Energy East (EAS) 10-Q 2003 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-Q

(Mark One)
[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934
      For the quarterly period ended  September 30, 2003

OR

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934
      For the transition period from           to           

Commission file number	Exact name of Registrant as specified in its charter, State of incorporation, Address and Telephone number	IRS Employer Identification No.
1-14766	Energy East Corporation(A New York Corporation) P. O. Box 12904 Albany, New York 12212-2904 (518) 434-3049 www.energyeast.com	14-1798693
1-5139	Central Maine Power Company(A Maine Corporation) 83 Edison Drive Augusta, Maine 04336 (207) 623-3521	01-0042740
1-3103-2	New York State Electric & Gas Corporation(A New York Corporation) P. O. Box 3287 Ithaca, New York 14852-3287 (607) 347-4131	15-0398550
1-672	Rochester Gas and Electric Corporation(A New York Corporation) 89 East Avenue Rochester, New York 14649 (585) 546-2700	16-0612110

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes    X      No        

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Registrant
Energy East Corporation	Yes     X	No
Central Maine Power Company	Yes	No     X
New York State Electric & Gas Corporation	Yes	No     X
Rochester Gas and Electric Corporation	Yes	No     X

As of October 31, 2003, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	146,044,151
Central Maine Power Company	Par value $5 per share	31,211,471(1)
New York State Electric & Gas Corporation	Par value $6.66 2/3 per share	64,508,477(2)
Rochester Gas and Electric Corporation	Par value $5 per share	34,506,513(2)

(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 byEnergy East Corporation, Central Maine Power Company, New York State Electric & Gas Corporation andRochester 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	TABLE OF CONTENTS	Page
	PART I - FINANCIAL INFORMATION
1 2	Financial Statements Management's Discussion and Analysis of Financial Condition     and Results of Operations
	Energy East Corporation   Condensed Consolidated Statements of IncomeCondensed Consolidated Balance SheetsCondensed Consolidated Statements of Cash FlowsCondensed Consolidated Statements of Retained EarningsCondensed Consolidated Statements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	1 2 4 5 5 6 15
	Central Maine Power Company   Condensed Consolidated Statements of IncomeCondensed Consolidated Balance SheetsCondensed Consolidated Statements of Cash FlowsCondensed Consolidated Statements of Retained EarningsCondensed Consolidated Statements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	19 20 22 23 23 24 25
	New York State Electric & Gas Corporation   Condensed Balance SheetsCondensed Statements of IncomeCondensed Statements of Cash FlowsCondensed Statements of Retained EarningsCondensed Statements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	26 28 29 30 30 31 32
	Rochester Gas and Electric Corporation   Condensed Statements of IncomeCondensed Balance SheetsCondensed Statements of Cash FlowsCondensed Statements of Retained Earnings   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	35 36 38 39 40 42

Item	TABLE OF CONTENTS - continued	Page
1	Notes to Financial StatementsForward-looking Statements	44 53
3	Quantitative and Qualitative Disclosures About Market Risk	53
4	Controls and Procedures	54
	PART II - OTHER INFORMATION
6	Exhibits and Reports on Form 8-K (a) Exhibits (b) Reports on Form 8-K	54 54
Signatures		55
Exhibit Index		56

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Energy East Corporation
Condensed Consolidated Statements of Income - (Unaudited)

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands, except per share amounts)
Operating Revenues
Utility	$828,710	$874,321	$3,131,625	$2,519,780
Nonutility	74,414	65,304	265,876	160,004
Total Operating Revenues	903,124	939,625	3,397,501	2,679,784
Operating Expenses
Electricity purchased and fuel used in generation
Utility	317,131	348,471	912,388	907,139
Nonutility	31,255	21,942	95,332	54,005
Natural gas purchased
Utility	70,428	61,512	621,140	331,419
Nonutility	19,545	19,695	98,297	47,461
Other operating expenses
Utility	197,945	175,354	596,651	421,702
Nonutility	18,783	15,698	25,733	48,533
Maintenance	38,923	42,156	128,346	108,046
Depreciation and amortization	75,330	74,627	225,284	168,191
Other taxes	61,555	64,120	205,226	157,144
Total Operating Expenses	830,895	823,575	2,908,397	2,243,640
Operating Income	72,229	116,050	489,104	436,144
Writedown of Investment	-	-	-	12,209
Other (Income)	(3,499)	(9,430)	(10,461)	(22,534)
Other Deductions	1,094	4,516	4,243	25,685
Interest Charges, Net	76,232	72,378	212,063	179,894
Preferred Stock Dividends of Subsidiaries	988	8,292	18,145	23,554
(Loss) Income From Continuing Operations   Before Income Taxes	(2,586)	40,294	265,114	217,336
Income Taxes (Benefit)	(4,670)	15,030	103,669	81,271
Income From Continuing Operations	2,084	25,264	161,445	136,065
Discontinued Operations
Loss from businesses held for sale (including   estimated loss on disposal in 2003 of $13,116)	(15,557)	(2,988)	(9,125)	(2,834)
Income taxes (benefit)	(7,494)	(1,466)	(4,882)	(1,403)
Loss from Discontinued Operations	(8,063)	(1,522)	(4,243)	(1,431)
Net (Loss) Income	$(5,979)	$23,742	$157,202	$134,634
Earnings Per Share from Continuing Operations,   basic and diluted	$.01	$.17	$1.11	$1.07
Total (Loss) Earnings Per Share, basic and diluted	$(.04)	$.16	$1.08	$1.06
Dividends Paid Per Share	$.25	$.24	$.75	$.72
Average Common Shares Outstanding, basic	145,684	144,621	145,400	126,489
Average Common Shares Outstanding, diluted	145,901	144,621	145,588	126,489

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Energy East Corporation
Condensed Consolidated Balance Sheets - (Unaudited)

	Sept. 30, 2003	Dec. 31,   2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$187,315	$250,490
Special deposits	35,729	47,643
Accounts receivable, net	568,551	737,876
Fuel, at average cost	178,514	117,678
Materials and supplies, at average cost	22,770	22,953
Accumulated deferred income tax benefits, net	12,178	8,697
Assets of businesses held for sale	116,759	-
Prepayments and other current assets	124,615	86,167
Total Current Assets	1,246,431	1,271,504
Utility Plant, at Original Cost
Electric	5,951,406	5,803,576
Natural gas	2,380,795	2,347,011
Common	360,205	360,776
	8,692,406	8,511,363
Less accumulated depreciation	3,887,023	3,877,164
Net Utility Plant in Service	4,805,383	4,634,199
Construction work in progress	224,296	179,557
Total Utility Plant	5,029,679	4,813,756
Other Property and Investments, Net	407,692	452,710
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	420,346	524,679
Unfunded future income taxes	228,107	234,487
Unamortized loss on debt reacquisitions	48,691	45,353
Environmental remediation costs	128,761	106,262
Nonutility generator termination agreements	109,250	116,782
Asset retirement obligation	157,550	-
Other	411,579	370,354
Total regulatory assets	1,504,284	1,397,917
Other assets
Goodwill, net	1,534,748	1,518,173
Prepaid pension benefits	596,963	540,426
Other	217,913	262,401
Total other assets	2,349,624	2,321,000
Total Regulatory and Other Assets	3,853,908	3,718,917
Total Assets	$10,537,710	$10,256,887

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Energy East Corporation
Condensed Consolidated Balance Sheets - (Unaudited)

	Sept. 30,   2003	Dec. 31,   2002
(Thousands)
Liabilities
Current Liabilities
Current portion of preferred stock of subsidiary subject to    mandatory redemption requirements	$1,250	- -
Current portion of long-term debt	190,768	$545,404
Notes payable	171,300	322,200
Accounts payable and accrued liabilities	342,905	361,499
Interest accrued	68,162	44,310
Taxes accrued	18,157	30,036
Liabilities of businesses held for sale	32,695	-
Other	192,643	200,927
Total Current Liabilities	1,017,880	1,504,376
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	471,709	203,926
Gain on sale of generation assets	137,326	152,648
Pension benefits	55,880	67,205
Other	90,512	104,937
Total regulatory liabilities	755,427	528,716
Other liabilities
Deferred income taxes	489,104	702,426
Nuclear plant obligations	277,359	314,013
Other postretirement benefits	407,822	391,049
Asset retirement obligation	431,843	-
Environmental remediation costs	147,482	133,933
Other	389,553	408,841
Total other liabilities	2,143,163	1,950,262
Total Regulatory and Other Liabilities	2,898,590	2,478,978
Company-obligated mandatorily redeemable trust preferred    securities of subsidiary holding solely parent debentures	345,000	- -
Preferred stock of subsidiary subject to mandatory    redemption requirements	23,750	- -
Long-term debt	3,645,112	3,351,959
Total Liabilities	7,930,332	7,335,313
Commitments	-	-
Preferred Stock of Subsidiaries  Company-obligated mandatorily redeemable trust preferred    securities of subsidiary holding solely parent debentures  Subject to mandatory redemption requirements  Redeemable solely at the option of subsidiaries	- -       - -       91,095	345,000  25,000  90,962
Common Stock Equity  Common stock	1,460	1,455
Capital in excess of par value	1,453,465	1,447,664
Retained earnings	1,109,670	1,061,428
Accumulated other comprehensive (loss)	(44,684)	(34,167)
Deferred compensation	(3,264)	-
Treasury stock, at cost	(364)	(15,768)
Total Common Stock Equity	2,516,283	2,460,612
Total Liabilities and Stockholders' Equity	$10,537,710	$10,256,887

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

Nine months ended September 30	2003	2002
(Thousands)
Operating Activities
Net income	$157,202	$134,634
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	307,710	205,644
Income taxes and investment tax credits deferred, net	96,338	30,453
Pension income	(33,099)	(52,385)
Writedown of investment	-	12,209
Changes in current operating assets and liabilities
Accounts receivable, net	146,936	145,495
Inventory	(70,444)	(10,629)
Prepayments and other current assets	(46,027)	(24,974)
Accounts payable and accrued liabilities	(25,261)	(23,792)
Interest accrued	23,968	29,541
Taxes accrued	(3,662)	16,415
Other current liabilities	(2,182)	7,141
Other assets	(134,050)	(16,260)
Other liabilities	28,258	(23,917)
Net Cash Provided by Operating Activities	445,687	429,575
Investing Activities
Acquisition, net of cash acquired	-	(681,397)
Utility plant additions	(187,267)	(144,765)
Sale of generation assets	-	59,442
Other property and investments additions	(24,773)	(20,759)
Other property and investments sold	9,532	7,477
Special deposits	5,150	(5,058)
Other	(3,615)	5,430
Net Cash Used in Investing Activities	(200,973)	(779,630)
Financing Activities
Issuance of common stock	3,330	12,866
Repurchase of common stock	-	(1,749)
Repayments of first mortgage bonds, including net premiums	(242,066)	(178,349)
Long-term note issuances	505,596	502,500
Long-term note repayments	(247,582)	(68,660)
Notes payable three months or less, net	(146,900)	38,102
Notes payable issuances	7,000	13,009
Notes payable repayments	(91,435)	(35,607)
Dividends on common stock	(95,832)	(90,715)
Net Cash (Used in) Provided by Financing Activities	(307,889)	191,397
Net Decrease in Cash and Cash Equivalents	(63,175)	(158,658)
Cash and Cash Equivalents, Beginning of Period	250,490	437,014
Cash and Cash Equivalents, End of Period	$187,315	$278,356

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Energy East Corporation
Condensed Consolidated Statements of Retained Earnings - (Unaudited)

Nine months ended September 30	2003	2002
(Thousands)
Balance, Beginning of Period	$1,061,428	$998,281
Add net income	157,202	134,634
Deduct dividends on common stock	108,960	90,715
Balance, End of Period	$1,109,670	$1,042,200

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Energy East Corporation
Condensed Consolidated Statements of Comprehensive Income - (Unaudited)

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands)
Net (loss) income	$(5,979)	$23,742	$157,202	$134,634
Other comprehensive income, net of tax
Net unrealized gains (losses) on investments, net    of income tax (expense) benefit for the three    months of $(87) in 2003 and $953 in 2002 and for    the nine months of $(730) in 2003 and $6,875    in 2002	132	(1,438)	1,096	(10,010)
Reclassification adjustment for investment losses    included in net income, net of income tax    benefit in 2002 of $4,919 for the nine months	- -	- -	- -	7,122
Minimum pension liability adjustment, net of income    tax (expense) for the three and nine months    in 2003 of $(73)	111	- -	111	- -
Unrealized (losses) gains on derivatives qualified    as hedges, net of income tax benefit (expense) for    the three months of $8,840 in 2003 and (6,529)    in 2002 and for the nine months of $(5,176) in    2003 and $(10,875) in 2002	(14,046)	9,755	7,762	13,081
Reclassification adjustment for derivative (gains)    losses included in net income, net of income tax    expense (benefit) for the three months of $1,345    in 2003 and $(1,285) in 2002 and for the nine    months of $12,919 in 2003 and $(6,319) in 2002	(2,032)	1,875	(19,486)	12,944
Net unrealized (losses) gains on derivatives    qualified as hedges	(16,078)	11,630	(11,724)	26,025
Total other comprehensive (loss) income	(15,835)	10,192	(10,517)	23,137
Comprehensive (Loss) Income	$(21,814)	$33,934	$146,685	$157,771

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

Energy East Corporation

(a) Liquidity and Capital Resources

Restructuring

In 2002 Energy East Corporation (Energy East or the company) initiated a corporate restructuring designed 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. (See report on Form 10-K for Energy East, Central Maine Power Company (CMP), New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E) for fiscal year ended December 31, 2002, Item 7 - Liquidity and Capital Resources.) As of September 30, 2003, all of the related involuntary severance liability of $9 million has been paid.

The voluntary early retirement program resulted in a reduction of 486 employees in the first quarter of 2003. Collectively the voluntary early retirement and involuntary severance programs resulted in a reduction in overall employee headcount of 679, or 8%, in 2003, including 79 from CMP, 255 from NYSEG and 254 from RG&E.

Integration savings, previously estimated at over $80 million annually, are now 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, as well as the implementation of other merger-enabled initiatives across the six operating utilities. The company completed its consolidation of information systems and supply chain during the second quarter of 2003.

On September 30, 2003, Energy East received authorization from the Securities and Exchange Commission (SEC) to form a shared services company that will provide services including accounting, treasury, information services, payroll and supply chain functions.

Electric Delivery Business

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.) The negotiation ended without consensus, and on September 16, 2003, FERC issued an order terminating the proceeding.

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 made an RTO filing with FERC on October 31, 2003. The NYISO is considering filings to improve its markets and is working on better coordination with neighboring systems. CMP, NYSEG and RG&E are participating in these efforts.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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 proposed 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, FERC issued a white paper on SMD in which FERC accommodates greater regional flexibility and seeks further comments. The SMD white paper included a preference for energy markets based on locational marginal pricing (LMP), which represented a significant change for some regions of the country. The NYISO and ISO New England already operate markets based on LMP. The companies are unable to predict SMD's ultimate eff ect, 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 RTOs, rather than the transmission owners, and also discuss redefining the cost-sharing responsibilities of interconnecting generators for transmission expansion costs. NYSEG, RG&E and other parties are in discussion with the NYISO on the establishment of a formal regional planning process. On July 24, 2003, FERC issued orders regarding generation interconnection terms, conditions and cost allocation that would require modifications to the companies' interconnection processes. Additional transmission planning and expansion proposals are included in the SMD NOPR. On July 31, 2003, ISO New England and the New England Power Pool submitted a filing to FERC concerning transmission expansion cost allocation. CMP, among other parties, protested the filing, arguing that it would require customers who would not benefit from new transmission projects to contribute to those project costs. The companies are unable to predict the ultimate effect, if any, of these proceedings on their transmission systems 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 FERC's policy proposal in the first half of 2003.

NYISO Demand Curve Proposal: On May 20, 2003, FERC accepted a NYISO proposal to amend its services tariff to adopt a demand curve. The NYISO uses 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, is required to purchase. NYSEG and RG&E expect that the demand curve will not have a material effect on their results of operations or financial position.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

NYPSC Collaborative on End State of Energy Competition: In March 2000 the New York State Public Service Commission (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. A recommended decision (RD) addressing these matters is before the NYPSC.

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 separate RD on the embedded cost of service studies filed by NYSEG and Consolidated Edison was issued on March 24, 2003. That 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 proposals. 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.

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 7.82% on the distribution portion of rates, which reflects a decrease in ice storm amortization expense and other items. In June 2003 the MPUC approved the decrease, which became effective July 1, 2003.

CMP Electricity Supply Responsibility: 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 2004. In July 2003 the MPUC chose suppliers of standard-offer electricity for the six months beginning September 1, 2003: FPL Energy Power Marketing, Inc. for medium class customers and Select Energy, Inc. for larger customers. 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 would fluctuate, however, if its status as a standard-offer provider changes. (See report on Form 10-K for Energy East and CMP for fiscal year ended December 31, 2002, Item 7 - Liquidity and Capital Resources.)

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. In June 2003 the MPUC approved a stipulation agreeing to a total of $7.4 million reduction in stranded cost rates over the period July 2003 through February 2005. The reduction reflects lower anticipated Maine Yankee costs and higher sales levels. The stipulation also provided for deferral and recovery of Yankee Atomic decommissioning costs not currently in rates.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

In response to a request from the Industrial Energy Consumers Group to mitigate high supply prices, the MPUC ordered CMP to lower stranded cost prices for medium and large commercial and industrial customers by $.003 per kWh for the period July 2003 through February 2005. The mitigation is to be funded from CMP's asset sale gain account.

Mandated Contracts with Two NYSEG Customers: (See report on Form 10-K for Energy East and NYSEG for fiscal year ended December 31, 2002, Item 7 - Liquidity and Capital Resources, Electric Delivery Business, NYPSC-mandated Contracts with Two Customers and NYSEG Electric Rate Plan.) 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 long-term electric service contracts with Nucor Steel Auburn, Inc. and Corning Incorporated. NYSEG believed the rates and the terms of those mandated contracts were unduly preferential and violated the law, NYSEG's tariffs and the NYPSC's guidelines. On December 9, 2002, the State Supreme Court dismissed NYSEG's petition.

NYSEG appealed that dismissal to the Appellate Division, Third Department, of the New York State Supreme Court. On July 17, 2003, the Appellate Division affirmed the New York State Supreme Court's dismissal. NYSEG has not requested permission to appeal the Appellate Division's decision.

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 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 (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 of 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 cost of replacement power that was incurred during the required Ginna nuclear plant refueling outage in the fall of 2003.

RG&E is disappointed with the Order 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. In May 2003 RG&E began a proceeding to appeal the most objectionable errors in the Order. That proceeding is now before the Appellate Division, Third Department, of the New York State Supreme Court. A decision on the proceeding is expected early in 2004.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

RG&E Cost Deferral Petitions: On April 9, 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 due to a scheduled refueling outage for the Ginna nuclear generating station (Ginna). The deferred costs are $31 million for repairs required due to the ice storm and an estimated $15 million for the Ginna replacement purchased power. These costs are included in RG&E's 2003 Electric and Gas Rate Proceeding described below.

On April 29, 2003, RG&E received a response from the NYPSC that described the NYPSC's history of allowing net prudent costs of this nature, which have a material effect on earnings, to be deferred and recovered from customers. The letter 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, is deferring those costs in accordance with generally accepted accounting principles, pending approval from the NYPSC, which is expected in early 2004.

On May 15, 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 January 1, 2003, through May 1, 2004, the expected effective date of rates in RG&E's 2003 Electric and Gas Rate Proceeding.

RG&E 2003 Electric and Gas Rate Proceeding: On May 16, 2003, RG&E filed a new 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 $25.3 million, or 7.6% overall and 19.7% on delivery rates. On August 29, 2003, RG&E submitted rate revisions based on continued review of its filing, requesting instead a $97.7 million annual electric rate increase and a $24.6 million annual increase in natural gas rates. RG&E's filing cites inadequate rate relief from the NYPSC's Order issued March 7, 2003, increased costs (see RG&E Cost Deferral Petitions) and the need for a fair and reasonable return on equity of 11.5%. In order to allow negotiations for a long-term rate plan, the NYPSC issued three orders in October 2003 grantin g RG&E's requests for extensions of the date for rates to become effective through June 8, 2004, subject to a make whole provision back to April 29, 2004. RG&E expects the NYPSC to issue a rate order in June 2004, with rates to become effective June 9, 2004, subject to the make whole provision to May 1, 2004, unless long-term rate plans are negotiated and approved earlier.

RG&E Electric Rate Unbundling: On June 5, 2003, as required by the NYPSC's Order issued March 7, 2003, RG&E filed documentation with the NYPSC to unbundle commodity charges and to create electric commodity options for all customers. RG&E expects that this filing will be incorporated into its pending 2003 Electric and Gas Rate Proceeding. In that proceeding RG&E proposes to continue to charge customers bundled rates, with an Electric Supply Reconciliation Mechanism, for the period May 1, 2004, through December 31, 2004. RG&E's unbundling filing proposes separate delivery and commodity service options (modeled on NYSEG's commodity service options) to become effective January 1, 2005, for two periods of two years: 2005 through 2006 and 2007 through 2008. This proceeding may be combined with the RG&E 2003 Electric and Gas Rate Proceeding and the two proceedings considered together by the NYPSC.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Sale of Ginna Station and Relicensing: In June 2003 RG&E announced that it intends to seek bids for the sale of its Ginna nuclear generating station (Ginna station), which it owns and operates. RG&E expects to announce the successful bidder in December 2003 and to close the transaction in mid-2004. The completion of the transaction is dependent on the Nuclear Regulatory Commission (NRC), FERC, NYPSC and other regulatory bodies approving the sale on terms acceptable to RG&E and on the renewal of Ginna's operating license.

The Ginna station 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. A decision on this matter is expected in the second quarter of 2004.

In October 2003 RG&E completed the 31st refueling of the reactor core at Ginna, which will support operations through the spring of 2005. During this refueling outage RG&E also successfully replaced Ginna's reactor vessel head as previously scheduled. The cost of the replacement is estimated to be $13 million and is expected to be recovered in rates. (See report on Form 10-K for Energy East and RG&E for fiscal year ended December 31, 2002, Item 7 - Liquidity and Capital Resources, Electric Delivery Business, Ginna Station.)

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.

Midwest and Northeast Power Outage of August 2003: On August 14, 2003, a major electrical power outage affecting approximately 60 million customers at the height of the outage occurred in the Midwest and Northeast United States and parts of Canada. Ultimate responsibility for the outage is yet to be determined. A joint United States/Canada government-appointed Power Outage Task Force was formed to determine the cause of the outage and to seek solutions to prevent further outages. Until the Task Force concludes their findings, the company is unable to predict the amount of capital expenditures that may be required, if any, should modifications to its electrical system be required as a result of the outage.

Natural Gas Delivery Business

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

RG&E 2003 Electric and Gas Rate Proceeding: See Electric Delivery Business.

NYPSC Collaborative on End State of Energy Competition: See Electric Delivery Business.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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.

CNG Purchased Gas Adjustment Clause: In April 2002 the Connecticut Department of Public Utility Control (DPUC) initiated a semiannual review of Connecticut Natural Gas Corporation's (CNG) 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. On May 28, 2003, the DPUC issued its final decision in this matter, modifying the draft decision and removing the disallowance. The DPUC also notified CNG concerning transactions reviewed in the semiannual review in August 2003, for which a final decision is due in January 2004. CNG is retaining its $1 million reserve contingency to cover the period November 1, 2001, through October 31, 2003, pending completion of the DPUC's review. 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 The Southern Connecticut Gas Company (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. 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. Hearings are currently ongoing and a final decision is expected in January 2004. CNG and SCG cannot predict the final outcome of these proceedings.

Other Businesses

Sale of Other Businesses: The company continues to rationalize its nonutility businesses to ensure they fit its strategic focus. In May 2003 Berkshire Propane Inc., a subsidiary of Berkshire Energy Resources, sold about one-fourth of its assets and customers for approximately book value. In November 2003 Berkshire Propane sold its remaining assets and in October 2003 Energetix sold its Griffith Oil subsidiary. Energetix is a subsidiary of RGS Energy Group, Inc. The estimated after tax loss on disposal recognized in the third quarter was $2 million for Berkshire Propane and $5 million for Griffith Oil. (See Item 1 - Note 2 to Energy East's Condensed Consolidated Financial Statements.)

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

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

useful life of the related asset. The determination of the liability includes various assumptions, the primary assumptions being the discount rate and forecasted cash flows. Changes in those assumptions could have a significant effect on the amount of the company's asset 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 8 to Energy East's Condensed Consolidated Financial Statements.)

Investing and Financing Activities

Investing Activities: Capital spending for the nine months ended September 30, 2003, was $187 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 nine months ended September 30, 2003, the company issued 833,078 shares of common stock at an average price of $19.83 per share, substantially all through its Dividend Reinvestment and Stock Purchase Plan. The shares issued included 331,797 treasury shares and 501,281 newly issued shares.

The company filed a shelf registration statement with the SEC in June 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 had $5 million available under a previous shelf registration statement. The company currently has $805 million available under the shelf registration statement filed in June 2003.

In September 2003 Energy East issued $200 million of 6.75% unsecured notes due in September 2033 under the shelf registration statements described above. The notes were issued as part of an exchange of securities for $156.36 million aggregate principal amount of the company's 7.75% Putable Asset Term Securities (PATS), putable/callable November 15, 2003 from the holders thereof. The remaining cash proceeds were used to finance the cancellation of the related call option with respect to the exchange of the PATS, to finance expenses associated with the offering and for general corporate purposes. Energy East plans to call the remaining PATS in mid-November and expects to fund the transaction with proceeds from the sale of certain nonutility businesses and short-term debt.

In August 2003 Energy East entered into a fixed-to-floating interest rate swap on a portion of the company's 8 1/4% junior subordinated debt securities. The company receives a fixed rate of 8 1/4% and will pay a rate based on the three-month London Interbank Offered Rate (LIBOR) plus 2.00% on a notional amount of $250 million through July 2031.

In August 2003 Energy East terminated a fixed-to-floating interest rate swap on it 5.75% notes due November 2006. The company received $4.2 million, the value of the swap on the date of termination, that it will amortize over the remaining life of the notes.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

In August 2003 CMP issued $35.7 million of Series E Medium Term Notes at a fixed rate of 5.1%, due August 2013. Through financial instruments issued in March 2003 CMP locked in the 10-year treasury rate component of that financing at a fixed rate of 4.105%, which reduced the effective rate on the notes by 10 basis points. The proceeds from the notes were used to help repay $50 million of medium term notes that matured in August 2003.

In March 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 primarily for the retirement or repurchase of certain of its indebtedness or preferred stock, the reduction of short-term debt and other general corporate purposes. NYSEG had $50 million available under a previous shelf registration statement. NYSEG currently has $150 million available under the shelf registration statement filed in March 2003.

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. In 2003 NYSEG redeemed $100 million of 7.45% Series first mortgage bonds: $23 million was redeemed at par on June 30, 2003, pursuant to a sinking fund provision in NYSEG's mortgage indenture and $77 million was redeemed at a premium on July 15, 2003. As of September 30, 2003, NYSEG had redeemed all of its outstanding first mortgage bonds. NYSEG intends to discharge its first mortgage indenture in the fourth quarter of 2003.

In May 2003 NYSEG issued $200 million of 5 3/4% unsecured notes due in May 2023 under the shelf registration statements described above. The proceeds of this unsecured issuance were used to refund commercial paper that was used in April 2003 to redeem the $50 million of 7.55% Series first mortgage bonds, and to redeem in June and July 2003 the $100 million of 7.45% Series first mortgage bonds.

NYSEG will amortize, over the term of the 5 3/4% unsecured notes, a $1.4 million premium on the redemption of its 7.55% Series first mortgage bonds, a $2.7 million premium on the redemption of its 7.45% Series first mortgage bonds and related unamortized debt expenses and debt issuance costs for both redemptions.

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 in 2014.

During the first quarter of 2003 RG&E paid at maturity $40 million of first mortgage bonds using temporary cash investments and internally generated funds. RG&E filed 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 that shelf registration for general corporate purposes, such as retirement or repurchase of certain of its indebtedness or preferred stock, reduction of short-term debt and additions to working capital. RG&E had $75 million available under a previous shelf registration statement. RG&E currently has $300 million available under the shelf registration statement filed in May 2003.

In July 2003 RG&E paid at maturity $40 million of first mortgage bonds using primarily temporary cash investments and short-term debt.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

In September 2003 RG&E issued $75 million of 6 3/8% first mortgage bonds due September 2033 under the shelf registration statements mentioned above. A portion of the net proceeds was used to repay short-term debt, including short-term debt that was issued to pay $40 million of first mortgage bonds that matured in July 2003. RG&E used the remainder of the net proceeds for general corporate purposes.

(b)Results of Operations

Three months ended September 30 (Thousands, except per share amounts)	2003	2002	Change
Operating Revenues	$903,124	$939,625	(4%)
Operating Income	$72,229	$116,050	(38%)
Income from Continuing Operations	$2,084	$25,264	(92%)
Net (Loss) Income	$(5,979)	$23,742	(125%)
Average Common Shares Outstanding, basic	145,684	144,621	1%
Earnings Per Share From Continuing Operations, basic	$.01	$.17	(94%)
(Loss) Earnings Per Share, basic and diluted	$(.04)	$.16	(125%)
Dividends Paid Per Share	$.25	$.24	4%

Earnings for the quarter in 2003 decreased 20 cents per share compared to earnings for the quarter in 2002. Earnings from continuing operations for the quarter in 2003 were 1 cent per share compared to 17 cents per share for the prior year quarter. In keeping with its focus on regulated electric and natural gas delivery businesses, during the past few years the company has been systematically exiting certain noncore businesses. In the third quarter of 2003 the company recognized a loss from discontinued operations of 5 cents per share for two businesses classified as held for sale. The loss from discontinued operations included an estimated after tax loss on disposal of $7 million for the two businesses. In October 2003 Energetix sold its Griffith Oil subsidiary at an estimated after tax loss of $5 million and in November 2003 Berkshire Propane sold its remaining assets at an estimated after tax loss of $2 million. The proceeds from the sales of approximately $80 million will be used to pay down  ;debt.

In addition to the effect of the businesses held for sale, earnings from continuing operations for the 2003 quarter were 7 cents per share lower due to a decrease in electric deliveries resulting from normal summer weather in the third quarter of 2003 compared to an abnormally warm summer last year. Earnings also decreased due to higher noncash stock-based compensation expense of 7 cents per share due to an increase in the price of the company's common stock and lower noncash pension income of 4 cents per share.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Nine months ended September 30 (Thousands, except per share amounts)	2003	2002	Change
Operating Revenues	$3,397,501	$2,679,784	27%
Operating Income	$489,104	$436,144	12%
Income From Continuing Operations	$161,445	$136,065	19%
Net Income	$157,202	$134,634	17%
Average Common Shares Outstanding, basic	145,400	126,489	15%
Earnings Per Share From Continuing Operations, basic	$1.11	$1.07	4%
Earnings Per Share, basic and diluted	$1.08	$1.06	2%
Dividends Paid Per Share	$.75	$.72	4%

Due to the merger completed in June 2002, the company's results of operations include RGS Energy beginning with July 2002.

Earnings per share for the nine months in 2003 increased 2 cents compared to the prior year period. Earnings from continuing operations for the nine months in 2003 were $1.11 per share compared to $1.07 per share for the nine months of the prior year. In the third quarter of 2003 the company recognized a loss from discontinued operations of 5 cents per share for two businesses classified as held for sale.

The increase in earnings from continuing operations was primarily the result of 9 cents per share for higher electric and natural gas deliveries due to colder winter weather in the first quarter of 2003. A decrease in the cost of natural gas, which includes NYSEG's natural gas supply charge that went into effect October 1, 2002, added 6 cents per share to earnings. Integration savings and other cost control efforts added 6 cents per share to earnings. The increase in earnings also includes 7 cents per share for a loss from the early retirement of debt in 2002 and 6 cents per share from the writedown of an investment in NEON Communications in 2002. The earnings increase was reduced 11 cents per share due to electric rate decreases, substantially all from an annualized reduction of $205 million ordered by the NYPSC for NYSEG, the company's largest utility. Earnings were further reduced 12 cents per share due to lower noncash pension income and 5 cents per share due to lower transmission revenues.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Operating Results for the Electric Delivery Business

Three months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	7,841	8,049	(3%)
Operating Revenues	$680,206	$741,338	(8%)
Operating Expenses	$589,619	$612,188	(4%)
Operating Income	$90,587	$129,150	(30%)

Operating revenues were $61 million lower for the quarter as a result of reductions of $16 million due to lower deliveries because of cooler summer weather, $11 million due to lower retail rates, $14 million caused by the elimination in 2002 of the partial amortization of NYSEG's asset sale gain account, which was used to fund a portion of NYSEG's price reduction effective March 1, 2002, and $5 million as a result of the net effect of customers choosing alternate suppliers and customers choosing the bundled rate option.

The $23 million decrease in operating expenses for the quarter was primarily due to decreases in purchased power of $31 million due to customers choosing alternate suppliers. Higher prices that increased purchased power expense were offset by decreased purchases due to lower deliveries. Lower noncash pension income of $6 million increased operating expenses for the quarter.

Nine months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	23,072	19,345	19%
Operating Revenues	$2,078,953	$1,876,742	11%
Operating Expenses	$1,728,856	$1,517,477	14%
Operating Income	$350,097	$359,265	(3%)

Operating revenues were $202 million higher for the nine months as a result of the addition of RG&E delivery revenues of $343 million. That increase was partially offset by decreases of $17 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002, $59 million due to the combined effects of NYSEG's price reduction, effective March 1, 2002, and customers choosing alternate suppliers, $32 million due to the elimination in 2002 of the partial amortization of an asset sale gain account that was used to fund a portion of NYSEG's price reduction effective in March 2002 and $13 million due to lower transmission revenues.

The $211 million increase in operating expenses for the nine months was primarily due to the addition of RG&E operating expenses of $282 million and lower noncash pension income of $28 million. Those amounts were partially offset by decreases in purchased power of $17 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002 and $29 million due to the effect of customers choosing alternate suppliers partially offset by increases caused by both higher market prices and higher retail deliveries because of colder winter weather. Operating expenses also decreased $17 million due to integration savings and cost control efforts, $6 million because of a decrease in wholesale nonutility generator purchases and $4 million due to reduced transmission congestion costs. RG&E deferred expenditures of $23 million during the second quarter and $8 million during the third quarter for

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

restoration work resulting from a severe ice storm in April 2003. Also during the third quarter this year RG&E deferred $8 million of purchased power costs in connection with a scheduled refueling outage for Ginna that began in September 2003 and was completed in October 2003.

Operating Results for the Natural Gas Delivery Business

Three months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	26,550	29,859	(11%)
Operating Revenues	$148,504	$132,983	12%
Operating Expenses	$166,355	$148,606	12%
Operating (Loss)	$(17,851)	$(15,623)	14%

Operating revenues were $16 million higher for the quarter because of increases of $18 million primarily due to gas cost recovery provisions.

Operating expenses increased $18 million for the quarter primarily due to higher natural gas costs of $13 million because of market conditions and the effect of various rate case deferrals.

Nine months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	154,792	116,318	33%
Operating Revenues	$1,052,672	$643,038	64%
Operating Expenses	$917,924	$562,007	63%
Operating Income	$134,748	$81,031	66%

Operating revenues were $410 million higher for the nine months primarily due to the addition of RG&E delivery revenues of $213 million and increases of $72 million due to higher retail deliveries because of colder weather, $112 million primarily due to gas cost recovery provisions and $8 million due to an increase in prices for wholesale sales because of market conditions.

Operating expenses increased $356 million for the nine months primarily due to the addition of RG&E operating expenses of $178 million, higher natural gas costs of $114 million due to market conditions net of the effect of various rate case deferrals and $43 million due to higher retail deliveries because of colder winter weather.

Item 1.  Financial Statements

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

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands)
Operating Revenues
Sales and services	$145,715	$153,663	$457,391	$493,485
Operating Expenses
Electricity purchased	59,104	61,745	179,790	207,162
Other operating expenses	44,238	44,006	132,543	133,167
Maintenance	6,249	8,828	22,384	28,985
Depreciation and amortization	10,282	10,168	30,647	29,101
Other taxes	4,869	5,816	15,273	16,977
Total Operating Expenses	124,742	130,563	380,637	415,392
Operating Income	20,973	23,100	76,754	78,093
Other (Income)	(1,195)	(1,322)	(2,943)	(3,815)
Other Deductions	331	301	1,130	944
Interest Charges, Net	6,531	6,794	19,818	21,735
Income Before Income Taxes	15,306	17,327	58,749	59,229
Income Taxes	5,737	5,955	22,257	19,282
Net Income	9,569	11,372	36,492	39,947
Preferred Stock Dividends	361	361	1,082	1,082
Earnings Available for Common Stock	$9,208	$11,011	$35,410	$38,865

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Central Maine Power Company
Condensed Consolidated Balance Sheets - (Unaudited)

	Sept. 30,   2003	Dec. 31,   2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$14,700	$20,415
Accounts receivable, net	95,295	124,711
Materials and supplies, at average cost	7,064	7,096
Accumulated deferred income tax benefits, net	702	1,902
Prepayments and other current assets	6,022	6,411
Total Current Assets	123,783	160,535
Utility Plant, at Original Cost
Electric	1,330,550	1,316,023
Less accumulated depreciation	523,648	499,381
Net Utility Plant in Service	806,902	816,642
Construction work in progress	6,628	2,952
Total Utility Plant	813,530	819,594
Other Property	5,874	5,880
Investment in Associated Companies, at Equity	23,878	27,137
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	173,668	211,268
Unfunded future income taxes	105,612	101,791
Unamortized loss on debt reacquisitions	8,894	9,722
Demand-side management program costs	5,634	8,394
Environmental remediation costs	3,306	4,440
Nonutility generator termination agreement	6,257	7,195
Other	60,454	58,259
Total regulatory assets	363,825	401,069
Other assets
Goodwill, net	325,580	325,580
Prepaid pension benefits	31,854	23,124
Other	28,595	23,404
Total other assets	386,029	372,108
Total Regulatory and Other Assets	749,854	773,177
Total Assets	$1,716,919	$1,786,323

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Central Maine Power Company
Condensed Consolidated Balance Sheets - (Unaudited)

	Sept. 30, 2003	Dec. 31,   2002
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$22,912	$52,975
Accounts payable and accrued liabilities	42,349	45,551
Interest accrued	2,056	6,056
Taxes accrued	1,369	6,118
Other	46,976	48,575
Total Current Liabilities	115,662	159,275
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	106,775	112,119
Gain on sale of generation assets	85,935	112,009
Other	15,239	11,926
Total regulatory liabilities	207,949	236,054
Other liabilities
Deferred income taxes	27,744	4,605
Nuclear plant obligations	173,668	211,268
Other postretirement benefits	74,872	71,236
Environmental remediation costs	2,867	2,987
Other	127,053	127,986
Total other liabilities	406,204	418,082
Total Regulatory and Other Liabilities	614,153	654,136
Long-term debt	315,381	291,796
Total Liabilities	1,045,196	1,105,207
Commitments	-	-
Preferred Stock  Preferred stock	35,571	35,571
Capital in excess of par value	(2,582)	(2,723)
Common Stock Equity  Common stock	156,057	156,057
Capital in excess of par value	485,353	485,297
Retained earnings	22,092	31,682
Accumulated other comprehensive (loss)	(24,768)	(24,768)
Total Common Stock Equity	638,734	648,268
Total Liabilities and Stockholder's Equity	$1,716,919	$1,786,323

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

Nine months ended September 30	2003	2002
(Thousands)
Operating Activities
Net income	$36,492	$39,947
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	46,106	50,122
Income taxes and investment tax credits deferred, net	15,172	10,635
Pension expense	6,270	1,849
Changes in current operating assets and liabilities
Accounts receivable, net	29,416	24,662
Inventory	32	384
Prepayments and other current assets	389	(523)
Accounts payable and accrued liabilities	(13,014)	(22,190)
Interest accrued	(4,000)	(2,790)
Taxes accrued	(4,749)	10,796
Other current liabilities	(1,591)	6,965
Asset sale gain amortization	(26,074)	(32,148)
Prepaid pension benefits	(15,000)	-
Other assets	(8,133)	(6,699)
Other liabilities	3,853	(15,127)
Net Cash Provided by Operating Activities	65,169	65,883
Investing Activities
Utility plant additions	(18,489)	(28,390)
Other	222	128
Net Cash Used in Investing Activities	(18,267)	(28,262)
Financing Activities
Long-term note issuances	35,700	105,000
Long-term note repayments	(52,235)	(50,887)
Notes payable three months or less, net	10,000	(13,000)
Notes payable issuances	-	5,000
Notes payable repayments	-	(23,500)
Dividends on common and preferred stock	(46,082)	(54,195)
Net Cash Used in Financing Activities	(52,617)	(31,582)
Net (Decrease) Increase in Cash and Cash Equivalents	(5,715)	6,039
Cash and Cash Equivalents, Beginning of Period	20,415	20,777
Cash and Cash Equivalents, End of Period	$14,700	$26,816

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Central Maine Power Company
Condensed Consolidated Statements of Retained Earnings - (Unaudited)

Nine months ended September 30	2003	2002
(Thousands)
Balance, Beginning of Period	$31,682	$31,304
Add net income	36,492	39,947
	68,174	71,251
Deduct Dividends on Capital Stock
Preferred	1,082	1,082
Common	45,000	53,113
	46,082	54,195
Balance, End of Period	$22,092	$17,056

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands)
Net income	$9,569	$11,372	$36,492	$39,947
Other comprehensive income, net of tax
Net unrealized gain on derivatives qualified as    hedges, net of income tax in 2003 of $(631)    for the three months	915	- -	- -	- -
Total other comprehensive income	915	-	-	-
Comprehensive Income	$10,484	$11,372	$36,492	$39,947

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

Central Maine Power Company

(a)Liquidity and Capital Resources

Restructuring

See Energy East Corporation's Item 2(a),Restructuring, for this discussion.

Electric Delivery Business

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

FERC Standard Market Design: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

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

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

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

MPUC Stranded Cost Proceeding: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Midwest and Northeast Power Outage of August 2003: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Investing and Financing Activities

Investing Activities: Capital spending for the nine months ended September 30, 2003, was $18 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: In August 2003 CMP issued $35.7 million of Series E Medium Term Notes at a fixed rate of 5.1%, due August 2013. Through financial instruments issued in March 2003 CMP locked in the 10-year treasury rate component of that financing at a fixed rate of 4.105%, which reduced the effective rate on the notes by 10 basis points. The proceeds from the notes were used to help repay $50 million of medium term notes that matured in August 2003.

Management's discussion and analysis of financial condition and results of operations

Central Maine Power Company

(b)Results of Operations

Three months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	2,310	2,267	2%
Operating Revenues	$145,715	$153,663	(5%)
Operating Expenses	$124,742	$130,563	(4%)
Operating Income	$20,973	$23,100	(9%)
Earnings Available for Common Stock	$9,208	$11,011	(16%)

Earnings for the quarter decreased approximately $2 million primarily as a result of lower operating revenues.

The $8 million reduction in operating revenues was primarily the result of a $4 million decrease due to lower retail rates pursuant to the Alternative Rate Plan, a $2 million decrease in accrued transmission congestion revenues and demand-side management (DSM) revenues because of lower costs and a $1 million decrease from lower sales of nonutility generator (NUG) entitlement power.

The $6 million decrease in operating expenses for the quarter was primarily the result of lower amortization of storm and DSM costs of $4 million and a reduction in purchased power costs of $2 million.

Nine months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	6,684	6,502	3%
Operating Revenues	$457,391	$493,485	(7%)
Operating Expenses	$380,637	$415,392	(8%)
Operating Income	$76,754	$78,093	(2%)
Earnings Available for Common Stock	$35,410	$38,865	(9%)

Earnings for the nine months decreased $3 million as a result of lower revenues and prior year income tax adjustments.

The $36 million decrease in operating revenues was primarily the result of CMP no longer being the standard-offer provider for the supply of electricity for residential and small commercial class customers effective March 2002, which reduced revenues $17 million; lower revenues from NUG entitlement sales of $6 million; lower rates pursuant to the Alternative Rate Plan of $8 million; a decrease in accrued DSM revenues of $4 million due to lower costs; and a decrease in transmission congestion costs of $3 million.

The $35 million decrease in 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 operating expenses $17 million; a decrease in NUG power purchases of $6 million; lower amortization of ice storm expenses of $4 million; reduced transmission congestion costs of $4 million; and lower payroll-related expenses of $3 million.

Item 1.  Financial Statements

New York State Electric & Gas Corporation
Condensed Balance Sheets - (Unaudited)

	Sept. 30,   2003	Dec. 31,   2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$17,409	$11,490
Special deposits	31,786	44,205
Accounts receivable, net	238,774	260,189
Fuel, at average cost	49,252	29,000
Materials and supplies, at average cost	5,970	5,573
Accumulated deferred income tax benefits, net	4,493	4,232
Prepayments	39,602	26,571
Total Current Assets	387,286	381,260
Utility Plant, at Original Cost
Electric	2,578,110	2,551,775
Natural gas	681,170	671,321
Common	119,525	121,661
	3,378,805	3,344,757
Less accumulated depreciation	1,428,370	1,371,892
Net Utility Plant in Service	1,950,435	1,972,865
Construction work in progress	48,108	40,166
Total Utility Plant	1,998,543	2,013,031
Other Property and Investments, Net	42,430	41,365
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes	15,327	20,467
Unamortized loss on debt reacquisitions	39,797	35,631
Environmental remediation costs	75,334	52,434
Other	67,090	23,563
Total regulatory assets	197,548	132,095
Other assets
Goodwill, net	11,199	11,199
Prepaid pension benefits	437,010	395,586
Other	55,687	78,890
Total other assets	503,896	485,675
Total Regulatory and Other Assets	701,444	617,770
Total Assets	$3,129,703	$3,053,426

Thenotes on pages 44 through 52 are an integral part of the financial statements.

New York State Electric & Gas Corporation
Condensed Balance Sheets - (Unaudited)

	Sept. 30,   2003	Dec. 31,   2002
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$209	$702
Notes payable	9,000	64,000
Accounts payable and accrued liabilities	153,941	169,884
Interest accrued	18,371	12,289
Taxes accrued	6,854	11,091
Other	73,969	58,577
Total Current Liabilities	262,344	316,543
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	50,944	26,199
Gain on sale of generation assets	51,390	40,638
Other	15,673	25,036
Total regulatory liabilities	118,007	91,873
Other liabilities
Deferred income taxes	356,922	347,355
Other postretirement benefits	205,788	197,193
Environmental remediation costs	98,000	75,100
Other	59,716	56,683
Total other liabilities	720,426	676,331
Total Regulatory and Other Liabilities	838,433	768,204
Long-term debt	1,066,181	1,017,902
Total Liabilities	2,166,958	2,102,649
Commitments	-	-
Preferred Stock  Redeemable solely at NYSEG's option	10,159	10,159
Common Stock Equity  Common stock	430,057	430,057
Capital in excess of par value	277,447	277,297
Retained earnings	227,014	206,519
Accumulated other comprehensive income	18,068	26,745
Total Common Stock Equity	952,586	940,618
Total Liabilities and Stockholder's Equity	$3,129,703	$3,053,426

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands)
Operating Revenues
Electric	$367,457	$389,216	$1,111,777	$1,184,687
Natural gas	39,170	35,675	283,945	222,902
Total Operating Revenues	406,627	424,891	1,395,722	1,407,589
Operating Expenses
Electricity purchased	214,811	229,019	612,924	642,269
Natural gas purchased	21,772	19,854	172,398	129,529
Other operating expenses	57,855	42,259	158,354	150,380
Maintenance	14,489	19,799	52,919	58,818
Depreciation and amortization	25,136	24,624	75,132	73,616
Other taxes	29,297	28,996	89,961	88,187
Total Operating Expenses	363,360	364,551	1,161,688	1,142,799
Operating Income	43,267	60,340	234,034	264,790
Other (Income)	836	(1,804)	(1,273)	(4,369)
Other Deductions	224	3,142	(1,072)	20,393
Interest Charges, Net	19,546	20,879	59,906	69,402
Income Before Income Taxes	22,661	38,123	176,473	179,364
Income Taxes	2,408	14,827	65,681	73,303
Net Income	20,253	23,296	110,792	106,061
Preferred Stock Dividends	99	99	297	297
Earnings Available for Common Stock	$20,154	$23,197	$110,495	$105,764

Thenotes on pages 44 through 52 are an integral part of the financial statements.

New York State Electric & Gas Corporation
Condensed Statements of Cash Flows - (Unaudited)

Nine months ended September 30	2003	2002
(Thousands)
Operating Activities
Net income	$110,792	$106,061
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	98,591	90,245
Income taxes and investment tax credits deferred, net	47,072	24,201
Pension income	(33,047)	(53,116)
Changes in current operating assets and liabilities
Accounts receivable, net	21,415	77,155
Inventory	(20,649)	2,778
Prepayments	(13,031)	(10,406)
Accounts payable and accrued liabilities	(15,943)	5,982
Interest accrued	6,082	3,694
Taxes accrued	(4,237)	12,426
Other current liabilities	15,392	7,616
Other assets	(57,177)	(7,967)
Other liabilities	10,823	(5,343)
Net Cash Provided by Operating Activities	166,083	253,326
Investing Activities
Utility plant additions	(63,574)	(62,480)
Sale of generation assets	-	59,442
Proceeds from sale of utility plant	379	6,348
Special deposits	5,156	(5,058)
Other	271	2,798
Net Cash (Used in) Provided by Investing Activities	(57,768)	1,050
Financing Activities
Notes payable three months or less, net	(55,000)	-
Repayments of first mortgage bonds, including net premiums	(154,085)	(177,025)
Long-term note issuances	196,986	-
Dividends on common and preferred stock	(90,297)	(60,297)
Net Cash Used in Financing Activities	(102,396)	(237,322)
Net Increase in Cash and Cash Equivalents	5,919	17,054
Cash and Cash Equivalents, Beginning of Period	11,490	21,617
Cash and Cash Equivalents, End of Period	$17,409	$38,671

Thenotes on pages 44 through 52 are an integral part of the financial statements.

New York State Electric & Gas Corporation
Condensed Statements of Retained Earnings - (Unaudited)

Nine months ended September 30	2003	2002
(Thousands)
Balance, Beginning of Period	$206,519	$164,197
Add net income	110,792	106,061
	317,311	270,258
Deduct Dividends on Capital Stock
Preferred	297	297
Common	90,000	90,000
	90,297	90,297
Balance, End of Period	$227,014	$179,961

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands)
Net income	$20,253	$23,296	$110,792	$106,061
Other comprehensive income, net of tax
Net unrealized gains (losses) on investments, net of     income tax (expense) benefit for the three months     of $(180) in 2003 and $433 in 2002 and for the     nine months of $(345) in 2003 and $790 in 2002	271	(653)	520	(1,191)
Minimum pension liability adjustment, net of income     tax (expense) for the three and nine months     in 2003 of $(73)	111	- -	111	- -
Unrealized (losses) gains on derivatives qualified    as hedges, net of income tax benefit (expense) for    the three months of $9,390 in 2003 and $(5,001)    in 2002 and for the nine months of $(6,793) in    2003 and $(7,820) in 2002	(14,159)	7,541	10,243	11,792
Reclassification adjustment for derivative (gains)    losses included in net income, net of income    tax expense (benefit) for the three months of    $1,377 in 2003 and $(1,447) in 2002 and for    the nine months of $12,966 in 2003 and $(6,220)    in 2002	(2,076)	2,181	(19,551)	9,378
Net unrealized (losses) gains on derivatives    qualified as hedges	(16,235)	9,722	(9,308)	21,170
Total other comprehensive (loss) income	(15,853)	9,069	(8,677)	19,979
Comprehensive Income	$4,400	$32,365	$102,115	$126,040

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

New York State Electric & Gas Corporation

(a)Liquidity and Capital Resources

Restructuring

See Energy East Corporation's Item 2(a),Restructuring, for this discussion.

Electric Delivery Business

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

FERC Standard Market Design: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

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

NYISO Demand Curve Proposal: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

NYPSC Collaborative on End State of Energy Competition: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Mandated Contracts with Two NYSEG Customers: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Manufactured Gas Plant Remediation Recovery: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Midwest and Northeast Power Outage of August 2003: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Natural Gas Delivery Business

NYPSC Collaborative on End State of Energy Competition: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

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

Asset Retirement Obligation: See Energy East's Item 2(a), Critical Accounting Policies, for this discussion.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Investing Activities

Investing Activities: Capital spending for the first nine months of 2003 was $64 million. Capital spending is projected to be $95 million for 2003 and is expected to be paid for with internally generated funds. Capital spending will be primarily for necessary improvements to existing facilities, the extension of energy delivery service, compliance with environmental requirements and governmental mandates and merger integration.

Financing Activities: In March 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 primarily for the retirement or repurchase of certain of its indebtedness or preferred stock, the reduction of short-term debt and other general corporate purposes. NYSEG had $50 million available under a previous shelf registration statement. NYSEG currently has $150 million available under the shelf registration statement filed in March 2003.

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. In 2003 NYSEG redeemed $100 million of 7.45% Series first mortgage bonds: $23 million was redeemed at par on June 30, 2003, pursuant to a sinking fund provision in NYSEG's mortgage indenture and $77 million was redeemed at a premium on July 15, 2003. As of September 30, 2003, NYSEG had redeemed all of its outstanding first mortgage bonds. NYSEG intends to discharge its first mortgage indenture in the fourth quarter of 2003.

In May 2003 NYSEG issued $200 million of 5 3/4% unsecured notes due in May 2023 under the shelf registration statements described above. The proceeds of this unsecured issuance were used to refund commercial paper that was used in April 2003 to redeem the $50 million of 7.55% Series first mortgage bonds, and to redeem in June and July 2003 the $100 million of 7.45% Series first mortgage bonds.

NYSEG will amortize, over the term of the 5 3/4% unsecured notes, a $1.4 million premium on the redemption of its 7.55% Series first mortgage bonds, a $2.7 million premium on the redemption of its 7.45% Series first mortgage bonds and related unamortized debt expenses and debt issuance costs for both redemptions.

(b)Results of Operations

Three months ended September 30 (Thousands)	2003	2002	Change
Operating Revenues	$406,627	$424,891	(4%)
Operating Income	$43,267	$60,340	(28%)
Earnings Available for Common Stock	$20,154	$23,197	(13%)

Third quarter 2003 earnings were $3 million lower than for the prior year quarter primarily due to $3 million for lower noncash pension income and $2 million for the net effect of higher purchased power costs and customers choosing alternate suppliers. Those earnings reductions were partially offset by a $3 million increase as a result of a change in estimate of prior year income taxes to reflect actual 2002 taxes as filed and revisions to the estimated effective tax rate for 2003.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Nine months ended September 30 (Thousands)	2003	2002	Change
Operating Revenues	$1,395,722	$1,407,589	(1%)
Operating Income	$234,034	$264,790	(12%)
Earnings Available for Common Stock	$110,495	$105,764	4%

Earnings increased $5 million for the nine months primarily due to increases of $14 million due to higher electric and natural gas retail deliveries primarily because of colder winter weather, $10 million due to the effect of a loss from the early retirement of debt in 2002, $9 million for integration savings and cost control efforts, $4 million for the recovery of natural gas prices through the gas supply charge and $6 million due to lower interest charges as a result of refinancings and repayments of first mortgage bonds. Those increases were partially offset by earnings reductions of $23 million caused by an electric price reduction effective March 1, 2002, $7 million for lower transmission revenues, and $10 million for lower noncash pension income.

Operating Results for the Electric Delivery Business

Three months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	3,672	3,752	(2%)
Operating Revenues	$367,457	$389,216	(6%)
Operating Expenses	$317,559	$323,493	(2%)
Operating Income	$49,898	$65,723	(24%)

The $22 million decrease in operating revenues for the quarter is primarily due to a decrease of $14 million caused by the elimination in 2002 of the partial amortization of an asset sale gain account, which was used to fund a portion of a price reduction effective March 1, 2002, and a decrease of $5 million as a result of the net effect of customers choosing alternate suppliers and customers choosing the bundled rate option.

Operating expenses decreased $6 million for the quarter primarily as a result of decreases in purchased power of $31 million due to customers choosing alternate suppliers. That decrease was partially offset by higher electricity prices that increased purchased power $17 million and an increase of $6 million due to lower noncash pension income.

Nine months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	11,079	10,813	2%
Operating Revenues	$1,111,777	$1,184,687	(6%)
Operating Expenses	$918,310	$943,825	(3%)
Operating Income	$193,467	$240,862	(20%)

Operating revenues for the nine months decreased $73 million primarily due to a $59 million decrease because of the combined effects of a price reduction, effective March 1, 2002, and the net effect of customers choosing alternate suppliers and customers choosing the bundled rate option, a $32 million decrease due to the elimination in 2002 of the partial amortization of an asset sale gain account that was used to fund a portion of the price reduction effective in March 2002 and a $12 million reduction in transmission revenues. Those decreases were partially offset by higher retail deliveries of $26 million because of colder winter weather.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

The $26 million decrease in operating expenses for the nine months was primarily the result of a $29 million decrease in purchased power resulting from customers choosing alternate suppliers partially offset by increases due to both higher market prices and higher retail deliveries because of colder winter weather, a $12 million decrease due to integration savings and cost control efforts and a $4 million decrease due to the elimination of a regulatory amortization of DSM program costs. Those decreases were partially offset by an $18 million increase because of lower noncash pension income.

Operating Results for the Natural Gas Delivery Business

Three months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	6,620	6,653	-
Operating Revenues	$39,170	$35,675	10%
Operating Expenses	$45,801	$41,058	12%
Operating (Loss)	$(6,631)	$(5,383)	23%

The $3 million increase in operating revenues for the quarter is primarily due to an increase of $5 million due to gas cost recovery resulting from a natural gas supply charge partially offset by a $2 million decrease because of lower wholesale sales.

Operating expenses increased $5 million for the quarter primarily due to a $4 million increase in the cost of natural gas purchased, after various deferrals of gas costs for future recovery, partially offset by a $2 million decrease in the cost of wholesale natural gas purchased due to decreased sales.

Nine months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	44,429	39,435	13%
Operating Revenues	$283,945	$222,902	27%
Operating Expenses	$243,378	$198,974	22%
Operating Income	$40,567	$23,928	70%

Operating revenues increased $61 million for the nine months primarily due to higher retail deliveries of $32 million because of colder winter weather, gas cost recovery of $27 million resulting from a natural gas supply charge and $9 million due to an increase in prices for wholesale sales because of market conditions.

Operating expenses for the nine months increased $44 million primarily due to a $21 million increase in natural gas purchased for higher retail deliveries because of colder winter weather this year and a $22 million increase in the cost of natural gas, after various deferrals of gas costs for future recovery.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation
Condensed Statements of Income - (Unaudited)

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands)
Operating Revenues
Electric	$167,016	$198,429	$509,694	$534,986
Natural gas	36,622	32,939	249,250	193,480
Total Operating Revenues	203,638	231,368	758,944	728,466
Operating Expenses
Electricity purchased and fuel used in generation	43,215	57,707	119,673	153,427
Natural gas purchased	17,687	15,692	148,937	108,794
Other operating expenses	67,387	65,155	222,716	202,241
Maintenance	15,141	10,368	42,591	42,545
Depreciation and amortization	26,464	25,990	79,377	76,120
Other taxes	18,572	21,034	62,363	67,540
Total Operating Expenses	188,466	195,946	675,657	650,667
Operating Income	15,172	35,422	83,287	77,799
Other (Income)	(1,274)	(5,590)	(3,815)	(13,411)
Other Deductions	423	318	1,386	6,154
Interest Charges, Net	15,307	15,319	61,694	42,523
Income Before Income Taxes	716	25,375	24,022	42,533
Income Taxes	3,577	8,088	10,720	21,527
Net (Loss) Income	(2,861)	17,287	13,302	21,006
Preferred Stock Dividends	513	925	2,363	2,775
(Loss) Earnings Available for Common Stock	$(3,374)	$16,362	$10,939	$18,231

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Condensed Balance Sheets - (Unaudited)

	Sept. 30, 2003	Dec. 31,   2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$32,072	$86,385
Special deposits	3,333	2,841
Accounts receivable, net	88,350	126,227
Affiliate receivable	38,224	20,330
Fuel, at average cost	37,350	20,555
Materials and supplies, at average cost	6,393	6,467
Prepayments and other current assets	53,279	35,324
Total Current Assets	259,001	298,129
Utility Plant, at Original Cost
Electric	2,042,746	1,935,778
Natural gas	520,468	515,829
Common	158,651	157,416
	2,721,865	2,609,023
Less accumulated depreciation	1,429,668	1,530,729
Net Utility Plant in Service	1,292,197	1,078,294
Construction work in progress	163,143	133,195
Total Utility Plant	1,455,340	1,211,489
Other Property and Investments, Net	259,678	226,373
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	246,679	313,412
Unfunded future income taxes	49,144	52,058
Environmental remediation costs	11,559	11,290
Nonutility generator termination agreement	102,993	109,587
Asset retirement obligation	157,550	-
Other	174,757	163,655
Total regulatory assets	742,682	650,002
Other assets
Prepaid pension benefits	11,662	-
Other	61,423	66,104
Total other assets	73,085	66,104
Total Regulatory and Other Assets	815,767	716,106
Total Assets	$2,789,786	$2,452,097

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Condensed Balance Sheets - (Unaudited)

	Sept. 30,   2003	Dec. 31,   2002
(Thousands)
Liabilities
Current Liabilities
Current portion of preferred stock subject to mandatory redemption   requirements	$1,250	- -
Current portion of long-term debt	-	$159,935
Accounts payable and accrued liabilities	94,085	67,787
Affiliate payable	9,959	7,365
Interest accrued	13,528	10,509
Taxes accrued	1,733	3,451
Other	29,102	40,523
Total Current Liabilities	149,657	289,570
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	260,253	18,179
Other	47,334	56,617
Total regulatory liabilities	307,587	74,796
Other liabilities
Deferred income taxes	-	225,325
Nuclear waste disposal	103,692	102,745
Other postretirement benefits	70,671	65,983
Environmental remediation costs	22,356	22,356
Asset retirement obligation	430,569	-
Other	44,521	59,721
Total other liabilities	671,809	476,130
Total Regulatory and Other Liabilities	979,396	550,926
Preferred stock subject to mandatory redemption requirements	23,750	-
Long-term debt	826,485	752,254
Total Liabilities	1,979,288	1,592,750
Commitments	-	-
Preferred Stock  Redeemable solely at RG&E's option  Subject to mandatory redemption requirements	47,000  - -	47,000  25,000
Common Stock Equity  Common stock	194,429	194,429
Capital in excess of par value	556,101	555,889
Retained earnings	130,206	154,267
Treasury stock, at cost	(117,238)	(117,238)
Total Common Stock Equity	763,498	787,347
Total Liabilities and Stockholder's Equity	$2,789,786	$2,452,097

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Condensed Statements of Cash Flows - (Unaudited)

Nine months ended September 30	2003	2002
(Thousands)
Operating Activities
Net income	$13,302	$21,006
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	133,852	124,035
Writedown of investments	-	13,718
Income taxes and investment tax credits deferred, net	13,918	(4,877)
Pension income	(13,326)	(15,652)
Excess earnings	44,051	-
Changes in current operating assets and liabilities
Accounts receivable, net	23,974	34,564
Inventory	(16,721)	(2,458)
Prepayments	(26,935)	(28,175)
Accounts payable and accrued liabilities	28,413	2,273
Interest accrued	3,019	4,571
Taxes accrued	(1,718)	(2,685)
Other current liabilities	(12,487)	(6,413)
Other assets	(54,158)	(36,305)
Other liabilities	23,121	9,108
Net Cash Provided by Operating Activities	158,305	112,710
Investing Activities
Utility plant additions	(74,115)	(97,140)
Sale of generation assets	-	50,484
Nuclear generating plant decommissioning fund	(13,012)	(13,012)
Other	(2,781)	(4,875)
Net Cash Used in Investing Activities	(89,908)	(64,543)
Financing Activities
Repayments of first mortgage bonds, including net premiums	(80,000)	(100,000)
Long-term note issuances	75,000	125,000
Repayment of promissory notes	(79,935)	(3,260)
Dividends on common and preferred stock	(37,775)	(57,829)
Net Cash Used in Financing Activities	(122,710)	(36,089)
Net (Decrease) Increase in Cash and Cash Equivalents	(54,313)	12,078
Cash and Cash Equivalents, Beginning of Period	86,385	19,462
Cash and Cash Equivalents, End of Period	$32,072	$31,540

Thenotes on pages 44 through 52 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Condensed Statements of Retained Earnings - (Unaudited)

Nine months ended September 30	2003	2002
(Thousands)
Balance, Beginning of Period	$154,267	$174,054
Add net income	13,302	21,006
	167,569	195,060
Deduct Dividends on Capital Stock
Preferred	2,363	2,775
Common	35,000	66,154
	37,363	68,929
Balance, End of Period	$130,206	$126,131

Thenotes on pages 44 through 52 are an integral part of the financial statements.

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

Rochester Gas and Electric Corporation

(a)Liquidity and Capital Resources

Restructuring

See Energy East Corporation's Item 2(a),Restructuring, for this discussion.

Electric Delivery Business

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

FERC Standard Market Design: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

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

NYISO Demand Curve Proposal: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

NYPSC Collaborative on End State of Energy Competition: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

RG&E 2002 Electric and Gas Rate Proceeding: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

RG&E Cost Deferral Petitions:See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

RG&E 2003 Electric and Gas Rate Proceeding: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

RG&E Electric Rate Unbundling: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Sale of Ginna Station and Relicensing:See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Manufactured Gas Plant Remediation Recovery:See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Midwest and Northeast Power Outage of August 2003: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Natural Gas Delivery Business

NYPSC Collaborative on End State of Energy Competition: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

RG&E 2002 Electric and Gas Rate Proceeding: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

RG&E 2003 Electric and Gas Rate Proceeding: See Energy East Corporation's Item 2(a), Electric Delivery Business, for this discussion.

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

Asset Retirement Obligation: See Energy East's Item 2(a), Critical Accounting Policies, for this discussion.

Investing and Financing Activities

Investing Activities: Capital spending for the first nine months of 2003 was $74 million, including nuclear fuel. Capital spending is projected to be $146 million for 2003, including nuclear fuel, and is expected to be paid for primarily 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: 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 in 2014.

During the first quarter of 2003 RG&E paid at maturity $40 million of first mortgage bonds using temporary cash investments and internally generated funds. RG&E filed 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 that shelf registration for general corporate purposes, such as retirement or repurchase of certain of its indebtedness or preferred stock, reduction of short-term debt and additions to working capital. RG&E had $75 million available under a previous shelf registration statement. RG&E currently has $300 million available under the shelf registration statement filed in May 2003.

In July 2003 RG&E paid at maturity $40 million of first mortgage bonds using primarily temporary cash investments and short-term debt.

In September 2003 RG&E issued $75 million of 6 3/8% first mortgage bonds due September 2033 under the shelf registration statements mentioned above. A portion of the net proceeds was used to repay short-term debt, including short-term debt that was issued to pay $40 million of first mortgage bonds that matured in July 2003. RG&E used the remainder of the net proceeds for general corporate purposes.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

(b)Results of Operations

Three months ended September 30 (Thousands)	2003	2002	Change
Operating Revenues	$203,638	$231,368	(12%)
Operating Income	$15,172	$35,422	(57%)
(Loss) Earnings Available for Common Stock	$(3,374)	$16,362	(121%)

Earnings decreased $20 million for the quarter primarily due to lower electric deliveries because of cooler summer weather in 2003, which reduced earnings $10 million, higher operating expenses that lowered earnings $3 million and a change in estimate of prior year income taxes to reflect actual 2002 taxes as filed that decreased earnings $3 million.

Nine months ended September 30 (Thousands)	2003	2002	Change
Operating Revenues	$758,944	$728,466	4%
Operating Income	$83,287	$77,799	7%
Earnings Available for Common Stock	$10,939	$18,231	(40%)

Earnings for the nine months decreased $7 million. The recognition of the terms and conditions of the NYPSC rate order for RG&E, which became effective January 15, 2003, reduced earnings $30 million. That amount includes $26 million for excess electric earnings and related interest. (See RG&E 2002 Electric and Gas Rate Proceeding.) That decrease was partially offset by an increase of $14 million primarily for higher natural gas deliveries because of colder winter weather in 2003. Earnings for the nine months also increased $9 million due to a writedown of software development costs that reduced earnings in 2002.

Operating Results for the Electric Delivery Business

Three months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	1,859	2,031	(8%)
Operating Revenues	$167,016	$198,429	(16%)
Operating Expenses	$147,279	$158,095	(7%)
Operating Income	$19,737	$40,334	(51%)

The $31 million decrease in operating revenues for the quarter is primarily due to a $26 million reduction in deliveries because of cooler summer weather in 2003.

Operating expenses decreased $11 million for the quarter primarily due to lower fuel costs of $14 million due to decreased purchases, partially offset by a $3 million increase associated with the establishment of a regulatory asset related to RG&E's property tax sharing mechanisms that reduced operating expenses in 2002. During the third quarter this year RG&E deferred $8 million for continued restoration work resulting from a severe ice storm in April 2003 and $8 million of purchased power costs in connection with a scheduled refueling outage for Ginna that began in September 2003 and was completed in October 2003.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Nine months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	5,309	5,468	(3%)
Operating Revenues	$509,694	$534,986	(5%)
Operating Expenses	$456,476	$471,598	(3%)
Operating Income	$53,218	$63,388	(16%)

Operating revenues for the nine months decreased $25 million primarily due to lower deliveries because of cooler summer weather in 2003.

The $15 million decrease in operating expenses for the nine months was primarily due to lower fuel costs as a result of decreased purchases of $28 million and a scheduled refueling at the Ginna nuclear plant that added $10 million to operating costs in 2002 and $10 million due to a writedown of software development costs that also increased operating costs in 2002. Those decreases were partially offset by the recognition of terms and conditions of the NYPSC rate order for RG&E, which became effective January 15, 2003, and increased operating expenses $30 million, primarily for excess electric earnings. (See RG&E 2002 Electric and Gas Rate Proceeding.) RG&E deferred expenditures of $23 million during the second quarter and $8 million during the third quarter for restoration work resulting from a severe ice storm in April 2003. Also during the third quarter this year RG&E deferred $8 million of purchased power costs in connection with a scheduled refueling outage for Ginna that began in September 2003 and was completed in October 2003.

Operating Results for the Natural Gas Delivery Business

Three months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	4,845	5,067	(4%)
Operating Revenues	$36,622	$32,939	11%
Operating Expenses	$41,187	$37,851	9%
Operating (Loss)	$(4,565)	$(4,912)	(7%)

The $4 million increase in operating revenues for the quarter is primarily due to gas cost recovery of $2 million associated with higher commodity market prices and a $1 million increase due to higher delivery prices collected from customers effective in March 2003.

Operating expenses increased $3 million for the quarter primarily due to higher natural gas costs of $2 million mainly due to market conditions.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Nine months ended September 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	39,192	34,957	12%
Operating Revenues	$249,250	$193,480	29%
Operating Expenses	$219,181	$179,069	22%
Operating Income	$30,069	$14,411	109%

Operating revenues increased $56 million for the nine months primarily due to higher retail deliveries of $26 million because of colder winter weather in 2003, gas cost recovery of $28 million associated with higher commodity market prices and a $4 million increase due to higher delivery prices collected from customers effective in March 2003.

Operating expenses for the nine months increased $40 million primarily due to higher natural gas purchases including $14 million for higher retail deliveries because of colder weather this year and a $26 million increase in the cost of natural gas due to market conditions.

Item 1.  Financial Statements

Notes to Condensed Financial Statements
for
Energy East Corporation
Central Maine Power Company
New York State Electric & Gas Corporation
Rochester Gas and Electric Corporation

Notes to Condensed Financial Statements of Registrants:

Registrant	Applicable Notes
Energy East	1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13
CMP	1, 3, 4, 5, 7, 8, 9, 10, 12, 13
NYSEG	1, 3, 4, 5, 7, 8, 9, 10 11, 12, 13
RG&E	1, 3, 4, 5, 7, 8, 9, 10, 12, 13

Note 1. Unaudited Condensed Financial Statements

The accompanying unaudited condensed financial statements reflect all adjustments necessary, in the opinion of the management of the registrants, for a fair presentation of the interim results. All such adjustments are of a normal, recurring nature. The year-end condensed balance sheet data presented in this quarterly report was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Energy East's financial statements and CMP's financial statements consolidate their majority-owned subsidiaries after eliminating all intercompany transactions.

The accompanying unaudited financial statements for each registrant should be read in conjunction with the financial statements and notes contained in the report on Form 10-K filed by each registrant for the year ended December 31, 2002. Due to the seasonal nature of the registrants' operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Note 2. Businesses Held for Sale

In keeping with its focus on regulated electric and natural gas delivery businesses, during the past few years the company has been systematically exiting certain noncore businesses. In the third quarter of 2003 the company recognized a loss from discontinued operations of 5 cents per share for two businesses classified as held for sale. The loss from discontinued operations included an estimated after tax loss on disposal of $7 million for the two businesses. In October 2003 Energetix sold its Griffith Oil subsidiary at an estimated after tax loss of $5 million and in November 2003 Berkshire Propane sold its remaining assets at an estimated after tax loss of $2 million. Both businesses and their assets were previously reported in the company's Other business segment.

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands, except per share amounts)
Revenue   Griffith Oil   Berkshire Propane	$85,142  $630	$75,829  $736	$296,685  $5,102	$75,829  $4,029
Expenses   Griffith Oil   Berkshire Propane	$98,278  $3,076	$78,132  $982	$303,258  $7,358	$78,132  $4,024
Other (income) and deductions and Interest charges, net   Griffith Oil   Berkshire Propane	$(95) $70	$407  $32	$552  $(256)	$407  $129
Pretax income (loss) from businesses held for sale   Griffith Oil (including estimated loss on disposal     in 2003 of $11,041)   Berkshire Propane (including estimated loss on disposal     in 2003 of $2,075)	$(13,041) $(2,516)	$(2,711) $(277)	$(7,125) $(2,000)	$(2,711) $(123)
Income Taxes   Griffith Oil   Berkshire Propane	$(7,313) $(181)	$(1,352) $(114)	$(5,206) $324	$(1,352) $(51)
Losses from business held for sale   Griffith Oil   Berkshire Propane	$(5,728) $(2,335)	$(1,359) $(163)	$(1,919) $(2,324)	$(1,359) $(72)
(Loss) Per Share from Discontinued Operations,   basic and diluted	$(.05)	$(.01)	$(.03)	$(.01)

The major classes of assets and liabilities of the businesses held for sale included in the company's Condensed Consolidated Balance Sheet, as of September 30, 2003, are as follows:

	Griffith Oil	Berkshire Propane
Assets   Other Property and Investments, net    Liabilities   Current liabilities	$111,950 $32,248	$4,809 $447

Note 3. Restructuring

In the fourth quarter of 2002 the company recorded $41 million of restructuring expenses, including $5 million for CMP, $26 million for NYSEG and a total of $10 million for Berkshire Gas, CNG and SCG. The restructuring expenses would have been $36 million higher, however RG&E was required by an NYPSC order approving RGS Energy's merger with the company to defer its portion of the restructuring charge for future recovery in rates. As of September 30, 2003, all of the related involuntary severance liability of $9 million has been paid. The employee positions affected by the restructuring were identified in the fourth quarter of 2002. The restructuring expenses reduced the company's 2002 net income by $24 million. Included in those amounts are $20 million for a voluntary early retirement program that will be paid from the companies' pension plans and $3 million for an involuntary severance program, primarily for salaried employees of the company's six operating utilities, and $1 million for other associated costs.

The voluntary early retirement program resulted in a reduction of 486 employees in the first quarter of 2003. Collectively the voluntary early retirement and involuntary severance programs resulted in a reduction in overall employee headcount of 679, or 8%, in 2003, including 79 from CMP, 255 from NYSEG and 254 from RG&E.

Note 4. Other (Income) and Other Deductions

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands)
Energy East
Interest income	$(1,637)	$(3,815)	$(4,025)	$(11,709)
Noncash returns	(520)	(2,316)	(985)	(4,433)
Allowance for funds used during construction	(531)	(1,083)	(1,497)	(1,222)
Gains from the sale of nonutility property	(121)	(7)	(299)	(219)
Earnings from equity investments	(1,006)	(980)	(3,549)	(3,344)
Miscellaneous	316	(1,229)	(106)	(1,607)
Total other (income)	$(3,499)	$(9,430)	$(10,461)	$(22,534)
NYSEG early retirement of debt	-	-	-	$16,145
Miscellaneous	$1,094	$4,516	$4,243	9,540
Total other deductions	$1,094	$4,516	$4,243	$25,685
CMP
Interest income	$(142)	$(461)	$(560)	$(883)
Noncash returns	(467)	(131)	(826)	(990)
Earnings from equity investments	(475)	(702)	(1,494)	(1,903)
Miscellaneous	(111)	(28)	(63)	(39)
Total other (income)	$(1,195)	$(1,322)	$(2,943)	$(3,815)
Miscellaneous	$331	$301	$1,130	$944
Total other deductions	$331	$301	$1,130	$944
NYSEG
Interest income	$(276)	$(765)	$(928)	$(4,052)
Noncash returns	(314)	(26)	(795)	(1,285)
Miscellaneous	1,426	(1,013)	450	968
Total other (income)	$836	$(1,804)	$(1,273)	$(4,369)
Early retirement of debt	-	-	-	$16,145
Miscellaneous	$224	$3,142	$(1,072)	4,248
Total other deductions	$224	$3,142	$(1,072)	$20,393

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
RG&E
Interest income	$(852)	$(1,192)	$(2,798)	$(3,841)
Noncash returns	-	(2,159)	-	(6,495)
Miscellaneous	(422)	(2,239)	(1,017)	(3,075)
Total other (income)	$(1,274)	$(5,590)	$(3,815)	$(13,411)
Merger costs	-	$221	-	$4,314
Miscellaneous	$423	97	$1,386	1,840
Total other deductions	$423	$318	$1,386	$6,154

Note 5. Income Taxes

The company's effective tax rate for the quarter differed from the expected annual effective tax rate as a result of a change in estimate of prior year income taxes to reflect actual 2002 taxes as filed and revisions to the estimated effective tax rate for 2003, a pretax loss for the quarter and the tax effect related to businesses held for sale. The company has provided for taxes for the nine months at the expected annual effective tax rate of 39%.

CMP has provided for taxes for the quarter and nine months at the expected annual effective tax rate.

NYSEG's effective tax rate for the quarter differed from the expected annual effective tax rate primarily as a result of a change in estimate of prior year income taxes to reflect actual 2002 taxes as filed and revisions to the estimated effective tax rate for 2003. NYSEG has provided for taxes for the nine months at the expected annual effective tax rate.

RG&E's effective tax rate for the quarter differed from the expected annual effective tax rate primarily as a result of a change in estimate of prior year income taxes to reflect actual 2002 taxes as filed and a low level of pretax income for the quarter. RG&E has provided for taxes for the nine months at the expected annual effective tax rate.

Note 6. Basic and Diluted Earnings per Share

Basic earnings per share (EPS) is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the period. The weighted-average common shares outstanding for diluted EPS include restricted stock awards and the incremental effect of stock options issued and exclude stock options issued in tandem with stock appreciation rights (SARs). However, all stock options are issued in tandem with SARs and, historically, substantially all stock option plan participants have exercised the SARs instead of the stock options. The numerator used in calculating basic and diluted EPS for each period is the reported net income. The reconciliation of basic and dilutive average common shares for each period follows:

	Three Months		Nine Months
Periods ended September 30	2003	2002	2003	2002
(Thousands)
Basic average common shares outstanding	145,684	144,621	145,400	126,489
Restricted stock awards	217	-	188	-
Potentially dilutive common shares	275	391	142	368
Options issued with SARs	(275)	(391)	(142)	(368)
Dilutive average common shares	145,901	144,621	145,588	126,489

On February 13, 2003, the company issued 229,230 shares of its common stock to certain employees under 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. An aggregate number of two million shares may be granted under the Restricted Stock Plan, subject to adjustment. Shares of restricted stock are awarded in the name of the employee, who has all the rights of a shareholder, subject to certain restrictions on transferability and a risk of forfeiture. The shares vest based on the conditions outlined in the restricted stock award grants, including the achievement of targeted shareholder returns, but no later than January 1, 2009.

Options to purchase shares of common stock are excluded from the determination of EPS when the exercise price of an option is greater than the average market price of a common share during the period. Shares excluded from the EPS calculation for the three months ended September 30 were: 2.4 million in 2003 and 2.1 million in 2002, and for the nine months ended September 30 were: 4.5 million in 2003 and 2.1 million in 2002.

Note 7. Accounts Receivable

Accounts receivable for the companies include unbilled revenues as follows: Energy East - consolidated unbilled revenues of $129 million at September 30, 2003, and $237 million at December 31, 2002; CMP - consolidated unbilled revenues of $20 million at September 30, 2003, and $33 million at December 31, 2002; NYSEG - unbilled revenues of $47 million at September 30, 2003, and $79 million at December 31, 2002; RG&E - unbilled revenues of $33 million at September 30, 2003, and $59 million at December 31, 2002.

Note 8. New Accounting Pronouncements

Statement 143: In June 2001 the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss.

The companies' adoption of Statement 143 as of January 1, 2003, did not have a material effect on their respective financial positions or results of operations. There was no effect on net income. The companies recognized various amounts on their balance sheets. Changes in the assumptions underlying the items shown in the following table could affect the balance sheet amounts and future costs related to the obligations.

	NYSEG	RG&E	Other	Consolidated Energy East
(Thousands)
Asset retirement obligation	$(539)	$(413,988)	$(942)	$(415,469)
Regulatory asset	$350	$139,611	$942	$140,903
Regulatory liability	$(3,689)	$(635)	-	$(4,324)
Increase in utility plant	$30	$74,064	-	$74,094
Decrease in accumulated depreciation	$3,848	$200,948	-	$204,796

In addition to the asset retirement obligations, Energy East's utilities have and will continue to have cost of removal liabilities ($79 million for CMP, $298 million for NYSEG, $186 million for RG&E and $158 million for Other, as of September 30, 2003) embedded within accumulated depreciation pursuant to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation.

Statement 150:In May 2003 the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. Statement 150 requires that certain financial instruments be classified as liabilities in statements of financial position. Under previous guidance such instruments were classified as equity. In accordance with Statement 150, Energy East and RG&E are required to classify their mandatorily redeemable preferred stock as a liability on their statements of financial position, which they had previously classified as equity, and to recognize as interest expense distributions that they had previously recognized as dividends. Energy East has a consolidated $370 million of mandatorily redeemable preferred stock, including RG&E's $25 million of mandatorily redeemable preferred stock. Statement 150 was effective at the beginning of the first interim period beginning after June 15, 2003, for instruments existing when the Statement was issued. The companies' adoption of Statement 150 on July 1, 2003, did not have a material effect on their respective financial positions or results of operations.

Note 9. Supplemental Disclosure of Cash Flows Information

	2003	2002
(Thousands)
Cash paid during the nine months ended September 30:
Interest, net of amounts capitalized     Energy East     CMP     NYSEG     RG&E	$175,009  $22,003  $35,733  $32,901	$138,577  $21,523  $46,009  $35,793
Income taxes, net of benefits received     Energy East     CMP     NYSEG     RG&E	$18,526  $11,834  $21,935  $(894)	$20,744  $(6,405) $44,113  $39,947
Energy East's Acquisition of RGS Energy
Fair value of assets acquired	-	$3,264,093
Liabilities assumed	-	(1,826,528)
Preferred stock of subsidiary	-	(72,000)
Common stock issued	-	(612,082)
Cash acquired	-	(72,086)
Net cash paid for acquisition	-	$681,397

Note 10. Goodwill and Other Intangible Assets

As required by Statement 142 both goodwill and intangible assets with indefinite lives (unamortized intangible assets) are tested at least annually for impairment. Intangible assets with finite lives are amortized (amortized intangible assets) and are reviewed for impairment. Annual impairment testing of goodwill was completed for Energy East, CMP and NYSEG and it was determined that there was no impairment of goodwill for the three companies at September 30, 2003. RG&E has no goodwill. The $17 million increase in the company's goodwill since December 31, 2002, was substantially due to the recognition of additional excess earnings in the electric segment, a preacquisition contingency for RG&E, partially offset by goodwill reclassified as assets held for sale.

	Electric      Delivery	Natural Gas     Delivery	Other	Total
Goodwill
September 30, 2003    Energy East    CMP    NYSEG	$845,174  $324,725  - -	$677,118  - -       $11,199	$12,456  $855  - -	$1,534,748  $325,580  $11,199
December 31, 2002    Energy East    CMP    NYSEG	$819,992  $324,725  - -	$677,952  - -       $11,199	$20,229  $855  - -	$1,518,173  $325,580  $11,199

Annual impairment testing of unamortized intangible assets was completed for Energy East, CMP, NYSEG and RG&E and it was determined that there was no impairment of unamortized intangible assets for the four companies at September 30, 2003.

The company's unamortized intangible assets had a carrying amount of $11 million at September 30, 2003, and primarily consisted of pension assets, and $17 million at December 31, 2002, and primarily consisted of trade names and pension assets. The company's amortized intangible assets had a gross carrying amount of $31 million at September 30, 2003, and $47 million at December 31, 2002, and primarily consisted of investments in pipelines and customer lists. The decreases in the carrying amounts of intangible assets since December 2003 relate to assets held for sale. Accumulated amortization was $12 million at September 30, 2003, and $15 million at December 31, 2002. Estimated amortization expense for intangible assets for the next five years is approximately $3 million for 2004, $2 million each year for 2005 through 2007 and $1 million for 2008.

CMP's unamortized intangible assets had a carrying amount of $2 million at September 30, 2003, and December 31, 2002, and consisted of pension assets. CMP's amortized intangible assets had a gross carrying amount and accumulated amortization of less than $0.3 million at September 30, 2003, and December 31, 2002, and primarily consist of technology rights. Estimated amortization expense for intangible assets is $9 thousand for each of the next five years, 2004 through 2008.

NYSEG's unamortized intangible assets had a carrying amount of $1.4 million at September 30, 2003, and $1.6 million at December 31, 2002, and primarily consisted of pension assets, franchises and consents. NYSEG's amortized intangible assets had a gross carrying amount of $1.5 million and accumulated amortization of $1 million at September 30, 2003, and December 31, 2002, and consisted of hydroelectric licenses. Estimated amortization expense for intangible assets for the next five years is $64 thousand each year for 2004 and 2005, $57 thousand for 2006 and $55 thousand each year for 2007 and 2008.

RG&E's amortized intangible assets had a gross carrying amount of $3 million and accumulated amortization of $2 million at September 30, 2003, and December 31, 2002, and consisted of water rights. Estimated amortization expense for intangible assets is $78 thousand for each of the next five years, 2004 through 2008.

Note 11. Environmental Liability

In the second quarter of 2003 NYSEG increased by approximately $23 million the liability to investigate and perform remediation, as necessary, at its known inactive gas manufacturing sites. NYSEG recorded a corresponding increase in its regulatory asset, net of insurance recoveries, since it expects to recover the net costs in rates. The increase is primarily based on a Proposed Remedial Action Plan issued by the New York State Department of Environmental Conservation (NYSDEC) for one of NYSEG's sites and a revised Feasibility Study NYSEG submitted to the NYSDEC for another of NYSEG's sites.

Note 12. Segment Information

Energy East's electric delivery business consists of its regulated transmission, distribution and generation operations in Maine and New York State; and its natural gas delivery business consists of its regulated transportation, storage and distribution operations in New York State, Connecticut, Maine and Massachusetts. Other includes: the company's corporate assets, interest income, interest expense and operating expenses; intersegment eliminations; and nonutility businesses.

CMP's electric delivery business, which it conducts in Maine, consists of its regulated transmission and distribution operations. Other consists of CMP's corporate assets.

NYSEG's electric delivery business consists of its regulated transmission, distribution and generation operations. Its natural gas delivery business consists of its regulated transportation, storage and distribution operations. NYSEG operates in New York State. Other consists of NYSEG's corporate assets.

RG&E's electric delivery business consists of its regulated transmission, distribution and generation operations. Its natural gas delivery business consists of its regulated transportation, storage and distribution operations. RG&E operates in New York State. Other consists of RG&E's corporate assets.

Selected information for Energy East's, CMP's, NYSEG's and RG&E's business segments is:

	Electric      Delivery	Natural Gas     Delivery	Other	Total
(Thousands)
Three Months Ended
September 30, 2003
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$680,206  $145,715  $367,457  $167,016	$148,504  - -       $39,170  $36,622	$74,414  - -       - -       - -	$903,124  $145,715  $406,627  $203,638
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$27,693  $9,569  $25,592  $5,172	$(23,366) - -       $(5,339) $(8,033)	$(10,306) - -       - -       - -	$(5,979) $9,569  $20,253  $(2,861)

	Electric      Delivery	Natural Gas     Delivery	Other	Total
(Thousands)
Three Months Ended (cont'd)
September 30, 2002
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$741,338  $153,663  $389,216  $198,429	$132,983  - -       $35,675  $32,939	$65,304  - -       - -       - -	$939,625  $153,663  $424,891  $231,368
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$50,136  $11,372  $29,401  $21,605	$(20,544) - -       $(6,105) $(4,318)	$(5,850) - -       - -       - -	$23,742  $11,372  $23,296  $17,287
Nine Months Ended
September 30, 2003
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$2,078,953  $457,391  $1,111,777  $509,694	$1,052,672  - -       $283,945  $249,250	$265,876  - -       - -       - -	$3,397,501  $457,391  $1,395,722  $758,944
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$120,268  $36,492  $93,315  $2,852	$42,257  - -       $17,477  $10,450	$(5,323) - -       - -       - -	$157,202  $36,492  $110,792  $13,302
September 30, 2002
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$1,876,742  $493,485  $1,184,687  $534,986	$643,038  - -       $222,902  $193,480	$160,004  - -       - -       - -	$2,679,784  $493,485  $1,407,589  $728,466
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$144,732  $39,947  $104,211  $18,218	$18,601  - -       $1,850  $2,788	$(28,699) - -       - -       - -	$134,634  $39,947  $106,061  $21,006
Total Assets
September 30, 2003    Energy East    CMP    NYSEG    RG&E	$6,876,217  $1,708,274  $2,261,483  $2,175,283	$3,221,134  - -       $808,034  $509,246	$440,359  $8,645  $60,186  $105,257	$10,537,710  $1,716,919  $3,129,703  $2,789,786
December 31, 2002    Energy East    CMP    NYSEG    RG&E	$6,582,234  $1,777,727  $2,256,343  $1,811,146	$3,201,235  - -       $737,629  $502,305	$473,418  $8,596  $59,454  $138,646	$10,256,887  $1,786,323  $3,053,426  $2,452,097

Note 13. Reclassifications

Certain amounts have been reclassified in the unaudited financial statements to conform with the 2003 presentation.

Forward-looking Statements

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

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties and that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated industry; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of changing energy prices; the operation of the New York Independent System Operator and ISO New England, Inc.; the operation of a regional transmission organization; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements now that most generation assets have been sold; the company's ability to expand its products and services, including its en ergy infrastructure in the Northeast; the company's ability to integrate the operations of Berkshire Energy Resources, CMP Group, Connecticut Energy Corporation, CTG Resources and RGS Energy; the company's ability to achieve enterprise-wide integration synergies; market risk; the ability to obtain adequate and timely rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; and other considerations, such as the effect of the volatility in the equity markets on pension benefit cost, that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk
(See report on Form 10-K for Energy East, CMP, NYSEG and RG&E for fiscal year ended December 31, 2002, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

Commodity Price Risk: NYSEG's current electric rate plan offers retail customers choice in their electricity supply including a variable rate option, an option to purchase electricity supply from an alternative energy company, and a bundled rate option. Based on the results from the enrollment period that ended December 31, 2002, approximately 30% of NYSEG's total electric load is now provided by an alternative energy company or at the market price. NYSEG's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the bundled rate option, which combines delivery and supply service at a fixed price. For calendar years 2003 and 2004 the supply component is based on average electricity forward prices for 2003 and 2004 during September 2002, plus a 35% margin to cover the costs and risk that NYSEG is assuming by providing a bundled rate option to retail customers. NYSEG has actively hedged the load required to serve customers who select the bundled rate option. As of November 1, 2003, NYSEG's load was 98% hedged for on-peak periods and 86% hedged for off-peak periods in 2003 and 94% hedged for on-peak periods and 83% hedged for off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.1 million in 2003 and $0.8 million in 2004. The percent of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

RG&E faces commodity price risk that relates to market fluctuations in the price of electricity. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. As of November 1, 2003, RG&E's load was 96% hedged for on-peak periods and fully hedged for off-peak periods in 2003 and fully hedged for both on-peak and off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of on-peak electricity would change earnings by less than $0.1 million in 2003. The percent of RG&E's hedged load is based on RG&E's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

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

Item 4.  Controls and Procedures

The principal executive officers and principal financial officers of Energy East, CMP, NYSEG and RG&E evaluated the effectiveness of their respective company's disclosure controls and procedures as of the end of the period covered by this report. "Disclosure controls and procedures" are controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, within the time periods specified in the Securities and Exchange Commission's rules and forms, is recorded, processed, summarized and reported, and is accumulated and communicated to the company's management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that their respective company's disclosure controls and procedures are effective.

Energy East, CMP, NYSEG and RG&E each maintain a system of internal control over financial reporting designed to provide reasonable assurance to its management and board of directors regarding the preparation of reliable published financial statements and the safeguarding of assets against loss or unauthorized use. Each company's system of internal control over financial reporting contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. There were no changes in the companies' internal control over financial reporting that occurred during each company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the respective company's internal control over financial reporting.

PART II - OTHER INFORMATION

Item 6.  Exhibits and Reports on Form 8-K

(a)  Exhibits - SeeExhibit Index.

(b)  The following reports on Form 8-K were filed during the quarter:

Energy East filed a Form 8-K dated July 25, 2003, to report certain information under Item 9, "Regulation FD Disclosure," and Item 12, "Disclosure of Results of Operations and Financial Condition."

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date:  November 12, 2003	ENERGY EAST CORPORATION                   (Registrant) By   /s/Robert E. Rude                                                             Robert E. Rude            Vice President and Controller            (Principal Accounting Officer)
Date:  November 12, 2003	CENTRAL MAINE POWER COMPANY                   (Registrant) By   /s/Curtis I. Call                                                             Curtis I. Call            Vice President, Controller & Treasurer            (Principal Financial Officer)
Date:  November 12, 2003	NEW YORK STATE ELECTRIC & GAS CORPORATION                   (Registrant) By   /s/Joseph J. Syta                                                              Joseph J. Syta            Controller and Treasurer            (Principal Financial Officer)
Date:  November 12, 2003	ROCHESTER GAS AND ELECTRIC CORPORATION                   (Registrant) By   /s/Joseph J. Syta                                                              Joseph J. Syta            Controller and Treasurer            (Principal Financial Officer)

EXHIBIT INDEX

The following exhibits are delivered with this report:

Registrant	Exhibit No.	Description of Exhibit
Energy East Corporation	4-9	Seventh Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of September 9, 2003, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000.
	(A)10-27	Amended and Restated 2000 Stock Option Plan, effective October 15, 2003.
	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Central Maine Power Company	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
New York State Electric & Gas Corporation	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Rochester Gas and Electric   Corporation	(A)10-23	Supplemental Executive Retirement Program Amendment No. 3, effective as of January 1, 2003.
	(A)10-24	Supplemental Retirement Benefit Program Amendment No. 3, effective as of January 1, 2003.
	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

_________________________________

(A) Management contract or compensatory plan or arrangement.