New York State Electric & Gas 10-Q 2003 Q2 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  June 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 July 31, 2003, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	145,792,828
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   Consolidated Statements of IncomeConsolidated Balance SheetsConsolidated Statements of Cash FlowsConsolidated Statements of Retained EarningsConsolidated 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   Consolidated Balance SheetsConsolidated Statements of IncomeConsolidated Statements of Cash FlowsConsolidated Statements of Retained EarningsConsolidated 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	18 20 21 22 22 23 24
	New York State Electric & Gas Corporation   Statements of IncomeBalance SheetsStatements of Cash FlowsStatements of Retained EarningsStatements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	25 26 28 29 29 30 31
	Rochester Gas and Electric Corporation   Balance SheetsStatements of IncomeStatements of Cash FlowsStatements of Retained Earnings   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	34 36 37 38 39 41

	TABLE OF CONTENTS - continued	Page
1	Notes to Financial StatementsForward-looking Statements	44 51
3	Quantitative and Qualitative Disclosures About Market Risk	52
4	Controls and Procedures	53
	PART II - OTHER INFORMATION
4	Submission of Matters to a Vote of Security Holders	53
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
Consolidated Statements of Income - (Unaudited)

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands, except per share amounts)
Operating Revenues
Utility	$904,089	$669,451	$2,302,915	$1,645,459
Nonutility	166,956	45,423	407,477	97,993
Total Operating Revenues	1,071,045	714,874	2,710,392	1,743,452
Operating Expenses
Electricity purchased and fuel used in generation
Utility	273,677	266,260	595,257	558,668
Nonutility	27,290	18,518	64,077	32,063
Natural gas purchased
Utility	148,873	81,782	550,713	269,906
Nonutility	29,541	6,160	78,752	27,766
Gasoline, propane and oil purchased, nonutility	73,739	509	181,715	1,737
Other operating expenses
Utility	186,603	121,743	372,340	246,348
Nonutility	28,488	17,199	53,083	33,818
Maintenance	44,297	31,097	91,607	65,921
Depreciation and amortization	76,348	47,670	154,259	93,813
Other taxes	58,876	42,460	144,961	93,066
Total Operating Expenses	947,732	633,398	2,286,764	1,423,106
Operating Income	123,313	81,476	423,628	320,346
Writedown of Investment	-	2,094	-	12,209
Other (Income)	(2,860)	(5,863)	(7,607)	(13,131)
Other Deductions	1,224	19,335	3,092	21,169
Interest Charges, Net	68,572	51,729	136,854	107,640
Preferred Stock Dividends of Subsidiaries	8,739	7,670	17,157	15,262
Income Before Income Taxes	47,638	6,511	274,132	177,197
Income Taxes	19,921	1,188	110,951	66,304
Net Income	$27,717	$5,323	$163,181	$110,893
Earnings Per Share, basic and diluted	$.19	$.05	$1.12	$.95
Dividends Paid Per Share	$.25	$.24	$.50	$.48
Average Common Shares Outstanding, basic	145,415	117,820	145,256	117,273
Average Common Shares Outstanding, diluted	145,640	117,820	145,429	117,273

Thenotes on pages 44 through 51 are an integral part of the financial statements.

Energy East Corporation
Consolidated Balance Sheets - (Unaudited)

	June 30, 2003	Dec. 31,   2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$217,522	$250,490
Special deposits	136,925	47,643
Accounts receivable, net	662,297	737,876
Fuel, at average cost	105,833	117,678
Materials and supplies, at average cost	23,308	22,953
Accumulated deferred income tax benefits, net	15,995	8,697
Prepayments and other current assets	78,848	86,167
Total Current Assets	1,240,728	1,271,504
Utility Plant, at Original Cost
Electric	5,921,790	5,803,576
Natural gas	2,364,383	2,347,011
Common	358,705	360,776
	8,644,878	8,511,363
Less accumulated depreciation	3,820,105	3,877,164
Net Utility Plant in Service	4,824,773	4,634,199
Construction work in progress	202,974	179,557
Total Utility Plant	5,027,747	4,813,756
Other Property and Investments, Net	473,513	452,710
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	433,485	524,679
Unfunded future income taxes	233,575	234,487
Unamortized loss on debt reacquisitions	46,188	45,353
Environmental remediation costs	128,172	106,262
Nonutility generator termination agreements	111,868	116,782
Other	525,777	370,354
Total regulatory assets	1,479,065	1,397,917
Other assets
Goodwill, net	1,540,185	1,518,173
Prepaid pension benefits	580,420	540,426
Other	282,402	262,401
Total other assets	2,403,007	2,321,000
Total Regulatory and Other Assets	3,882,072	3,718,917
Total Assets	$10,624,060	$10,256,887

Thenotes on pages 44 through 51 are an integral part of the financial statements.

Energy East Corporation
Consolidated Balance Sheets - (Unaudited)

	June 30, 2003	Dec. 31,   2002
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$517,982	$545,404
Notes payable	182,000	322,200
Accounts payable and accrued liabilities	308,196	361,499
Interest accrued	41,374	44,310
Taxes accrued	76,679	30,036
Other	162,309	200,927
Total Current Liabilities	1,288,540	1,504,376
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	216,309	203,926
Gain on sale of generation assets	135,877	152,648
Pension benefits	59,655	67,205
Other	122,967	104,937
Total regulatory liabilities	534,808	528,716
Other liabilities
Deferred income taxes	734,174	702,426
Nuclear plant obligations	283,381	314,013
Other postretirement benefits	400,993	391,049
Asset retirement obligation	426,377	-
Environmental remediation costs	149,147	133,933
Other	394,219	408,841
Total other liabilities	2,388,291	1,950,262
Total Regulatory and Other Liabilities	2,923,099	2,478,978
Long-term debt	3,382,661	3,351,959
Total Liabilities	7,594,300	7,335,313
Commitments	-	-
Preferred Stock of Subsidiaries  Company-obligated mandatorily redeemable trust preferred    securities of subsidiary holding solely parent debentures  Redeemable solely at the option of subsidiaries  Subject to mandatory redemption requirements	345,000  91,056  25,000	345,000  90,962  25,000
Common Stock Equity  Common stock	1,458	1,455
Capital in excess of par value	1,448,143	1,447,664
Retained earnings	1,152,043	1,061,428
Accumulated other comprehensive (loss)	(28,849)	(34,167)
Deferred compensation	(3,727)	-
Treasury stock, at cost	(364)	(15,768)
Total Common Stock Equity	2,568,704	2,460,612
Total Liabilities and Stockholders' Equity	$10,624,060	$10,256,887

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

Six months ended June 30	2003	2002
(Thousands)
Operating Activities
Net income	$163,181	$110,893
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	206,568	110,046
Income taxes and investment tax credits deferred, net	55,216	10,504
Pension income	(18,814)	(33,451)
Writedown of investment	-	12,209
Changes in current operating assets and liabilities
Accounts receivable, net	56,673	100,855
Inventory	11,772	21,730
Prepayments and other current assets	15,571	18,138
Accounts payable and accrued liabilities	(53,844)	(33,887)
Interest accrued	(2,941)	(2,527)
Taxes accrued	46,422	54,864
Other current liabilities	(39,399)	(18,539)
Other assets	(86,369)	40,110
Other liabilities	23,935	(16,348)
Net Cash Provided by Operating Activities	377,971	374,597
Investing Activities
Cash acquired in acquisition	-	72,086
Utility plant additions	(112,955)	(73,641)
Sale of generation assets	-	59,442
Other property and investments additions	(13,631)	(8,765)
Other property and investments sold	5,054	5,021
Special deposits	(81,134)	(5,044)
Other	(2,377)	4,584
Net Cash (Used in) Provided by Investing Activities	(205,043)	53,683
Financing Activities
Issuance of common stock	2,466	1,027
Repurchase of common stock	-	(1,749)
Repayments of first mortgage bonds and preferred    stock of subsidiaries, including net premiums	(115,270)	(177,908)
Long-term note issuances	196,986	475,000
Long-term note repayments	(6,140)	(57,637)
Notes payable three months or less, net	(128,700)	(108,683)
Notes payable repayments	(91,435)	(10,000)
Dividends on common stock	(63,803)	(49,354)
Net Cash (Used in) Provided by Financing Activities	(205,896)	70,696
Net (Decrease) Increase in Cash and Cash Equivalents	(32,968)	498,976
Cash and Cash Equivalents, Beginning of Period	250,490	437,014
Cash and Cash Equivalents, End of Period	$217,522	$935,990

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

Six months ended June 30	2003	2002
(Thousands)
Balance, Beginning of Period	$1,061,428	$998,281
Add net income	163,181	110,893
Deduct dividends on common stock	72,566	56,032
Balance, End of Period	$1,152,043	$1,053,142

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands)
Net income	$27,717	$5,323	$163,181	$110,893
Other comprehensive income, net of tax
Net unrealized gains (losses) on investments, net    of income tax (expense) benefit for the three    months of $(391) in 2003 and $ 1,457 in 2002 and    for the six months of $(642) in 2003 and $5,921    in 2002	578	(2,147)	964	(8,572)
Reclassification adjustment for investment losses     included in net income, net of income tax     benefit in 2002 of $844 for the three months and     $4,919 for the six months	- -	1,222	- -	7,122
Unrealized (losses) gains on derivatives qualified    as hedges, net of income tax benefit (expense)    for the three months of $4,737 in 2003 and $11,211    in 2002 and for the six months of $(14,016) in 2003    and $(2,324) in 2002	(7,012)	(16,889)	21,808	3,326
Reclassification adjustment for derivative (gains)     losses included in net income, net of income tax     expense (benefit) for the three months of $2,544     in 2003 and $(381) in 2002 and for the six months     of $11,574 in 2003 and $(6,873) in 2002	(3,836)	574	(17,454)	11,069
Net unrealized (losses) gains on derivatives     qualified as hedges	(10,848)	(16,315)	4,354	14,395
Total other comprehensive income (loss)	(10,270)	(17,240)	5,318	12,945
Comprehensive Income (Loss)	$17,447	$(11,917)	$168,499	$123,838

Thenotes on pages 44 through 51 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 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.) During 2003 the related involuntary severance liability decreased $9 million.

The voluntary early retirement resulted in a decline of 486 employees in the first quarter of 2003, including 34 from CMP, 210 from NYSEG and 176 from RG&E. Collectively the voluntary early retirement and involuntary severance programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by the end of 2003.

Integration savings, previously estimated at over $80 million annually, are now expected to be approximately $100 million annually by 2006. Those savings, which include operating expenses and capital, will come from the consolidation of functions such as accounting, finance, information services and supply chain, as well as the implementation of other merger-enabled initiatives across the six operating utilities. The company completed its consolidation of information systems during the second quarter of 2003.

On March 18, 2003, Energy East filed an application with the Securities and Exchange Commission (SEC) requesting authorization to form a shared services company that will provide accounting, finance, information services and supply chain functions. Energy East expects that the SEC will act on the request in the second half of 2003.

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.) NYSEG, CMP and RG&E have consistently advocated the formation of a Northeast/Mid-Atlantic RTO, including PJM Interconnection, L.L.C. (PJM), or functionally combined markets throughout the Northeast because they believe that a larger wholesale power market is essential to facilitate greater liquidity and competition. The negotiation ended without consensus, and FERC has not taken any further action.

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

Energy East Corporation

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

FERC Standard Market Design: In October 2001 FERC commenced a proceeding to consider national standard market design (SMD) issues and in July 2002 issued a Notice of Proposed Rulemaking (the SMD NOPR). The SMD NOPR proposes rules that would require, among other things, changes in the wholesale power markets, transmission planning, services and charges, market power monitoring and mitigation, and the organization and structure of ISOs. CMP, NYSEG and RG&E filed comments jointly with other transmission owners in November 2002 and in early 2003. On April 28, 2003, the FERC issued a white paper on SMD in which the FERC accommodates greater regional flexibility and seeks further comments. The SMD white paper includes a preference for energy markets based on locational marginal pricing (LMP), which represents a significant change for some regions of the country. The NYISO and ISO New England already operate markets based on LMP. The companies are unable to predict SMD's ultim ate effect, if any, on their results of operations or financial position.

Transmission Planning and Expansion and Generation Interconnection: In June and July 2001 FERC issued orders that address a number of transmission planning and expansion issues that would directly affect CMP, NYSEG and RG&E as transmission owners. The FERC orders discuss giving exclusive responsibility for the transmission planning process to 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 formation of a formal regional planning process. On July 24, 2003, FERC issued orders regarding generation interconnection terms, conditions and cost allocation. The companies are analyzing the orders. Additional transmission planning and expansion proposals are included in the SMD NOPR. The companies are unable to predict the ultimate effect, if any, of the expected rulemakings 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

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 Electric Transmission Rates: On June 30, 2003, CMP made its required annual informational filing with FERC, updating its local transmission formula rates. CMP's annual transmission revenue requirement decreased by $4 million reflecting decreased costs for calendar year 2002. Rates pursuant to this filing became effective July 1, 2003, for most customers.

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 will fluctuate, however, as 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 recovery of Yankee Atomic decommissioning costs not currently in rates.

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.

NYPSC-mandated Contracts with Two 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.) On July 24, 2002, NYSEG filed a petition with the New York State Supreme Court, Albany County, asking the court to overturn the New York State Public Service Commission's (NYPSC) orders directing NYSEG to enter into long-term electric service contracts with Nucor Steel Auburn, Inc. and Corning Incorporated. NYSEG believes the rates and the terms of those mandated contracts are unduly preferential and violate the law, NYSEG's tariffs and the NYPSC's guidelines. On December 9, 2002, the State Supreme Court dismissed NYSEG's petition.

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

Energy East Corporation

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 is exploring its options and has until August 21, 2003, to request permission to appeal that decision to the New York State Court of Appeals.

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 costs of replacement power that will be incurred during the required Ginna nuclear plant refueling outage in the fall of 2003.

RG&E is disappointed with the 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.

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 that began on April 3, 2003, and replacement purchased power costs to be incurred in 2003 due to a scheduled refueling outage for the Ginna nuclear generating station (Ginna). The deferred costs are estimated to be $30 million for repairs required due to the ice storm and $16 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, will defer those costs in accordance with generally accepted accounting principles, pending approval from the NYPSC, which is expected in early 2004.

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

Energy East Corporation

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 proposes an annual increase in electric rates of $105 million, or 16.2%, and an annual increase in natural gas rates of $25 million, or 7.6% overall and 19.7% on delivery rates. RG&E'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%. RG&E expects the NYPSC will issue a rate order in April 2004, with rates to become effective 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 with the NYPSC to unbundle supply charges and to create electricity supply 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 supply service options (modeled on NYSEG's supply service options) to become effective January 1, 2005, for two periods of two years: 2005 through 2006 and 2007 through 2008.

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 by the fourth quarter of 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 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 one in 2003. A decision on this matter is expected by the end of June 2004.

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

Manufactured Gas Plant Remediation Recovery: RG&E and NYSEG began cost contribution actions against FirstEnergy Corp. (formerly GPU, Inc.) in federal district court; RG&E in the Western District of New York in August 2000 and NYSEG in the Northern District of New York in April 2003. The actions are for both past and future costs incurred for the investigation and

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

Energy East Corporation

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.

Natural Gas Delivery Business

RG&E Natural Gas Supply Agreement: RG&E entered into a two-year supply portfolio management agreement that began in April 2002 with Dynegy Marketing and Trade, for Dynegy to assist RG&E in the cost-effective management of RG&E's firm contractual rights to natural gas supply, transportation and storage services. The agreement was designed to ensure that RG&E could reliably meet its customers' supply requirements while seeking to minimize the annual delivered cost of natural gas. RG&E terminated its agreement with Dynegy after Dynegy announced in October 2002 that it would exit the marketing and trading business over the next several months. RG&E entered into a new portfolio management agreement with Entergy-Koch Trading, LP that extends through March 31, 2004, and includes the same reliability and cost-minimization objectives as the prior agreement with Dynegy. RG&E and Dynegy have entered into an agreement that resolves all issues in connection with the termination of the Dynegy management agreement.

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

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

RG&E Union Vote: See Electric Delivery Business.

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive natural gas and electricity markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets and providing recommendations concerning Provider of Last Resort and related issues. 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.

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

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

Energy East Corporation

a work stoppage involving approximately 57% of the workforce is in effect. The net additional cost of operating Berkshire Gas while the work stoppage is in effect is approximately $200,000 per month.

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 to be reviewed in the next semiannual review in August 2003, for which a final decision is due in October 2003. 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. The comments included a discussion of the benchmark standards set in the draft decision and how merger-enabled gas supply savings should be defined, quantified and shared among cus tomers and shareholders. 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.

Investing and Financing Activities

Investing Activities: Capital spending for the first six months of 2003 was $113 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.

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

Energy East Corporation

Financing Activities: During the six months ended June 30, 2003, the company issued 584,783 shares of common stock at an average price of $19.31 per share, substantially all through its Dividend Reinvestment and Stock Purchase Plan. The shares issued included 331,797 treasury shares and 252,986 newly issued shares.

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

The company 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 currently has $5 million available under a previous shelf registration statement.

In August 2003 CMP issued $35.7 million of Series E Medium Term Notes at a fixed rate of 5.1%, due August 2013. The proceeds will be used to help repay $50 million of medium-term notes that mature 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 for general corporate purposes, such as retirement or repurchase of certain of its indebtedness or preferred stock, reduction of short-term debt, financing the development and construction of new facilities and additions to working capital. NYSEG currently has $50 million available under a previous shelf registration statement.

In April 2003 NYSEG redeemed, at a premium, $50 million of 7.55% Series first mortgage bonds callable on April 1, 2003, using commercial paper. In June and July 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. NYSEG has no more first mortgage bonds outstanding and intends to discharge its first mortgage indenture in the second half of 2003.

In May 2003 NYSEG issued $200 million of 5 3/4% unsecured notes due in May 2023 under the shelf registration statement described above. The proceeds 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 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.

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

Energy East Corporation

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, financing the development and construction of new facilities and additions to working capital. RG&E currently has $75 million available under a previous shelf registration statement.

In July 2003 RG&E paid at maturity $40 million of first mortgage bonds using primarily temporary cash investments and internally generated funds.

RG&E plans to issue $75 million of long-term debt in the third quarter of 2003 under the shelf registration statement described above, to replace the $80 million of first mortgage bonds that matured earlier in the year. Through financial instruments issued in April 2003, Energy East has locked in the 30-year treasury rate component for $50 million of that financing at a fixed rate of 4.902%.

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

Asset Retirement Obligation: As required by Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, the company recorded a liability for the fair value of its asset retirement obligation on January 1, 2003. The company will adjust the liability to its present value periodically over time, and the capitalized cost will be depreciated over the useful life of the related asset. The determination of the liability includes various assumptions, the primary assumptions 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 6 to Energy East's Consolidated Financial State ments.)

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

Energy East Corporation

(b)Results of Operations

Due to the merger completed in June 2002, the company's results of operations include RGS Energy for the three months and six months ended June 30, 2003.

Three months ended June 30 (Thousands, except per share amounts)	2003	2002	Change
Operating Revenues	$1,071,045	$714,874	50%
Operating Income	$123,313	$81,476	51%
Net Income	$27,717	$5,323	421%
Average Common Shares Outstanding, basic	145,415	117,820	23%
Earnings Per Share, basic and diluted	$.19	$.05	280%
Dividends Paid per Share	$.25	$.24	4%

Earnings per share for the quarter were 19 cents compared to 5 cents for the prior year quarter. The increase in earnings per share for the quarter was primarily the result of decreases in costs that include 6 cents per share for lower purchased power costs and 6 cents per share for integration savings and other cost control efforts. The increase in earnings also included 8 cents per share for a loss from the early retirement of debt in 2002 and 1 cent per share from a writedown of an investment in NEON Communications in 2002. The increase was partially reduced by 4 cents per share due to lower noncash pension income and 4 cents per share for lower electricity transmission revenues.

Six months ended June 30 (Thousands, except per share amounts)	2003	2002	Change
Operating Revenues	$2,710,392	$1,743,452	55%
Operating Income	$423,628	$320,346	32%
Net Income	$163,181	$110,893	47%
Average Common Shares Outstanding, basic	145,256	117,273	24%
Earnings Per Share, basic and diluted	$1.12	$.95	18%
Dividends Paid per Share	$.50	$.48	4%

Earnings per share for the six months were $1.12 compared to 95 cents for the prior year period. The increase in earnings per share for the 2003 period was primarily the result of 17 cents per share for higher electric and natural gas deliveries due to colder winter weather in 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 5 cents per share to earnings. Integration savings and other cost control efforts added 12 cents per share to earnings. The increase in earnings also included 8 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. Those increases were reduced 16 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 8 cents per share due to lower noncash pen sion 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 June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	7,141	5,316	34%
Operating Revenues	$640,035	$504,364	27%
Operating Expenses	$536,329	$437,334	23%
Operating Income	$103,706	$67,030	55%

Operating revenues were $136 million higher for the quarter as a result of the addition of RG&E delivery revenues of $166 million. That amount was partially offset by reductions of $13 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, $11 million due to lower transmission revenues and $5 million as a result of customers choosing alternate suppliers partially offset by customers choosing the bundled rate option.

The $99 million increase in operating expenses for the quarter was primarily due to addition of RG&E operating expenses of $136 million and $6 million due to lower noncash pension income. Those increases were partially offset by decreases in purchased power of $17 million due to customers choosing alternate suppliers and $7 million because of lower purchased power prices and an $18 million decrease due to integration savings and other cost control efforts. RG&E deferred $23 million of operating expenses during the second quarter for restoration work resulting from a severe ice storm in April 2003.

Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	15,231	11,296	35%
Operating Revenues	$1,398,748	$1,135,404	23%
Operating Expenses	$1,139,237	$905,289	26%
Operating Income	$259,511	$230,115	13%

Operating revenues were $263 million higher for the six months as a result of the addition of RG&E delivery revenues of $343 million and higher retail deliveries of $22 million because of colder winter weather in 2003. Those amounts were partially offset by decreases of $17 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002, $8 million because of a decrease in amortization of CMP's asset sale gain, $62 million due to the combined effects of NYSEG's price reduction, effective March 1, 2002, and customers choosing alternate suppliers, and $13 million due to lower transmission revenues.

The $234 million increase in operating expenses for the six months was primarily due to the addition of RG&E operating expenses of $282 million and lower noncash pension income of $13 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 $11 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 $26 million due to integration savings and cost control efforts, $8 million because of a decrease in wholesale nonutility generator purchases and $4 million due to the elimination of a regulatory

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

Energy East Corporation

amortization of demand-side management (DSM) program costs. RG&E deferred $23 million of operating expenses during the second quarter for restoration work resulting from a severe ice storm in April 2003.

Operating Results for the Natural Gas Delivery Business

Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	39,026	30,352	29%
Operating Revenues	$264,054	$165,087	60%
Operating Expenses	$244,033	$149,124	64%
Operating Income	$20,021	$15,963	25%

Operating revenues were $99 million higher for the quarter primarily due to the addition of RG&E delivery revenues of $62 million, and increases of $34 million due to gas cost recovery provisions and $3 million due to an increase in prices for wholesale sales because of market conditions.

Operating expenses increased $95 million for the quarter primarily due to the addition of RG&E operating expenses of $56 million and higher natural gas costs of $32 million due to market conditions and after various rate case deferrals.

Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	128,242	86,459	48%
Operating Revenues	$904,167	$510,055	77%
Operating Expenses	$751,569	$413,402	82%
Operating Income	$152,598	$96,653	58%

Operating revenues were $394 million higher for the six months primarily due to the addition of RG&E delivery revenues of $213 million, and increases of $77 million due to higher retail deliveries because of colder weather, $96 million 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 $338 million for the six months primarily due to the addition of RG&E operating expenses of $178 million, and higher natural gas costs of $102 million due to market conditions and after various rate case deferrals and $45 million due to higher retail deliveries because of colder winter weather.

Item 1.  Financial Statements

Central Maine Power Company
Consolidated Balance Sheets - (Unaudited)

	June 30, 2003	Dec. 31,   2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$29,698	$20,415
Accounts receivable, net	104,499	124,711
Materials and supplies, at average cost	7,086	7,096
Accumulated deferred income tax benefits, net	789	1,902
Prepayments and other current assets	4,099	6,411
Total Current Assets	146,171	160,535
Utility Plant, at Original Cost
Electric	1,324,575	1,316,023
Less accumulated depreciation	515,467	499,381
Net Utility Plant in Service	809,108	816,642
Construction work in progress	4,501	2,952
Total Utility Plant	813,609	819,594
Other Property	5,844	5,880
Investment in Associated Companies, at Equity	23,674	27,137
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	179,776	211,268
Unfunded future income taxes	104,480	101,791
Unamortized loss on debt reacquisitions	9,194	9,722
Demand-side management program costs	5,988	8,394
Environmental remediation costs	3,840	4,440
Nonutility generator termination agreement	6,570	7,195
Other	55,966	58,259
Total regulatory assets	365,814	401,069
Other assets
Goodwill, net	325,580	325,580
Prepaid pension benefits	30,614	23,124
Other	25,480	23,404
Total other assets	381,674	372,108
Total Regulatory and Other Assets	747,488	773,177
Total Assets	$1,736,786	$1,786,323

Thenotes on pages 44 through 51 are an integral part of the financial statements.

Central Maine Power Company
Consolidated Balance Sheets - (Unaudited)

	June 30, 2003	Dec. 31,   2002
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$62,916	$52,975
Accounts payable and accrued liabilities	38,825	45,551
Interest accrued	6,056	6,056
Other	51,458	54,693
Total Current Liabilities	159,255	159,275
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	105,162	112,119
Gain on sale of generation assets	94,873	112,009
Other	14,135	11,926
Total regulatory liabilities	214,170	236,054
Other liabilities
Deferred income taxes	16,992	4,605
Nuclear plant obligations	179,776	211,268
Other postretirement benefits	73,771	71,236
Environmental remediation costs	2,962	2,987
Other	127,922	127,986
Total other liabilities	401,423	418,082
Total Regulatory and Other Liabilities	615,593	654,136
Long-term debt	280,407	291,796
Total Liabilities	1,055,255	1,105,207
Commitments	-	-
Preferred Stock  Preferred stock	35,571	35,571
Capital in excess of par value	(2,629)	(2,723)
Common Stock Equity  Common stock	156,057	156,057
Capital in excess of par value	485,331	485,297
Retained earnings	32,884	31,682
Accumulated other comprehensive (loss)	(25,683)	(24,768)
Total Common Stock Equity	648,589	648,268
Total Liabilities and Stockholder's Equity	$1,736,786	$1,786,323

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands)
Operating Revenues
Sales and services	$135,259	$139,208	$311,676	$339,822
Operating Expenses
Electricity purchased	60,048	60,727	120,686	145,417
Other operating expenses	41,817	43,029	88,305	89,161
Maintenance	8,765	9,644	16,135	20,157
Depreciation and amortization	10,145	10,079	20,365	18,933
Other taxes	3,448	5,681	10,404	11,161
Total Operating Expenses	124,223	129,160	255,895	284,829
Operating Income	11,036	10,048	55,781	54,993
Other (Income)	(761)	(1,007)	(1,748)	(2,493)
Other Deductions	420	306	799	643
Interest Charges, Net	6,614	6,857	13,287	14,941
Income Before Income Taxes	4,763	3,892	43,443	41,902
Income Taxes (Benefit)	1,942	(1,401)	16,520	13,327
Net Income	2,821	5,293	26,923	28,575
Preferred Stock Dividends	361	361	721	721
Earnings Available for Common Stock	$2,460	$4,932	$26,202	$27,854

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

Six months ended June 30	2003	2002
(Thousands)
Operating Activities
Net income	$26,923	$28,575
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	32,503	32,801
Income taxes and investment tax credits deferred, net	4,485	8,717
Pension (income) expense	4,510	3,035
Changes in current operating assets and liabilities
Accounts receivable, net	20,211	20,133
Inventory	11	300
Prepayments and other current assets	2,311	5,576
Accounts payable and accrued liabilities	(10,781)	(21,397)
Interest accrued	-	(803)
Taxes accrued	2,101	3,525
Other current liabilities	(5,335)	6,148
Asset sale gain amortization	(17,137)	(24,317)
Other assets	(12,042)	(2,642)
Other liabilities	1,458	(12,165)
Net Cash Provided by Operating Activities	49,218	47,486
Investing Activities
Utility plant additions	(12,847)	(19,928)
Other	119	77
Net Cash Used in Investing Activities	(12,728)	(19,851)
Financing Activities
Long-term note issuances	-	75,000
Long-term note repayments	(1,486)	(51,478)
Notes payable three months or less, net	-	(30,000)
Dividends on common and preferred stock	(25,721)	(31,834)
Net Cash Used in Financing Activities	(27,207)	(38,312)
Net Increase (Decrease) in Cash and Cash Equivalents	9,283	(10,677)
Cash and Cash Equivalents, Beginning of Period	20,415	20,777
Cash and Cash Equivalents, End of Period	$29,698	$10,100

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

Six months ended June 30	2003	2002
(Thousands)
Balance, Beginning of Period	$31,682	$31,304
Add net income	26,923	28,575
	58,605	59,879
Deduct Dividends on Capital Stock
Preferred	721	721
Common	25,000	31,113
	25,721	31,834
Balance, End of Period	$32,884	$28,045

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands)
Net income	$2,821	$5,293	$26,923	$28,575
Other comprehensive income, net of tax
Net unrealized (losses) on derivatives qualified as     hedges, net of income tax benefit in 2003 of $624     for the three months and $631 for the six months	(904)	- -	(915)	- -
Total other comprehensive income	(904)	-	(915)	-
Comprehensive Income	$1,917	$5,293	$26,008	$28,575

Thenotes on pages 44 through 51 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 Electric Transmission Rates: 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.

Investing and Financing Activities

Investing Activities: Capital spending for the first six months of 2003 was $13 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. The proceeds will be used to help repay $50 million of medium-term notes that mature 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 June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	2,110	1,991	6%
Operating Revenues	$135,259	$139,208	(3%)
Operating Expenses	$124,223	$129,160	(4%)
Operating Income	$11,036	$10,048	10%
Earnings Available for Common Stock	$2,460	$4,932	(50%)

Earnings for the quarter decreased $2 million as a result of a $3 million increase in income taxes.

The $4 million decrease in operating revenues is primarily the result of an approximately $1 million decrease in accrued demand-side management (DSM) revenues due to lower costs and a $2 million reduction in an electric conservation assessment for a low income program.

The $5 million decrease in operating expenses is primarily the result of a $1 million decrease in other operating expenses due to lower DSM costs and a $2 million decrease in other taxes.

Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	4,373	4,235	3%
Operating Revenues	$311,676	$339,822	(8%)
Operating Expenses	$255,895	$284,829	(10%)
Operating Income	$55,781	$54,993	1%
Earnings Available for Common Stock	$26,202	$27,854	(6%)

Earnings for the six months decreased $2 million as a result of a $3 million increase in income taxes.

The $28 million decrease in operating revenues is the result of CMP no longer being the standard-offer provider for the supply of electricity effective March 2002, which reduced revenues $17 million, a decrease in amortization of the asset sale gain of $8 million and a decrease in accrued DSM revenues of approximately $3 million due to lower costs.

The $29 million decrease in operating expenses is 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 wholesale nonutility generator purchases of $8 million, lower amortization of ice storm expense of $2 million and reduced DSM expenses of $2 million.

Item 1.  Financial Statements

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

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands)
Operating Revenues
Electric	$338,353	$365,098	$744,320	$795,472
Natural Gas	75,011	60,347	244,775	187,227
Total Operating Revenues	413,364	425,445	989,095	982,699
Operating Expenses
Electricity purchased	179,603	205,534	398,114	413,251
Natural gas purchased	43,569	32,759	150,626	109,675
Other operating expenses	52,685	55,411	100,499	108,121
Maintenance	17,034	18,070	38,430	39,019
Depreciation and amortization	25,063	24,560	49,995	48,992
Other taxes	25,291	27,592	60,664	59,190
Total Operating Expenses	343,245	363,926	798,328	778,248
Operating Income	70,119	61,519	190,767	204,451
Other (Income)	(184)	(1,778)	(2,108)	(2,566)
Other Deductions	(1,553)	16,438	(1,297)	17,251
Interest Charges, Net	21,022	23,350	40,360	48,524
Income Before Income Taxes	50,834	23,509	153,812	141,242
Income Taxes	20,911	10,364	63,272	58,476
Net Income	29,923	13,145	90,540	82,766
Preferred Stock Dividends	99	99	198	198
Earnings Available for Common Stock	$29,824	$13,046	$90,342	$82,568

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

	June 30, 2003	Dec. 31,   2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$36,208	$11,490
Special deposits	132,973	44,205
Accounts receivable, net	262,782	260,189
Fuel, at average cost	24,354	29,000
Materials and supplies, at average cost	6,222	5,573
Accumulated deferred income tax benefits, net	4,372	4,232
Prepayments	19,851	26,571
Total Current Assets	486,762	381,260
Utility Plant, at Original Cost
Electric	2,569,767	2,551,775
Natural gas	674,928	671,321
Common	119,479	121,661
	3,364,174	3,344,757
Less accumulated depreciation	1,406,094	1,371,892
Net Utility Plant in Service	1,958,080	1,972,865
Construction work in progress	41,884	40,166
Total Utility Plant	1,999,964	2,013,031
Other Property and Investments, Net	41,983	41,365
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes	21,703	20,467
Unamortized loss on debt reacquisitions	36,993	35,631
Environmental remediation costs	75,334	52,434
Other	52,005	23,563
Total regulatory assets	186,035	132,095
Other assets
Goodwill, net	11,199	11,199
Prepaid pension benefits	423,179	395,586
Other	93,657	78,890
Total other assets	528,035	485,675
Total Regulatory and Other Assets	714,070	617,770
Total Assets	$3,242,779	$3,053,426

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

	June 30, 2003	Dec. 31,   2002
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$77,414	$702
Notes payable	69,000	64,000
Accounts payable and accrued liabilities	148,811	169,884
Interest accrued	9,624	12,289
Taxes accrued	31,215	11,091
Other	51,348	58,577
Total Current Liabilities	387,412	316,543
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	44,461	26,199
Gain on sale of generation assets	41,004	40,638
Other	25,550	25,036
Total regulatory liabilities	111,015	91,873
Other liabilities
Deferred income taxes	362,824	347,355
Other postretirement benefits	201,591	197,193
Environmental remediation costs	98,000	75,100
Other	57,680	56,683
Total other liabilities	720,095	676,331
Total Regulatory and Other Liabilities	831,110	768,204
Long-term debt	1,065,829	1,017,902
Total Liabilities	2,284,351	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	277,430	277,297
Retained earnings	206,861	206,519
Accumulated other comprehensive income	33,921	26,745
Total Common Stock Equity	948,269	940,618
Total Liabilities and Stockholder's Equity	$3,242,779	$3,053,426

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

Six months ended June 30	2003	2002
(Thousands)
Operating Activities
Net income	$90,540	$82,766
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	63,400	64,854
Income taxes and investment tax credits deferred, net	28,202	9,723
Pension income	(22,009)	(35,160)
Changes in current operating assets and liabilities
Accounts receivable, net	(2,593)	60,959
Inventory	3,997	15,736
Prepayments	6,720	6,229
Accounts payable and accrued liabilities	(21,073)	(9,627)
Interest accrued	(2,665)	(2,246)
Taxes accrued	20,124	36,630
Other current liabilities	(7,229)	(20,552)
Other assets	(46,442)	12,936
Other liabilities	(3,882)	(34)
Net Cash Provided by Operating Activities	107,090	222,214
Investing Activities
Utility plant additions	(38,836)	(36,361)
Sale of generation assets	-	59,442
Proceeds from sale of utility plant	211	6,334
Special deposits	(81,128)	(5,014)
Other	(17)	(977)
Net Cash (Used in) Provided by Investing Activities	(119,770)	23,424
Financing Activities
Notes payable, three months or less	5,000	-
Repayments of first mortgage bonds, including net premiums	(74,390)	(177,025)
Long-term note issuances	196,986	-
Dividends on common and preferred stock	(90,198)	(60,198)
Net Cash Provided by (Used in) Financing Activities	37,398	(237,223)
Net Increase in Cash and Cash Equivalents	24,718	8,415
Cash and Cash Equivalents, Beginning of Period	11,490	21,617
Cash and Cash Equivalents, End of Period	$36,208	$30,032

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

Six months ended June 30	2003	2002
(Thousands)
Balance, Beginning of Period	$206,519	$164,197
Add net income	90,540	82,766
	297,059	246,963
Deduct Dividends on Capital Stock
Preferred	198	198
Common	90,000	60,000
	90,198	60,198
Balance, End of Period	$206,861	$186,765

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands)
Net income	$29,923	$13,145	$90,540	$82,766
Other comprehensive income, net of tax
Net unrealized gains (losses) on investments, net of     income tax (expense) benefit for the three months     of $(173) in 2003 and $175 in 2002 and for the six     months of $(166) in 2003 and $357 in 2002	260	(264)	250	(538)
Unrealized (losses) gains on derivatives qualified    as hedges, net of income tax benefit (expense) for    the three months of $2,565 in 2003 and $7,467 in    2002 and for the six months of $(16,184) in 2003    and $(2,819) in 2002	(3,868)	(11,259)	24,402	4,251
Reclassification adjustment for derivative (gains)     losses included in net income, net of income     tax expense (benefit) for the three months of     $2,563 in 2003 and $(360) in 2002 and for the six     months of $11,590 in 2003 and $(4,773) in 2002	(3,864)	543	(17,476)	7,197
Net unrealized (losses) gains on derivatives     qualified as hedges	(7,732)	(10,716)	6,926	11,448
Total other comprehensive (loss) income	(7,472)	(10,980)	7,176	10,910
Comprehensive Income	$22,451	$2,165	$97,716	$93,676

Thenotes on pages 44 through 51 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-mandated Contracts with Two 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.

Natural Gas Delivery Business

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

Investing Activities

Investing Activities: Capital spending for the first six months of 2003 was $39 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 for general corporate purposes, such as retirement or repurchase of certain of its indebtedness or preferred stock, reduction of short-term debt, financing the development and construction of new facilities and additions to working capital. NYSEG currently has $50 million available under a previous shelf registration statement.

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

New York State Electric & Gas Corporation

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 June and July 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. NYSEG has no more first mortgage bonds outstanding and intends to discharge its first mortgage indenture in the second half of 2003.

In May 2003 NYSEG issued $200 million of 5 3/4% unsecured notes due in May 2023 under the shelf registration statement described above. The proceeds 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 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.

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.

(b)Results of Operations

Three months ended June 30 (Thousands)	2003	2002	Change
Operating Revenues	$413,364	$425,445	(3%)
Operating Income	$70,119	$61,519	14%
Earnings Available for Common Stock	$29,824	$13,046	129%

Earnings for the quarter were $17 million higher than for the prior year quarter primarily due to the effect of a $10 million loss from the early retirement of debt in 2002, $8 million for lower purchased power costs and customers choosing alternate suppliers and $6 million for integration savings and cost control efforts. Those increases were partially offset by reductions to earnings of $6 million for lower transmission revenues and $3 million for lower noncash pension income.

Six months ended June 30 (Thousands)	2003	2002	Change
Operating Revenues	$989,095	$982,699	1%
Operating Income	$190,767	$204,451	(7%)
Earnings Available for Common Stock	$90,342	$82,568	9%

Earnings increased $8 million for the six months primarily due to increases of $18 million due to higher electric and natural gas retail deliveries because of colder winter weather, $9 million for integration savings and cost control efforts, $10 million due to the effect of a loss from the early retirement of debt in 2002, $4 million for the recovery of natural gas prices through the gas

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

New York State Electric & Gas Corporation

supply charge and $5 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 $30 million caused by an electric price reduction effective March 1, 2002, $8 million for lower transmission revenues, and $7 million for lower noncash pension income.

Operating Results for the Electric Delivery Business

Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	3,362	3,325	1%
Operating Revenues	$338,353	$365,098	(7%)
Operating Expenses	$276,011	$308,109	(10%)
Operating Income	$62,342	$56,989	9%

The $27 million decrease in operating revenues for the quarter is primarily due to reductions of $13 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 the price reduction effective March 1, 2002, $10 million due to lower transmission revenues and $5 million as a result of customers choosing alternate suppliers partially offset by customers choosing the bundled rate option.

Operating expenses decreased $32 million for the quarter as a result of decreases in purchased power of $17 million due to customers choosing alternate suppliers and $7 million because of lower purchased power prices, and a decrease of $9 million due to integration savings and cost control efforts. Those decreases were partially offset by an increase of $5 million due to lower noncash pension income.

Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	7,408	7,061	5%
Operating Revenues	$744,320	$795,472	(6%)
Operating Expenses	$600,753	$620,333	(3%)
Operating Income	$143,567	$175,139	(18%)

Operating revenues for the six months decreased $51 million primarily due to the combined effects of a price reduction, effective March 1, 2002, and customers choosing alternate suppliers that reduced revenues $62 million and a reduction in transmission revenues of $13 million. Those decreases were partially offset by higher retail deliveries of $22 million because of colder winter weather.

The $20 million decrease in operating expenses for the six months was primarily the result of a $12 million decrease due to integration savings and cost control efforts, an $11 million decrease in purchased power caused by the effect of customers choosing alternate suppliers partially offset by increases due to both higher market prices and higher retail deliveries because of colder winter weather, and a $4 million decrease due to the elimination of a regulatory amortization of DSM program costs. Those decreases were partially offset by an $11 million increase due to lower noncash pension income.

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

New York State Electric & Gas Corporation

Operating Results for the Natural Gas Delivery Business

Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	11,301	10,944	3%
Operating Revenues	$75,011	$60,347	24%
Operating Expenses	$67,234	$55,817	20%
Operating Income	$7,777	$4,530	72%

The $15 million increase in operating revenues for the quarter is primarily due to increases of $8 million due to gas cost recovery resulting from a natural gas supply charge, $3 million due to an increase in prices for wholesale sales because of market conditions and $2 million from higher retail deliveries because of colder weather.

Operating expenses increased $11 million for the quarter primarily due to a $9 million increase in the cost of natural gas, after various deferrals of gas costs for future recovery.

Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	37,809	32,783	15%
Operating Revenues	$244,775	$187,227	31%
Operating Expenses	$197,575	$157,915	25%
Operating Income	$47,200	$29,312	61%

Operating revenues increased $58 million for the six months primarily due to higher retail deliveries of $32 million because of colder winter weather, gas cost recovery of $23 million resulting from a natural gas supply charge and $8 million due to an increase in prices for wholesale sales because of market conditions.

Operating expenses for the six months increased $40 million primarily due to a $21 million increase in natural gas purchased for higher retail deliveries because of colder winter weather this year and an $18 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
Balance Sheets - (Unaudited)

	June 30, 2003	Dec. 31,   2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$23,797	$86,385
Special deposits	3,344	2,841
Accounts receivable, net	110,437	126,227
Affiliate receivable	29,293	20,330
Fuel, at average cost	21,034	20,555
Materials and supplies, at average cost	6,399	6,467
Prepayments and other current assets	30,206	35,324
Total Current Assets	224,510	298,129
Utility Plant, at Original Cost
Electric	2,027,448	1,935,778
Natural gas	518,896	515,829
Common	157,284	157,416
	2,703,628	2,609,023
Less accumulated depreciation	1,402,401	1,530,729
Net Utility Plant in Service	1,301,227	1,078,294
Construction work in progress	150,665	133,195
Total Utility Plant	1,451,892	1,211,489
Other Property and Investments, Net	253,029	226,373
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	253,710	313,412
Unfunded future income taxes	49,626	52,058
Environmental remediation costs	10,688	11,290
Nonutility generator termination agreement	105,298	109,587
Asset retirement obligation	151,570	-
Other	163,257	163,655
Total regulatory assets	734,149	650,002
Other assets
Prepaid pension benefits	5,962	-
Other	66,759	66,104
Total other assets	72,721	66,104
Total Regulatory and Other Assets	806,870	716,106
Total Assets	$2,736,301	$2,452,097

Thenotes on pages 44 through 51 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Balance Sheets - (Unaudited)

	June 30, 2003	Dec. 31,   2002
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$40,000	$159,935
Accounts payable and accrued liabilities	63,844	67,787
Affiliate payable	9,169	7,365
Interest accrued	10,109	10,509
Taxes accrued	10,034	3,451
Other	30,733	40,523
Total Current Liabilities	163,889	289,570
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	16,547	18,179
Other	63,057	56,617
Total regulatory liabilities	79,604	74,796
Other liabilities
Deferred income taxes	231,300	225,325
Nuclear waste disposal	103,606	102,745
Other postretirement benefits	69,005	65,983
Environmental remediation costs	22,356	22,356
Asset retirement obligation	425,042	-
Other	45,474	59,721
Total other liabilities	896,783	476,130
Total Regulatory and Other Liabilities	976,387	550,926
Long-term debt	752,292	752,254
Total Liabilities	1,892,568	1,592,750
Commitments	-	-
Preferred Stock  Redeemable solely at RG&E's option  Subject to mandatory redemption requirements	47,000  25,000	47,000  25,000
Common Stock Equity  Common stock	194,429	194,429
Capital in excess of par value	555,962	555,889
Retained earnings	138,580	154,267
Treasury stock, at cost	(117,238)	(117,238)
Total Common Stock Equity	771,733	787,347
Total Liabilities and Stockholder's Equity	$2,736,301	$2,452,097

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands)
Operating Revenues
Electric	$166,384	$167,599	$342,678	$336,556
Natural Gas	62,228	51,208	212,628	160,541
Total Operating Revenues	228,612	218,807	555,306	497,097
Operating Expenses
Electricity purchased and fuel used in generation	34,025	51,679	76,458	95,720
Natural gas purchased	33,545	29,173	131,250	93,103
Other operating expenses	64,846	78,389	155,328	137,086
Maintenance	14,017	16,259	27,450	32,177
Depreciation and amortization	25,688	25,162	52,913	50,130
Other taxes	19,457	21,010	43,792	46,504
Total Operating Expenses	191,578	221,672	487,191	454,720
Operating Income	37,034	(2,865)	68,115	42,377
Other (Income)	(423)	(3,184)	(2,541)	(7,822)
Other Deductions	815	4,181	963	5,837
Interest Charges, Net	12,405	12,919	46,387	27,203
Income Before Income Taxes	24,237	(16,781)	23,306	17,159
Income Taxes	9,564	228	7,143	13,439
Net Income (Loss)	14,673	(17,009)	16,163	3,720
Preferred Stock Dividends	925	925	1,850	1,850
Earnings (Loss) Available for Common Stock	$13,748	$(17,934)	$14,313	$1,870

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

Six months ended June 30	2003	2002
(Thousands)
Operating Activities
Net income	$16,163	$3,720
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	90,288	82,895
Writedown of investments	-	13,718
Income taxes and investment tax credits deferred, net	4,006	(4,603)
Pension income	(8,014)	(10,512)
Excess earnings	44,051	-
Changes in current operating assets and liabilities
Accounts receivable, net	(2,249)	26,755
Inventory	(411)	6,998
Prepayments	4,614	(12,867)
Accounts payable and accrued liabilities	(2,140)	6,424
Interest accrued	(399)	(1,970)
Taxes accrued	6,583	7,055
Other current liabilities	(10,004)	(157)
Other assets	(27,311)	(15,511)
Other liabilities	24,778	16,869
Net Cash Provided by Operating Activities	139,955	118,814
Investing Activities
Utility plant additions	(40,044)	(74,231)
Sale of generation assets	-	50,484
Nuclear generating plant decommissioning fund	(8,662)	(8,662)
Other	(2,052)	(3,065)
Net Cash Used in Investing Activities	(50,758)	(35,474)
Financing Activities
Repayments of first mortgage bonds and preferred stock	(40,000)	(100,000)
Long-term debt issuances, net of discount or premiums	-	125,000
Repayment of promissory notes	(79,935)	(2,153)
Notes payable three months or less, net	-	-
Dividends on common and preferred stock	(31,850)	(56,903)
Net Cash Used in Financing Activities	(151,785)	(34,056)
Net (Decrease) Increase in Cash and Cash Equivalents	(62,588)	49,284
Cash and Cash Equivalents, Beginning of Period	86,385	19,462
Cash and Cash Equivalents, End of Period	$23,797	$68,746

Thenotes on pages 44 through 51 are an integral part of the financial statements.

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

Six months ended June 30	2003	2002
(Thousands)
Balance, Beginning of Period	$154,267	$174,054
Add net income	16,163	3,720
	170,430	177,774
Deduct Dividends on Capital Stock
Preferred	1,850	1,850
Common	30,000	66,155
	31,850	68,005
Balance, End of Period	$138,580	$109,769

Thenotes on pages 44 through 51 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.

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.

RG&E Union Vote: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.

Natural Gas Delivery Business

RG&E Natural Gas Supply Agreement: See Energy East Corporation's Item 2(a), Natural Gas Delivery Business, for this discussion.

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

Rochester Gas and Electric Corporation

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.

RG&E Union Vote: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), Natural Gas Delivery Business, for this discussion.

Investing and Financing Activities

Investing Activities: Capital spending for the first six months of 2003 was $40 million, including nuclear fuel. Capital spending is projected to be $146 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: 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 this shelf registration for general corporate purposes, such as retirement or repurchase of certain of its indebtedness or preferred stock, reduction of short-term debt, financing the development and construction of new facilities and additions to working capital. RG&E currently has $75 million available under a previous shelf registration statement.

In July 2003 RG&E paid at maturity $40 million of first mortgage bonds using primarily temporary cash investments and internally generated funds.

RG&E plans to issue $75 million of long-term debt in the third quarter of 2003 under the shelf registration statement described above, to replace the $80 million of first mortgage bonds that matured earlier in the year.

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.

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

Rochester Gas and Electric Corporation

(b)Results of Operations

Three months ended June 30 (Thousands)	2003	2002	Change
Operating Revenues	$228,612	$218,807	4%
Operating Income (Loss)	$37,034	$(2,865)	*
Earnings (Loss) Available for Common Stock	$13,748	$(17,934)	*

* Not meaningful

Earnings increased $32 million for the quarter. Higher electric and natural gas deliveries this quarter added $14 million to earnings. Earnings for the quarter also increased $4 million because of a scheduled refueling outage at the Ginna nuclear plant that added to purchased power costs in 2002 and $9 million due to a writedown of software development costs that reduced earnings in 2002.

Six months ended June 30 (Thousands)	2003	2002	Change
Operating Revenues	$555,306	$497,097	12%
Operating Income	$68,115	$42,377	61%
Earnings Available for Common Stock	$14,313	$1,870	*

* Not meaningful

Earnings for the six months increased $12 million due to an increase of $23 million for higher natural gas and electric deliveries primarily due to colder winter weather in 2003. Earnings for the six months also increased $7 million because of a scheduled refueling outage at the Ginna nuclear plant that added to purchased power costs in 2002 and $9 million due to a writedown of software development costs that reduced earnings in 2002. Those increases were partially offset by the recognition of the terms and conditions of the NYPSC rate order for RG&E, which became effective January 15, 2003, and 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.)

Operating Results for the Electric Delivery Business

Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	1,669	1,725	(3%)
Operating Revenues	$166,384	$167,599	(1%)
Operating Expenses	$136,048	$166,674	(18%)
Operating Income	$30,336	$925	*

* Not meaningful

The $1 million decrease in operating revenues for the quarter is primarily due to lower wholesale deliveries of $1 million.

Operating expenses decreased $31 million for the quarter primarily due to lower purchased power costs of $12 million due to decreased purchases and a scheduled refueling at the Ginna nuclear plant that added $6 million to operating costs in 2002 and $10 million due to a writedown of software development costs that also increased operating costs in 2002. RG&E deferred $23 million of operating expenses during the second quarter for restoration work resulting from a severe ice storm in April 2003.

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

Rochester Gas and Electric Corporation

Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	3,450	3,438	-
Operating Revenues	$342,678	$336,556	2%
Operating Expenses	$309,196	$313,504	(1%)
Operating Income	$33,482	$23,052	45%

Operating revenues for the six months increased $6 million primarily due to higher deliveries of $4 million because of colder winter weather in 2003.

The $4 million decrease in operating expenses for the six months was primarily due to lower purchased power costs of $11 million due to decreased purchases 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 the terms and conditions of the NYPSC rate order for RG&E, which became effective January 15, 2003, and increased operating expenses $30 million. That amount includes $26 million for excess electric earnings and related interest. (See RG&E 2002 Electric and Gas Rate Proceeding.) RG&E deferred $23 million of operating expenses during the second quarter for restoration work resulting from a severe ice storm in April 2003.

Operating Results for the Natural Gas Delivery Business

Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	9,314	9,146	2%
Operating Revenues	$62,228	$51,208	22%
Operating Expenses	$55,530	$54,998	1%
Operating Income (Loss)	$6,698	$(3,790)	*

* Not meaningful

The $11 million increase in operating revenues for the quarter is primarily due to gas cost recovery of $6 million associated with higher market prices, higher retail deliveries of $2 million because of colder weather in 2003 and a $2 million increase due to higher delivery prices collected from customers that became effective in March 2003.

Operating expenses increased $1 million for the quarter primarily due to higher natural gas costs of $6 million due to market conditions, offset by a decrease of $4 million due to a writedown of software development costs that increased operating costs in 2002.

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

Rochester Gas and Electric Corporation

Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	34,347	29,890	15%
Operating Revenues	$212,628	$160,541	32%
Operating Expenses	$177,995	$141,216	26%
Operating Income	$34,633	$19,325	79%

Operating revenues increased $52 million for the six months primarily due to higher retail deliveries of $25 million because of colder winter weather in 2003, gas cost recovery of $25 million associated with higher market prices and a $2 million increase due to higher delivery prices collected from customers that became effective in March 2003.

Operating expenses for the six months increased $37 million primarily due to higher natural gas purchases including $14 million for higher retail deliveries because of colder weather this year and a $25 million increase in the cost of natural gas due to market conditions.

Item 1.  Financial Statements

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

Notes to Financial Statements of Registrants:

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

Note 1. Unaudited Financial Statements

The accompanying unaudited 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.

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. 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. During 2003 the related involuntary severance liability decreased $9 million. 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. 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 resulted in a decline of 486 employees in the first quarter of 2003, including 34 from CMP, 210 from NYSEG and 176 from RG&E. Collectively the voluntary early retirement and involuntary severance programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by the end of 2003. That includes approximately 70 from CMP, 260 from NYSEG, 250 from RG&E and 70 from Berkshire Gas, CNG and SCG. The employees affected by the involuntary severance program were notified in January 2003.

Note 3. Other (Income) and Other Deductions

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands)
Energy East
Interest income	$(1,109)	$(2,795)	$(2,421)	$(7,894)
Noncash returns	(209)	(1,227)	(464)	(2,117)
Allowance for funds used during construction	(422)	(63)	(966)	(139)
Gains from the sale of nonutility property	(31)	(73)	(178)	(212)
Earnings from equity investments	(884)	(964)	(2,542)	(2,364)
Miscellaneous	(205)	(741)	(1,036)	(405)
Total other (income)	$(2,860)	$(5,863)	$(7,607)	$(13,131)
NYSEG early retirement of debt	-	$16,145	-	$16,145
Miscellaneous	$1,224	3,190	$3,092	5,024
Total other deductions	$1,224	$19,335	$3,092	$21,169
CMP
Interest income	$(162)	$(284)	$(418)	$(423)
Noncash returns	(156)	(122)	(359)	(859)
Earnings from equity investments	(480)	(586)	(1,018)	(1,201)
Miscellaneous	37	(15)	47	(10)
Total other (income)	$(761)	$(1,007)	$(1,748)	$(2,493)
Miscellaneous	$420	$306	$799	$643
Total other deductions	$420	$306	$799	$643
NYSEG
Interest income	$(274)	$(204)	$(652)	$(3,286)
Noncash returns	(267)	(1,105)	(481)	(1,258)
Miscellaneous	357	(469)	(975)	1,978
Total other (income)	$(184)	$(1,778)	$(2,108)	$(2,566)
Early retirement of debt	-	$16,145	-	$16,145
Miscellaneous	$(1,553)	293	$(1,297)	1,106
Total other deductions	$(1,553)	$16,438	$(1,297)	$17,251
RG&E
Interest income	$(236)	$(586)	$(1,947)	$(2,649)
Noncash returns	-	(2,165)	-	(4,336)
Miscellaneous	(187)	(433)	(594)	(837)
Total other (income)	$(423)	$(3,184)	$(2,541)	$(7,822)
Merger costs	-	$3,838	-	$4,093
Miscellaneous	$815	343	$963	1,744
Total other deductions	$815	$4,181	$963	$5,837

Note 4. 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 diluted EPS for each period follows:

	Three Months		Six Months
Periods ended June 30	2003	2002	2003	2002
(Thousands)
Numerator
Net Income	$27,717	$5,323	$163,181	$110,893
Denominator
Basic average common shares outstanding	145,415	117,820	145,256	117,273
Restricted stock awards	225	-	173	-
Potentially dilutive common shares	107	429	127	240
Options issued with SARs	(107)	(429)	(127)	(240)
Dilutive average common shares	145,640	117,820	145,429	117,273
EPS - basic	$.19	$.05	$1.12	$.95
EPS - diluted	$.19	$.05	$1.12	$.95

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 June 30 were: 5.2 million in 2003 and 2.0 million in 2002, and for the six months ended June 30 were: 5.2 million in 2003 and 4.0 million in 2002.

Note 5. Accounts Receivable

Accounts receivable for the companies include unbilled revenues as follows: Energy East - consolidated unbilled revenues of $131 million at June 30, 2003, and $237 million at December 31, 2002; CMP - consolidated unbilled revenues of $20 million at June 30, 2003, and $33 million at December 31, 2002; NYSEG - unbilled revenues of $47 million at June 30, 2003, and $79 million at December 31, 2002; RG&E - unbilled revenues of $39 million at June 30, 2003, and $59 million at December 31, 2002.

Note 6. 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. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability.

The companies' adoption of Statement 143 as of January 1, 2003, did not have a material effect on their respective financial position 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 ($77 million for CMP, $282 million for NYSEG, $127 million for RG&E and $155 million for Other, as of June 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 could have been 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 have previously classified as equity, and to recognize as interest expense distributions that have previously been 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 is effective at the beginning of the first interim period begi nning after June 15, 2003, for instruments existing when the Statement was issued. The company's adoption of Statement 150 on July 1, 2003, did not have a material effect on its financial position and results of operations.

Note 7. Acquisition of RGS Energy Group

Due to the completion of the company's merger with RGS Energy Group, Inc. on June 28, 2002, the company's consolidated financial statements include RGS Energy's results beginning with July 2002. RGS Energy did not push goodwill down to RG&E. As of June 30, 2003, $29 million of the purchase price for RGS Energy was allocated to intangible assets, based on an appraisal.

The following pro forma information for the company for the three months and six months ended June 30, 2002, which is based on unaudited data, gives effect to the company's merger with RGS Energy as if it had been completed January 1, 2002. This information does not reflect future revenues or cost savings that may result from the merger and is not indicative of actual results of operations had the merger occurred at the beginning of the period presented or of results that may occur in the future.

Periods ended June 30, 2002	Three Months	Six Months
(Thousands, except per share amounts)
Operating revenues	$1,017,312	$2,425,023
Net income (loss)	$(1,624)	$123,811
Earnings per share of common stock	$(.01)	$.86

Pro forma adjustments reflected in the amounts presented above include: (1) adjusting RGS Energy's nonutility assets to fair value based on an independent appraisal, (2) adjusting depreciation and amortization of assets to the accounting base recognized in recording the combination, (3) amortization of other intangible assets with finite lives, (4) elimination of merger costs, (5) additional interest expense due to the issuance of merger-related debt, (6) adjustments for estimated tax effects of the above adjustments and (7) additional common shares issued in connection with the merger. The pro forma results include a loss from the writedown of CMP Group's investment in NEON Communications of 1 cent per share for the quarter ended June 30, 2002, and 6 cents per share for the six months ended June 30, 2002. The pro forma results of operations include the results of operations of RGS Energy as follows (in thousands): three months ended June 30, 2002 - Operating revenues - $302,438, Operating expenses - $290 ,388, Operating income - $12,050, Income before income taxes - $(3,716), and Net income - $(8,558); six months ended June 30, 2002 - Operating revenues - $681,571, Operating expenses - $615,851, Operating income - $65,720, Income before income taxes - $36,850, and Net income - $15,550.

Note 8. Supplemental Disclosure of Cash Flows Information

	2003	2002
(Thousands)
Cash paid during the six months ended June 30:
Interest, net of amounts capitalized     Energy East     CMP     NYSEG     RG&E	$133,319  $12,091  $31,051  $24,403	$100,505  $13,234  $37,412  $27,810
Income taxes, net of benefits received     Energy East     CMP     NYSEG     RG&E	$15,954  $9,934  $14,193  $(945)	$2,749  $(6,549) $17,769  $32,218
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 payable for acquisition(1)	-	$681,397

(1) Cash portion of the purchase price that was paid to RGS Energy shareholders in July 2002 of $753,483, net of cash acquired of $72,086.

Note 9. Intangible Assets

The company's unamortized intangible assets had a carrying amount of $17 million at June 30, 2003, and December 31, 2002, and primarily consist of trade names and pension assets. The company's amortized intangible assets had a gross carrying amount of $46 million at June 30, 2003, and $47 million at December 31, 2002, and primarily consist of customer lists and investments in pipelines. Accumulated amortization was $17 million at June 30, 2003, and $15 million at December 31, 2002. Estimated amortization expense for intangible assets for the next five years is approximately $4 million each year for 2003 and 2004, and $3 million each year for 2005 through 2007.

CMP's unamortized intangible assets had a carrying amount of $2 million at June 30, 2003, and December 31, 2002, and consist of pension assets. CMP's amortized intangible assets had a gross carrying amount and accumulated amortization of less than $0.3 million at June 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, 2003 through 2007.

NYSEG's unamortized intangible assets had a carrying amount of $1.6 million at June 30, 2003, and December 31, 2002, and primarily consist 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 June 30, 2003, and December 31, 2002, and consist of hydroelectric licenses. Estimated amortization expense for intangible assets for the next five years is $64 thousand for the years 2003 through 2005, $57 thousand for 2006 and $55 thousand for 2007.

RG&E's amortized intangible assets had a gross carrying amount of $3 million and accumulated amortization of $2 million at June 30, 2003, and December 31, 2002, and consist of water rights. Estimated amortization expense for intangible assets is $78 thousand for each of the next five years, 2003 through 2007.

Note 10. 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, reflected on its balance sheets. 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 11. 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. The $22 million increase in 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.

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:

(Thousands)	Electric      Delivery	Natural Gas     Delivery	Other	Total
Three Months Ended
June 30, 2003
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$640,035  $135,259  $338,353  $166,384	$264,054  - -       $75,011  $62,228	$166,956  - -       - -       - -	$1,071,045  $135,259  $413,364  $228,612
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$29,900  $2,821  $28,130  $12,030	$(602) - -       $1,793  $2,643	$(1,581) - -       - -       - -	$27,717  $2,821  $29,923  $14,673
June 30, 2002
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$504,364  $139,208  $365,098  $167,599	$165,087  - -       $60,347  $51,208	$45,423  - -       - -       - -	$714,874  $139,208  $425,445  $218,807
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$17,639  $5,293  $16,320  $(10,576)	$(2,036) - -       $(3,175) $(6,433)	$(10,280) - -       - -       - -	$5,323  $5,293  $13,145  $(17,009)
Six Months Ended
June 30, 2003
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$1,398,748  $311,676  $744,320  $342,678	$904,167  - -       $244,775  $212,628	$407,477  - -       - -       - -	$2,710,392  $311,676  $989,095  $555,306
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$92,575  $26,923  $67,722  $(2,319)	$65,623  - -       $22,818  $18,482	$4,983  - -       - -       - -	$163,181  $26,923  $90,540  $16,163

- continued (Thousands)	Electric      Delivery	Natural Gas     Delivery	Other	Total
June 30, 2002
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$1,135,404  $339,822  $795,472  $336,556	$510,055  - -       $187,227  $160,541	$97,993  - -       - -       - -	$1,743,452  $339,822  $982,699  $497,097
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$94,595  $28,575  $74,810  $(3,386)	$39,145  - -       $7,956  $7,106	$(22,847) - -       - -       - -	$110,893  $28,575  $82,766  $3,720
Total Assets
June 30, 2003    Energy East    CMP    NYSEG    RG&E	$6,970,312  $1,728,185  $2,247,507  $2,156,518	$3,208,981  - -       $784,108  $495,557	$444,767  $8,601  $211,164  $84,226	$10,624,060  $1,736,786  $3,242,779  $2,736,301
December 31, 2002    Energy East    CMP    NYSEG    RG&E	$6,582,234  $1,777,727  $2,218,737  $1,811,146	$3,201,235  - -       $737,629  $502,305	$473,418  $8,596  $97,060  $138,646	$10,256,887  $1,786,323  $3,053,426  $2,452,097
Goodwill
June 30, 2003    Energy East    CMP    NYSEG	$845,332  $324,725  - -	$677,169  - -       $11,199	$17,684  $855  - -	$1,540,185  $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

Note 12. 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 August 1, 2003, NYSEG's load was 93% hedged for on-peak periods and 84% hedged for off-peak periods in 2003 and 92% hedged for on-peak periods and 85% hedged for off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.3 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 and natural gas. 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 August 1, 2003, RG&E's load was 90% hedged for on-peak periods and fully hedged for off-peak periods in 2003 and fully hedged for both on-peak and off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of on-peak electricity would change earnings by $0.1 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 4.  Submission of Matters to a Vote of Security Holders

Energy East Corporation

Energy East's Annual Meeting of Stockholders was held on June 13, 2003. The following matters were voted on:

(a)  The election of five directors:

Nominees	Votes For	Votes Withheld
Joseph J. Castiglia	117,007,259	7,272,736
Lois B. DeFleur	118,768,534	5,511,461
G. Jean Howard	119,542,025	4,737,970
Walter G. Rich	119,617,280	4,662,715
Wesley W. von Schack	119,201,124	5,078,871

(b)  Approval of an amendment of the 2000 Stock Option Plan to increase the number of shares available for awards under the Plan from 10,000,000 to 13,000,000:

Shares For:	98,324,238
Shares Against:	23,644,358
Shares Abstain:	2,311,399

(c) Approval of a stockholder proposal recommending that the Board of Directors redeem any poison pill previously issued (if applicable) and not adopt or extend any poison pill unless such adoption or extension has been submitted to a shareholder vote:

Shares For:	53,102,878
Shares Against:	45,940,940
Shares Abstain:	3,681,109
Broker Nonvoted:	21,555,068

Central Maine Power Company

CMP's Annual Meeting of Stockholders was held on June 16, 2003. The election of three directors was voted on:

Nominees	Votes For	Votes Withheld
Sara J. Burns	3,121,680	-
Kenneth M. Jasinski	3,121,680	-
Wesley W. von Schack	3,121,680	-

New York State Electric & Gas Corporation

On June 13, 2003, RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation and the owner of all of the outstanding shares of NYSEG's common stock, by written consent in lieu of the annual meeting of stockholders, elected Kenneth M. Jasinski, James P. Laurito and Wesley W. von Schack directors of NYSEG.

Rochester Gas and Electric Corporation

On June 13, 2003, RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation and the owner of all of the outstanding shares of RG&E's common stock, by written consent in lieu of the annual meeting of stockholders, elected Kenneth M. Jasinski, James P. Laurito, Wesley W. von Schack and Paul C. Wilkens directors of RG&E.

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 two reports on Form 8-K; one, dated April 25, 2003, was filed to report certain information under Item 9, "Regulation FD Disclosure," and Item 12, "Disclosure of Results of Operations and Financial Condition," and the other, dated April 29, 2003, was filed to report certain information under Item 5, "Other Events."

RG&E filed a Form 8-K dated April 29, 2003, to report certain information under Item 5, "Other Events."

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:  August 13, 2003	ENERGY EAST CORPORATION                   (Registrant) By   /s/Robert E. Rude                                                             Robert E. Rude            Vice President and Controller            (Principal Accounting Officer)
Date:  August 13, 2003	CENTRAL MAINE POWER COMPANY                   (Registrant) By   /s/Curtis I. Call                                                                   Curtis I. Call            Vice President, Controller & Treasurer            (Principal Financial Officer)
Date:  August 13, 2003	NEW YORK STATE ELECTRIC & GAS CORPORATION                   (Registrant) By   /s/Joseph J. Syta                                                              Joseph J. Syta            Controller and Treasurer            (Principal Financial Officer)
Date:  August 13, 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	(A)10-24	Employment Agreement dated as of April 30, 2003, by and among Connecticut Natural Gas Corporation, Energy East Management Corporation, Energy East Corporation and Michael I. German.
	(A)10-25	Director's Charitable Giving Program.
	(A)10-26	Amended and Restated 2000 Stock Option Plan, effective June 13, 2003.
	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002 of Energy East Corporation.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002 of Energy East Corporation.
Central Maine Power Company	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002 of Central Maine Power Company.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002 of Central Maine Power Company.
New York State Electric   & Gas Corporation	4-10	Third Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of May 9, 2003, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002.
	(A)10-35	Amendment No. 4 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001.
	(A)10-36	Separation Agreement, General Release and Waiver dated as of April 7, 2003, by and among Ralph R. Tedesco, the Company and Energy East Management Corporation.
	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002 of New York State Electric & Gas Corporation.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002 of New York State Electric & Gas Corporation.
Rochester Gas and Electric   Corporation	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002 of Rochester Gas and Electric Corporation.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002 of Rochester Gas and Electric Corporation.

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(A) Management contract or compensatory plan or arrangement.