(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

Energy East Corporation and RGS Energy Merger

On June 28, 2002, Energy East Corporation (Energy East or the company) completed its merger with RGS Energy Group, Inc. The transaction had an equity market value of approximately $1.4 billion. Under the merger agreement 45% of the common stock of RGS Energy (15.6 million shares) was converted into 27.5 million shares of Energy East common stock, and 55% of the common stock of RGS Energy was exchanged for $753 million in cash, which was $39.50 per RGS Energy share. Energy East assumed approximately $932 million of RGS Energy long-term debt. The RGS Energy 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 1 - Note 5 to Energy East's Consolidated Financial Statements.)

As a result of the merger RGS Energy became a wholly-owned subsidiary of Energy East. Rochester Gas and Electric Corporation (RG&E) continues to be a wholly-owned subsidiary of RGS Energy and New York State Electric & Gas Corporation (NYSEG) became a wholly-owned subsidiary of RGS Energy.

Restructuring Initiative

The company announced on October 24, 2002, a voluntary early retirement program for salaried employees of its six operating utilities. Approximately 550 employees are eligible for the program, including about 220 from NYSEG, 190 from RG&E, 60 from Central Maine Power Company (CMP), and a total of about 80 from The Berkshire Gas Company (Berkshire Gas), Connecticut Natural Gas Corporation (CNG) and The Southern Connecticut Gas Company (SCG). 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 addition to the voluntary early retirement program, an involuntary severance program will be utilized by the operating companies after they determine the additional positions that must be eliminated to achieve optimum organizational efficiency and effectiveness. The employees affected by the involuntary program will be notified in the first quarter of 2003. Energy East expects to incur a one-time restructuring charge of between $50-$100 million in the fourth quarter of 2002, including $5-$10 million for CMP, $20-$35 million for NYSEG, $25-$45 million for RG&E and the remainder for Berkshire Gas, CNG and SCG. All or a portion of NYSEG's and RG&E's restructuring costs may be deferred in accordance with the NYPSC order approving the RGS Energy merger.

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. RTOs are similar to ISOs, but have more authority and cover broader geographic regions. 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) for 45 days, 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. The New England ISO and the NYISO entered into an agreement to consider forming an RTO, and PJM Interconnection, L.L.C. (PJM) entered into an agreement to form common market systems with the Midwest ISO. The New England ISO 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.

NYSEG, CMP and RG&E have consistently advocated the formation of a Northeast/Mid-Atlantic RTO, including 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. The companies plan to file comments on the joint petition. A FERC decision is expected early in 2003. A Northeast RTO may include one or more independent transmission companies that would be owned by participating transmission owners. The transmission companies would share RTO responsibilities with an independent market administrator and would focus on transmission investment opportunities, instead of energy, capacity and other generation-based markets.

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. FERC is expected to issue a final rule on the SMD NOPR next year. The companies are analyzing the SMD NOPR and plan to file comments. 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. The company is unable to predict the ultimate effect, if any, of the expected RTO order and the SMD rulemaking on wholesale power markets and the company's tr ansmission 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, FERC issued a NOPR regarding generation interconnection terms, conditions and cost allocation. FERC is expected to issue a final rule later in 2002. 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.

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. Recovery of stranded costs, primarily over-market nonutility generator (NUG) contracts, 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 Stipulation allowing CMP's distribution prices to change effective beginning 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 demand-side management, 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 other than power entitlements under long-term contracts from NUGs and 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 February 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 Item 2(b) - Energy East Operating Results for the Electric Delivery Business and Central Maine Power Company Results of Operations.)

NYPSC-mandated Contracts with Customers: In March and April 2002 the New York State Public Service Commission (NYPSC) issued orders directing NYSEG to enter into long-term electric service contracts with two large industrial customers 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. No decision has been issued to date. On September 24, 2002, consistent with the NYPSC's orders, NYSEG signed one of the two 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 the Nine Mile Point 2 nuclear generating station (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 report on Form 10-K for Energy East and NYSEG for fiscal year ended December 31, 2001, Item 7 - Liquidity and Capital Resources, NYSEG Electric Rate Settlement), 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 2001 this cumulative overpayment was more than $148 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.

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 in January 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 14, 2003. The filing included both a traditional single-year filing and a multi-year proposal outline 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 likely remain in effect until a new order is issued by the NYPSC. (See RG&E's r eport on Form 10-K for the fiscal year ended December 31, 2001, Item 1, Regulatory Matters - 2002 Electric and Gas Rate Proposal.) The lack of progress did not justify continuation of settlement discussions and the parties are now proceeding on a litigation track. Evidentiary hearings took place in late October 2002. The proceedings are expected to be completed in February 2003.

Ginna Station: Several nuclear power plant operators have recently 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 plant could continue to operate with the existing head, RG&E decided to replace the reactor vessel head. 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 and a decision on this matter is expected no later than 2005.

Natural Gas Supply Alliance: Four of Energy East's natural gas companies: NYSEG, The Southern Connecticut Gas Corporation, Connecticut Natural Gas Corporation and The Berkshire Gas Company, 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 price risk 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 Gas Supply Management Agreement: 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. RG&E and Dynegy are developing a transition plan to maintain continued reliable service and preclude any adverse effects on RG&E or its customers.

NYSEG Natural Gas Rate Filings: In October 2001 NYSEG filed a natural gas rate case with the NYPSC. NYSEG proposed to unbundle delivery and gas supply charges, increase delivery rates by approximately $23 million, implement a gas adjustment clause, a weather normalization clause and a delivery adjustment clause, and continue the promotion of retail choice for all customers. The filing proposed to change the existing residential rate structure from fully bundled fixed sales service rates to fixed delivery rates and floating gas supply charges. Similarly, for nonresidential customers, delivery charges would be reset and fixed, while gas supply charges would float with market changes. NYSEG also proposed rate design changes by rate area and service class to more closely match NYSEG's cost to serve.

In October 2001 NYSEG also filed a petition with the NYPSC for authorization to defer the difference between natural gas costs embedded in its residential gas sales rates and actual gas costs incurred for residential sales customers during the period November 1, 2001, through September 30, 2002. The petition was the result of sustained unanticipated high wholesale commodity costs. (See Item 3 - Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk.) The petition also addressed the direction NYSEG received to refund to natural gas customers approximately $1 million beginning January 1, 2002, representing the alleged overcollection of state taxes during calendar year 2000.

On September 13, 2002, NYSEG filed with the NYPSC a joint proposal, which was endorsed by NYPSC Staff, the NY State Consumer Protection Board, large customer groups and numerous gas marketers that proposed to freeze delivery rates from October 1, 2002, through December 31, 2008, and phase in the rate impact of a gas supply charge to collect the actual cost of gas. The joint proposal would resolve issues related to NYSEG's petition to defer the difference in natural gas costs referred to above by allowing NYSEG to defer $14 million in 2002 for recovery. The NYPSC is expected to consider the joint proposal at its open session on November 20, 2002.

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.

Berkshire Service Solutions: 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 Resources, was sold at a loss of about $2 million. Berkshire Energy Resources is a wholly-owned subsidiary of Energy East.

Statement 146: In June 2002 the Financial Accounting Standards Board (FASB) issued Statement 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 are evaluating the effect that adopting Statement 146 may have on their results of operations or financial position.

Investing and Financing Activities

Investing Activities: Capital spending for the nine months ended September 30, 2002, excluding the RGS Energy merger transaction, was $145 million. Capital spending, including RGS Energy capital spending beginning with July 2002, is projected to be $272 million for 2002, 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 and compliance with environmental requirements.

The equity markets have experienced significant declines and volatility in 2002. Despite those market conditions, the company's pension plans continue to be well funded with assets exceeding the projected benefit obligation. As a result, the company does not currently anticipate significant funding requirements for its plans. Due to the funded status of the plans and previously favorable investment returns, the company's pension plans generated $78 million in pre-tax pension income in 2001 (net of amounts capitalized). Through the first nine months of 2002 the plans generated $52 million in pre-tax pension income (net of amounts capitalized), $4 million less than the first nine months of 2001. The company is currently unable to predict the effect that an equity market decline, coupled with the voluntary early retirement program and the involuntary severance program (See Item 2(a) Restructuring Initiative), would have on pension income for 2003 and beyond.

Financing Activities: During the nine months ended September 30, 2002, the company repurchased 92,600 shares of its common stock, at an average price of $18.89 per share, and issued 617,290 shares, at an average price of $20.84 per share, through its Dividend Reinvestment and Stock Purchase Plan, substantially out of treasury stock.

On October 22, 2002, the company filed to amend its Dividend Reinvestment and Stock Purchase Plan to allow non-shareholders who reside in Connecticut, Maine, Massachusetts or New York State to enroll directly in the Plan by making an initial cash investment. The amendment will become effective December 15, 2002.

During the second and third quarters of 2002 the company and certain of its subsidiaries renewed credit agreements with certain banks that provide for borrowing up to $410 million as follows: $260 million for 364-day periods, which the company expects to renew annually, and $150 million for a three-year period.

In May 2001 the company filed a shelf registration statement with the Securities and Exchange Commission to sell up to $1 billion in an unspecified combination of debt and trust preferred securities, of which $5 million is currently available. Under the shelf registration statement the company issued debt and trust preferred securities to fund the cash portion of the consideration for the merger with RGS Energy, for general corporate purposes, such as short-term debt reduction, repurchases of securities and to fund an equity contribution to NYSEG in 2001. (See Energy East Corporation 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 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, short-term debt and for general corporate purposes:

• On May 22, 2002, $37.5 million, 6.50%, due May 2009.
• On May 28, 2002, $37.5 million, 6.65%, due May 2012.
• On August 29, 2002, $15 million, 5.70%, due August 2012.
• On September 10, 2002, $15 million, 4.25%, due September 2007.

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 the company's Form 10-Q for the quarter ended March 31, 2002, Item 2(a) Liquidity and Capital Resources - Electric Delivery Business - Sale of Nine Mile Point 2). 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.

Additional financing needed by NYSEG to refund commercial paper that was used in October 2002 to repay $150 million of maturing 6 3/4% Series first mortgage bonds is expected to be completed in November 2002. Through financial instruments issued in June 2002 NYSEG has locked in the five-year treasury rate component of the financing at an average rate of 4.246%.

Over the next several months, NYSEG plans to call its remaining first mortgage bonds: $100 million 8.30% Series first mortgage bonds callable on December 15, 2002, $50 million 7.55% Series first mortgage bonds callable on April 1, 2003, and $100 million 7.45% Series first mortgage bonds callable on July 15, 2003. Additional financing needed by NYSEG to call the $100 million 8.30% Series first mortgage bonds is expected to be completed in November 2002. Through financial instruments issued in August 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.19%. Additional financing needed by NYSEG to call the $50 million 7.55% Series and the $100 million 7.45% Series 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%.

In July 2002 CNG retired $10 million of Medium Term Notes that had matured, 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.

Earnings for the quarter ended September 30, 2002, were 18 cents per share compared to 21 cents per share for the prior year quarter, excluding a loss of two cents per share on the sale of Berkshire Service Solutions this quarter and a writedown of CMP Group, Inc.'s investment in NEON Communications, Inc. that reduced earnings per share 39 cents in the third quarter of 2001. (See Note 9 to the company's consolidated Financial Statements.) The decrease is primarily the result of an electric price reduction for NYSEG effective March 1, 2002, that lowered earnings per share 20 cents, substantially offset by increases of nine cents per share for higher electric deliveries (primarily residential and commercial) due to warmer summer weather this year, five cents per share due to the elimination of goodwill amortization in 2002 and two cents per share because of cost control efforts.

Earnings per share for the nine months were $1.22 compared to $1.43 for the same period in 2001, excluding a loss of two cents per share on the sale of Berkshire Service Solutions this quarter, a loss of eight cents per share from NYSEG's early retirement of debt in the second quarter of 2002 and the writedowns of CMP Group, Inc.'s investment in NEON Communications, Inc. that reduced earnings per share six cents in 2002 and 39 cents in 2001. (See Note 9 to the company's consolidated Financial Statements.) The decrease is primarily the result of an electric price reduction for NYSEG effective March 1, 2002, that lowered earnings 37 cents per share and a decrease of 10 cents per share due to fewer wholesale electric sales at lower market prices. Those decreases were partially offset by increases of 12 cents per share for lower costs of natural gas purchases and 16 cents per share due to the elimination of goodwill amortization in 2002.

The $117 million increase in operating revenues for the quarter is primarily the result of the addition of RG&E's delivery revenues of $198 million and increased retail deliveries of $26 million due to warmer summer weather. Those increases are partially offset by CMP no longer being the standard-offer provider for the supply of electricity effective in March 2002, which reduced revenues by $42 million; a price reduction for NYSEG, effective March 1, 2002, of $41 million; and lower wholesale deliveries of $21 million.

Operating expenses increased $95 million for the quarter primarily due to the addition of RG&E's operating expenses of $158 million; an $11 million increase in purchased power costs for higher retail deliveries due to warmer summer weather; and a $17 million increase for purchased power costs to replace energy previously provided by NMP2, which was partially offset by a $10 million decrease in certain operating expenses primarily due to the sale of NMP2. Those increases were partially offset by a $42 million decrease in electricity purchased because CMP is no longer the standard-offer provider for the supply of electricity, a $21 million decrease due to lower wholesale deliveries, $6 million due to the elimination of a regulatory amortization of demand-side management program costs and $2 million due to the elimination of goodwill amortization in 2002.

The $28 million decrease in operating revenues for the nine months is primarily the result of a reduction of $111 million because of CMP no longer being the standard-offer provider for the supply of electricity effective in March 2002; $77 million due to a price reduction for NYSEG, effective March 1, 2002; lower wholesale revenues of $53 million primarily due to lower market prices for electricity; and a $15 million decrease primarily due to lower industrial sales. Those decreases were partially offset by the addition of RG&E's delivery revenues of $198 million and increased retail deliveries of $26 million due to warmer summer weather.

Operating expenses increased $9 million for the nine months. Increases include the addition of RG&E's operating expenses of $158 million; $11 million for the pass-through of the market price of electricity allowed in NYSEG's electric rate settlement; $11 million of purchased power costs for higher retail deliveries due to warmer summer weather; and $36 million for purchased power costs to replace energy previously provided by NMP2, which was partially offset by a $31 million decrease in certain operating expenses due to the sale of NMP2. Those increases were partially offset by a $110 million decrease in electricity purchased because CMP is no longer

the standard-offer provider for the supply of electricity, $24 million primarily due to fewer electricity purchases as a result of lower industrial sales, $30 million due to lower market prices for electricity, $14 million due to the elimination of a regulatory amortization of demand-side management program costs and $6 million due to the elimination of goodwill amortization in 2002.

Operating expenses increased $18 million for the quarter primarily due to the addition of RG&E's operating expenses of $38 million, partially offset by a $15 million decrease in purchased gas costs caused by lower market prices, reduced purchases of gas of $5 million due to lower wholesale deliveries and a $4 million decrease due to the elimination of goodwill amortization in 2002.

Operating expenses decreased $185 million for the nine months primarily due to a $169 million decrease in purchased gas costs caused by lower market prices, reduced purchases of gas of $41 million due to lower deliveries and a $12 million decrease due to the elimination of goodwill amortization in 2002. Those decreases were partially offset by the addition of RG&E's operating expenses of $38 million.

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

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

Electric Delivery Business

Regional Transmission Organization: See Energy East Corporation's Item 2(a), Electric Delivery Business, for the discussion of this item.

Transmission Planning and Expansion: See Energy East Corporation's Item 2(a), Electric Delivery Business, for the discussion of this item.

CMP Alternative Rate Plan: See Energy East Corporation's Item 2(a), Electric Delivery Business, for the discussion of this item.

CMP Electricity Supply Responsibility: See Energy East Corporation's Item 2(a), Electric Delivery Business, for the discussion of this item.

Other Matters

Statement 146: See Energy East Corporation's Item 2(a), Other Matters, for the discussion of this item.

Investing and Financing Activities

Investing Activities: Capital spending for the nine months ended September 30, 2002, was $28 million. Capital spending is projected to be $41 million in 2002 and is expected to be paid for with internally generated funds. Capital spending will be primarily for the extension of electric delivery service, necessary improvements to existing facilities and compliance with environmental requirements.

(See Energy East Corporation's Item 2(a), Investing Activities.) CMP's pension plans generated less than a million in pre-tax pension expense in 2001 (net of amounts capitalized). Through the first nine months of 2002, the plans generated $2 million in pre-tax pension expense (net of amounts capitalized), $2 million more than the first nine months of 2001.

Financing Activities: In January 2002 CMP cancelled its shares of treasury stock, which had a carrying value of $19 million, and restored the shares to the status of authorized but unissued shares of common stock of the corporation.

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:

• On May 22, 2002, $37.5 million, 6.50%, due May 2009.
• On May 28, 2002, $37.5 million, 6.65%, due May 2012.
• On August 29, 2002, $15 million, 5.70%, due August 2012.
• On September 10, 2002, $15 million, 4.25%, due September 2007.

2. Results of Operations
   

CMP's earnings for the quarter were nearly unchanged compared to the prior year.

The $47 million decrease in operating revenues for the quarter is primarily the result of CMP not being the standard-offer provider for the supply of electricity effective in March 2002, which reduced revenues by $42 million.

Operating expenses decreased $46 million for the quarter, primarily due to a $42 million decrease in electricity purchased as a result of CMP not being the standard-offer provider for the supply of electricity effective in March 2002. Operating expenses also decreased $2 million due to the elimination of goodwill amortization in 2002.

Earnings for the nine months increased approximately $3 million, primarily due to the elimination of goodwill amortization in 2002 of $6 million.

The $129 million decrease in operating revenues for the nine months is primarily the result of CMP not being the standard-offer provider for the supply of electricity effective in March 2002, which reduced revenues $111 million, and a $15 million decrease primarily due to lower industrial sales.

Operating expenses also decreased $129 million for the nine months, primarily due to a decrease in electricity purchased of $110 million as a result of CMP no longer being the standard-offer provider for the supply of electricity effective in March 2002 and $24 million primarily due to fewer purchases as a result of lower industrial sales. Operating expenses also decreased $6 million due to the elimination of goodwill amortization in 2002.

New York State Electric & Gas Corporation
Statements of Income - (Unaudited)