(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.

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

Energy East Corporation's (Energy East or the company) management focuses its strategic efforts on those areas of the company that have the greatest effect on shareholder value. Efficient operations are a key aspect of increasing shareholder value. As discussed below, management has implemented plans to achieve savings through a company-wide restructuring, consolidation of utility support services and other changes.

In addition, because Energy East's primary operations - its electric and natural gas utility operations - are subject to rate regulation, the approved regulatory treatment on various matters could significantly affect the company's operations and, therefore, its financial position and results of operations. Energy East has long-term rate plans for New York State Electric & Gas Corporation (NYSEG), Central Maine Power Company (CMP), Connecticut Natural Gas Corporation (CNG), The Southern Connecticut Gas Company (SCG) and The Berkshire Gas Company (Berkshire Gas). The plans provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including exogenous and stranded costs, and provide stable rates for customers and revenue predictability for those five operating companies. Rochester Gas and Electric Corporation (RG&E) has reached agreement with various parties for a similar long-term plan, and expects approval of the plan by the New York State Public Service Commission (NYPSC) in the second quarter of 2004.

Over the last several years Energy East has focused its strategic efforts on its electric and natural gas delivery operations, rather than on the more volatile electricity generation business, and has sought to rationalize its nonutility businesses to ensure they fit its strategic focus. As discussed below, during 2003 the company reached an agreement to sell its Ginna nuclear generating station (Ginna) and expects to complete the sale by the end of June 2004, subject to approval by several regulatory agencies.

The continuing evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings that could significantly affect operations, although the outcomes of those proceedings are difficult to predict. Those proceedings could have an effect on the nature of the electric and natural gas utility industry in New York and New England. Recent events in the proceedings are described below.

The company engages in various investing and financing activities to meet its strategic objectives. Investing activities are primarily for maintaining a reliable energy delivery infrastructure and are funded primarily with internally generated funds. Financing activities, therefore, are focused on maintaining adequate liquidity, improving credit quality and minimizing the cost of capital.

Energy East initiated a corporate restructuring in 2002 designed to improve organizational efficiency and effectiveness. The savings from the 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. Integration savings are expected to be approximately $100 million annually by 2006. Those savings, which include reductions in operating expenses and capital expenditures, will come from the consolidation of functions such as accounting, finance, information services and supply chain that were completed in 2003, as well as the implementation of other merger-enabled initiatives across the company's six operating utilities.

Energy East recognized a $4 million total liability for an enhanced severance program for 83 accounting and finance employees who were employed through March 31, 2004. The company recorded approximately $2 million of that liability as of the end of the fourth quarter of 2003 and recorded the remaining $2 million of the liability in the first quarter of 2004.

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

Joint Proposals in RG&E 2003 Electric and Gas Rate Proceeding: In May 2003 RG&E filed a rate case with the NYPSC to recover costs that RG&E has incurred and will continue to incur in providing safe and reliable electric and natural gas service. The filing proposed an annual increase in electric rates of $105 million, or 16.2%, and an annual increase in natural gas rates of $25 million, or 7.6% overall and 19.7% on delivery rates. RG&E submitted various rate revisions based on continued review of its filing, requesting in February 2004 an $80 million annual electric rate increase and a $21 million annual natural gas rate increase. The filing cited inadequate rate relief from the NYPSC's Order issued March 7, 2003 (see RG&E 2002 Electric and Gas Rate Proceeding), increased costs (see RG&E Cost Deferral Petitions) and the need for a fair and reasonable return on equity (ROE) of 11.25%.

In December 2003 Chairman Flynn of the NYPSC issued a one-Commissioner order transferring the ratemaking treatment for the sale of Ginna from RG&E's pending Section 70 filing (see Sale of Ginna Station and Relicensing) to the pending electric rate proceeding.

Staff of the NYPSC (NYPSC Staff) filed their litigation case under this proceeding on December 31, 2003, proposing to hold electric revenues constant through an electric base rate reduction of $7 million, an acceleration of the amortization of the Nine Mile Point 2 nuclear generating station (NMP2) regulatory asset, and the implementation of a $7 million retail access surcharge. The NYPSC Staff also proposed a natural gas delivery rate reduction of $7 million and the implementation of a $7 million merchant function charge.

On March 9, 2004, RG&E announced that it had reached agreement with various parties, including the NYPSC Staff, on Electric and Natural Gas Joint Proposals (Joint Proposals) that address RG&E electric and natural gas rates through 2008. The Joint Proposals were filed with the NYPSC on March 9, 2004, and the parties are requesting approval by the end of May 2004. The Joint Proposals resolve: the RG&E 2003 Electric and Gas Rate Proceeding; remaining issues related to the RG&E 2002 Electric and Gas Rate Proceeding and RG&E's five-year rate plan ended June 30, 2002; rate treatment concerning the sale of Ginna; recovery of certain deferred costs; and the unbundling of electric rates.

Key features of the Electric Joint Proposal include:

• Freezing electric delivery rates through December 2008, except for the implementation of a retail access surcharge effective May 1, 2004, that is expected to recover $7 million annually.
• Allowing RG&E to recover its actual electricity supply costs beginning in May 2004.
• Refunding to customers over the term of the plan $110 million of an estimated $360 million gain from the sale of Ginna, including refunding $60 million shortly after the closing, and refunding the remaining $50 million over the following three years. (See Sale of Ginna Station and Relicensing.)
• Establishing an Asset Sale Gain Account (ASGA) with the net proceeds from the Ginna sale. Portions of the ASGA would be used as follows:

• To cover $6 million of replacement purchased power costs incurred during the 2003 Ginna refueling outage;
• To offset a $2 million annual increase in electric delivery rates;
• To compensate RG&E for maximizing the sale value of Ginna through a credit to RG&E of $3.3 million annually over the term of the settlement; and
• RG&E estimates that at the end of 2008 $121 million will remain in the ASGA, which may be used at the discretion of the NYPSC for rate moderation, among other things.

• Establishing an earnings sharing mechanism to allow customers and stockholders to share equally in earnings over 12.25%.
• Creating and expanding initiatives to enable energy services companies (ESCOs) in RG&E's service territory to attract new customers. RG&E would be allowed to increase its earning sharing threshold to 12.50% by meeting standards designed to measure improvements in its retail access program, including assisting customer migration.
• Ensuring that RG&E continues to maintain the high quality of service and reliability that it currently provides by specifying service quality and reliability standards and capital investment objectives.
  

Key features of the Natural Gas Joint Proposal include:

• Freezing natural gas delivery rates through December 2008, except for the implementation of a merchant function charge that is expected to recover $7 million annually beginning May 1, 2004.
• Implementing a weather normalization adjustment to protect both customers and RG&E from certain costs that fluctuate due to swings in temperature outside a normal range.
• Implementing gas cost incentive mechanisms to provide a means of sharing with customers future gas supply cost savings achieved by RG&E.
• Establishing provisions similar to those in the Electric Joint Proposal regarding earnings sharing and service quality and reliability. The level for earnings sharing is 12.00%, with the opportunity to increase to 12.25% if certain customer migration targets are achieved.

RG&E 2002 Electric and Gas Rate Proceeding: In February 2002 RG&E filed a request with the NYPSC for new electric and natural gas rates to go into effect on January 15, 2003. The single year filing, as updated, supported a $40 million increase in annual electric rates and a $19 million increase in annual natural gas rates.

In March 2003 the NYPSC issued an order (Order) in the proceeding authorizing a $16 million electric revenue requirement reduction and limiting the natural gas rate increase to $6 million. 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 were incurred during the required Ginna refueling outage in the fall of 2003.

RG&E was disappointed with the Order because it ignored the record that was developed in the proceeding, reversed many of the recommendations of the ALJ without adequate explanation and did not provide adequate revenue for RG&E to earn its authorized rate of return. In May 2003 RG&E began a proceeding to appeal the most objectionable errors in the Order. RG&E has agreed to withdraw its appeal in the event that the Joint Proposals are approved.

RG&E Cost Deferral Petitions: In April 2003 RG&E filed a letter with the NYPSC requesting the deferral of costs, including interest, for restoration work resulting from a severe ice storm in April 2003 and replacement purchased power costs incurred in 2003 in connection with a scheduled refueling outage for Ginna. The deferred costs are $36 million for repairs required due to the ice storm and $15 million for the Ginna replacement purchased power. Recovery of those costs is provided for in the Electric Joint Proposal.

In May 2003 RG&E filed a letter with the NYPSC seeking deferral and true up of an estimated $9 million of pension costs in accordance with the NYPSC's Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Post Retirement Benefits Other than Pensions. The request covers the 16-month period from January 1, 2003, through May 1, 2004. The Joint Proposals provide for recovery of incremental pension costs for the period July 1, 2003, to December 31, 2003, estimated at $2 million, and will reconcile pension costs according to the NYPSC's pension policy statement, beginning January 1, 2004.

Sale of Ginna Station and Relicensing: In November 2003 RG&E announced an agreement to sell Ginna to Constellation Generation Group LLC (CGG). In December 2003 RG&E and CGG jointly filed a revised Section 70 petition with the NYPSC that includes, among other things, all the transaction documents and details of the auction process. The Electric Joint Proposal includes the accounting and ratemaking treatment for the sale and an incentive payment to RG&E of $3.3 million annually over the term of the plan for maximizing the proceeds from the sale of Ginna.

The sale of Ginna is subject to approvals by several regulatory agencies, including the NYPSC, the Nuclear Regulatory Commission (NRC) and the Federal Energy Regulatory Commission (FERC). The outcome of these proceedings cannot be determined at this time. The sale is also conditioned on receiving reasonably satisfactory accounting and ratemaking treatment from the NYPSC. Assuming the Joint Proposals are approved, RG&E expects to complete the sale of Ginna by the end of June 2004.

Upon closing of the proposed Ginna sale, RG&E will transfer approximately $202 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. The amount is expected to fully meet the NRC's decommissioning funding requirements for Ginna. RG&E projects that it will retain $59 million in excess decommissioning funds, to be credited to customers as part of the ASGA. The sale agreement includes a 10-year purchase power agreement so that RG&E's customers will continue to receive the benefit of power from Ginna.

Ginna's operating license expires in 2009. In July 2002 RG&E filed a license renewal application with the 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 two in 2003. In April 2004 the Advisory Committee on Reactor Safeguards met and recommended approval of the renewal of the operating license for an additional 20 years beyond its current license term. A final decision on this matter is expected by the end of June 2004. As part of the Electric Joint Proposal, depreciation rates and decommissioning costs for Ginna were revised to reflect the new expected license life.

RG&E Electric Rate Unbundling: In June 2003, as required by the NYPSC's Order issued March 7, 2003, RG&E filed documentation with the NYPSC to unbundle commodity charges from delivery charges and to create electric commodity options for all customers. The Electric Joint Proposal provides for that unbundling and for the commodity options. Beginning January 1, 2005, customers would have an opportunity to choose to purchase commodity service from RG&E at a fixed rate or at a price that varies monthly based on the market price of electricity. Alternatively, customers may continue to choose to purchase their commodity service from an ESCO.

RG&E Transmission Project: In September 2003 RG&E applied to the NYPSC for approval to upgrade its electric transmission system. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, NY, area in order to assure adequate service to customers after the planned closing of RG&E's 257 megawatt coal-fired Russell Station in 2007. The estimated cost of the multi-year project is $75 million. Construction on the project is expected to begin in the spring of 2005.

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 2004 CMP submitted its annual ARP filing proposing a decrease of 0.5% on the distribution portion of rates, which is the result of inflation being less than the productivity offset for 2004 and adjustments to prior years' inflation estimates.

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive electricity and natural gas 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 January 2004 the NYPSC issued a Notice seeking additional comments in light of the passage of time and the evolution of competitive markets. In March and April 2004

NYSEG and RG&E submitted comments supporting periodic assessment of the retail competitive marketplace and opposing the adoption of any policies restricting customer choice of supplier or limiting the availability of supply options from any particular supplier. NYSEG and RG&E believe that the NYPSC should not adopt a single end state vision for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.

Regional Transmission Organization: ISO New England and the New England transmission owners, including CMP, made a joint regional transmission organization (RTO) filing with FERC in October 2003. On March 24, 2004, the FERC accepted the six-state RTO filing submitted by ISO New England and the New England transmission owners, subject to certain conditions. The FERC approved a proposed 50 basis point incentive adder to the ROE component, to be recovered in RTO New England's rates for regional network service. The FERC accepted a proposed 100 basis point ROE adder to reward new transmission investment, subject to suspension, hearing and application of the FERC's Pricing Policy Statement when it is issued. The FERC also accepted, subject to suspension and hearing, the transmission owners' proposed base level ROE. The transmission owners had requested a midpoint ROE of 12.8%. To provide parties an opportunity to resolve matters, the FERC instituted settlement procedures covering all matters set for hearing. CMP is considering the FERC's order and is working with the other New England transmission owners and ISO New England to evaluate the FERC order and develop appropriate responses.

CMP Collective Bargaining Agreement: Effective April 30, 2004, the union contract expired between CMP and the local union of the International Brotherhood of Electrical Workers. On May 5, 2004, the union membership voted to accept CMP's offer for a new contract, which expires on April 30, 2009. The contract provides for increases of 3.25% in 2004, 3.0% in each year 2005, 2006 and 2007, and 2.75% in 2008. It also includes provisions for active employees to contribute to medical plans at a level reflecting CMP's cost-sharing philosophy for all plans by the end of the contract period and for employees who retire on or after July 1, 2005, to contribute toward the cost of medical coverage according to a predetermined schedule.

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: Energy East's natural gas companies - NYSEG, RG&E, SCG, CNG, Berkshire Gas, and Maine Natural Gas - have a three-year strategic alliance with BP Energy Company, effective April 1, 2004, for the acquisition of natural gas supply and optimization of transportation and storage services.

SCG Request for Recovery of Exogenous Costs: In December 2003 SCG filed an application with the Connecticut Department of Public Utility Control (DPUC) to recover exogenous costs of approximately $21 million under its approved Incentive Rate Plan (IRP). The recovery of exogenous costs is for qualified pension and other postretirement benefits expense, taxes, uncollectible expense and the Customer Hardship Arrearage Forgiveness Program. Those

costs were the result of events that were unanticipated and beyond SCG's control. SCG's IRP decision from the DPUC allows SCG to petition for relief from substantial and material costs resulting from such exogenous events. The DPUC has established a docket for this proceeding

and initial interrogatories have been issued. Hearings were held in April 2004. SCG cannot predict the outcome of this proceeding at this time.

CNG's Purchased Gas Adjustment Clause: In April 2002 the DPUC initiated a semiannual review of CNG's Purchased Gas Adjustment Clause (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. In May 2003 the DPUC issued its final decision in the matter, modifying the draft decision and removing the disallowance. The DPUC also notified CNG concerning transactions reviewed in an August 2003 semiannual review, for which a final decision is due in mid-2004. The DPUC issued a draft decision in April 2004 that would allow CNG to collect the $1 million. CNG is retaining its $1 million reserve contingency to cover the period November 1, 2001, through October 31, 2003, pending final approval of the draft decision. CNG cannot predict the final outcome of this proceeding.

Connecticut Merger-Enabled Gas Supply Savings and Gas Cost Reduction Plan Filings: In 2001 CNG and SCG submitted filings to the 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. In February 2003, based on its understanding of the components of the 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 March 26, 2004, the DPUC issued a notice that encouraged the parties to settle the MEGS issue, which resulted in the assignment of Prosecutorial Staff of the DPUC to assist in the settlement process. The docket was suspended to allow the settlement process to procee d. CNG and SCG are diligently working toward settlement of the issues, but cannot predict the final outcome of these proceedings.

FIN 46R: In December 2003 the Financial Accounting Standards Board (FASB) issued its revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin (ARB) No. 51 (FIN 46R). FIN 46R addresses consolidation of variable interest entities. A variable interest entity is an entity that is not controllable through voting interests and/or in which the equity investor does not bear the residual economic risks and rewards. The company was required to apply FIN 46R to all entities subject to the interpretation as of March 31, 2004. (See Note 5 to the Condensed Financial Statements.)

Investing Activities: Capital spending for the first three months of 2004 was $57 million, including nuclear fuel. Capital spending is projected to be $345 million for 2004, 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: The financing activities discussed below include those activities necessary for the company and its subsidiaries to maintain adequate liquidity, improve credit quality and ensure access to capital markets. Activities include maintenance of credit facilities, minimal common stock issuances and various medium-term and long-term debt arrangements.

During the three months ended March 31, 2004, the company issued 212,736 shares of common stock, at an average price of $23.59 per share, through its Investor Services Program (formerly known as the Dividend Reinvestment and Stock Purchase Plan). The shares issued were original issue shares.

In February 2004 the company awarded 240,138 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of $6 million based on the market price of $23.89 per share of common stock on the date of the award.

RG&E Financing Activities: On March 1, 2004, RG&E redeemed, at par, as required by a mandatory sinking fund provision, $1.25 million of 6.60% Series V preferred stock, Par Value $100, using available cash.

On May 5, 2004, RG&E redeemed its remaining preferred stock, including: $12 million of 4% Series F, $8 million of 4.10% Series H, $6 million of 4 3/4% Series I, $5 million of 4.10% Series J, $6 million of 4.95% Series K and $10 million of 4.55% Series M, all redeemed at a premium; and $23.75 million of 6.60% Series V, redeemed at par. On May 6, 2004, RG&E redeemed, at a premium, $40 million of 7.45% Series first mortgage bonds due July 2023, and the following Series of first mortgage bonds due March 2023: $33 million of 7.64%, $5 million of 7.66%, and $12 million of 7.67%. Those redemptions were financed through available cash and short-term credit facilities.

Earnings of 83 cents per share for the quarter ended March 31, 2004, were 7 cents lower than earnings from continuing operations of 90 cents per share for the quarter ended March 31, 2003. Earnings decreased primarily because of an increase in the market value of Energy East's common stock during the first quarter this year (as compared to a decline in the first quarter of 2003), which resulted in higher stock-based compensation of 10 cents per share. The company's stock price increased from $22.40 per share to $25.36 per share in the first quarter of 2004, resulting in an expense of $12 million. The stock price decreased from $22.09 per share to $17.80 per share in the first quarter of 2003, resulting in a benefit of $11 million.

The operating companies experienced a modest decrease in deliveries as natural gas retail deliveries declined 1.8% and electric retail deliveries declined 0.5% for the quarter, primarily because of warmer winter weather in 2004 as compared to 2003. This reduced earnings 6 cents per share. That reduction was offset by integration savings and other cost reductions of 7 cents per share.

Operating revenues for the first quarter of 2004 decreased $28 million. The primary factors were rate reductions for CMP of approximately $18 million to reflect lower operating costs and amortization, and $8 million due to a change in market structure for RG&E that allows ESCOs to provide electricity. The results of this change were lower retail revenues offset by higher wholesale revenues and lower fuel costs. The net revenue reduction for the quarter was $8 million.

Operating expenses decreased $15 million primarily due to a $16 million reduction in purchased power costs. The $16 million reduction was the result of a $9 million adjustment for amounts owed to the New York Independent System Operator and lower load requirements at RG&E as a result of the change in market structure.

Operating revenues increased $42 million for the first quarter of 2004. The increase resulted from higher gas costs, which are passed on to customers.

Operating expenses increased $49 million compared to the prior year quarter. The primary cause was an increase in natural gas purchases of $37 million. Operations and maintenance costs also increased by $10 million compared to the prior year quarter.

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

CMP's electric delivery business consists of its regulated electricity transmission and distribution operations.

Earnings for the quarter decreased approximately $3 million, primarily as a result of lower operating revenues.

The $14 million reduction in operating revenues for the quarter was due primarily to an $18 million decrease because of rate reductions that were substantially allocated to winter months, partially offset by an increase of $4 million for higher deliveries resulting from economic growth.

The $6 million decrease in operating expenses for the quarter was primarily the result of lower amortization of ice storm, demand-side management costs of $4 million and decreases in depreciation and other taxes.