(1) All shares are owned by CMP Group, Inc., a wholly-owned subsidiary of Energy East Corporation.
⁽²⁾ All shares are owned by RGS Energy Group, Inc. a wholly-owned subsidiary of Energy East Corporation.

This combined Form 10-Q is separately filed by Energy East Corporation, Central Maine Power Company, New York State Electric & Gas Corporation and Rochester Gas and Electric Corporation. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

Energy East Corporation
Consolidated Statements of Income - (Unaudited)

Energy East Corporation
Consolidated Statements of Cash Flows - (Unaudited)

Item 2.  Management's discussion and analysis of financial condition
             and results of operations

Restructuring

In 2002 Energy East Corporation (Energy East or the company) initiated a corporate restructuring to achieve optimum organizational efficiency and effectiveness. The savings from that 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 related to its voluntary early retirement and involuntary severance programs at six of its operating companies. There was no change during the first quarter of 2003 in the related liability recorded. The voluntary early retirement resulted in a decline of 486 employees in the first quarter of 2003, including 34 from Central Maine Power Company (CMP), 210 from New York State Electric & Gas Corporation (NYSEG) and 176 from Rochester Gas and Electric Corporation (RG&E). Collectively the voluntary early retirement and involuntary severance program s are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by the end of 2003. Integration savings, previously estimated at over $80 million annually, are now expected to be approximately $100 million by 2006. These savings, which include operating expenses and capital, will come from the consolidation of functions such as accounting, finance, information services and supply chain, as well as the implementation of other merger-enabled initiatives across the six operating utilities. On March 18, 2003, Energy East filed an application with the Securities and Exchange Commission (SEC) requesting authorization to form a shared services company that will provide those functions. Energy East expects that the SEC will act on the request in the second half of 2003. (See report on Form 10-K for Energy East, CMP, NYSEG and RG&E for fiscal year ended December 31, 2002, Item 7 - Liquidity and Capital Resources, Restructuring.)

Regional Transmission Organization (RTO): In July 2001 the Federal Energy Regulatory Commission (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. (See report on Form 10-K for Energy East, CMP, NYSEG and RG&E for fiscal year ended December 31, 2002, Item 7 - Electric Delivery Business, Regional Transmission Organization.) 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.

On January 16, 2003, ISO New England, Inc. (ISO New England) announced that it would work with New England transmission owners to seek input and the advice of all market participants, regulators and other stakeholders to pursue the creation of a New England-only RTO. ISO New England and the NYISO are considering individual RTO filings and better coordination with neighboring systems. CMP, NYSEG and RG&E are participating in these efforts.

FERC Standard Market Design: In October 2001 FERC commenced a proceeding to consider national standard market design (SMD) issues and in July 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 in early 2003. On April 28, 2003, the FERC issued a white paper on SMD in which the FERC accommodates greater regional flexibility and seeks further comments. CMP, NYSEG and RG&E plan to submit comments. The SMD white paper includes a preference for energy markets based on locational marginal pricing (LMP), which represents a significant change for some regions of the country. The NYISO and ISO New England already operate markets based on LMP. A final SMD rule is expected in the second half of 2003. The companies are unable to predict SMD's ultimate effect, if any, on their results of operations or financial position.

Transmission Planning and Expansion and Generation Interconnection: In June and July 2001 FERC issued orders that address a number of transmission planning and expansion issues that would directly affect CMP, NYSEG and RG&E as transmission owners. The FERC orders discuss giving exclusive responsibility for the transmission planning process to a Northeast RTO, rather than the transmission owners, and also discuss redefining the cost-sharing responsibilities of interconnecting generators for transmission expansion costs. In April 2002 and August 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.

In January 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. In addition, 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 filed comments on the FERC's policy proposal in the first half of 2003.

NYISO Demand Curve Proposal: On March 21, 2003, the NYISO filed with the FERC a proposal to amend its services tariff to adopt a demand curve. If implemented, the NYISO would use the demand curve to establish administratively determined electric capacity prices and the quantity of capacity that each load-serving entity, including NYSEG and RG&E, would be required to purchase. NYSEG, RG&E and many other parties filed protests in opposition to the use of a demand curve. The FERC may not permit the NYISO to implement the demand curve or may require significant modifications to it. NYSEG and RG&E are unable to predict the proposed demand curve's ultimate effect, if any, on their results of operations or financial position.

CMP Alternative Rate Plan: In September 2000 the Maine Public Utilities Commission (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. 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. In March 2003 CMP submitted its annual ARP filing proposing a decrease of $18 million, which reflects a decrease in ice storm amortization expense and other items.

MPUC Stranded Cost Proceeding: In December 2002 the MPUC initiated an investigation to review CMP's 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 in February 2003, concluding that no change in the current stranded costs rate was appropriate. On April 25, 2003, CMP filed rebuttal testimony supporting the sales forecast used in its initial filing but recommending that rate payers be given credit for lower Maine Yankee costs of $2 million.

RG&E 2002 Electric and Gas Rate Proceeding: In February 2002 RG&E filed a request with the New York State Public Service Commission (NYPSC) for new electric and natural gas rates to go into effect on January 15, 2003. The single year filing, as updated, supported an increase in annual electric rates of $40 million, or 5.7%, and an increase in natural gas rates of $19 million, or 6.6%. In December 2002 the administrative law judge (ALJ) in this proceeding issued a recommended decision that, if approved, would have resulted in a $9 million, or 3.3%, overall increase for natural gas service and no increase for electric service.

On March 7, 2003, the NYPSC issued an order in the proceeding authorizing a $16 million electric revenue requirement reduction. The order requires a $16 million increase in the amortization of previously deferred costs, without increasing electric rates. The NYPSC also limited the natural gas rate increase to $6 million, or 1.9%. The rate decision set the cost of equity at 9.96%, with an equity ratio 41.4% and an overall weighted cost of capital of 8.11%. The NYPSC also credited to customers $55 million of electric earnings that, according to the NYPSC, exceeded a preset level under the five-year rate plan that expired on June 30, 2002, subject to a final audit of the fifth year amount. The NYPSC also ignored the costs of replacement power that will be incurred during the required Ginna nuclear plant refueling outage in the fall of 2003.

RG&E is disappointed with the decision because it ignores the record that was developed in the proceeding, reverses many of the recommendations of the ALJ without adequate explanation and does not provide adequate revenue for RG&E to earn its authorized rate of return. RG&E plans to file a new rate case in May 2003 for an increase in electric and natural gas rates to recover costs that RG&E has incurred and will continue to incur in providing safe and reliable electric and natural gas service.

RG&E Cost Deferral Petitions: On April 9, 2003, RG&E filed a petition with the NYPSC requesting the deferral for future recovery of costs, including interest, for restoration work resulting from a severe ice storm that began on April 3, 2003, and replacement power costs to be incurred in 2003 due to a scheduled refueling outage for the Ginna nuclear generating station (Ginna). The costs are currently estimated to be in excess of $15 million for repairs required due to the ice storm and $16 million for the Ginna replacement power.

On April 29, 2003, RG&E received a response from the NYPSC that indicated the NYPSC's history of allowing net prudent costs of this nature, that have a material effect on earnings, to be deferred and recovered from customers, and acknowledged that those costs are not

currently included in RG&E's rates. Based on the NYPSC letter, RG&E believes that recovery is probable and, therefore, will defer those costs in accordance with generally accepted accounting principles, pending approval from the NYPSC, which is expected midyear.

Ginna Relicensing: The Ginna station operating license expires in 2009. In July 2002 RG&E filed a license renewal application with the Nuclear Regulatory Commission (NRC), which, if approved, would extend the license to September 19, 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 June 2004.

RG&E Union Vote: On April 1, 2003, RG&E's electric and gas field operations personnel voted to be represented by the International Brotherhood of Electrical Workers. RG&E recognizes the employees' right to make this decision and respects the collective votes of its employees.

Manufactured Gas Plant Remediation Recovery: RG&E and NYSEG began cost contribution actions against FirstEnergy Corp. (formerly GPU, Inc.) in federal district court; RG&E in the Western District of New York in August 2000 and NYSEG in the Northern District of New York in April 2003. The actions are for both past and future costs incurred for the investigation and remediation of inactive manufactured gas plant (MGP) sites. The RG&E action is being litigated and mediated concurrently and the parties are in the final stages of discovery. RG&E and NYSEG are unable to predict the outcome of these actions at this time.

RG&E Natural Gas Supply Agreement: RG&E entered into a two-year supply portfolio management agreement that began in April 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 was designed to ensure that RG&E could reliably meet its customers' supply requirements while seeking to minimize the annual delivered cost of natural gas. RG&E terminated its agreement with Dynegy after Dynegy announced in October 2002 that it would exit the marketing and trading business over the next several months. RG&E entered into a new portfolio management agreement with Entergy-Koch Trading, LP that extends 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 appropriate action to resolve any outstanding issues.

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. A recommended decision (RD) on the embedded cost of service studies filed by NYSEG and Consolidated Edison was issued on March 24, 2003. The RD discusses the utilities' cost studies and concludes that they generally comply with the NYPSC's directives. The RD recommended adoption of NYSEG's lost revenue recovery mechanisms contained in NYSEG's electric and natural gas joint proposal. Briefs on the recommended decision were filed in April 2003 by NYSEG and RG&E. NYSEG took exception to the RD's treatment of certain costs. RG&E filed its brief on exception, not taking formal exception to any of the RD's proposals, but commenting that given the material differences among utilities, it would be both impossible and improper to impose the conclusions in this RD on the remaining utilities in this proceeding.

Berkshire Gas Union Contract: Effective April 1, 2003, the union contract expired between The Berkshire Gas Company (Berkshire Gas) and the local union of the United Steelworkers of America. Berkshire Gas and the local union have been unable to negotiate a new contract and a work stoppage involving approximately 57% of the workforce is in effect. The net additional cost of operating Berkshire Gas while the work stoppage is in effect is approximately $250,000 to $350,000 per month.

Connecticut Merger-Enabled Gas Supply Savings and Gas Cost Reduction Plan Filings: In 2001 Connecticut Natural Gas Corporation (CNG) and The Southern Connecticut Gas Company (SCG) submitted filings to the Connecticut Department of Public Utility Control (DPUC) regarding merger-enabled gas supply savings (MEGS) and a gas-cost reduction plan, which covered the initial period April 1, 2001, through September 30, 2001. CNG provided calculations for total MEGS of $1.3 million and SCG provided calculations for total MEGS of $2.2 million. On February 26, 2003, based on their understanding of the components of MEGS, the DPUC issued a draft decision on CNG's and SCG's filed MEGS and gas-cost reduction plan results, modifying the MEGS amounts to $134,000 for CNG and $9,000 for SCG. CNG and SCG filed comments and additional detail with regard to the draft decision on April 28, 2003, the DPUC's extended due date. The comments included a discussion of the benchmark standards set in the draft decision and how merger-enabled gas supply savings should be defined, quantified and shared among customers and shareholders. CNG and SCG cannot predict the final outcome of the proceedings.

Investing and Financing Activities

Investing Activities: Capital spending for the first three months of 2003 was $50 million, including nuclear fuel. Capital spending is projected to be $338 million for 2003, including nuclear fuel, and is expected to be paid for with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

Financing Activities: During the three months ended March 31, 2003, the company issued 276,568 shares of common stock out of its treasury stock, at an average price of $19.29 per share, through its Dividend Reinvestment and Stock Purchase Plan.

On February 13, 2003, the company issued 229,230 shares of common stock out of its treasury stock, to certain employees through its Restricted Stock Plan, and recorded deferred compensation of $4.4 million based on the market price of $19.20 per share of common stock on the date of the award. (See Item 1 - Note 4 to Energy East's Consolidated Financial Statements.)

The company plans to file a shelf registration statement with the SEC in May 2003 to sell up to $1 billion in an unspecified combination of debt, preferred stock, common stock and trust preferred securities. The company plans to use the net proceeds from the sale of securities under this shelf registration for general corporate purposes, such as the repurchase or refinancing of securities. The company currently has $5 million available under a previous shelf registration statement.

CMP plans to issue $35 million of 10-year debt in the third quarter of 2003 to help repay $50 million of medium-term notes that will mature in August 2003. Through financial instruments issued in March 2003, CMP has locked in the 10-year treasury rate component of that financing at a fixed rate of 4.105%.

On March 19, 2003, NYSEG filed a shelf registration statement with the SEC to sell up to $300 million in an unspecified combination of debt and preferred stock. NYSEG plans to use the net proceeds from the sale of securities under this shelf registration for general corporate purposes, such as retirement or repurchase of certain of its indebtedness or preferred stock, reduction of short-term debt, financing the development and construction of new facilities and additions to working capital. NYSEG currently has $50 million available under a previous shelf registration statement.

In April 2003 NYSEG redeemed, at a premium, $50 million of 7.55% Series first mortgage bonds callable on April 1, 2003, using commercial paper. The $1.4 million premium on that redemption and the related unamortized debt expense and debt issuance costs will be amortized over the term of the new financing. In July 2003 NYSEG plans to redeem $100 million of 7.45% Series first mortgage bonds callable on July 15, 2003. In May 2003 NYSEG expects to complete, under the shelf registration statements described above, additional senior unsecured financing needed to call its first mortgage bonds and repay the commercial paper. 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%.

In January 2003 RG&E used an 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.

During the three months ended March 31, 2003, RG&E paid at maturity $40 million of medium term notes using temporary cash investments and internally generated funds.

RG&E plans to file a shelf registration statement with the SEC in May 2003 to sell up to $300 million in debt. RG&E plans to use the net proceeds from the sale of securities under this shelf registration for general corporate purposes, such as retirement or repurchase of certain of its indebtedness or preferred stock, reduction of short-term debt, financing the development and construction of new facilities and additions to working capital. RG&E currently has $75 million available under a previous shelf registration statement.

RG&E plans to issue $75 million of 30-year debt in the third quarter of 2003, in part to repay $40 million of debt that matures in July 2003. Through financial instruments issued in April 2003, Energy East has locked in the 30-year treasury rate component for $50 million of that financing at a fixed rate of 4.902%.

Critical Accounting Policies
(See Energy East's report on Form 10-K for fiscal year ended December 31, 2002, Item 7, Critical Accounting Policies.)

Asset Retirement Obligation: As required by Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, the company recorded a liability for the fair value of its asset retirement obligation on January 1, 2003. The company will adjust the liability to its present value periodically over time, and the capitalized cost will be depreciated over the useful life of the related asset. The determination of the liability 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 amount of the company's retirement obligation. The company's asset retirement obligation is recovered through rates collected from customers, therefore, the depreciation of the capitalized costs and adjustments to the liability are deferred until those amounts are included in rates. (See Item 1 Note 6 to Energy East's Consolidated Financial Statements.)

Due to the merger completed in June 2002, the company's results of operations include RGS Energy for the three months ended March 31, 2003.

Earnings per share for the quarter were 93 cents compared to 90 cents for the prior year quarter, and include the nonrecurring item shown in the table below. The decrease in earnings per share, excluding the nonrecurring item, for the 2003 quarter is primarily the result of an electric rate reduction of $205 million ordered by the NYPSC for NYSEG, the company's largest utility. This rate reduction, which became effective March 1, 2002, reduced earnings 16 cents per share. Earnings were further reduced by 4 cents per share due to lower noncash pension income and 5 cents per share due to an increase in the cost of purchased power. Those

decreases were significantly offset by 18 cents per share for higher electric and natural gas deliveries (primarily residential and commercial) due to colder winter weather in 2003 and 4 cents per share due to NYSEG's natural gas supply charge, which began October 1, 2002.

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.

Operating revenues were $128 million higher for the quarter primarily as a result of increases of $176 million due to the addition of RG&E's delivery revenues and $22 million due to higher retail deliveries because of colder winter weather in 2003. Those amounts were partially offset by decreases of $17 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002 and $40 million due to NYSEG's price reduction effective March 2002 and customers choosing alternate suppliers.

The $135 million increase in operating expenses for the quarter was primarily due to increases of $146 million due to the addition of RG&E's operating expenses; $12 million for purchased power due to both higher market prices and higher retail deliveries because of colder winter weather, offset by the effect of customers choosing alternate suppliers; and $6 million due to lower noncash pension income. Those amounts were partially offset by decreases of $17 million in purchased power because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002.

Operating expenses increased $243 million for the quarter primarily as a result of increases of $123 million due to the addition of RG&E's operating expenses, $70 million for natural gas purchased costs due to market conditions and after various rate case deferrals, and $45 million for natural gas purchased due to higher retail deliveries because of colder winter weather.

Central Maine Power Company
Consolidated Statements of Income - (Unaudited)

Central Maine Power Company
Consolidated Statements of Cash Flows - (Unaudited)

Item 2.  Management's discussion and analysis of financial condition
             and results of operations

Investing and Financing Activities

Investing Activities: Capital spending for the first three months of 2003 was $7 million. Capital spending is projected to be $42 million for 2003, and is expected to be paid for with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

Financing Activities: CMP plans to issue $35 million of 10-year debt in the third quarter of 2003 to help repay $50 million of medium-term notes that will mature in August 2003. Through financial instruments issued in March 2003, CMP has locked in the 10-year treasury rate component of that financing at a fixed rate of 4.105%.

Earnings for the quarter increased $1 million as a result of reduced interest charges due to lower short-term borrowing in 2003.

The $24 million decrease in both operating revenues and operating expenses is primarily the result of CMP no longer being the standard-offer provider for the supply of electricity effective March 2002, which reduced revenues $17 million. The decrease in revenues was offset by a corresponding decrease in purchased power.