(1) Cayuga Energy's 85% share of the generating capability.
⁽²⁾ Cayuga Energy's 50.1% share of the generating capability.

CMP has ownership interests in three nuclear generating facilities: Maine Yankee in Wiscasset, Maine, 38%; Yankee Atomic in Rowe, Massachusetts, 9.5%; and Connecticut Yankee in Haddam, Connecticut, 6%. Those facilities have been permanently shut down and are in the process of being decommissioned.

CMP owns 301 substations in Maine having an aggregate transformer capacity of 6,506,334 kilovolt-amperes (Kva). The transmission system consists of 2,554 circuit miles of line. The distribution system consists of 22,216 pole miles of overhead lines and 152 miles of underground lines.

NYSEG owns 430 substations in New York having an aggregate transformer capacity of 12,710,510 Kva. The transmission system consists of 4,389 circuit miles of line. The distribution system consists of 34,096 pole miles of overhead lines and 2,364 miles of underground lines.

RG&E owns 158 substations in New York having an aggregate transformer capacity of 2,447,596 Kva. The transmission system consists of 742 circuit miles of overhead lines and 424 circuit miles of underground lines. The distribution system consists of 16,495 circuit miles of overhead lines and 4,497 circuit miles of underground lines.

The operating companies' natural gas systems consist of the following:

Substantially all of the company's utility plant is subject to liens or mortgages securing its subsidiaries' first mortgage bonds. None of CMP's utility plant is subject to liens or mortgages securing first mortgage bonds. NYSEG's and RG&E's first mortgage bond indentures constitute direct first mortgage liens on substantially all of their respective properties. (See Item 8 - Note 6 to the company's and Note 5 to CMP's Consolidated Financial Statements, and Note 5 to NYSEG's and RG&E's Financial Statements.)

Item 3.  Legal proceedings
(See Item 7 - Electric Delivery Business and Natural Gas Delivery Business and Item 8 - Note 11 to the company's and Note 10 to CMP's Consolidated Financial Statements, and Note 10 to NYSEG's and RG&E's Financial Statements.)

Since the New York State Public Service Commission (NYPSC), Connecticut Department of Public Utility Control (DPUC), MPUC and Massachusetts Department of Telecommunications and Energy (DTE) have allowed the company's operating companies to recover in rates remediation costs for certain of the sites referred to in the second and fourth paragraphs of Note 11 to the company's and Note 10 to CMP's Consolidated Financial Statements and the second and fourth paragraphs of Note 10 to NYSEG's and RG&E's Financial Statements there is a reasonable basis to conclude that such operating companies will be permitted to recover in rates any remediation costs that they may incur for all of the sites referred to in those paragraphs. Therefore, the company, CMP, NYSEG and RG&E believe that the ultimate disposition of the matters referred to in the paragraphs of the Notes referred to above in the company's and CMP's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements will not have a mat erial adverse effect on their results of operations or financial position.

(a)  In August 1997 NYSEG was notified by the New York State Department of Environmental Conservation (NYSDEC) that NYSDEC was contemplating enforcement action against NYSEG with respect to violations of regulations concerning opacity of air emissions at all of the company's New York coal-fired stations. NYSEG is in the process of negotiating a consent order with the NYSDEC to resolve the NYSDEC's demand for a penalty of approximately $650,000. The company sold its New York coal-fired stations to The AES Corporation (AES) in May 1999.

(b)  NYSEG received a letter in October 1999 from the New York State Attorney General's office alleging that NYSEG may have constructed and operated major modifications to certain emission sources at the Goudey and Greenidge generating stations, which it formerly owned, without obtaining the required prevention of significant deterioration or new source review permits. The Goudey and Greenidge plants were sold to AES in May 1999. The letter requested that NYSEG and AES provide the Attorney General's office with a large number of documents relating to this allegation. In January 2000 NYSEG received a subpoena from the NYSDEC ordering production of similar documents. The NYSDEC subsequently requested similar documents with respect to the Hickling and Jennison generating stations, which the company formerly owned. Those stations were also sold to AES in May 1999.

In April 2000 NYSEG received a letter from the EPA requesting information with respect to the operation of the Milliken and Kintigh generating stations, which the company formerly owned. Those stations were also sold to AES in May 1999. NYSEG furnished documents pursuant to the Attorney General's, NYSDEC's and EPA's requests.

In May 2000 NYSEG received a notice of violation from the NYSDEC alleging that two projects at Goudey and four projects at Greenidge were constructed without the necessary permits having been obtained.

In April 2001 EPA notified NYSEG by telephone that EPA would be issuing notices of violation alleging that various projects at the Milliken and Kintigh generating stations were constructed without the necessary permits having been obtained.

NYSEG believes it has complied with the applicable rules and regulations and there is no basis for the Attorney General's, NYSDEC's and EPA's allegations. NYSEG believes that any liability related to this matter will be the responsibility of AES in accordance with the asset purchase agreement.

(c)  In October 2000 NYSEG and Pennsylvania Electric Company (Penelec) received a letter from EME Homer City Generation, L.P. (EME), a subsidiary of the purchaser of the Homer City generating station (Station) in which NYSEG and Penelec each formerly owned a one-half interest. The letter gave NYSEG and Penelec notice that the EPA has found alleged violations of the federal Clean Air Act related to the Station. EME has indicated that it will claim that certain fines, penalties and costs arising out of or related to these alleged violations, which NYSEG believes may be material, are liabilities retained by NYSEG and Penelec under the terms of the asset purchase agreement for the Station. While it will continue to examine this matter, NYSEG believes that such fines, penalties and costs are not liabilities retained by it.

(d)  In October 1999 RG&E received a letter from the New York State Attorney General's office alleging that RG&E may have constructed and operated major modifications to the Beebee and Russell generating stations without obtaining the required prevention of significant deterioration or new source review permits. The letter requested that RG&E provide the Attorney General's office with a large number of documents relating to this allegation. In January 2000 RG&E received a subpoena from the NYSDEC ordering production of similar documents.

The NYSDEC served RG&E with a notice of violation in May 2000 alleging that between 1983 and 1987 RG&E completed five projects at Russell Station and two projects at Beebee Station without obtaining the appropriate permits. RG&E believes it has complied with the applicable rules and there is no basis for the Attorney General's and NYSDEC's allegations.

RG&E is not able to definitively predict the outcome of this matter. A number of options that would resolve the notice of violation are under investigation.

Item 4.  Submission of matters to a vote of security holders

None for Energy East, CMP, NYSEG or RG&E.

* * * * * * * * * * *

Wesley W. von Schack and Kenneth M. Jasinski each have an employment agreement for a term ending February 7, 2006. Mr. von Schack's agreement provides for his employment as Chairman, President & Chief Executive Officer of the company and Mr. Jasinski's agreement provides for his employment as Executive Vice President and Chief Financial Officer of the company. Michael I. German has an employment agreement for a term ending on December 31, 2004. Mr. German's agreement provides for his employment as Senior Vice President, Business Development of Energy East Management Corporation and President and Chief Executive Officer of The Energy Network, Inc. Each agreement provides for automatic one-year extensions unless either party to an agreement gives notice that such agreement is not to be extended.

Robert M. Allessio, Sara J. Burns and F. Michael McClain each have an employment agreement for a term of three years beginning September 1, 2000, which is automatically extended each month unless either party to an agreement gives written notice that it is not to be extended. Ms. Burns' agreement provides for her employment as President of CMP and Mr. Allessio's agreement provides for his employment as President and Chief Executive Officer of Berkshire Gas. Paul C. Wilkens has an employment agreement for a term of three years beginning June 28, 2002, which is automatically extended each month unless either party to the agreement gives written notice that it is not to be extended. Mr. Wilkens' agreement provides for his employment as President of RG&E.

Each officer holds office for the term for which he or she is elected or appointed, and until his or her successor is elected and qualifies. The term of office for each officer extends to and expires at the meeting of the Board of Directors following the next annual meeting of shareholders.

Item 5.  Market for Registrants' common equity and related stockholder matters

See Item 8 - Note 17 to the company's Consolidated Financial Statements.

CMP Group, Inc., a wholly-owned subsidiary of Energy East, owns all of CMP's common stock. See Item 8 - CMP's Consolidated Statements of Changes in Common Stock Equity for information regarding dividends declared.

RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East, owns all of NYSEG's and all of RG&E's common stock. See Item 8 - NYSEG's and RG&E's Statements of Changes in Common Stock Equity for information regarding dividends declared.

Item 6.  Selected financial data

See the information under the heading Selected financial data for each registrant, which is included in this report as follows:

Energy East - page 19
CMP - page 72
NYSEG - page 96
RG&E - page 125

Item 7.  Management's discussion and analysis of financial condition and results of operations

See the information under the heading Management's discussion and analysis of financial condition and results of operations for each registrant, which is included in this report as follows:

Energy East - pages 20 to 38
CMP - pages 72 to 75
NYSEG - pages 96 to 102
RG&E - pages 125 to 131

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

Market risk represents the risk of changes in value of a financial or commodity instrument, derivative or nonderivative, caused by fluctuations in interest rates and commodity prices. The following discussion of the companies' 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 companies handle market risks in accordance with established policies, which may include various derivative transactions. (See Item 8 - Note 1 to the company's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.)

The financial instruments held or issued by the companies are for purposes other than trading or speculation. Quantitative and qualitative disclosures are discussed as they relate to the following market risk exposure categories: Interest Rate Risk, Commodity Price Risk and Other Market Risk.

Interest Rate Risk: The companies are exposed to risk resulting from interest rate changes on their variable-rate debt and commercial paper. The company and its subsidiaries use interest rate swap agreements to manage interest rate risk and/or to maintain desired fixed-to-floating rate ratios. Amounts paid and received under those agreements are recorded as adjustments to the interest expense of the specific debt issues. The companies estimate that, at December 31, 2002, a 1% change in average interest rates would change annual interest expense for variable rate debt by about $4.6 million for Energy East, including $0.2 million for CMP, $1.3 million for NYSEG and $0.7 million for RG&E. (See Item 8 - Notes 6 and 12 to the company's and Notes 5 and 11 to CMP's Consolidated Financial Statements, and Notes 5 and 12 to NYSEG's and Notes 5 and 11 RG&E's Financial Statements.)

The company also uses financial instruments to lock in the treasury rate component of future financings to mitigate risk resulting from interest rate changes.

Commodity Price Risk: Commodity price risk is a significant issue for the company, NYSEG and RG&E due to volatility experienced in both the electric and natural gas wholesale markets. The companies manage this risk through a combination of regulatory mechanisms, such as allowing for the pass-through of the market price of electricity and natural gas to customers, and through comprehensive risk management processes. These measures mitigate the companies' commodity price exposure, but do not completely eliminate it.

Although CMP has no long-term supply responsibilities, the MPUC can mandate that CMP be a standard-offer provider for supply service should bids by competitive suppliers be deemed unacceptable by the MPUC. (See Item 7 - CMP Electricity Supply Responsibility.) In September 2001 the MPUC chose Constellation Power Source Maine, LLC as the new supplier of standard-offer electricity to CMP's residential and small commercial standard-offer class for a three-year period beginning March 1, 2002. In January 2003 the MPUC chose suppliers of standard-offer electricity for the six months beginning March 1, 2003: FPL Energy Power Marketing, Inc. for medium class customers and Select Energy , Inc. for larger customers.

All of Energy East's natural gas utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. (See Item 7 - Natural Gas Supply Agreements, NYSEG Natural Gas Rate Plan and Connecticut Regulatory Proceedings.)

NYSEG and RG&E use natural gas futures to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures is included in the commodity cost when the related sales commitments are fulfilled.

NYSEG and RG&E use electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity. The cost or benefit of those contracts is included in the amount expensed for electricity purchased when the electricity is sold.

NYSEG's electric rate plan offers retail customers choice in their electricity supply including a variable rate option, an option to purchase electricity supply from an alternative energy company, and a bundled rate option. Based on the results from the enrollment period that ended December 31, 2002, approximately 30% of NYSEG's total electric load is now provided by an alternative energy company or at the market price. NYSEG's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the bundled rate option, which combines delivery and supply service at a fixed price. For calendar years 2003 and 2004 the supply component is based on average electricity forward prices for 2003 and 2004 during September 2002, plus a 35% margin to cover the costs and risk that NYSEG is assuming by providing a bundled rate option to retail customers. NYSEG is actively hedging the load required to serve customers who select the bundled rate option. As of Ja nuary 31, 2003, NYSEG's load was 93% hedged for on-peak periods and 87% hedged for off-peak periods in 2003 and 86% hedged for both on-peak and off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.7 million in 2003 and $1 million in 2004. The percent of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

RG&E faces commodity price risk that relates to market fluctuations in the price of electricity and natural gas. Under its electric settlement, RG&E's electric rates were capped at specified levels through June 30, 2002. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. As of January 31, 2003, RG&E's load was 90% hedged for on-peak periods and fully hedged for off-peak periods in 2003 and fully hedged for both on-peak and off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of on-peak electricity would change earnings by $0.2 million in 2003. The percent of RG&E's hedged load is based on RG&E's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast. RG&E has filed a request with the NYPSC for new electric rates commencing i n January 2003. The NYPSC has not ruled on the rate request; therefore, RG&E's current fixed electric rates will remain in effect until a new rate order is issued. A new rate order is expected to be issued in March 2003, for electric rates retroactive to January 2003. (See Item 7 - RG&E 2002 Electric and Gas Rate Proceeding.)

While owned coal-fired and nuclear generation provides RG&E with a natural hedge against electric price risk, it also subjects it to operating risk. Operating risk is managed through a combination of strict operating and maintenance practices and the use of derivative contracts.

The broad and continued decline in credit quality across the energy supply and marketing industries combined with the withdrawal of many entities from energy trading operations could limit the company's ability to purchase electricity and place financial hedges with counterparties that meet its credit requirements. While the company has been successful in implementing its hedging strategies by finding creditworthy counterparties or requiring adequate financial

assurances in the form of cash or letters of credit, continued contraction and credit deterioration across the energy supply and marketing industries may adversely affect the company's ability to effectively implement its hedging strategies going forward.

Other Market Risk: The companies' pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in those markets as well as changes in interest rates cause the companies to recognize increased or decreased pension income or expense. If the expected return on plan assets were to change by 1/4%, pension income would change by approximately $6 million. (See Item 8 - Note 15 to the company's and Note 13 to CMP's Consolidated Financial Statements, and Note 13 to NYSEG's and Note 12 to RG&E's Financial Statements.)

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 involve risks and uncertainties and 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; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of changing energy prices; the operation of the New York Independent System Operator and ISO New England, Inc.; the operation of a regional transmission organization; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements now that most generation assets have been sold; the company's ability to expand its products and services, including its en ergy infrastructure in the Northeast; the company's ability to integrate the operations of Berkshire Energy, CMP Group, CNE, CTG Resources and RGS Energy with its operations and achieve anticipated synergies; 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 the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; and other considerations, such as the effect of the volatility in the equity markets on pension benefit cost, that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 8.  Financial statements and supplementary data

Index to 2002 Financial Statements

Item  9.  Changes in and disagreements with accountants on accounting and
financial disclosure

None for Energy East, CMP, NYSEG or RG&E.

All per share amounts and shares outstanding have been restated to reflect the two-for-one common stock split effective April 1, 1999.
Reclassifications: Certain amounts included in Selected Financial Data have been reclassified to conform with the 2002 presentation.
(1) Due to the completion of the company's merger transaction during 2002 the consolidated financial statements include RGS Energy's results beginning with July 2002.
(2) Includes the writedown of CMP Group's investment in NEON Communications, Inc. that decreased net income $7 million and earnings per share six cents and the effect of restructuring expenses that decreased net income $24 million and earnings per share 19 cents.
(3) Includes the writedown of CMP Group's investment in NEON Communications, Inc. that decreased net income $46 million and earnings per share 39 cents.
(4) Due to the completion of the company's merger transactions during 2000 the consolidated financial statements include CNE's results beginning with February 2000 and include CMP Group's, CTG Resources' and Berkshire Energy's results beginning with September 2000.
(5) Depreciation and amortization includes accelerated amortization of the Nine Mile Point 2 nuclear generating station (NMP2) related to the sale of the company's coal-fired generation assets, authorized by the NYPSC.

Restructuring

In 2002 Energy East initiated a corporate restructuring to achieve optimum organizational efficiency and effectiveness. The savings from this initiative are essential for the company to meet the rate reduction or efficiency targets imputed in utility rates by regulators, as well as to meet the expectations of customers and investors. In the fourth quarter of 2002 Energy East recorded $41 million of restructuring expenses, including $5 million for CMP, $26 million for NYSEG and a total of $10 million for Berkshire Gas, CNG and SCG. The restructuring expenses would have been $36 million higher, however RG&E was required by a NYPSC order approving RGS Energy's merger with the company to defer its portion of the restructuring charge for future recovery in rates. The employee positions affected by the restructuring were identified in the fourth quarter of 2002. The restructuring expenses reduced the company's 2002 net income by $24 million or 19 cents per share. Included in those amounts are $20 million for a voluntary early retirement program that will be paid from the companies' pension plans and $3 million for an involuntary severance program, primarily for salaried employees of the company's six operating utilities, and $1 million for other associated costs.

Those programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by April 30, 2003. That includes approximately 70 from CMP, 260 from NYSEG, 245 from RG&E and 75 from Berkshire Gas, CNG and SCG. The employees affected by the involuntary severance program were notified in January 2003.

Energy East and RGS Energy Merger

On June 28, 2002, Energy East completed its merger with RGS Energy. Under the merger agreement 45% of RGS Energy common stock, 15.6 million shares, was converted into 27.5 million shares of Energy East common stock valued at $612 million. The value of the shares issued was determined based on the market price of Energy East's stock at the end of the day on June 27, 2002. The remaining 55% of the RGS Energy common stock was exchanged for $753 million in cash, which was $39.50 per RGS Energy share. The purchase price was about $1.4 billion, which includes $11 million of merger-related costs. The transaction was accounted for using the purchase method. Energy East's consolidated statements of income and cash flows include RGS Energy's results of operations beginning with July 2002. (See Item 8 - Note 3 to the company's Consolidated Financial Statements.)

As a result of the merger RGS Energy became a wholly-owned subsidiary of Energy East. RG&E continues to be a wholly-owned subsidiary of RGS Energy and NYSEG became a wholly-owned subsidiary of RGS Energy.

The company's electric delivery business consists primarily of its regulated electricity generation, transmission and distribution operations in upstate New York and Maine.

Regional Transmission Organization (RTO): In July 2001 the FERC issued an order requiring the New York Independent System Operator (NYISO) and neighboring New England and Mid-Atlantic independent system operators (ISOs) to negotiate to form a single Northeast RTO. The NYISO and other parties involved in negotiating the formation of the Northeast RTO participated in mediation facilitated by a FERC administrative law judge (ALJ), leading to a business plan detailing the process to develop a Northeast RTO. The business plan, coupled with an ALJ's report, were submitted to the FERC. NYSEG, CMP and RG&E have consistently advocated the formation of a Northeast/Mid-Atlantic RTO, including PJM Interconnection, L.L.C. (PJM), or functionally combined markets throughout the Northeast because they believe that a larger wholesale power market is essential to facilitate greater liquidity and competition.

In January 2002 the ISO New England, Inc. (ISO New England) and the NYISO entered into an agreement to consider forming an RTO, and PJM entered into an agreement to form common market systems with the Midwest ISO. The ISO New England and the NYISO submitted a joint petition to the FERC on August 23, 2002, asking for a declaratory order stating that a merger of the two ISOs, as described in the petition, would satisfy FERC requirements for an RTO. On November 22, 2002, the New England ISO and the NYISO withdrew their proposal, citing opposition from stakeholders, including CMP, NYSEG and RG&E. The companies opposed the proposal because, among other things, it failed to demonstrate that the benefits outweighed the costs and failed to recognize the need for a larger market.

In October 2001 FERC commenced a proceeding to consider national standard market design issues and on July 31, 2002, issued a Notice of Proposed Rulemaking (the SMD NOPR). The SMD NOPR proposes rules that would require, among other things, changes in the wholesale power markets, transmission planning services and charges, market power monitoring and mitigation, and the organization and structure of ISOs. CMP, NYSEG and RG&E filed comments jointly with other transmission owners in November 2002 and January 2003. The companies generally support the proposed SMD because it would functionally combine the Northeast markets. The companies plan to file additional comments in 2003. The proposals in the SMD NOPR include the adoption of an energy market based on locational marginal pricing (LMP), which represents a significant change for some regions of the country. The NYISO already operates a market based on LMP, and ISO New England is in the process of developing and implementing an LMP system.

Transmission Planning and Expansion: In June and July 2001 FERC issued orders that addressed a number of transmission planning and expansion issues that would directly affect CMP, NYSEG and RG&E as transmission owners. The FERC orders discussed giving exclusive responsibility for the transmission planning process to a Northeast RTO, rather than the transmission owners. The orders also discussed redefining the cost-sharing responsibilities of interconnecting generators for transmission expansion costs. On April 24, 2002, and August 16, 2002, FERC issued NOPRs regarding generation interconnection terms, conditions and cost allocation. FERC is expected to issue a final rule in 2003. Additional transmission planning and

expansion proposals are included in the SMD NOPR. The company is unable to predict the ultimate effect, if any, of the expected rulemakings on its transmission system or on future capital expenditures.

On January 15, 2003, FERC issued a proposed policy statement on transmission pricing. FERC proposes a 50 basis point return on equity adder on facilities over which transmission owners turn control to an RTO. The NYISO and ISO New England satisfy most of the requirements of an RTO. Additionally, FERC proposes that unaffiliated third parties will receive the equivalent of an additional 150 basis point adder applicable to transmission facilities that transmission owning utilities divest. Finally, FERC proposes a 100 basis point adder for new transmission facilities found appropriate through an RTO planning process. The company is evaluating FERC's policy proposal and plans to file comments.

Electric Transmission Rates: On June 28, 2002, CMP made its required annual informational filing with FERC updating its local transmission formula rates. CMP's annual transmission revenue requirement increased by $0.6 million reflecting increased costs associated with transmission constraints during periods of high demand. Rates pursuant to this filing became effective June 1, 2002, and reflect actual cost and revenues from the 2001 calendar year.

Sale of Nuclear Interests: (See Item 8 - Note 10 to the company's and Note 9 to CMP's Consolidated Financial Statements.) On July 31, 2002, Vermont Yankee Nuclear Power Corporation sold the Vermont Yankee nuclear power plant, including CMP's 4% ownership interest, to Entergy Corporation. Any benefits realized from the sale, which are expected to be less than $1 million, will be used to reduce CMP customers' future obligations for stranded costs. The transaction included a power purchase agreement that calls for Entergy to provide all of the plant's electricity to the sellers through 2012, the year the operating license for the plant expires.

Upon completion of the sale of NMP2, an asset sale gain of approximately $110 million was recorded, in accordance with the NYPSC's order, as a regulatory liability under Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (Statement 71). The gain includes a gross up for unfunded future income taxes and is being returned to customers in accordance with NYSEG's current electric rate plan, which was approved by the NYPSC in February 2002.

CMP Alternative Rate Plan: In September 2000 the MPUC approved CMP's Alternative Rate Plan (ARP 2000). ARP 2000 applies only to CMP's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services. The revenue requirement related to transmission services is established by FERC. Recovery of stranded costs, primarily overmarket NUG contracts and nuclear decommissioning costs, has been provided for under Maine's Restructuring Law. 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.

On June 25, 2002, the MPUC approved a filing allowing CMP's distribution prices to change effective July 1, 2002. As a result, distribution rates for customers not subject to special contracts decreased by 4.84%. The reduction reflects a decrease of 3.03% in distribution rates resulting from expiring amortizations and the application of a price cap mechanism, and an additional one-time decrease of 1.81% reflecting over-collections of certain costs, such as for low-income assistance programs and insurance proceeds related to environmental remediation.

CMP Electricity Supply Responsibility: Under Maine Law adopted in 1997 CMP was mandated to sell its generation assets and relinquish its supply responsibilities. CMP no longer owns any generating assets but does retain its power entitlements under long-term contracts from NUGs and a power purchase contract with Vermont Yankee, and its ownership interests in three nuclear facilities that have been shut down. CMP's retail electricity prices are set to provide recovery of the costs associated with these ongoing obligations.

Under Maine Law the MPUC can mandate that CMP be a standard-offer provider for supply service if the MPUC should deem bids by competitive suppliers to be unacceptable. CMP has no standard-offer obligations through August 2003. If in the future CMP should have standard-offer obligations there would be no effect on net income because CMP is ensured cost recovery through Maine Law. CMP's revenues and purchased power costs will fluctuate, however, as its status as a standard-offer provider changes. (See the company's Operating Results for the Electric Delivery Business, CMP's Results of Operations and Item 8 - Note 9 to the company's and Note 8 to CMP's Consolidated Financial Statements.)

In September 2001 the MPUC chose Constellation Power Source Maine, LLC as the new supplier of standard-offer electricity to CMP's residential and small commercial standard-offer class for a three-year period beginning March 1, 2002. In January 2003 the MPUC chose suppliers of standard-offer electricity for the six months beginning March 1, 2003: FPL Energy Power Marketing, Inc. for medium class customers and Select Energy, Inc. for larger customers.

MPUC Stranded Cost Proceeding: In December 2001 the MPUC approved a stipulation among CMP, the Office of the Public Advocate and the Industrial Energy Consumer Group settling all issues related to the setting of CMP's stranded cost revenue requirement for the period March 1, 2002, through February 28, 2005. In January 2002 CMP submitted a compliance filing to the MPUC setting the three-year stranded cost revenue requirement. The amount of the revenue requirement reflects the ongoing costs related to CMP's remaining nondivested generating resources and the decommissioning of two nuclear power plants, offset by revenues to be received for the output from the remaining nondivested generating resources and amortization of amounts from CMP's gain on sale of generation assets account. Under the terms of the stipulation, parties can request a review of stranded costs if revenues differ significantly from anticipated costs. On December 17, 2002, the MPUC initiated an investigation to review CMP's&nb sp;current level of recovery of stranded costs, including the costs associated with decommissioning the Yankee Atomic plant. As ordered by the MPUC in this proceeding, CMP made its initial filing on February 7, 2003, concluding that no change in the current stranded costs rate is appropriate. CMP expects the MPUC to act on its filing by July 1, 2003.

NYSEG Electric Rate Plan: In February 2002 the NYPSC issued an Order (NYPSC February 2002 Order) approving a five-year NYSEG electric rate plan, which extends through December 31, 2006, and Energy East's merger with RGS Energy. The electric rate plan resulted from a settlement reached by the company, NYSEG, RGS Energy, RG&E, the NYPSC Staff, the Attorney General of the State of New York, the New York State Consumer Protection Board, Multiple Intervenors and other parties. NYSEG's 1998 electric rate and restructuring agreement and an NYPSC Order issued in January 2002, regarding temporary rates for NYSEG's electric customers, were superseded by the NYPSC February 2002 Order. The NYPSC February 2002 Order also provided for the discontinuance of several outstanding NYSEG proceedings. NYSEG's and the company's earnings were lower in 2002 (one year earlier than expected) as a result of the electric rate plan because NYSEG's electric rates now reflect the sale of generation assets that was c ompleted in 1999.

The NYPSC February 2002 Order reduced annualized electric rates by $205 million for NYSEG customers effective March 1, 2002, which amounted to an overall average reduction of 13% for most customers. In the first rate year ending December 31, 2002, approximately $55 million of the annualized reduction was funded with the partial amortization of an asset sale gain account created by NYSEG's sale in 2001 of its interest in NMP2. The NYPSC February 2002 Order also requires equal sharing of earnings between NYSEG customers and shareholders of returns on equity in excess of 15.5% for 2002, and equal sharing on the greater of returns on equity in excess of 12.5% on electric delivery, or 15.5% on the total electric business (including supply) for each of the years 2003 through 2006. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $700 million.

NYPSC-mandated Contracts with Two Customers: In March and April 2002 the NYPSC issued orders directing NYSEG to enter into long-term electric service contracts with Nucor Steel Auburn, Inc. and Corning Incorporated, that in NYSEG's opinion contain unduly low and preferential rates. In April 2002 NYSEG petitioned for rehearing of these orders on the basis that each order, and each underlying contract, violates law, NYSEG's tariffs and NYPSC guidelines. In May 2002 the NYPSC denied NYSEG's petitions for rehearing. On July 24, 2002, NYSEG filed a petition with the New York State Supreme Court, Albany County, asking the court to overturn the NYPSC's orders directing NYSEG to enter into the long-term electric service contracts because the rates and the terms of those mandated contracts are unduly preferential and violate the law, NYSEG's tariffs and the NYPSC's guidelines. Oral arguments were held in the proceeding on September 13, 2002. On December 9, 2002, the State Supreme Court dismissed NYSE G's petition. NYSEG has appealed that dismissal to the Appellate Division, Third Department, of the New York State Supreme Court. On September 24, 2002, and November 25, 2002, consistent with the NYPSC's orders, NYSEG signed the mandated contracts under protest, subject to review by the courts.

Lost revenues associated with these long-term electric service contracts are recovered through the asset sale gain account created by NYSEG's sale in 2001 of its interest in NMP2 and do not affect earnings. After giving effect to the amortization of the asset sale gain account to fund the first year of the electric rate reduction (see NYSEG Electric Rate Plan), the remaining balance would be entirely consumed by discounts offered to these two large industrial customers. NYSEG believes that the remaining balance should not be used for discounts provided to just two customers, but should be available to fund other economic development projects and for the recovery of uncontrollable costs.

Nonutility Generation: In December 1999 NYSEG notified the owners of Allegheny Hydro No. 8 and Allegheny Hydro No. 9 demanding that they each provide adequate assurance that they will perform their individual contractual obligations under two power purchase agreements with NYSEG, including the obligation to pay back overpayments made by NYSEG over the course of the agreements. Such overpayments are the cumulative difference between the rate NYSEG pays for power under the agreements and its actual avoided costs. At the end of 2002 this cumulative overpayment was more than $170 million and is expected to grow substantially by 2030 when both agreements expire. Allegheny and its lenders filed a motion in the New York State Supreme Court (N.Y. County) seeking a declaration that NYSEG's demand for adequate assurance was improper. The motion was denied by the court in September 2002. Unless a settlement can be reached, the matter is expected to proceed to trial.

CMP and NYSEG together expensed approximately $611 million for NUG power in 2002. They estimate that their combined NUG power purchases will total $613 million in 2003, $632 million in 2004, $642 million in 2005, $578 million in 2006 and $544 million in 2007. CMP and NYSEG continue to seek ways to provide relief to their customers from above-market NUG contracts that state regulators ordered the companies to sign, and which, in 2002, averaged 8.7 cents per kilowatt-hour for CMP and 8.3 cents per kilowatt-hour for NYSEG. Recovery of these NUG costs is provided for in CMP's and NYSEG's current regulatory plans. (See Item 8 - Note 9 to the company's Consolidated Financial Statements.)

RG&E 2002 Electric and Gas Rate Proceeding: On February 15, 2002, RG&E filed a request with the NYPSC for new electric and natural gas rates to go into effect on January 15, 2003. Subsequently, the date for a decision by the NYPSC was extended to March 2003 with a "make-whole" provision under which rates and any associated mechanisms would be adjusted to put RG&E and its customers in the same position they would have been had rates been allowed to go into effect as of January 15, 2003. The filing included both a traditional single-year filing and elements of a multi-year proposal for potential settlement negotiations. The single-year filing, as updated, provides a basis to increase annual electric rates by $40 million, or 5.7%, and increase annual natural gas rates by $19 million, or 6.6%, for the 12-month period ending June 30, 2003. RG&E's current base rates for electric and natural gas service will remain in effect until a new order is issued by the NYPSC. A lack of progre ss did not justify continuation of settlement discussions at that time and the parties proceeded on a litigation track. Evidentiary hearings took place in late October 2002. On December 17, 2002, the ALJ in this proceeding issued a recommended decision that, if approved, would result in a $9 million, or 3.3%, overall increase for natural gas service and no increase for electric service. Briefs on exception to the recommended decision were filed on January 7, 2003. Briefs opposing exceptions were filed on January 17, 2003. Following the submission of briefs settlement conferences in the natural gas rate proceeding were held.

As part of the current RG&E rate proceeding, the ALJ found RG&E to have excess electric earnings of $45 million, including interest, from RG&E's prior rate plan. RG&E continues to believe its reserve of $26 million for the estimated five-year excess earnings is appropriate. The calculation of the excess earnings will be subject to final approval by the NYPSC. RG&E is unable to predict what the NYPSC's ultimate determination of excess earnings under RG&E's prior rate plan will be.

Ginna Station: Several nuclear power plant operators have identified defects in their reactor vessel heads, which has prompted heightened Nuclear Regulatory Commission (NRC) oversight. During the summer of 2001 RG&E thoroughly reviewed this issue and an inspection plan was implemented during the spring 2002 refueling outage. Although the inspection demonstrated that the Ginna station could continue to operate with the existing head, RG&E decided to replace the reactor vessel head in order to avoid significant expenditures associated with maintenance, inspections and length of future outages. The replacement is scheduled to be completed during the fall 2003 refueling outage. The duration of the 2003 refueling outage is not expected to be significantly different than the duration of previous outages. The cost of the replacement is estimated to be $13 million and is expected to be recovered in rates.

Ginna Relicensing: The Ginna station operating license expires in 2009. On July 31, 2002, RG&E filed a license renewal application with the NRC, which, if approved, would extend the license through September 2029. The NRC has deemed the application complete. The NRC held two sets of public meetings in 2002, and plans to hold one more in 2003. RG&E's renewal application was unopposed. A decision on this matter is expected by the end of 2004.

The company's natural gas delivery business consists of its regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts.

Natural Gas Supply Agreements: Four of Energy East's natural gas companies - NYSEG, SCG, CNG and Berkshire Gas - have a two-year strategic alliance with BP Energy Company, effective April 1, 2002, for the acquisition, optimization and management of certain natural gas supply, transportation and storage services, including portfolio management. The alliance provides the companies with greater supply flexibility, enhances the benefits of a larger natural gas portfolio and is based on sharing incremental savings. The companies still own and control their natural gas assets and work with BP Energy to obtain the lowest cost supply while maintaining reliability of service. The Energy East natural gas companies have received the required regulatory approvals concerning the alliance.

RG&E entered into a two-year supply portfolio management agreement that began April 1, 2002, with Dynegy Marketing and Trade, for Dynegy to assist RG&E in the cost-effective management of RG&E's firm contractual rights to natural gas supply, transportation and storage services. The agreement is designed to ensure that RG&E can reliably meet its customers' supply requirements while seeking to minimize the annual delivered cost of natural gas. On October 16, 2002, Dynegy announced that it would exit the marketing and trading business over the next several months. As a result of Dynegy's actions RG&E terminated its agreement with Dynegy and entered into a new portfolio management agreement with Entergy-Koch Trading, LP. The new arrangement with Entergy-Koch will extend through March 31, 2004, and includes the same reliability and cost-minimization objectives as the prior agreement with Dynegy. RG&E is assessing its position relative to the Dynegy termination and will take appr opriate action to resolve any outstanding issues.

NYSEG Natural Gas Rate Plan: On November 20, 2002, the NYPSC approved the joint proposal that NYSEG filed with the NYPSC on September 13, 2002, and that had been endorsed by NYPSC Staff, the NY State Consumer Protection Board, large customer groups and numerous gas marketers. The approved natural gas rate plan became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, and implements a gas supply charge to collect the actual costs of gas and contains an earnings sharing mechanism. The earnings sharing mechanism requires equal sharing of earnings between NYSEG customers and shareholders of returns on equity in excess of 11.5% for the 27-month period ended December 31, 2004, and in excess of 12.5% for each of the calendar years from 2005 through 2008. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $240 million.

Connecticut Regulatory Proceedings: During 2001 the Connecticut Office of Consumer Counsel (OCC) filed appeals in State Superior Court arguing that the DPUC's order in December 2000 approving an SCG multi-year incentive rate plan (IRP) and its order in May 2001 approving a CNG IRP were unlawful. In March 2001 the OCC filed a Motion to Stay the implementation of the DPUC's order concerning the SCG IRP, but the court denied the motion in June 2001. In August 2001 the court appeals for SCG's and CNG's IRPs were combined.

In October 2001 SCG and CNG reached a settlement with the OCC, also endorsed by Prosecutorial Staff of the DPUC, resolving numerous outstanding regulatory and legal proceedings. The proceedings resolved by the settlement include a review of past SCG affiliate transactions, SCG's Purchased Gas Adjustment Clause (PGA) charges and credits, alleged overearnings at SCG and CNG, and a court appeal of the DPUC-approved IRPs for SCG and CNG.

SCG and CNG received a final decision from the DPUC approving the settlement in February 2002. The settlement provided rate reductions of $1.5 million for SCG and $0.5 million for CNG, effective October 1, 2001, extends the approved IRPs for an additional year through September 2005 and maintains an earnings sharing mechanism (ESM) that generally shares any earnings above the authorized returns on equity equally between shareholders and customers. The settlement also permits the recovery of SCG deferred gas costs through the PGA and through the customer portion of earnings sharing by the end of the IRP in 2005. Merger-enabled gas costs savings for both companies are also shared equally between customers and shareholders, with the shareholder portion recovered through the PGA.

In June 2002 the DPUC initiated proceedings to address the need for an interim rate decrease for SCG. Upon review of SCG's financial reports the DPUC concluded that a rate decrease was not required. SCG's earnings in excess of its allowed rate of return were primarily the result of merger-enabled gas costs savings and provided a direct benefit to customers because of the ESM that is an integral part of SCG's IRP.

In April 2002 the DPUC initiated a semiannual review of CNG's PGA. The DPUC issued its draft decision in December 2002, disallowing approximately $1 million of natural gas costs that would be returned to customers through the PGA. As a result, at December 31, 2002, CNG recognized a liability of $1 million for those costs. The DPUC has postponed its final decision in this matter.

Berkshire Gas Rate Increase: In January 2002 the DTE approved a rate increase of $2.3 million, or 4.5%, on total annual revenues for Berkshire Gas. The new rates became effective February 1, 2002. The DTE's approval included Berkshire Gas' proposal for a 10-year incentive-based rate plan with a midperiod review after five years. After the initial rate increase, rates will be frozen until September 2004, at which time rates will be adjusted annually based on inflation less a 1% consumer dividend. The DTE also approved Berkshire Gas' proposed rate design based on seasonal rates for residential and small commercial and industrial customers that are the same in the winter and summer. Berkshire Gas' proposal for service quality enhancements will be addressed in another proceeding.

RG&E 2002 Electric and Gas Rate Proceeding: See Electric Delivery Business.

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive natural gas and electricity markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets and providing recommendations concerning Provider of Last Resort and related issues. In a separate phase of this proceeding, the NYPSC issued an order in November 2001 directing the development of embedded cost of service studies for use in implementing unbundled rates. The embedded cost of service studies have been filed and are currently under review.

The company's other businesses include a nonutility generating company, a liquid fuels distribution company, a retail energy marketing company, telecommunications assets, a propane distribution company, a district heating and cooling system, a FERC-regulated liquefied natural gas peaking plant and an energy services and construction company.

Sale of Other Businesses: The company continues to rationalize its nonutility businesses to ensure they fit its strategic focus. On August 12, 2002, Berkshire Service Solutions, Inc., an energy services provider and a subsidiary of Berkshire Energy, was sold at a loss of about $2 million. Berkshire Energy is a wholly-owned subsidiary of Energy East. During the fourth quarter of 2002 CNE Venture Tech Inc., a subsidiary of CNE, sold its 5% interest in the Nth Power Technologies Fund II, LP, at a loss of about $1 million.

Maine Natural Gas: In June 2001 Maine Natural Gas began construction of a new natural gas distribution system to serve the towns of Bowdoin, Brunswick and Topsham, Maine. It has served natural gas to certain larger customers since November 2001 and began serving residential and commercial customers in early 2002. Maine Natural Gas is also expanding its distribution system in Windham and Gorham, Maine.

Natural Gas Storage Facility: In August 2001 Seneca Lake Storage, Inc. (SLSI), a subsidiary of the company, announced plans to develop a high-deliverability natural gas storage facility in depleted salt caverns in the Town of Reading, New York. SLSI is currently assessing the demand for the facility. The storage facility would be linked to interstate pipelines, have a working gas capacity of 300,000 dekatherms (dth) and be capable of delivering up to 50,000 dth a day. In February 2002 FERC issued a certificate allowing the construction of certain

natural gas storage facilities and requiring that the facilities be completed and made available for service within one year of the order. In December 2002 the FERC granted a request by SLSI to modify the certificate to extend by one year the date within which SLSI has to complete construction of the proposed facilities and initiate service.

Statement 71: Statement 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.

The company believes its public utility subsidiaries will continue to meet the criteria of Statement 71 for their regulated electricity and natural gas operations in New York State, Connecticut, Maine and Massachusetts; however, the company cannot predict what effect a competitive market or future actions of the NYPSC, MPUC, DPUC or DTE will have on their ability to continue to do so. If the company's public utility subsidiaries can no longer meet the criteria of Statement 71 for all or a separable part of their regulated operations, they may have to record as expense or revenue certain regulatory assets and liabilities.

Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The company adopted Statement 143 as of January 1, 2003. The adoption of Statement 143 did not have a material effect on the company's financial position or results of operations. (See Item 8 - Note 1 to the company's Consolidated Financial Statements.)

Statement 145: In April 2002 the FASB issued Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. Early application of the provisions of Statement 145 is encouraged and the company elected to do so beginning in April 2002. The company now classifies the aggregate of gains and/or losses from the early extinguishment of debt as other income or other deductions on its income statement, as appropriate, instead of as an extraordinary item. The company has reclassified such extraordinary items presented on its income statements in prior periods. The remaining provisions of Statement 145 did not have a material effect on the company's financial position or results of operations.

Statement 146: In June 2002 the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities. Statement 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than at a plan or commitment date for the exit or disposal activity. It establishes fair value as the objective for initial measurement of the liability. The provisions of Statement 146 are effective for exit or disposal activities initiated after December 31, 2002. The company and its subsidiaries have determined that their adoption of Statement 146 on January 1, 2003, did not have a material effect on their results of operations or financial position.

At December 31, 2002, the company's contractual obligations and commercial commitments that will become due during the next five years are:

Energy East has two revolving credit agreements in which it covenants not to permit, without the consent of the lenders, its ratio of consolidated indebtedness to consolidated total capitalization at the last day of any fiscal quarter to exceed 0.65 to 1.00. Continued unremedied failure to comply with this covenant for 15 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. Energy East's ratio of consolidated indebtedness to consolidated total capitalization was 0.59 to 1.00 at December 31, 2002.

CMP has a revolving credit facility, which is secured by its accounts receivable, in which it covenants that (i) its consolidated total debt shall at all times be no more than 65% of the sum of its consolidated total debt and its total stockholders equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00. Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2002, CMP's consolidated total debt ratio was 33.6% and its interest coverage ratio was 3.73 to 1.00.

NYSEG and RG&E have a joint revolving credit agreement in which they each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2002, the ratio of earnings

before interest expense and income tax to interest expense was 3.4 to 1.0 for NYSEG and 2.3 to 1.0 for RG&E, and the ratio of total indebtedness to total capitalization was 0.53 to 1.00 for NYSEG and 0.52 to 1.00 for RG&E.

NYSEG has two letters of credit and reimbursement agreements in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 as of the last day of any fiscal quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2002.

In preparing the financial statements in accordance with generally accepted accounting principles, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. The company's most critical accounting policies include the determination of the appropriate accounting for its pensions and other postretirement benefits, the effects of utility regulation on its financial statements and its risk management activities and the estimates and assumptions used to complete its annual goodwill and other intangibles impairment analyses.

Goodwill and Other Intangible Assets: As required by Statement 142, effective January 1, 2002, the company no longer amortizes goodwill and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized and are reviewed for impairment. The impairment test includes various assumptions. The primary assumptions are the discount rate and forecasted cash flows. Changes in those assumptions could have a significant effect on the company's determination of an impairment. (See Item 8 - Note 4 to the company's and Note 3 to CMP's Consolidated Financial Statements and Note 3 to NYSEG's and RG&E's Financial Statements.)

Pension and Other Postretirement Benefit Plans: The company has pension and other postretirement benefit plans covering substantially all of its employees. In accordance with Statement of Financial Accounting Standards No. 87, Employer's Accounting for Pensions, and Statement of Financial Accounting Standards No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, the valuation of benefit obligations and the performance of plan assets are subject to various assumptions. The primary assumptions include the discount rate, expected return on plan assets, rate of compensation increase, health care cost inflation rates, expected years of future service under the pension benefit plans and the methodology used to amortize gains or losses. Changes in those assumptions could also have a significant effect on the company's noncash pension income or expense or on the company's postretirement benefit costs. As of December 31, 2002, the company decreased the discount rate from 7.0 % to 6.5% and the expected return on plan assets from 9.0% to 8.75% effective January 1, 2003. (See the company's, CMP's, NYSEG's and RG&E's Results of Operations, Other Items.)

Risk Management: See Item 7A - Quantitative and Qualitative Disclosures About Market Risk and Item 8 - Note 1 to the company's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.

Utility Regulation: The company's regulated utilities are subject to regulation by their respective state regulatory commissions and the FERC. Approximately 90% of the company's revenues are derived from operations that are accounted for pursuant to Statement 71. The rates the utilities charge their customers are based upon cost basis regulation reviewed and approved by those regulatory commissions. (See Other Matters, Accounting Issues, Statement 71.)

Investing Activities: Capital spending totaled $229 million in 2002, $223 million in 2001 and $168 million in 2000, including capital spending for RGS Energy and nuclear fuel for RG&E beginning July 1, 2002. Capital spending does not include the amounts representing the company's merger transaction for RGS Energy in 2002 nor the four merger transactions in 2000. (See Item 8 - Note 3 to the company's Consolidated Financial Statements.) Capital spending in all three years was financed with internally generated funds and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements and governmental mandates.

Capital spending is projected to be $338 million in 2003, which includes RGS Energy and nuclear fuel. It is expected to be paid for with internally generated funds and will be primarily for the same purposes described above and merger integration. (See Item 8 - Note 9 to the company's Consolidated Financial Statements.)

The company's pension plans generated pretax noncash pension income (net of amounts capitalized) of $70 million in 2002, compared to $76 million in 2001 and $68 million in 2000. The company expects noncash pension income (net of amounts capitalized) for 2003 to decline, affecting earnings by approximately 15 cents per share as compared to 2002. That expected decrease is due to the significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute its pension liability (reduced from 7% to 6.5% as of December 31, 2002) and return on assets (reduced from 9% to 8.75% effective January 1, 2003). The company anticipates minimal funding requirements in 2003 as total plan assets approximates the projected benefit obligation. The company is currently unable to predict the effect that future equity market performance will have on pension income for 2004 and beyond. (See Item 8 - Note 15 to the company's Consolidated Financial Statements.)

Financing Activities: (See Item 8 - Note 6 to the company's Consolidated Financial Statements.)

The company raised its common stock dividend 4% in January 2003 to a new annual rate of $1.00 per share.

During 2002 the company repurchased 113,500 shares of its common stock at an average price of $18.85 per share. Future repurchases will depend on expected cash flows, alternative uses of cash, and overall economic and market conditions.

In August 2001 the company began issuing new common shares through its Dividend Reinvestment and Stock Purchase Plan (DRIP) rather than purchasing them on the open market. During 2002 the company issued 852,824 shares at an average price of $20.92 per share through its DRIP, substantially out of treasury stock. The company expects to issue approximately one million shares per year under this plan.

In December 2002 the company amended its DRIP to allow nonshareholders who reside in Connecticut, Maine, Massachusetts or New York State to enroll directly in the Plan by making an initial cash investment.

The company and its subsidiaries have credit agreements with various expiration dates in 2003 and 2005. The agreements provided for maximum borrowings of $755 million at December 31, 2002 and 2001. (See Contractual Obligations and Commercial Commitments.)

The company and its subsidiaries use short-term, unsecured notes and drawings on their credit agreements (see above) to finance certain refundings and for other corporate purposes. There was $322 million of such short-term debt outstanding at December 31, 2002, and $173 million outstanding at December 31, 2001. The weighted-average interest rate on short-term debt was 2.1% at December 31, 2002, and 2.6% at December 31, 2001.

In May 2001 the company filed a shelf registration statement with the SEC to sell up to $1 billion in an unspecified combination of debt and trust preferred securities. The company has issued $995 million of debt and trust preferred securities under the shelf registration statement to fund the cash portion of the consideration for the merger with RGS Energy, for general corporate purposes, such as short-term debt reduction and to fund an equity contribution to NYSEG in 2001. (See Energy East and RGS Energy Merger.)

In June 2002 the company issued $400 million of 6.75% 10-year notes due June 2012 under the shelf registration statement described above. The proceeds were used to help fund the RGS Energy merger.

In July 2002 the company entered into a fixed-to-floating interest rate swap on the company's 5.75% notes due November 2006. The company receives a fixed rate of 5.75% and will pay a rate based on the six month London Interbank Offered Rate (LIBOR) plus 1.565%, on a notional amount of $250 million through November 2006.

In July 2002 the company terminated a fixed-to-floating interest rate swap on the company's 8.05% notes due November 2010. The company received $16 million, the value of the swap on the date of termination, and will amortize about $15 million of that gain over the remaining life of the notes.

CMP issued the following Series E Medium Term Notes, the proceeds of which were used to repay $50 million of maturing medium-term notes, as well as short-term debt and for general corporate purposes in 2002: in May 2002 - $37.5 million, 6.50%, due May 2009 and $37.5 million, 6.65%, due May 2012; in August 2002 - $15 million, 5.70%, due August 2012; in September 2002 - $15 million, 4.25%, due September 2007; and in November 2002 - $15 million, quarterly adjustable rate based on the three month LIBOR plus 0.6%, due January 2006.

In May 2002 NYSEG redeemed, at a premium, $150 million of 8 7/8% Series first mortgage bonds due November 1, 2021, and redeemed, at par, the remaining $21.34 million of two 9 7/8% Series first mortgage bonds due 2020. The redemptions were financed with internally generated cash and the proceeds from the prepayment of a promissory note by Constellation Nuclear in April 2002. (See Sale of Nuclear Interests). NYSEG incurred a $10 million reduction to earnings in the second quarter of 2002 as a result of these redemptions, but will save over $16 million each year in interest costs. (See Other Matters, Statement 145.)

In November 2002 NYSEG issued $150 million of 4 3/8% unsecured notes due November 2007 and $100 million of 5 1/2% unsecured notes due November 2012. NYSEG used the net proceeds from those notes to refund commercial paper that was used in October 2002 to repay $150 million of maturing 6 3/4% Series first mortgage bonds and to repay $100 million of 8.30% Series first mortgage bonds that were called on December 15, 2002.

In 2003 NYSEG plans to call its remaining first mortgage bonds: $50 million of 7.55% Series first mortgage bonds callable on April 1, 2003, and $100 million of 7.45% Series first mortgage bonds callable on July 15, 2003. Additional financing needed by NYSEG to call its remaining first mortgage bonds is expected to be completed in June 2003. Through financial instruments issued in September 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.085%.

On January 9, 2003, RG&E used a $50 million equity contribution from its parent, RGS Energy, along with internally generated funds, to pay off the remaining $80 million balance of a 7% promissory note that was due to mature in 2014.

In July 2002 CNG paid at maturity $10 million of medium term notes using short-term debt. In October 2002 CNG redeemed $3.5 million of Series AA first mortgage bonds, including $2.5 million pursuant to a sinking fund provision and $1 million at a premium, using short-term debt.

Due to the various mergers completed by the company, its results of operations include for 2002: RGS Energy beginning with July 2002; and for 2000: CNE beginning with February 2000 and CMP Group, CTG Resources and Berkshire Energy beginning with September 2000.

Earnings Per Share

Earnings per share for 2002 were $1.44 compared to $1.61 for 2001, and include the nonrecurring items shown in the following table. The decrease in earnings for 2002 excluding nonrecurring items was primarily the result of an electric rate reduction of $205 million ordered by the NYPSC for NYSEG, effective March 1, 2002, which reduced earnings 50 cents per share. Other items that reduced earnings include: 16 cents per share for higher operating costs, such as the cost of merger integration efforts; 15 cents per share for fewer wholesale sales at lower market prices and 7 cents per share for a loss on early retirement of debt. Those decreases were significantly offset by increases of 29 cents per share due to lower natural gas costs, which includes the benefit of NYSEG's natural gas supply charge that went into effect October 1, 2002; 13 cents per share for higher electric deliveries (primarily residential and commercial) due to warmer summer weather in 2002 and colder winter weather in the fourth quarter of 2002; and 19 cents per share due to the elimination of goodwill amortization in 2002.

Earnings per share for 2001 were $1.61 compared to $2.06 for 2000, and include the nonrecurring items shown in the following table. The increase in 2001 earnings excluding nonrecurring items was primarily due to 20 cents per share for cost control efforts, 10 cents per share due to earnings from the merged companies, 1 cent per share for a loss on early retirement of debt in 2000 and 4 cents per share for a loss on the sale of XENERGY in 2000. Those increases were partially offset by 23 cents per share for lower electric and natural gas deliveries due to warmer weather and 13 cents per share for reduced electric transmission revenues.

The company provides information on earnings exclusive of nonrecurring items because it believes this information may be helpful to investors in assessing the company's results of ongoing operations. The company cautions investors that its view of nonrecurring items may differ from that of other companies and earnings exclusive of nonrecurring items should not be used as a surrogate for reported earnings prepared in accordance with generally accepted accounting principles.

Other operating expenses includes net periodic pension benefit income of $70 million in 2002, $76 million in 2001 and $68 million in 2000. Other operating expenses would have been $6 million lower for 2002 and would have been $8 million higher for 2001 without those changes in net periodic pension benefit income. Net periodic pension benefit income represented 22% of net income for 2002, 24% for 2001 and 17% for 2000. The earnings effect from differences between actual and projected pension benefit income was based on any earnings sharing mechanisms approved by state utility commissions.

Other (income) decreased $8 million in 2002 primarily due to a decrease in miscellaneous income of $6 million, and decreased $14 million in 2001 primarily due to an $18 million decrease in interest income largely due to funds used to finance the company's merger transactions in 2000. Other deductions increased $10 million in 2002 primarily due to NYSEG's $16 million loss on early retirement of debt and were unchanged in 2001. (See Financing Activities and Item 8 - Note 1 to the company's Consolidated Financial Statements.)

Interest charges increased $41 million in 2002 including $34 million because of the addition of RGS Energy and $17 million for additional borrowings to finance the company's merger transaction with RGS Energy. Those increases were partially offset by $10 million of interest savings due to NYSEG's refinancings and repayments of first mortgage bonds. Interest charges increased $65 million in 2001 due to a $32 million increase for additional borrowings to finance the company's merger transactions, including the RGS Energy merger, and a $32 million increase for interest charges due to the acquisitions of CNE, CMP Group, CTG Resources and Berkshire Energy in 2000.

The $18 million increase in preferred stock dividends in 2002 includes $16 million due to the company's issuance of trust preferred securities in July 2001 and $2 million because of the addition of RGS Energy. Preferred stock dividends increased $13 million in 2001 due to the company's issuance of trust preferred securities in July 2001.

The effective tax rate was 31% in 2002 and 43% in 2001. The decrease is the result of various items including the elimination of goodwill amortization in 2002, the flow-through effect (in 2001 only) of the sale of NMP2, a lower state income tax rate in 2002 due to combined filing benefits, and an increase in distributions on trust preferred securities that were outstanding for a full year in 2002.

Operating Revenues: The $63 million increase in operating revenues for 2002 is primarily due to the addition of RG&E's delivery revenues of $369 million and increased retail deliveries of $33 million primarily due to warmer summer weather in 2002. Those increases were partially offset by a reduction of $138 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002; $114 million due to a rate reduction for NYSEG, effective March 1, 2002; and lower wholesale revenues of $64 million primarily due to lower market prices for electricity.

Operating revenues for 2001 increased $481 million compared to 2000 primarily due to the first full year of CMP's delivery revenues, which added $565 million, and amortization of deferred gains of $9 million. Those increases were partially offset by $37 million due to lower wholesale deliveries because of warmer weather, $32 million as a result of CMP no longer collecting revenue for the supply of electricity to certain retail customers and $22 million due to reduced transmission revenues.

Operating Expenses: Operating expenses for 2002 increased $168 million. The increase in operating expenses for 2002 was $131 million excluding $25 million for restructuring expenses in 2002 and $12 million for the effect of the sale of NYSEG's share of NMP2 in 2001. That increase includes $291 million for the addition of RG&E's operating expenses; $15 million of purchased power costs for higher retail deliveries due to warmer summer weather in 2002 and colder winter weather in the fourth quarter of 2002; $15 million for merger integration efforts; and $44 million for purchased power costs to replace energy previously provided by NMP2, which was partially offset by a $35 million decrease in certain operating expenses due to the sale of NMP2. Those increases were partially offset by decreases including $138 million of electricity purchased because CMP is no longer the standard-offer provider for the supply of electricity, $32 million due to lower market prices for electricity and $9 million due to the elimination of goodwill amortization in 2002.

Operating expenses for 2001 increased $411 million. The increase in operating expense for 2001 was $423 million, excluding $12 million for the effect of the sale of NYSEG's share of NMP2, primarily due to the first full year of CMP's operating costs of $490 million. That increase was partially offset by $31 million because of lower purchased power costs primarily due to lower deliveries, $17 million for lower electricity supply costs because CMP no longer supplies electricity unless directed to by the MPUC, and $18 million due to cost control efforts relating to retirement benefits and compensation.

Operating Revenues: Operating revenues increased $6 million for 2002. Operating revenues increased $126 million due to the addition of RG&E's delivery revenues and $8 million due to increased deliveries primarily because of colder winter weather in the fourth quarter of 2002. Those increases were partially offset by a $98 million decrease because of lower market prices of natural gas that are passed on to customers and a $30 million decrease due to fewer wholesale customers.

For 2001, operating revenues increased $254 million primarily due to the first full year of revenues from SCG - $69 million, CNG - $245 million and Berkshire Gas - $45 million. Recovery of natural gas costs primarily from nonresidential deliveries also added $27 million to revenues. Those increases were partially offset by $116 million due to lower deliveries because of warmer weather and $11 million due to lower natural gas prices for wholesale sales.

Operating Expenses: Operating expenses decreased $54 million for 2002. The decrease in operating expenses for 2002 was $69 million excluding $15 million for restructuring expenses. That decrease was primarily due to a $159 million decrease in purchased gas costs caused by lower market prices, a $33 million decrease in purchased gas due to fewer wholesale customers and a $15 million decrease due to the elimination of goodwill amortization in 2002. Those decreases were partially offset by $115 million for the addition of RG&E's operating expenses, $9 million for increased purchases of natural gas due to higher deliveries because of colder winter weather in the fourth quarter of 2002, $9 million for higher uncollectible expenses and $6 million for merger integration efforts.

Operating expenses for 2001 increased $237 million primarily due to the first full year of natural gas purchases and operating costs for SCG - $58 million, CNG - $218 million and Berkshire Gas - $41 million. Those increases were partially offset by $60 million of reduced purchased natural gas costs due to lower prices and deliveries and $13 million for cost control efforts relating to retirement benefits and compensation.