OR

Commission File number 1-5139

Registrants telephone number, including area code: (207) 623-3521

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

                                                                              Yes  X        No     

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ X ]

The number of shares of common stock (par value $5 per share) outstanding as of March 15, 2000 was 31,211,471 shares. All shares are owned by CMP Group, Inc.

CENTRAL MAINE POWER COMPANY

TABLE OF CONTENTS

PART I

Item 1.   BUSINESS.

(a) General development of business

Central Maine Power Company (the Company) is a public utility incorporated in Maine in 1905. In September 1998, the Company was reorganized into a holding company structure pursuant to a Plan of Merger with CMP Group Inc. (CMP Group). All of the shares of the Company's common stock were converted into an equal number of shares of CMP Group common stock and CMP Group became the Company's parent. Effective September 1, 2000, pursuant to a Plan of Merger, CMP Group became a wholly owned subsidiary of Energy East Corporation (Energy East).

The following general developments have occurred in the Company's business since January 1, 2000:

(See Item 7 - Electric Business and Item 8 - Note 2 to the Financial Statements.)

(See Item 7 - Electric Business - Alternative Rate Plan, MPUC Decision on Price Mitigation, Electric Transmission Rates, Installed Capability Deficiency Charge, Maine Yankee Replacement Power, and Merchant Plants.)

(b) Financial information about segments

The Company operates in the electric business segment only.

(c) Narrative description of business

The Company is primarily engaged in the business of transmitting and distributing electric energy generated by others for the benefit of customers in southern and central Maine. On March 1, 2000, the Company's obligation to generate or otherwise supply electric energy terminated as part of the restructuring of the electric utility industry in Maine. Although the Company has no long-term supply responsibility, the Maine Public Utilities Commission (MPUC) can mandate that the Company be the default standard offer provider. In February 2001, the MPUC directed the Company to provide energy services to commercial and industrial customers as the standard offer provider for the period March 1, 2001 through February 28, 2002.

The Company is the largest transmission-and-distribution electric utility in Maine, serving approximately 544,000 customers in its 11,000 square-mile service area in southern and central Maine. The Company's service area contains most of Maine's industrial and commercial centers, including Portland, the state's largest city, and the Lewiston-Auburn, Augusta-Waterville and Bath-Brunswick areas, and approximately one million people, representing about 80 percent of the total population of the state. In the year 2000, large pulp-and-paper industry customers accounted for approximately 55 percent of the Company's industrial sales and approximately 20 percent of total service-area sales. No single customer accounts for 5 percent or more of revenues.

Item 2.   PROPERTIES.

The Company's electric properties form a single integrated system which is connected at 345 kilovolts and 115 kilovolts with the lines of Public Service Company of New Hampshire at the southerly end and connected at 115 kilovolts with Bangor Hydro-Electric Company at the northerly end of the Company's system. The Company's system is also connected with the system of The New Brunswick Power Corporation and with Bangor Hydro-Electric Company, in each case through the 345-kilovolt interconnection constructed by Maine Electric Power Company (MEPCO), a 78 percent-owned subsidiary of the Company. At December 31, 2000, the Company had approximately 2,342 circuit-miles of overhead transmission lines, 20,479 pole-miles of overhead distribution lines and 164 miles of underground and submarine cable. The Company owns 285 substations having an aggregate transformer capacity of 5,948 kilovolt-amperes.

(See Item 7, Electric Business - Alternative Rate Plan, and Maine Yankee Termination of Decommissioning Operations Contract.)

Not applicable

********************************

The officers hold office until the first meeting of the Board of Directors following the next annual shareholder meeting and until their respective successors are chosen and qualified.

The Company has entered into an employment agreement with Ms. Burns for a term of three years beginning September 1, 2000, which is automatically extended each month unless either the Company, Energy East or Ms. Burns gives written notice that it will not be extended. The agreement provides for her employment as President of the Company.

The Company has entered into an employment agreement with Mr. Call for a term of one year, which is automatically extended annually unless either the Company or Mr. Call gives written notice that it will not be extended. The agreement provides for his employment as Treasurer of the Company.

Item 5.   MARKET FOR THE REGISTRANT'S COMMON EQUITY
               AND RELATED STOCKHOLDER MATTERS.

CMP Group, Inc., a wholly-owned subsidiary of Energy East Corporation, owns all of the Company's common stock. For information regarding dividends declared see Item 8 - Consolidated Statement of Changes in Common Stock Equity.

Item 6.   SELECTED FINANCIAL DATA.

The following table sets forth selected consolidated financial data of the Company for the five years ended December 31, 1996 through 2000. This information should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes thereto included in Items 7 and 8. The selected consolidated financial data for the years ended December 31, 1996, through 2000 are derived from the audited consolidated financial statements of the Company.

Item 7   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
              AND RESULTS OF OPERATIONS.

Earnings for 2000 decreased by $15.2 million due primarily to lower sales of electricity as a result of the deregulation of Maine's electric industry. The Company no longer supplies electricity unless it is directed by the MPUC as the standard offer provider. The Company is currently the standard offer provider for commercial and small industrial rate classes. Net Income increased $13.9 million in 1999 due to a strong economy and increases in sales to all customer classes, except wholesale sales.

The Company's operating revenues decreased $63.5 million in 2000. This decrease is the result of the Company no longer collecting revenue for the supply of electricity unless it is directed to by the MPUC. An increase in the sale of electricity partially offset this decrease. Operating revenues increased $12.9 million in 1999 due to growth in all customer classes except the wholesale class.

The Company's operating expenses decreased by $28.1 million as the result of the sale of generation assets and lower electricity supply costs due to the Company no longer supplying electricity unless directed to by the MPUC. Operating expenses increased by $8.1 million in 1999 due to the cost of power purchased.

The company's principal electric business is transmitting and distributing electricity. It also generates electricity from its minority interests in jointly-owned nuclear stations but no longer sells this energy at retail.

Alternative Rate Plan:  On September 18, 2000, the MPUC approved a revised Alternative Rate Plan (ARP 2000) for the Company. ARP 2000 provides the vehicle for the Company and Energy East to share merger synergies with the Company's customers. Merger synergies have been estimated to be $25 million to $30 million per year.

ARP 2000 applies only to the Company's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services. Recovery of stranded costs, primarily above-market non-utility generator (NUG) contracts, has been provided for under Maine's Restructuring Law. Rates for transmission service are subject to regulation by the Federal Energy Regulatory Commission (FERC) and are expected to change each July. ARP 2000 began January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1 in the years 2002 through 2007.

Price changes will be calculated by taking the prior year's inflation rate as determined by the gross domestic product (GDP) price index and subtracting a "productivity offset." The productivity offset for the years of the plan range between 2.0% in 2002 and 2.9% in 2007. The productivity offset for 2001 will be equal to the GDP price index, thereby producing a price freeze for that year. In addition, certain expiring amortizations will flow through to customers at the time of the annual price adjustments.

Mandated costs outside of the Company's control that exceed $150,000 individually and $3 million in aggregate in any calendar year will be recovered through the annual price adjustment. Mandated costs include nonrecurring events such as storms, floods and labor disturbances, and recurring costs that result from accounting, federal or state legislative, regulatory or tax changes.

The Company is required to meet certain standards of service quality and reliability. These standards include: 1) customer average interruption duration, 2) system average interruption, 3) MPUC complaint ratio, 4) percent of business calls answered, 5) percent of outage calls answered, 6) new service installation, 7) call center service quality, and 8) market responsiveness.

On December 18, 2000, an appeal was filed by the Industrial Energy Consumer Group arguing that the MPUC order in the Company's ARP 2000, in certain respects, was unlawful. The outcome of this appeal cannot be predicted, but the Company believes it is without merit.

MPUC Decision on Price Mitigation: Although the Company's obligation to provide energy ended in March 2000 with the restructuring of the electric utility industry in Maine, in February 2001 the MPUC directed the Company to provide standard offer service to certain medium and large customer classes for the period March 2001 through February 2002. The Company subsequently arranged supply contracts to meet this obligation and the MPUC established standard offer rates to recover the costs of the standard offer service. In March, 2001, in an effort to mitigate price increases resulting from standard offer service, the MPUC reduced those standard offer rates by 0.8 cents per kilowatt hour, effective April 15, 2001. The Company's total revenues will not, however, be affected by this rate reduction of approximately $30 million through February 2002 because the MPUC is permitting the Company to amortize a corresponding amount into revenues from the Company's deferred asset sale gain account, established as a result of the sale of its non-nuclear generation assets.

Electricity Transmission Rates:  On September 28, 2000, the FERC approved new transmission rates for the Company, which became effective September 1, 2000, and will cover increased transmission costs.

Installed Capability Deficiency Charge:  On December 15, 2000, the FERC issued an order approving an Installed Capability (ICAP) deficiency charge of $8.75/kW-month effective August 1, 2001. FERC stated that the deficiency charge represents an approximate cost to install a peaking unit and a reasonable basis for setting incentives to construct new generation. In March 2001, FERC changed the effective date of its decision to April 1, 2001. The Company incurs such charges through its obligation as the default standard offer provider for large commercial and industrial customers. On December 22, 2000 the MPUC raised the standard offer rates to recoup a portion of the resulting increase and provided the Company a deferral mechanism for such costs, which will be recovered from customers in future rates.

Insurance Distribution: In November 2000, Maine Yankee terminated its membership in a nuclear industry mutual insurance company. As a result, Maine Yankee received a terminating distribution of approximately $20.5 million, substantially all of which was credited, prorata, to the Maine Yankee sponsors' November power-contract bills, with the balance paid to Maine Yankee's decommissioning trust. The Company received approximately $7.6 million from the distribution.

Maine Yankee Replacement Power:  In closing Maine Yankee, the MPUC set criteria for recovery of the cost of Maine Yankee using replacement power measurements. In September 2000, the MPUC staff advised the Company that it could not use the previously selected replacement power measurement. At that time the Company had recorded a liability of $31.2 million in the purchase accounting entries associated with the merger with Energy East with an offset to goodwill and deferred income taxes. The Company sought to mitigate this liability. In December the Company and the MPUC reached a settlement and the MPUC reduced the liability through 2004 to $12 million. The decrease of the liability was recorded as well as a corresponding adjustment to the goodwill account.

Maine Yankee - Termination of Decommissioning Operations Contract:  On May 4, 2000, Maine Yankee notified its decommissioning operations contractor, Stone & Webster Engineering Corp., that it was terminating its decommissioning operations contract pursuant to the terms of the contract. Stone & Webster subsequently notified Maine Yankee that it was disputing Maine Yankee's grounds for terminating the contract. On May 8, 2000, Stone & Webster announced a proposed transaction in which it would transfer substantially all of its assets in exchange for an immediate credit facility and other consideration, including cash and stock. Stone & Webster said the credit facility was intended to enable it to address its liquidity difficulties and continue to operate its businesses until the asset sale was completed. Stone & Webster also announced that it intended to seek bankruptcy court approval of the asset sale and credit agreement.

On June 2, 2000, Stone & Webster filed a voluntary petition under Chapter 11 of the United States Bankruptcy Code with the United States Bankruptcy Court for the District of Delaware. By Order dated July 13, 2000, the Bankruptcy Court approved the sale of substantially all of Stone & Webster's assets to the successful bidder in the Chapter 11 sale, The Shaw Group, Inc. (Shaw), for cash, stock, and the assumption of certain liabilities of Stone & Webster, and the proposed transaction announced earlier by Stone & Webster was terminated. Stone & Webster reported that the Shaw transaction was effectively closed on July 14, 2000, and that it would continue to operate as a Debtor-in-Possession subject to the supervision and orders of the Bankruptcy Court.

Commencing in May 2000 Maine Yankee entered into interim agreements with Stone & Webster in order to allow decommissioning work to continue and to avoid the adverse consequences of an abrupt or inefficient demobilization from the Plant site. After obtaining assignments of several subcontracts from Stone & Webster, Maine Yankee temporarily assumed the general contractor role. The decommissioning of the Plant site continued throughout the year 2000, with major emphasis directed to maintaining the schedule on critical-path projects such as construction of the on-site independent spent fuel storage installation (ISFSI) and preparation of the Plant's reactor vessel for eventual shipment to an off-site disposal facility. During this period Maine Yankee performed a comprehensive assessment of its long-term alternatives for safely and efficiently completing the decommissioning, including evaluating detailed competitive-bid proposals from prospective successor general contractors. On January 26, 2001, Maine Yankee announced its decision to continue to manage the decommissioning project itself without an external general contractor.

On June 30, 2000, Federal Insurance Company (Federal), which provided performance and payment bonds in the amount of approximately $37.6 million each in connection with the decommissioning operations contract, filed a Complaint for Declaratory Judgment against Maine Yankee in the United States Bankruptcy Court for the District of Delaware, which was subsequently transferred to the United States District Court in Maine. The Complaint alleges that Maine Yankee improperly terminated the decommissioning operations contract with Stone & Webster and failed to give proper notice of the termination to Federal under the contract, and that Federal therefore had no further obligations under the bonds.

On August 24, 2000, Maine Yankee also filed a $78.2 million (later increased to $86 million) proof of claim in the Stone & Webster Bankruptcy Court proceeding in Delaware seeking to recover its additional costs caused by Stone & Webster's contract default. Maine Yankee expects the court hearings in both proceedings to take place later in 2001. Maine Yankee believes that its termination of the Stone & Webster contract was proper and that it is entitled to recover such additional costs in the bankruptcy proceeding or under the bonds, but cannot predict the outcome of the litigation.

Non-utility Generation:  The Company has reduced its NUG costs by implementing buyouts and restructurings of its NUG contracts, whenever practicable. A significant portion of NUG costs which had been previously deferred was written off on March 1, 2000 against the proceeds from the sale of its non-nuclear generation assets as prescribed by the MPUC rate case decision. The Company will continue to seek opportunities to reduce its NUG costs, but the Company cannot predict what level of additional savings it will be able to achieve. The aggregate above market cost associated with these contracts is estimated to be approximately $1 billion, based on certain market price assumptions which could fluctuate with energy prices. The Company expensed approximately $243 million for NUG power in 2000. The Company estimates that it will spend approximately $250 million for NUG power for each of the next 3 years.

Merchant Plants:  On June 28, 2000, FERC issued an order regarding the funding responsibility for transmission network upgrades to accommodate the direct interconnection with new merchant generating plants. The Company has required the merchant plant developers to fund all interconnection and network upgrades in advance. The Company received $58 million in deposits from customers relating to pending merchant plant activity since 1999. The Company anticipates refunding approximately $8 million to $13 million over the next two years for completed construction. Any amounts refunded to developers will be capitalized on the Company's books and recovered through regional or local open access tariffs, as appropriate, as prescribed by FERC.

Statement 71:  Statement of Financial Accounting Standards 71, Accounting for the Effects of Certain Types of Regulation, allows companies that meet certain criteria to capitalize, as regulatory assets, incurred costs that are probable of recovery in future periods. Those companies record, as regulatory liabilities, obligations to refund previously collected revenue or obligations to spend revenue collected from customers on future costs.

Although the Company believes it will continue to meet the criteria of Statement 71 for the regulated electricity operations, the Company cannot predict what effect a competitive market or future actions of the MPUC will have on its ability to continue to do so. If the Company can no longer meet the criteria of Statement 71 for all or a separable part of its regulated operations, it may have to record as expense or revenue certain regulatory assets and liabilities. The Company may also have to record as a loss an estimated $1.0 billion, on a present value basis at December 31, 2000, of above-market costs on its power purchase contracts with NUGs. These costs are currently recovered in rates.

Statement 133:  The FASB issued Statement 133, Accounting for Derivative Instruments and Hedging Activities, in June 1998, which was amended in later FASB pronouncements. Statement 133 establishes standards for the accounting and reporting for derivative instruments and for hedging activities. Statement 133 requires that all derivatives be recognized as either assets or liabilities on a company's balance sheet at their fair value.

The Company adopted FASB Statement 133, as of January 1, 2001. The transition adjustment as of January 1, 2001 recorded in Other Comprehensive Income, net of tax, and the earnings effect was zero. Based on the Company's current risk management strategy, this adoption is not expected to have a material effect on its financial position and results of operations. Fair value adjustments could change based on guidance received from the Derivatives Implementation Group, which was appointed by the FASB to identify implementation issues and develop recommendations.

The company's financial strength provides the flexibility required to compete in the emerging competitive energy market and continue expanding its products and services, including its energy infrastructure, in the Northeast.

Capital spending, including nuclear fuel and transmission network upgrades due to merchant plant activity, totaled $66 million in 2000, $75 million in 1999 and $50 million in 1998. Capital spending in all three years was financed with internally generated funds and deposits from merchant plant developers and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements.

Beginning in 1999, the Company incurred significant capital expenditures to upgrade its transmission network to handle the increased power flows from new merchant plant developers. Through December 31, 2000 approximately $47 million in expenditures had been recorded against the $58 million of merchant plant developers' deposits. The Company currently estimates its overall construction program to be $45 million in 2001. It is expected to be paid for primarily with internally generated funds.

The Company issued in June 2000 $25 million of 8.125% Series E Medium Term Notes (MTN) due June 2025 and $50 million of 7.50% Series E MTN due June 2002. The Company also issued in August 2000 $50 million of 7.43% Series E MTN due August 2003.

The Company redeemed in February 2000 $30 million of 6.38% Series C MTN, redeemed in June 2000 $5 million of 9.65% Series A MTN and redeemed in June 2000 $25 million of 6.50% Series D MTN.

The Company uses funds obtained from short-term borrowing to provide initial financing for construction and other corporate purposes. The Company had $46.5 million in loans outstanding at December 31, 2000 under a three year secured credit facility.

On October 1, 1999 and 2000, the Company redeemed $18.0 million and $9.9 million respectively, of its 7.999% Preferred Stock, reducing dividends by approximately $1.4 million for the year ended December 31, 2000, compared to 1999.

This Form 10-K contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements.

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated industry; regulatory uncertainty in a politically-charged environment to recover stranded costs; operation of the New England Independent System Operator (NEISO); the Company's ability to control non-utility generator and other costs; market risk,; the ability to obtain adequate and timely rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which it is doing business; weather variations affecting customer energy usage; and other considerations that may be disclosed from time to time in its publicly disseminated documents and filings. The Company undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
                  RISK.

Market risk represents the risk of changes in value of a financial instrument, derivative or non-derivative, caused by fluctuations in interest rates and prices. The following discussion of the Company's risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those contemplated in the "forward-looking" statements. The Company handles market risks in accordance with established policies.

Quantitative and qualitative disclosures are discussed as they relate to the following three market risk exposure categories: Interest Rate Risk, Commodity Price Risk and Other Market Risk.

Interest Rate Risk: The Company is exposed to risk resulting from interest rate changes on its variable-rate debt and short term debt. The Company is able to use interest rate swap agreements to manage the risk of increases in certain variable rate issues. If the Company used interest rate swaps, it would record amounts paid and received under those agreements as adjustments to the interest expense of the specific debt issues.

As of December 31, 2000, the Company had $135 million of medium-term notes outstanding, $10 million of which were floating, LIBOR-based rates. Variable-rate long-term debt of $78.6 million at December 31, 2000 had a weighted average rate of 9.15 percent with maturing periods between 2001 - 2019.

Commodity Price Risk: While the Company in general, has no long-term supply responsibilities, the MPUC can mandate that the Company be a standard offer provider for supply service should standard offer bids by competitive suppliers be deemed inadequate by the MPUC. The Company is required to secure standard offer power for commercial and industrial customers through February 2002, but is permitted to recover any difference between the standard offer rate and its cost of procuring supply.

Other Market Risk: The Company's pension plan assets are made up of equity and fixed income investments. Fluctuations in those markets could cause the Company to recognize increased or decreased pension income or expense.

The Company contributes to a qualified trust fund for Millstone Unit No. 3, as required by the Nuclear Regulatory Commission, to fund certain costs of nuclear decommissioning. The funds in the qualified trust are invested in money market instruments. The Company believes that the market risk exposure is limited to immaterial fluctuations in the money markets. (See Note 9 to the Financial Statements.)

The accompanying notes are an integral part of these financial statements.

The accompanying notes are an integral part of these financial statements.

The accompanying notes are an integral part of these financial statements.

The accompanying notes are an integral part of these financial statements

The accompanying notes are an integral part of these financial statements.

Revenue Recognition:  Operating revenues include amounts billed to customers and an estimate of unbilled sales for services rendered but not yet billed.

Income Taxes:  The Company files under a consolidated federal income tax return. Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.

Utility Plant:  Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation.

Depreciation and Amortization:  Depreciation of electric property is calculated using the straight-line method. The weighted average composite rate was 2.8% in 2000 and 1999, and 3.1% in 1998.

Goodwill:  The excess of the cost over fair value of net assets of purchased businesses is recorded as goodwill and is amortized on a straight-line basis over 40 years. The Company continually evaluates the carrying value of goodwill and any impairments would be recognized when the expected future operating cash flows derived from such goodwill is less than its carrying value.

Regulatory Assets and Liabilities:  Pursuant to Statement of Financial Accounting Standards 71, Accounting for the Effects of certain Types of Regulation, the Company capitalizes, as regulatory assets, incurred costs that are probable of recovery in future electric rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. Approximately $300 million of the regulatory liability resulting from the Company's sale of non-nuclear assets was used to offset regulatory assets in March of 2000.

Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Unamortized loss on debt reacquisitions is amortized over the lives of the related debt issues. Nuclear plant obligations, demand-side management program costs, gain on sale of generation assets, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with the company's current rate agreements. The company earns a return on substantially all regulatory assets for which funds have been spent.

Statement of Cash Flows:  The company considers all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents. Those investments are included in cash and cash equivalents on the balance sheet.

Total income taxes paid were $25.3 million in 2000, $364 million in 1999 and $7 million in 1998.

Interest paid, net of amounts capitalized, was $16 million in 2000, $38 million in 1999, and $50 million in 1998.

Statement 133:  The FASB issued Statement 133, Accounting for Derivative Instruments and Hedging Activities, in June 1998, which was amended in later FASB pronouncements. Statement 133 establishes standards for the accounting and reporting for derivative instruments and for hedging activities. Statement 133 requires that all derivatives be recognized as either assets or liabilities on a company's balance sheet at their fair value.

The Company adopted FASB Statement 133, as of January 1, 2001. The transition adjustment as of January 1, 2001 recorded in Other Comprehensive Income, net of tax, and the earnings effect was zero. Based on the Company's current risk management strategy, this adoption is not expected to have a material effect on its financial position and results of operations. Fair value adjustments could change based on guidance received from the Derivatives Implementation Group, which was appointed by the FASB to identify implementation issues and develop recommendations.

Estimates:  Preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of 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.

Reclassification:  Certain amounts from prior-years financial statements have been reclassified to conform with the 2000 presentation.

CMP Group, Inc., the owner of the Company's Common Stock, became a wholly-owned subsidiary of Energy East Corporation on September 1, 2000. The transaction was accounted for using purchase accounting. The cost in excess of the fair value of the net assets acquired was recorded as goodwill and will be amortized on a straight-line basis over the estimated useful life of 40 years. Goodwill may be adjusted over the twelve months following the merger as actual amounts for estimated liabilities become known.

As a result of the merger on September 1, 2000, as required under purchase accounting by generally accepted accounting principles, retained earnings of the Company were reset to zero and moved to other paid-in capital. On September 5, 2000, the Company's Board of Directors declared and paid a liquidating dividend amounting to $190 million, which reduced other paid-in capital. This dividend aligned the Company's capital structure with that assumed by the MPUC in establishing the current tariff charges and was facilitated with the proceeds from the sale of the Company's generation assets in 1999.

*Includes the effect of the sale of non-nuclear generation assets in 1999.

The Company's effective tax rate differed from the statutory rate of 35% due to the following:

(1)  Reflects impact of MPUC rate case settlement.

(2)  Reflects impact of generation asset sale.

Construction Program:  Capital spending, including nuclear fuel and costs related to merchant plants totaled $66 million in 2000, $75 million in 1999 and $50 million in 1998. Capital spending in all three years was financed with internally generated funds and deposits from merchant plant developers and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements.

The Company's current forecast of capital expenditures is $45 million for 2001.

Power Agreements:  The New England Power Pool, of which the Company is a member, has contracted to purchase power from Hydro-Quebec. The contracts entitle the Company to 44.5 megawatts of capacity credit during the winter and 127.25 megawatts of capacity credit during the summer. The Company has entered into agreements to pay its share of related transmission facilities. The Company's share of the support responsibility and of associated benefits is approximately 7 percent.

The Company, through certain equity interests, is entitled to a portion of the generating capacity and energy production of four nuclear generating facilities (the Yankee companies), three of which have been permanently shut down. The Company is obligated to pay its proportionate share of costs, which include fuel, depreciation, operation and maintenance expenses, a return on invested capital, and the estimated cost of decommissioning the nuclear plants.

The Company owns interests in five nuclear generating facilities in New England, three of which have permanently ceased operations and one of these three has been decommissioned. The Company's estimated liability for decommissioning its various interests in jointly-owned nuclear plants is $209 million in 2001 dollars.

Maine Yankee:  In August 1997, the Board of Directors of Maine Yankee Atomic Power Company voted to permanently shut down and decommission the Maine Yankee plant. The plant had experienced a number of operational and regulatory problems and did not operate after December 6, 1996. The decision to close the plant was based on an economic analysis of the costs, risks and uncertainties associated with operating the plant compared to those associated with closing and decommissioning it .

Connecticut Yankee:  In December 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted to permanently shut down and decommission the Connecticut Yankee plant for economic reasons. The plant did not operate after July 22, 1996.

Yankee Atomic:  In 1993 the FERC approved a settlement agreement regarding recovery of decommissioning costs and plant investment, and all issues with respect to the prudence of the owners decision to discontinue operation of the Yankee Atomic plant. The Company estimates that it will not incur any future costs for the shut down of Yankee Atomic.

Vermont Yankee:  The Vermont Yankee plant is an operating unit. Its NRC operating license is scheduled to expire in the year 2012. Vermont Yankee is in the process of selling the nuclear plant through an auction process.

Millstone Unit No. 3:  Pursuant to a joint ownership agreement, the Company has a 2.5 percent direct ownership interest in the Millstone Unit No. 3 nuclear unit in Waterford, Connecticut, which is operated by Northeast Utilities. The Company and substantially all of the other joint owners have contracted to sell their interests in the unit and expect the sale to close in mid 2001.

The Company is obligated to pay its proportionate share of the operating expenses, including depreciation and a return on invested capital, of each of the Yankee Companies referred to above for periods expiring at various dates to 2012. Pursuant to the joint ownership agreement for Millstone Unit No. 3, the Company is similarly obligated to pay its proportionate share of the operating costs of Millstone Unit No. 3. The Company is also required to pay its share of the estimated decommissioning costs of each of the Yankee Companies and Millstone Unit No. 3, which are included in the Company's stranded costs for purposes of rate recovery.

Nuclear Insurance:  The Price-Anderson Act is a federal statute providing, among other things, a limit on the maximum liability for damages resulting from a nuclear incident. Coverage for the liability is provided for by existing private insurance and retrospective assessments for costs in excess of those covered by insurance, up to $84.0 million for each reactor owned, with a maximum assessment of $10 million per reactor in any year. However, after appropriate exemptive action by the NRC, Maine Yankee, and therefore its sponsors, are not responsible for retrospective assessments resulting from any event or incident occurring after January 7, 1999. Based on the Company's stock ownership in the other Yankee companies and its 2.5 percent direct ownership interest in the Millstone Unit No. 3 nuclear unit, the Company's retrospective premium for post-January 7, 1999, events or incidents could be as high as $0.7 million in any year, for a cumulative total of $5.5 million.

In addition to the insurance required by the Price-Anderson Act, the nuclear generating facilities mentioned above carry additional nuclear property-damage insurance. This additional insurance is provided from commercial sources and from the nuclear electric utility industry's insurance company through a combination of current premiums and retrospective premium adjustments. In recognition of the reduced risk posed by the shutdown of the Maine Yankee Plant and its defueled reactor, Maine Yankee substantially reduced its property-damage coverage effective January 19, 1999, and in November 2000, terminated its membership in the nuclear industry insurance company.

From time to time environmental laws, regulations and compliance programs may require changes in the Company's operations and facilities and may increase the cost of electric service.

The U.S. Environmental Protection Agency and various state environmental agencies, as appropriate, notified the Company that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at 22 waste sites. The 22 sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the 22 sites, seven are included in Maine's Uncontrolled Sites Program, one is included on the Massachusetts Non-Priority Confirmed Disposal Site list, three are also included on the National Priorities list and 16 have Maine interim-hazardous waste licenses and/or closure requirements.

Any liability may be joint and several for certain of these sites. The company has recorded an estimated liability of $2.9 million related to the 22 sites. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to the Company.

The Company has a program to investigate and perform necessary remediation at five sites where gas was manufactured in the past. Four sites are part of Maine's Voluntary Response Action Program and three of those four sites are part of Maine's Uncontrolled Sites Program.

The Company's estimate for all costs related to investigation and remediation of these five sites ranges from $1.25 million to $5.0 million at December 31, 2000. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations.

The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites, reflected on the Company's consolidated balance sheets was $1.25 million at December 31, 2000, and $0.45 million at December 31, 1999.

The sale of generation assets in 1999 resulted in a curtailment gain and a settlement gain, which were the result of the termination of certain generation employees. The curtailment gain reduced the expected years of future service under the pension benefit plan and the settlement gain reduced the postretirement benefit obligation. As a result of purchase accounting all unrecognized actuarial gain/loss, prior service cost and net transition asset/obligation were eliminated as of September 1, 2000.

The Company assumed a 5.6% annual rate of increase in the costs of covered health care benefits for 2000 that gradually decreases to 5% by the year 2021.

At December 31, 2000 and 1999, the Company's consolidated long-term debt was: