

Net deferred tax assets 41,307 37,012 Deferred tax liabilities:

Plant and equipment (30,383) (33,507)

(3,640) (3,054)

Other Total gross deferred tax liabilities (34,023) (36,561)

$7,284 $451 Net deferred tax asset (liability) refunds The valuation allowance is primarily the result of a provision in Vermont tax law which limits resulting from carrybacks of net operating losses.

NOTE 11. Supplemental Cash Flow Information The following information supplements the cash flow information provided in the Statements of Cash Flows (Dollars in thousands):

Cash paid during the year for: 2001 2000 1999 Interest (net of amount capitalized) $5,649 $6,362 $6,350 Income taxes $16,941 $14,627 $13,174 NOTE 12. Pension, Post Retirement and Other Benefit Plans all The Company has two qualified defined benefit pension plans which together cover substantially plans are based on final average earnings, integrated of its employees. The benefits provided under these pension plan with Social Security benefits. The Company also has a supplemental unfunded nonqualified earnings. In addition, the Company has two for certain employees providing benefits based on final and life insurance benefits to retired employees postretirement welfare benefit plans providing healthcare and their covered spouses.

The Company has two severance plans which together provide substantially all of its employees with benefits continuing income and other benefits for a period of time in the event of a layoff. The individual employee's final base salary and years of service with the provided under these plans are based on the these plans are event driven and no such event has oc Company. Since the benefits provided under curred, the plans have had no impact on the results of operations or financial position of the Company.

The following tables reconcile the beginning and ending benefit obligation balances for the plans:

Pension plan benefits (aggregated) 2001 2000 Beginning of year benefit obligation $36,169 $30,143 Service cost 1,651 1,639 Interest cost 2,652 2,350 Actuarial loss (gain) (1,167) 2,885 Disbursements (951) (848)

Plan Amendments 2,458 End of year benefit obligation $40,812 $36,169 Postretirement welfare plan benefits (aggregated) 2001 2000 Beginning of year benefit obligation $14,358 $10,661 Service cost 1,225 902 Interest cost 1,107 833 Participant contributions 15 11 Actuarial loss (gain) (166) 2,279 Disbursements (332) (328)

Plan Amendments End of year benefit obligation $16,207 $14,358 The following Lables reconcile the beginning and ending fair value of assets for the plans:

Pension plan assets (aggregated) 2001 2000 Beginning of year fair value of assets $33,763 $34,554 Actual return on assets 904 (17)

Company contributions 302 74 Disbursements (961) (848)

End of year fair value of assets $34,008 $33,763 Postretirement welfare plan assets (aggregated) 2001 2000 Beginning of year fair value of assets $13,668 $12,721 Actual return on assets (163) 843 Company t ontributions 424 420 Disbursements (net) (332) (316)

End of year fair value of assets $13,597 $13,668 Plan assets consist primarily of cash equivalent funds, fixed income securities and equity securities.

The following tables reconcile the funded status of the plans as of December 31:

Pension plans (aggregated) 2001 2000 Projected benefit obligation (PBO) $(40,812) $(36,169)

Fair value of assets (FVA) 34,008 33,763 PBO (in ex ess of) less than FVA (6,804) (2,406)

Unrecognized prior service cost 3,058 968 Unrecognized net transition obligation 521 584 Unrecognized actuarial loss (gain) (7,661) (9,112)

Net amount recognized $00,886) $(9,966)

Amounts recognized in the balance sheets:

$(10,886) $(9,966)

Accrued benefit liability (574) (155)

Additional minimmum liability 574 155 Intangible asset

$(10,886) $(9,966)

Net amount recognized 2001 2000 Postretirement welfare plans (aggregated)

$(16,207) $(14,358)

Accumulated postretirement benefit obligation (APBO) 13,597 13,668 Fair value of assets (FVA)

(2,610) (690)

APBO less than (in excess of) FVA 5,412 5,953 Unrecognized net transition obligation (3,954) (5,316)

Unrecognized actuarial loss (gain)

$(1,152) $(53)

Net amount recognized Amounts recognized in the balance sheets:

$1,364 $1,555 Prepaid benefit cost (2,516) (1,608)

Accrued benefit liability

$(1,152) $(53)

Net amount recognized Net periodic benefit costs recognized for the periods ended December 31 are as follows:

2001 2000 1999 Pension benefits (aggregated)

$1,651 $1,639 $1,856 Service cost 2,652 2,350 2,224 Interest cost (2,982) (2,782) (2,463)

Expected return on assets Net amortization:

367 100 100 Prior service cost (529) (602) (253)

Net actuarial loss (gain) 63 63 63 Net transition obligation (99) (439) (90)

Total amortization Loss (gain) recognized due to settlement/curtailment

$1,222 $768 $1,527 Net periodic benefit cost 2001 2000 1999 Postretirement welfare benefits (aggregated)

$1,225 $902 $1,046 Service cost 1,107 833 768 Interest cost (1,006) (948) (914)

Expected return on assets Net amortization:

(359) (664) (580)

Net actuarial loss (gain) 541 541 541 Net transition obligation Total amortization 182 (123) (39)_

$1,508 $664 $861 Net periodic benefit cost The following weighted average assumptions were used as of December 31:

2001 2000 1999 Discount rate 7.25% 7.25% 7.50%

Compensation scale 4.50% 4.50% 4.00%

Expected return on assets:

Manaeement VEBA (post-tax) 6.00% 6.00% 6.00%

All other plan assets 8.50% 8.50% 8.50%

For measurement purposes, a 7.5% percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2002. The raLe was assumed to decrease to 6.5% for 2003, 5.5% for 2004 and remain at that level thereafter. A one pernentage point change in assumed health care cost trend rates would have the following effects on the information for the postretirement welfare plans:

1% Increase 1% Decrease Effect on total service and interest cost components S398 S(324)

Effect on atCuMulated postretirement benefit obligation 52,518 $(2,072)

NOTE 13. Lease Commitmeits The Company leases equipment and systems tnder noncancelable operating leases. Charges against income for leases were approximately ,555.2 million in 2001, $5.2 million in 2000 and S7.2 million in 1999.

Minimum future lease payments as of Detember 31, 2001 are as follows (Dollars in thousands):

Annual Fiscal years ended Leases 2002 $ 5,194 20003 4,618 2004 4,618 2005 2,309 Thereafter 0 InCtluded in the above lease payments is the cost of low pressure turbines constructed by General Electric Corporation valued at approximately 530.8 million minluding installation costs when installed in 1995. U nder the lease agreement which Chommen ed on July 1, 1995, the Company will make 120 monthly payments of S384,834.

NOTEF 14. Commitmients ani Continlgelneies (a) Low-level Waste In 1998, the U.S. Congress approved the tri-state compact between Vermont, Texas and Maine to site a facility in Texas for the disposal of low-level radioat tive waste. Also in 1998, the proposed Texas low level waste disposal site in Hudspeth County was rejected because of geological and socioeconomic concerns. V\arious parties have proposed alternative sites in Texas. Because of delays in the ratification and siting processes, the Company cannot predict when a facility in Texas will be licensed and built.

However, it is unlikely that waste disposal under the compact will begin prior to 2003. The Company has been disposing of low-level waste at other a tive sites and Currently has the capacity to store all of its low-will level waste on site until the year 2007. If the Texas facility is not available by that date, other options continue to be pursued.

turn Under the terms of the compact and related Vermont Statutes, Vermont will pay Texas, and in the disposal assess in-state generators of low level waste up to $27.5 million to site, license and construct of the three States participating in the compact have agreed that any required facility. The Governors The Com payment under the compact will be deferred until a site is selected and a facility is licensed.

the remain pany has received approval from FERC to recover the cost of this compact from Sponsors over ing license life of the Plant, commencing with the first payment to Texas.

million The Company has recorded a non-current liability of $23.1 million to recognize the $27.5 and a correspond compact fund requirements less the remaining fund balance from the State of Vermont, billings to ing deferred debit of $25.7 million which represents the total amount to be included in future have both de Sponsors under the Power Contracts. The deferred debit and deferred credit amounts of Vermont creased by $0.1 million from the amounts reflected in 2000 as a result of earnings on the State fund balance.

(b) Nuclear Fuel The Company has several "requirements based" contracts for the four components (uranium, conver if the sion, enrichment and fabrication) used to produce nuclear fuel. These contracts are executed only activity would need or requirement for fuel arises. Under these contracts, any disruption of operating through allow the Company to cancel or postpone deliveries until actually required. The contracts extend various time periods and contain clauses to allow the Company the option to extend the agreements.

on Negotiation of new contracts and re-negotiation of existing contracts routinely occurs, often focusing

$16 million and the one of the four components at a time. The cost of the 2001 reload was approximately on cost of the 2002 reload is estimated to be approximately $23 million. Future reload costs will depend market and contract prices.

(c) Insurance The Price-Anderson Act currently sets the statutory limit for nuclear liability from a single incident at Price a nuclear power plant to $9.5 billion. Any damages beyond $9.5 billion are provided for under the of nuclear liability coverage is Andersen Act, but subject to Congressional approval. The first $200 million program is a retrospec the maximum provided by private insurance. The Secondary Financial Protection of the tive insurance plan providing additional coverage up to $9.3 billion per incident by assessing each a retrospective premium of 106 reactor units that are currently subject to the Program in the United States of $10 million per incident per up to $88.1 million per unit per incident, limited to a maximum assessment reflect nuclear unit in any one year. The maximum assessment is adjusted at least every five years to inflationary changes.

is set The Price-Anderson Act has been renewed three times since it was first enacted in 1957. The Act to expire in August 2002 and Congress is currently considering reauthorization of this legislation.

The above insurance now covers all workers employed at nuclear facilities for bodily injury claims.

million The Company had previously purchased a Master Worker insurance policy with limits of $200 employed on or after January 1, 1988.

with one automatic reinstatement of policy limits to cover workers based worker policy and has replaced this Vermont Yankee no longer participates in this retrospectively The Company does however retain a poten policy with the guaranteed cost coverage mentioned above.

did not tial obligation for retrospective adjustments due to past operations of several smaller facilities that to exist no later than December 31, 2007. Vermont join the new program. These exposures will cease Yankee's maximum retrospective obligation remains at $3.1 million. The Secondary Financial Protection layer, as referenced above, would be in excess of the Master Worker policy.

costs of Insurance has been purchased from Nuclear Electric Insurance Limited ("NEIL") to cover the property damage, decontamination or premature decommissioning resulting from an incident. All companies insured with NElL are subjectt to retroactive assessments if so determined by the Board of NEIL due to losses. The maximum potential assessment against the Company with respect to NEIL losses arising during the current policy year is $16.2 million. The Company's liability for the retrospective premium adjustment for any polioy year (eases six years after the end of that policy year unless prior demand has been made.

(d) Industry Restructuring and Other Regulatory Developments The electric utility industry has been in a period of potential transition which may result in a shift away from cost of service and return on equity based rates to market based rates. Most states in which the Company's Sponsors operate have explored or, in some cases, have implemented plans to bring greater competition, customer choice, and market influence to the industry while retaining the benefits associated with the current regulatory system.

The Company cannot predict what effec t these restructuring plans will have on the Company or its Sponsors. It is possible, however, that these restructuring orders or other regulatory actions could have a material adverse effect on the Sponsors, which could, in turn, have a material adverse effect on the Company.

NOTEi 15. New Aeeoniting Principles In August 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (ARO's). Effective for fiscal years beginning after June 15, 2002, ARO's must be recotgnized as a liability and measured at fair value.

The liability will be recognized when the obligation is incurred which, in many cases, will be when the long-lived asset is placed in service. Costs associated with recognizing an ARO will be capitalized as part of the related long-lived asset and amortized on a systematic and rational basis over its useful life as depreciation expense. Additionally, because the ARO is initially recorded at fair value (discounted),

accretion expense will be recognized each period as an operating expense.

The new rules apply to all companies that incur legal obligations to retire tangible long-live assets, such as the obligation for decommissioning a nuclear power plant. The Company will have to convert to the new standard, recognizing the resulting change in its dec ommissioning obligation via a cumulative effect adjustment at adoption. See Note 4 for further explanation.

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Board of Direetors ROSS P. BARKHURST ROBERT H. MARTIN President and Chief Executive Officer Director of Energy Supply Vermont Yankee Nuclear Power Corporation NSTAR Brattleboro, VT Boston, MA (2)

NANCY R. BROCK MARY ALICE McKENZIE Chief Financial Officer Vice President of Employee & Community Relations Green Mountain Power Corporation Vermont State Colleges Colchester, VT Waterbury, VT Director KENT R. BROWN Central Vermont Public Service Corporation Senior Vice President, Engineering & Operations Rutland, VT Central Vermont Public Service Corporation Rutland, VT GERALD C. POULIN Former Chief Operating Officer for Energy Services CHRISTOPHER L. DUTTON Central Maine Power Company President and Chief Executive Officer Augusta, ME Green Mountain Power Corporation Colchester, VT ROBERT G. POWDERLY Vice President TED C. FEIGENBAUM National Grid USA Exec. Vice President and Chief Nuclear Officer Westborough, MA North Atlantic Energy Service Corporation Seabrook, NH TERRY L. SCHWENNESEN Vice President of Generation Investments FREDERIC E. GREENMAN New England Power Company Former Vice President and General Counsel Westborough, MA New England Power Company Westborough, MA ROBERT H. YOUNG Chairman JAMES J. KEANE Vermont Yankee Nuclear Power Corporation Former Vice President, Energy Supply & Engineering Services Brattleboro, VT COM Electric Company President and Chief Executive Officer Wareham, MA (1) Central Vermont Public Service Corporation Rutland, VT JOHN B. KEANE Vice President of Administration (1) Resigned February 28, 2001 Northeast Utilities (2) Elected February 28, 2001 Hartford, CT Offieers ROBERT H. YOUNG DON M. LEACH Chairman Vice President, Engineering ROSS P. BARKHURST JOHN J. BOGUSLAWSKI President and Chief Executive Officer Controller and Secretary MICHAEL A. BALDUZZI NANCY S. MALMQUIST, Esq.

Senior Vice President, Chief Nuclear Officer Assistant Secretary BRUCE W. WIGGETT Senior Vice President of Finance and Administration, Treasurer This report is not to be considered an offer to sell or buy or solicitation of an offer to I sell or buy any security.

Vermnont Yankee Nuclear Power Corporation 185 Old Ferry Road P. 0. Box 7002 Brattleboro, Vermont 05302-7002