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

~~(Mark~~FORM ~~One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2001~~ 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

[  ]  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

AsIndicate ofby ~~October~~check ~~31,~~mark ~~2001,~~whether ~~shares~~the ofregistrant ~~common~~is ~~stock~~an ~~outstanding~~accelerated ~~for~~filer ~~each~~(as ~~registrant~~defined ~~were:~~in Rule 12b-2 of the Exchange Act).

Registrant	Description	Shares
Energy East Corporation Central Maine Power Company New York State Electric & Gas Corporation	Par value $.01 per share Par value $5 per share Par value $6.66 2/3 per share	116,532,239 31,211,471 (1) 64,508,477 (2)

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

Item	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 Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Retained Earnings Consolidated Statements of Comprehensive Income Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	1 2 4 5 5 6 1415
	Central Maine Power Company Consolidated Statements of Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Retained Earnings Consolidated Statements of Comprehensive Income Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	17 18 20 21 21 22 23
	Central Maine Power Company Consolidated Balance Sheets Consolidated Statements of Income Consolidated Statements of Cash Flows Consolidated Statements of Retained Earnings Consolidated Statements of Comprehensive Income Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	18 20 21 22 22 23 24
	New York State Electric & Gas Corporation Statements of Income Balance Sheets Statements of Cash Flows Statements of Retained Earnings 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	25 26 28 29 29 30 31
	Notes to Financial Statements Forward-looking Statements	33 36
	Rochester Gas and Electric Corporation Balance Sheets Statements of Income Statements of Cash Flows Statements of Retained Earnings Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	34 36 37 38 39 41
3	Quantitative and Qualitative Disclosures About Market Risk	37
	PART II - OTHER INFORMATION
6	Exhibits and Reports on Form 8-K (a) Exhibits (b) Reports on Form 8-K	37 37
Signatures		38
Exhibit Index		39

	TABLE OF CONTENTS - continued	Page
1	Notes to Financial Statements Forward-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		~~Nine~~Six Months
Periods Ended September 30	2001	2000		2001	2000
Periods ended June 30	2003	2002	2003	2002
(Thousands, except per share amounts)	~~(Thousands, except per share amounts)~~
Operating Revenues
Sales and services	$798,848	$651,146		$2,918,997	$1,907,491
Utility	$904,089	$669,451	$2,302,915	$1,645,459
Operating Expenses
Nonutility	166,956	45,423	407,477	97,993
Electricity purchased and fuel used in generation	359,677	281,263		1,051,774	730,392
Total Operating Revenues	1,071,045	714,874	2,710,392	1,743,452
Natural gas purchased	74,100	66,009		588,259	246,909
Operating Expenses
Other operating expenses	139,552	114,082		425,341	277,321
Electricity purchased and fuel used in generation
Maintenance	34,260	20,258		102,714	67,580
Utility	273,677	266,260	595,257	558,668
Depreciation and amortization	50,967	44,375		153,480	111,944
Nonutility	27,290	18,518	64,077	32,063
Other taxes	45,725	23,877		150,173	104,620
Natural gas purchased
Total Operating Expenses	704,281	549,864		2,471,741	1,538,766
Utility	148,873	81,782	550,713	269,906
Operating Income	94,567	101,282		447,256	368,725
Nonutility	29,541	6,160	78,752	27,766
Writedown of Investment	78,422	-		78,422	-
Gasoline, propane and oil purchased, nonutility	73,739	509	181,715	1,737
Other (Income) and Deductions	(4,836)	(14,050)		(13,912)	(29,205)
Other operating expenses
Interest Charges, Net	52,487	39,156		164,741	96,732
Utility	186,603	121,743	372,340	246,348
Preferred Stock Dividends of Subsidiaries	5,835	287		6,790	485
Nonutility	28,488	17,199	53,083	33,818
Income (Loss) Before Income Taxes	(37,341)	75,889		211,215	300,713
Maintenance	44,297	31,097	91,607	65,921
Income Taxes (Benefit)	(16,284)	42,540		90,097	117,566
Depreciation and amortization	76,348	47,670	154,259	93,813
Net Income (Loss)	$(21,057)	$33,349		$121,118	$183,147
Other taxes	58,876	42,460	144,961	93,066
Earnings (Loss) Per Share, basic and diluted	$(.18)	$.30		$1.04	$1.62
Total Operating Expenses	947,732	633,398	2,286,764	1,423,106
Dividends Paid Per Share	$.23	$.22		$.69	$.66
Operating Income	123,313	81,476	423,628	320,346
Average Common Shares Outstanding	116,436	112,812		116,737	112,995
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

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

Item 1.
Energy East Corporation
Consolidated Balance Sheets - (Unaudited)

	Sep. 30, 2001	Dec. 31, 2000
	June 30, 2003	Dec. 31, 2002
Assets	(Thousands)
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$~~238~~217,~~769~~522	$~~143~~250,~~626~~490
Special deposits	1136,~~558~~925	2147,~~516~~643
Accounts receivable, net	~~539~~662,~~807~~297	~~536~~737,~~280~~876
Fuel, at average cost	~~103~~105,~~122~~833	65117,~~496~~678
Materials and supplies, at average cost	2123,~~554~~308	22,~~759~~953
Accumulated deferred income tax benefits, net	~~563~~15,995	58,~~007~~697
Prepayments	56,875	57,720
Prepayments and other current assets	78,848	86,167
Total Current Assets	~~962~~1,~~248~~240,728	~~852~~1,~~404~~271,504
Utility Plant, at Original Cost
Electric	45,~~705~~921,~~034~~790	45,~~784~~803,~~312~~576
Natural gas	12,~~725~~364,~~122~~383	12,~~665~~347,~~386~~011
Common	~~212~~358,~~930~~705	~~220~~360,~~124~~776
	6,643,086	6,669,822
	8,644,878	8,511,363
Less accumulated depreciation	3,~~078~~820,~~359~~105	3,~~096~~877,~~283~~164
Net Utility Plant in Service	34,~~564~~824,~~727~~773	34,~~573~~634,~~539~~199
Construction work in progress	57202,~~294~~974	59179,~~389~~557
Total Utility Plant	35,~~622~~027,~~021~~747	34,~~632~~813,~~928~~756
Other Property and Investments, Net	~~260~~473,~~753~~513	~~259~~452,~~708~~710
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	~~222~~433,~~670~~485	~~234~~524,~~929~~679
Unfunded future income taxes	~~191~~233,~~630~~575	~~184~~234,~~570~~487
Unamortized loss on debt reacquisitions	5446,~~657~~188	5845,~~848~~353
Demand-side management program costs	25,835	48,929
Environmental remediation costs	128,172	106,262
Environmental remediation costs	71,314	78,406
Nonutility generator termination agreements	111,868	116,782
Other	~~257~~525,~~195~~777	~~241~~370,~~396~~354
Total regulatory assets	~~823~~1,~~301~~479,065	~~847~~1,~~078~~397,917
Other assets
Goodwill, net	~~912~~1,~~290~~540,185	~~952~~1,~~358~~518,173
Prepaid pension benefits	~~413~~580,~~615~~420	~~350~~540,~~038~~426
Other	~~116~~282,~~104~~402	~~119~~262,~~214~~401
Total other assets	12,~~442~~403,~~009~~007	12,~~421~~321,~~610~~000
Total Regulatory and Other Assets	23,~~265~~882,~~310~~072	23,~~268~~718,~~688~~917
Total Assets	$710,~~110~~624,~~332~~060	$710,~~013~~256,~~728~~887

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Item 1.
Energy East Corporation
Consolidated Balance Sheets - (Unaudited)

	Sep. 30, 2001	Dec. 31, 2000
	June 30, 2003		Dec. 31, 2002
Liabilities	(Thousands)
(Thousands)
Current Liabilities
Liabilities
Current portion of long-term debt	$83,759	$25,285
Current Liabilities
Notes payable	205,183	418,995
Current portion of long-term debt	$517,982		$545,404
Accounts payable and accrued liabilities	230,963	345,424
Notes payable	182,000		322,200
Interest accrued	53,863	35,309
Accounts payable and accrued liabilities	308,196		361,499
Taxes accrued	19,994	-
Interest accrued	41,374		44,310
Other	148,732	211,784
Taxes accrued	76,679		30,036
Total Current Liabilities	742,494	1,036,797
Other	162,309		200,927
Regulatory and Other Liabilities
Total Current Liabilities	1,288,540		1,504,376
Regulatory liabilities
Regulatory and Other Liabilities
Deferred income taxes	97,969	91,421
Regulatory liabilities
Deferred income taxes, unfunded future income taxes	89,171	75,473
Deferred income taxes	216,309		203,926
Gain on sale of generation assets	~~204~~135,~~298~~877	~~232,041~~	152,648
Pension benefits	9259,~~237~~655	~~96,514~~	67,205
Other	68122,~~802~~967	~~76,813~~	104,937
Total regulatory liabilities	~~552~~534,~~477~~808	~~572,262~~	528,716
Other liabilities
Deferred income taxes	~~442~~734,~~338~~174	~~457,495~~	702,426
Nuclear plant obligations	~~222~~283,~~670~~381	~~234,929~~	314,013
Other postretirement benefits	~~288~~400,~~321~~993	~~279,864~~	391,049
Environmental remediation costs	90,287	91,811
Asset retirement obligation	426,377		-
Other	251,876	233,910
Environmental remediation costs	149,147		133,933
Total other liabilities	1,295,492	1,298,009
Other	394,219		408,841
Total Regulatory and Other Liabilities	1,847,969	1,870,271
Total other liabilities	2,388,291		1,950,262
Long-term debt	2,391,846	2,346,814
Total Regulatory and Other Liabilities	2,923,099		2,478,978
Total Liabilities	4,982,309	5,253,882
Long-term debt	3,382,661		3,351,959
Commitments	-	-
Total Liabilities	7,594,300		7,335,313
Preferred Stock of Subsidiaries Company-obligated mandatorily redeemable trust preferred securities of subsidiary holding solely parent debentures	345,000	-
Commitments	-		-
Preferred stock redeemable solely at the option of subsidiaries	43,329	43,324
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,~~180~~458	~~1,191~~	1,455
Capital in excess of par value	~~839~~1,~~361~~448,143	~~871,078~~	1,447,664
Retained earnings	~~958~~1,~~594~~152,043	~~918,016~~	1,061,428
Accumulated other comprehensive income (loss)	(20,501)	(34,823)
Accumulated other comprehensive (loss)	(28,849)		(34,167)
Treasury stock, at cost	(38,940)	(38,940)
Deferred compensation	(3,727)		-
Total Common Stock Equity	1,739,694	1,716,522
Treasury stock, at cost	(364)		(15,768)
Total Liabilities and Stockholders' Equity	$7,110,332	$7,013,728
Total Common Stock Equity	2,568,704		2,460,612
Total Liabilities and Stockholders' Equity	$10,624,060		$10,256,887

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Item 1.
Energy East Corporation
Consolidated Statements of Cash Flows - (Unaudited
)

Nine Months Ended September 30	2001	2000
Six months ended June 30		2003	2002
Operating Activities	(Thousands)
(Thousands)
Net income	$121,118	$183,147
Operating Activities
Adjustments to reconcile net income to net cash provided by operating activities
Net income		$163,181	$110,893
Depreciation and amortization	153,480	111,944
Adjustments to reconcile net income to net cash provided by operating activities
Income taxes and investment tax credits deferred, net	(13,453)	(6,334)
Depreciation and amortization		206,568	110,046
Pension income	(55,637)	(49,233)
Income taxes and investment tax credits deferred, net		55,216	10,504
Writedown of investment	78,422	-
Pension income		(18,814)	(33,451)
Changes in current operating assets and liabilities
Writedown of investment		-	12,209
Accounts receivable	148,473	84,984
Changes in current operating assets and liabilities
Sale of accounts receivable program	(152,000)	-
Accounts receivable, net		56,673	100,855
Inventory	~~(36,421)~~	~~(26~~11,~~577)~~772	21,730
Prepayments	845	491
Prepayments and other current assets		15,571	18,138
Accounts payable and accrued liabilities	~~(114,461)~~	(~~128~~53,~~427~~844)	(33,887)
Interest accrued	~~18,554~~	12(2,~~512~~941)	(2,527)
Taxes accrued	~~19,994~~	446,~~335~~422	54,864
Other current liabilities	~~(63,052)~~	10(39,~~945~~399)	(18,539)
Other, net	4,307	(53,683)
Other assets		(86,369)	40,110
Net Cash Provided by Operating Activities	110,169	144,104
Other liabilities		23,935	(16,348)
Investing Activities
Net Cash Provided by Operating Activities		377,971	374,597
Acquisitions, net of cash acquired	-	(1,442,717)
Investing Activities
Utility plant additions	(126,438)	(88,779)
Cash acquired in acquisition		-	72,086
Temporary investments, net	-	936,174
Utility plant additions		(112,955)	(73,641)
Other property and investments	(13,625)	12,286
Sale of generation assets		-	59,442
Other	4,707	4,067
Other property and investments additions		(13,631)	(8,765)
Net Cash Used in Investing Activities	(135,356)	(578,969)
Other property and investments sold		5,054	5,021
Financing Activities
Special deposits		(81,134)	(5,044)
Issuance of common stock	3,547	-
Other		(2,377)	4,584
Repurchase of common stock	(24,116)	(149,261)
Net Cash (Used in) Provided by Investing Activities		(205,043)	53,683
Issuance of mandatorily redeemable trust preferred securities	345,000	-
Financing Activities
Repayments of first mortgage bonds and preferred stock of subsidiaries, including net premiums	(1,446)	(96,705)
Issuance of common stock		2,466	1,027
Long-term note issuances	107,879	650,530
Repurchase of common stock		-	(1,749)
Long-term note retirements	(16,182)	(1,430)
Repayments of first mortgage bonds and preferred stock of subsidiaries, including net premiums		(115,270)	(177,908)
Notes payable, net	(213,812)	53,886
Long-term note issuances		196,986	475,000
Dividends on common stock	(80,540)	(73,611)
Long-term note repayments		(6,140)	(57,637)
Net Cash Provided by Financing Activities	120,330	383,409
Notes payable three months or less, net		(128,700)	(108,683)
Net Increase (Decrease) in Cash and Cash Equivalents	95,143	(51,456)
Notes payable repayments		(91,435)	(10,000)
Cash and Cash Equivalents, Beginning of Period	143,626	116,806
Dividends on common stock		(63,803)	(49,354)
Cash and Cash Equivalents, End of Period	$238,769	$65,350
Net Cash (Used in) Provided by Financing Activities		(205,896)	70,696
Supplemental Disclosure of Cash Flows Information
Net (Decrease) Increase in Cash and Cash Equivalents		(32,968)	498,976
Cash paid during the period: Interest, net of amounts capitalized Income taxes	$139,871 $87,690	$79,389 $108,506
Cash and Cash Equivalents, Beginning of Period		250,490	437,014
Acquisitions: Fair value of assets acquired Liabilities assumed Common stock issued Cash acquired	- - - -	$2,526,971 (689,180) (373,708) (21,366)
Cash and Cash Equivalents, End of Period		$217,522	$935,990
Net cash paid for acquisitions	-	$1,442,717

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Item 1.
Energy East Corporation
Consolidated Statements of Retained Earnings - (Unaudited)

Nine Months Ended September 30	2001	2000
Six months ended June 30	2003	2002
(Thousands)	~~(Thousands)~~
Balance, Beginning of Period	$~~918~~1,~~016~~061,428	$~~782~~998,~~588~~281
Add net income	~~121~~163,~~118~~181	~~183~~110,~~147~~893
Deduct dividends on common stock	8072,~~540~~566	7356,~~611~~032
Balance, End of Period	$~~958~~1,~~594~~152,043	$~~892~~1,~~124~~053,142

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Energy East Corporation
Consolidated Statements of Comprehensive Income - (Unaudited)

	Three Months		~~Nine~~Six Months
Periods Ended September 30	2001	2000	2001	2000
Periods ended June 30	2003	2002	2003	2002
(Thousands)	~~(Thousands)~~
Net income (loss)	$(21,057)	$33,349	$121,118	$183,147
Net income	$27,717	$5,323	$163,181	$110,893
Other comprehensive income (loss), net of tax
Other comprehensive income, net of tax
Foreign currency translation adjustment	-	7	86	(31)
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)
Net unrealized loss on investments	(12,208)	(9,664)	(11,000)	(8,657)
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
Reclassification adjustment for losses included in net income	45,748	-	45,748	-
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
Minimum pension liability adjustment	-	720	50	720
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
Unrealized gains (losses) on derivatives qualified as hedges
Net unrealized (losses) gains on derivatives qualified as hedges	(10,848)	(16,315)	4,354	14,395
Unrealized gains on derivatives qualified as hedges arising during the period due to cumulative effect of a change in accounting principle	-	-	58,250	-
Total other comprehensive income (loss)	(10,270)	(17,240)	5,318	12,945
Unrealized losses on derivatives qualified as hedges	(13,138)	-	(80,736)	-
Comprehensive Income (Loss)	$17,447	$(11,917)	$168,499	$123,838
Reclassification adjustment for losses included in net income	14,436	-	1,924	-
Net unrealized gains (losses) on derivatives qualified as hedges	1,298	-	(20,562)	-
Total other comprehensive income (loss)	34,838	(8,937)	14,322	(7,968)
Comprehensive income	$13,781	$24,412	$135,440	$175,179

The notes 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

~~RGS~~Restructuring ~~Energy Merger Agreement~~

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.

~~Under~~The ~~the~~voluntary ~~merger~~early ~~agreement~~retirement ~~45%~~resulted ofin ~~the RGS Energy common stock will be exchanged for Energy East common stock with~~ a ~~value~~decline of ~~$39.50~~486 ~~per~~employees ~~RGS~~in ~~Energy share, subject to restrictions on~~ the ~~minimum~~first ~~and~~quarter ~~maximum number~~ of ~~shares to be issued~~2003, ~~and~~including ~~55%~~34 offrom ~~the~~CMP, ~~RGS~~210 ~~Energy~~from ~~common~~NYSEG ~~stock~~and ~~will~~176 befrom ~~converted into $39~~RG&E.50 inCollectively ~~cash~~the ~~per~~voluntary ~~RGS~~early ~~Energy~~retirement ~~share.~~and ~~RGS~~involuntary ~~Energy~~severance ~~shareholders~~programs ~~will~~are beexpected ~~able~~ to ~~elect~~result ~~the~~in ~~form~~a ofdecline ~~consideration~~in ~~they~~overall ~~wish~~employee toheadcount ~~receive,~~of ~~subject to~~approximately ~~proration.~~650, ~~The~~or ~~company~~8%, ~~intends~~by ~~to finance~~ the ~~cash~~end ~~portion~~ of ~~the transaction primarily through the issuance of long-term debt and trust preferred securities~~2003. ~~(See Item 2 - Financing Activities.)~~

~~RGS~~Integration ~~Energy~~savings, ~~and~~previously ~~Energy~~estimated ~~East~~at ~~each~~over ~~held~~$80 ~~their~~million ~~annual~~annually, ~~meeting~~are onnow ~~June~~expected 15to be approximately $100 million annually by 2006. Those savings, ~~2001:~~which ~~RGS~~include ~~Energy's~~operating ~~shareholders~~expenses ~~approved~~and capital, will come from the ~~merger~~consolidation of functions such as accounting, finance, information services and ~~Energy~~supply ~~East's~~chain, ~~shareholders~~as ~~approved~~well as the ~~issuance~~implementation of ~~Energy~~other ~~East~~merger-enabled ~~shares~~initiatives inacross ~~connection~~the ~~with~~six operating utilities. The company completed its consolidation of information systems during the ~~merger~~second quarter of 2003.

~~The~~On ~~merger~~March ~~is subject to~~18, ~~among other things~~2003, ~~various regulatory approvals, including the New York State Public Service Commission (NYPSC), Federal~~ Energy ~~Regulatory~~East ~~Commission~~filed ~~(FERC),~~an ~~Nuclear~~application ~~Regulatory~~with ~~Commission~~the ~~(NRC) and~~ Securities and Exchange Commission (SEC). ~~The~~requesting ~~company~~authorization ~~has~~to ~~made~~form ~~all~~a ~~required~~shared ~~regulatory~~services ~~filings~~company ~~and~~that ~~received~~will ~~approval~~provide ~~from~~accounting, ~~FERC in September 2001. In addition~~finance, ~~the~~information ~~transaction~~services ~~cleared~~and ~~anti-trust~~supply ~~review~~chain ~~by the U~~functions. S.Energy ~~Department~~East ofexpects ~~Justice~~that inthe ~~October~~SEC ~~2001.~~will ~~The~~act ~~company~~on ~~expects to complete~~ the ~~merger~~request in the ~~first~~second ~~quarter~~half of ~~2002~~ 2003.

Electric Delivery Business

~~Sale~~Regional ofTransmission ~~Nine~~Organization ~~Mile Point 2~~(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.

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

Energy East Corporation

~~sale~~On ~~gain~~January ~~account~~16, to2003, beISO ~~established~~New atEngland, ~~the~~Inc. ~~time~~(ISO ofNew ~~closing.~~England) ~~Disposition~~announced ofthat ~~the~~it ~~asset~~would ~~sale~~work ~~gain,~~with ~~which~~New isEngland ~~estimated~~transmission owners to beseek ~~approximately~~input ~~$110~~and ~~million~~the advice of all market participants, ~~will~~regulators beand ~~determined~~other bystakeholders ~~the~~to ~~NYPSC,~~pursue ~~after~~the ~~consultation~~creation ~~with~~of ~~NYSEG~~a ~~and~~New ~~interested~~England-only ~~parties~~RTO. ~~All~~ISO ~~regulatory~~New ~~approvals~~England ~~have~~and ~~been~~the ~~received~~NYISO are considering individual RTO filings and ~~the~~better ~~transaction~~coordination iswith ~~expected~~neighboring tosystems. ~~close~~CMP, NYSEG and RG&E are participating in ~~November~~these ~~2001~~efforts.

~~The~~FERC ~~sellers'~~Standard ~~pre-existing~~Market ~~decommissioning funds will be transferred to Constellation, which will take responsibility for all future decommissioning funding.~~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 ultimate effect, if any, on their results of operations or financial position.

~~The~~Transmission ~~transaction~~Planning ~~includes~~and aExpansion ~~power~~and ~~purchase~~Generation agreement that calls for Constellation to provide electricity to the sellers, at fixed prices, for 10 years. After the power purchase agreement is completed, a revenue sharing agreement will begin. The revenue sharing agreement could provide additional revenue to the sellers through 2021, which would mitigate increases in electricity prices. Both agreements are based on plant output.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.

~~Sale~~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 ~~Vermont~~the ~~Yankee~~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.

~~NYSEG~~NYISO ~~Electric~~Demand ~~Rate~~Curve ~~Agreement~~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.

~~The~~Management's ~~addition~~discussion ofand aanalysis 3%of ~~price~~financial ~~reduction~~condition onand ~~January~~results 1,of ~~2002, for all NYSEG electricity customers except energy-intensive customers who will receive a 5% price reduction on March 1, 2002.~~operations

Offering two options, beginning January 1, 2003, to enhance competitive choices. Under one option, customers could choose a fixed price from NYSEG for electric supply and delivery to ensure price stability. Under a second option, customers could choose to pay NYSEG a fixed price for delivery and receive their supply from an energy services company. These new pro-competition options would be separate from NYSEG's existing customer choice program.
Shortening the term of the Price Protection Plan. The plan would now end December 31, 2007, with the option for NYSEG to extend it one year with the NYPSC's approval.
The addition of a mechanism, beginning in 2003, to share electric earnings above a threshold of $100 million with customers. NYSEG would also retain savings brought about by the merger between Energy East and RGS Energy.
NYPSC proceedings to review the Price Protection Plan are ongoing. In October 2001 the administrative law judges assigned to the Price Protection Plan established a schedule for parties to submit briefs on the Price Protection Plan and additional briefs on temporary rates. NYSEG believes there is no basis for consideration of temporary rates and such action is inconsistent with its electric Restructuring Agreement. NYSEG anticipates that the NYPSC will issue its decision later this year.
Item 2.
Energy East Corporation
~~Retail~~CMP ~~Access~~Alternative ~~Credit~~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.

OnCMP ~~April~~Electric ~~26,~~Transmission 2001, the NYPSC issued an order denying NYSEG's request to recover costs and lost revenues associated with the implementation of the market-based retail access credit. On May 24, 2001, NYSEG filed a petition for rehearing with the NYPSC. On May 25, 2001, NYSEG began an action in the New York State Supreme Court (Albany County) for review of the NYPSC order. On August 30, 2001, the NYPSC issued an order denying NYSEG's petition for rehearing. 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.

~~Independent~~CMP ~~System~~Electricity ~~Operators~~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.)

InMPUC ~~early~~Stranded ~~2000~~Cost the NYISO's operating reserves markets experienced problems that resulted in substantial charges to all customers required to buy operating reserves, including NYSEG. Several parties, including NYSEG, commenced FERC and court proceedings in response to these problems. In May 2000 the FERC ordered a bid cap for a portion of the operating reserves markets until the market problems are corrected and the NYISO demonstrates that all reserves markets are competitive, but did not order refunds of earlier higher operating reserves prices as sought by NYSEG. Several parties sought rehearing of FERC's order. On October 1, 2001, the United States District Court for the Northern District of New York issued a stay of NYSEG's action for a period of 12 months or until the FERC issues a decision on the parties' request for rehearing.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 ~~complaints~~a ~~and~~request ~~other~~from ~~filings~~the byIndustrial ~~NYSEG~~Energy ~~and~~Consumers ~~other~~Group ~~parties~~to ~~that~~mitigate ~~raised~~high ~~concerns~~supply ~~over energy market flaws~~prices, ~~FERC~~the ~~approved~~MPUC inordered ~~July~~CMP ~~2000~~to alower ~~bid~~stranded ~~cap~~cost onprices ~~energy~~for ofmedium ~~$1,000~~and ~~per~~large ~~megawatt-hour~~commercial inand ~~the~~industrial ~~NYISO's~~customers ~~energy~~by ~~markets~~$.003 ~~FERC~~per ~~subsequently~~kWh ~~extended~~for the ~~bid~~period ~~cap~~July ~~until~~2003 ~~the~~through ~~Northeast~~February ~~Regional~~2005. ~~Transmission~~The ~~Organization~~mitigation ~~(RTO)~~ is ~~operational~~to ~~and~~be ~~compliant~~funded ~~with~~from ~~FERC~~CMP's ~~recently~~asset ~~announced~~sale ~~market~~gain ~~design rulemaking~~account. ~~(See Regional Transmission Organization, below.) The bid cap may limit the price NYSEG pays or receives for energy it buys or sells in the NYISO energy markets.~~

InNYPSC-mandated ~~the~~Contracts ~~second quarter of 2001 the NYISO filed~~ with ~~FERC~~Two an Automated Mitigation Procedure (AMP). The AMP is designed to mitigate certain unusually high bids so that market prices are not driven by bids that appear to be influenced by the exercise of market power. FERC approved the implementation of the AMP through October 31, 2001. The NYISO filed an application with FERC to extend the AMP.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.

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

Energy East Corporation

~~Regional~~NYSEG ~~Transmission~~appealed ~~Organization~~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.

~~Non-utility~~RG&E ~~Generation~~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.

~~NYSEG~~On ~~commenced~~March an7, ~~action~~2003, in the ~~United~~NYPSC ~~States~~issued ~~District~~an ~~Court~~order ~~for~~(Order) in the ~~Northern~~proceeding ~~District~~authorizing ofa ~~New~~$16 million ~~York~~electric inrevenue ~~August~~requirement ~~1997~~reduction. The ~~complaint~~order ~~asked~~requires ~~the~~a ~~District~~$16 ~~Court~~million toincrease ~~either~~in ~~reform~~ the ~~two~~amortization ~~NUG~~of ~~contracts~~previously bydeferred ~~reducing~~costs, ~~the~~without ~~price~~increasing ~~NYSEG~~electric ~~must~~rates. ~~pay~~The ~~for~~NYPSC ~~electricity~~also ~~under~~limited the ~~contracts,~~natural orgas ~~send~~rate ~~the~~increase ~~matter back~~ to ~~the~~$6 ~~FERC~~million, or to1.9%. ~~the~~The ~~NYPSC~~rate ~~with~~decision ~~direction~~set ~~that~~the ~~they~~cost ~~modify~~of ~~such~~equity ~~contracts~~at 9.96%, ~~The~~with ~~complaint~~an ~~also~~equity ~~sought~~ratio ~~repayment~~ of ~~all~~41.4% ~~monies~~and ~~paid~~an ~~above~~overall ~~NYSEG's~~weighted ~~avoided~~cost ~~costs.~~of Oncapital ~~September~~of ~~29,~~8.11%. ~~2000,~~The ~~the~~NYPSC ~~District~~also ~~Court~~credited ~~dismissed~~to ~~NYSEG's~~customers ~~complaint~~$55 ~~and~~million ~~endorsed~~of ~~the~~electric ~~FERC~~earnings ~~decision~~that, ~~denying~~according ~~NYSEG's~~to ~~petition.~~the ~~NYSEG~~NYPSC, ~~appealed~~exceeded ~~the~~a ~~District~~preset ~~Court's~~level ~~decision~~under to the ~~United~~five-year ~~States~~rate ~~Court~~plan ofthat ~~Appeals~~expired ~~(Second~~on ~~Circuit).~~June ~~On October 5~~30, ~~2001~~2002, ~~the~~subject ~~Second~~to ~~Circuit~~a ~~affirmed~~final audit of the ~~District~~fifth ~~Court's~~year ~~decision~~amount. ~~NYSEG~~The isNYPSC ~~considering~~also ~~appealing~~ignored the ~~Second~~costs ~~Circuit's~~of ~~decision~~replacement topower ~~the~~that ~~United~~will ~~States~~be ~~Supreme~~incurred ~~Court~~during orthe ~~asking~~required ~~the~~Ginna ~~Second~~nuclear ~~Circuit~~plant ~~for~~refueling aoutage ~~rehearing~~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 ~~Energy~~Supreme ~~Taxes~~Court. A decision on the proceeding is expected early in 2004.

~~Item~~RG&E 2.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

~~Central~~On ~~Maine~~May ~~Power~~15, ~~Electricity~~2003, ~~Supply~~RG&E ~~Responsibility~~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.

OnRG&E ~~September~~2003 ~~18,~~Electric ~~2001, the MPUC named Constellation Power Source Maine, LLC as the new supplier of standard-offer electricity to CMP's residential~~ and ~~small~~Gas ~~commercial~~Rate ~~standard offer class starting in March 2002. The standard-offer rates are in effect for three years until February 1, 2005.~~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.

~~MPUC~~RG&E ~~Stranded~~Electric ~~Cost~~Rate ~~Proceeding~~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.

~~Item~~Sale 2.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

~~NYSEG~~RG&E Natural Gas ~~Rate~~Supply ~~Filings~~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.

~~NYSEG's~~NYPSC ~~natural~~Collaborative ~~gas prices have been frozen for six years. The requested increases will allow NYSEG to recover and earn a return~~ on ~~over~~End ~~$250~~State ~~million in infrastructure improvements since 1995, and ensure the continued safety and reliability~~ of ~~its~~Energy ~~natural gas delivery system. The rate plan is premised on an 11.5% return on equity and a 48% equity ratio. The new rates would become effective October 2002.~~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.

OnIn ~~October~~a ~~29,~~separate ~~2001~~phase of this proceeding, ~~NYSEG~~the ~~filed~~NYPSC aissued ~~petition~~an ~~with~~order in November 2001 directing the ~~NYPSC~~development of embedded cost of service studies for ~~the~~use ~~right~~in toimplementing ~~defer~~unbundled ~~the~~rates. ~~difference~~A ~~between~~separate ~~natural~~RD ~~gas~~on ~~costs~~the embedded incost ~~its~~of ~~residential~~service ~~gas~~studies ~~sales~~filed ~~rates~~by NYSEG and ~~actual~~Consolidated ~~gas~~Edison ~~costs~~was ~~incurred~~issued ~~for~~on ~~residential~~March ~~sales~~24, ~~customers~~2003. ~~during~~That RD discusses the ~~period~~utilities' ~~November~~cost 1,studies ~~2001,~~and ~~through~~concludes ~~September~~that ~~30,~~they ~~2002~~generally comply with the NYPSC's directives. The ~~petition~~RD isrecommended adoption of NYSEG's lost revenue recovery mechanisms contained in NYSEG's electric and natural gas joint proposals. Briefs on the ~~result~~recommended ofdecision ~~sustained~~were ~~unanticipated~~filed ~~high~~in ~~wholesale~~April ~~commodity~~2003 ~~costs~~by NYSEG and RG&E. NYSEG ~~expects~~took exception to the ~~NYPSC~~RD's totreatment ~~issue~~of certain costs. RG&E filed its ~~decision~~brief ~~later~~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 ~~year~~RD on the remaining utilities in this proceeding.

~~Connecticut~~Berkshire ~~Regulatory~~Gas ~~Proceedings~~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

~~In May 2001 the DPUC issued a decision for Connecticut Natural Gas~~Management's ~~(CNG)~~discussion ~~IRP, approving a four-year term~~ and ~~replacing~~analysis ~~the proposed sharing in returns on equity with a graduated sharing in returns on equity in excess~~ of ~~10.8%.~~financial ~~The~~condition ~~excess over 10.8% would be shared among shareholders~~ and ~~customers~~results asof follows: first 2% 75/25, next 4% 50/50 and over 6% 25/75. Performance and service measures were also adopted. After-tax merger-related natural gas cost savings are to be shared 50/50. On June 20, 2001, the OCC filed an appeal in Superior Court, arguing that the IRP approved by the DPUC for CNG was unlawful. operations

In August 2001 the appeals for SCG's and CNG's IRPs were combined.
On October 23, 2001, SCG and CNG reached a settlement agreement with the OCC which resolves numerous outstanding regulatory and legal proceedings. The settlement agreement has also been endorsed by Prosecutorial Staff of the DPUC.
The proceedings resolved by this settlement include a review of past SCG affiliate transactions, SCG's Purchased Gas Adjustment Clause (PGA) charges and credits, alleged over-earnings at SCG and CNG, and the above court appeal of the approved IRPs for SCG and CNG.
The settlement provides rate reductions of $1.5 million for SCG and $0.5 million for CNG, effective October 1, 2001. The settlement extends the approved IRPs for an additional year through September 2005 and maintains an earnings sharing mechanism that generally shares earnings above the authorized returns on equity 50/50 between shareholders and customers. In
Item 2.
Energy East Corporation

~~addition,~~a ~~the~~work ~~settlement~~stoppage ~~permits~~involving ~~the~~approximately ~~recovery~~57% of ~~SCG~~the ~~deferred~~workforce ~~gas~~is ~~costs~~in ~~through~~effect. ~~the~~The ~~PGA~~net ~~and~~additional ~~through~~cost ~~the customer portion~~ of ~~earnings~~operating ~~sharing~~Berkshire byGas while the ~~end~~work ofstoppage ~~the~~is ~~IRP~~ in ~~2005.~~effect ~~Merger-enabled~~is ~~gas~~approximately ~~costs savings for both companies are also shared 50/50 between customers and shareholders~~$200,000 ~~with~~per ~~the shareholder portion recovered through the PGA~~month.

~~The settlement was filed with the DPUC on October 25, 2001, and SCG and~~ CNG ~~expect~~Purchased toGas ~~receive~~Adjustment ~~DPUC approval of this settlement in November.~~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 customers 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.

Natural Gas Storage Facility
Other Matters
Accounting Issues
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.

InManagement's ~~August~~discussion ~~2001~~and ~~the~~analysis ~~company provided a $100 million equity contribution to NYSEG. The contribution was used by NYSEG to repay $152 million in debt in connection with the termination~~ of ~~its~~financial ~~sale~~condition ~~of accounts receivable program. The equity contribution~~ and ~~debt~~results ~~repayment~~of ~~increased NYSEG's equity ratio to 40% at September 30, 2001.~~operations

Item 2.
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 ~~August~~February ~~2001~~2003 the company ~~began~~issued ~~issuing~~229,230 shares of common stock out of its treasury stock, to certain employees through its ~~Dividend~~Restricted ~~Reinvestment~~Stock Plan, and ~~Stock~~recorded ~~Purchase~~deferred ~~Plan~~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 ~~has~~filed ~~renewed~~a ~~its~~shelf ~~revolving~~registration ~~credit~~statement ~~agreement~~ with ~~certain~~the ~~banks~~SEC ~~that~~in ~~provides~~June ~~for~~2003 ~~borrowing~~to sell up to $~~300~~1 billion ~~million~~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 ageneral ~~364-day~~corporate ~~period~~purposes, ~~which~~such as the repurchase or refinancing of securities. The company ~~expects~~currently tohas ~~continue~~$5 tomillion ~~renew~~available ~~annually~~under a previous shelf registration statement.

OnIn ~~May~~August ~~31,~~2003 ~~2001,~~CMP ~~the~~issued ~~company filed a shelf registration statement with the SEC to sell up to~~ $~~1 billion in an unspecified combination of debt and trust preferred securities~~35.7 ~~The~~million ~~company plans to use the net proceeds to fund the cash portion~~ of ~~the~~Series ~~consideration~~E ~~for~~Medium ~~the~~Term ~~pending~~Notes ~~merger~~at ~~with RGS Energy. (See Item 2 - RGS Energy Merger Agreement.) The company may also use~~ a ~~portion~~fixed ofrate ~~the proceeds for general corporate purposes, such as debt reduction, new facilities, working capital, repurchases~~ of ~~securities and to fund equity contributions to subsidiaries~~5. ~~In July 2001 a business trust subsidiary issued $345 million of 81/4~~1%, ~~Capital~~due ~~Securities~~August 2013. The proceeds ~~were used to purchase Energy East's 81/4% junior subordinated debt securities. Payments on such debt securities~~ will be used ~~by the trust~~ to ~~pay~~help ~~dividends~~repay on$50 ~~the~~million ~~Capital~~of ~~Securities.~~medium-term ~~(See~~notes ~~Item~~that 1,mature ~~Note~~in 4August ~~to the Financial Statements~~2003.)

~~CMP~~In ~~issued~~March ~~the~~2003 ~~following~~NYSEG ~~Series~~filed Ea ~~Medium~~shelf ~~Term~~registration ~~Notes~~statement ~~(MTN),~~with the ~~proceeds~~SEC ofto ~~which~~sell ~~were~~up ~~used~~ to ~~redeem~~$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.

OnIn ~~January~~April 302003 NYSEG redeemed, ~~2001~~at a premium, $2550 million of 67.6755% Series Efirst ~~MTNs~~mortgage ~~due~~bonds ~~January~~callable ~~2006~~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.

OnIn ~~June~~May ~~20,~~2003 ~~2001,~~NYSEG issued $10200 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 Efirst ~~MTNs~~mortgage ~~due~~bonds ~~June~~and ~~2011~~to redeem the $100 million of 7.45% Series first mortgage bonds.

OnNYSEG ~~July~~will 16amortize, ~~2001~~over the term of the 5 3/4% unsecured notes, a $51.4 million premium on the redemption of 6its 7/8.55% Series Efirst ~~MTNs~~mortgage ~~due~~bonds, ~~July~~a ~~2008~~$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.

OnManagement's ~~July~~discussion ~~23,~~and ~~2001,~~analysis ~~$20 million~~ of 6financial ~~3/8%~~condition ~~Series~~and Eresults ~~MTNs~~of ~~due July 2005.~~operations

On August 14, 2001, $15 million of 7% Series E MTNs due August 15, 2011.
On September 28, 2001, SCG issued $30 million of 6.59% Secured Medium-Term Notes due September 2011. The proceeds were used to repay short-term debt and for working capital purposes.
The company expects to issue $250 million of five-year notes in November 2001. The proceeds will be used to fund the $100 million equity contribution to NYSEG noted above and the RGS Energy merger.
Additional financing needed to complete the RGS merger, estimated at $400 million, is expected to be issued in the first quarter of 2002. Through financial instruments entered into in August 2001, the company has locked in the treasury rate component of that financing at an average rate of 5.05%.
Item 2.
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 Statements.)

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

Energy East Corporation
(b) Results of Operations

Three months ended September 30 (Thousands, except per share amounts)	2001	2000	Change
Operating Revenues	$798,848	$651,146	23%
Operating Income	$94,567	$101,282	(7%)
Net Income	$(21,057)	$33,349	(163%)
Average Common Shares Outstanding	116,436	112,812	3%
Earnings Per Share, basic and diluted	$(.18)	$.30	(160%)
Dividends Paid Per Share	$.23	$.22	5%

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.

Earnings per share for the quarter were 21 cents compared to 34 cents for the prior year quarter, excluding a writedown of CMP Group's investment in NEON Communications, Inc. in 2001 and the sale of XENERGY, Inc. in 2000. The decrease is primarily due to the higher costs of wholesale electricity purchases and reduced electric transmission revenues, which was partially offset by cost control efforts.

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%

Nine months ended September 30 (Thousands, except per share amounts)	2001	2000	Change
Operating Revenues	$2,918,997	$1,907,491	53%
Operating Income	$447,256	$368,725	21%
Net Income	$121,118	$183,147	(34%)
Average Common Shares Outstanding	116,737	112,995	3%
Earnings Per Share, basic and diluted	$1.04	$1.62	(36%)
Dividends Paid Per Share	$.69	$.66	5%

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.

Earnings per share for the nine months of 2001 were $1.43 compared to $1.59 for the same period in 2000, excluding a writedown of CMP Group's investment in NEON Communications, Inc. in 2001, and the sale of XENERGY, Inc. and a non-recurring benefit from the sale of the company's coal-fired generation assets in 2000. The decrease is primarily due to the higher costs of natural gas and wholesale electricity purchases and reduced electric transmission revenues. Those decreases were partially offset by earnings from the merged companies, cost control efforts and the share repurchase program. Earnings are expected to be stronger in the fourth quarter of 2001, as compared to last year, due to the realization of merger synergies and lower earnings last year for NYSEG and The Energy Network.

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%

~~Item~~Earnings 2per 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 pension income and 5 cents per share due to lower transmission revenues.

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

Energy East Corporation

Operating Results for the Electric Delivery Business

Three months ended September 30 (Thousands)	2001	2000	Change
Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	57,~~863~~141	45,~~322~~316	3634%
Operating Revenues	$~~623~~640,~~997~~035	$~~519~~504,~~866~~364	2027%
Operating Expenses	$~~517~~536,~~242~~329	$~~380~~437,~~332~~334	3623%
Operating Income	$~~106~~103,~~755~~706	$~~139~~67,~~534~~030	~~(23~~55%)

~~The~~Operating revenues were $~~104~~136 million ~~increase~~higher infor ~~operating~~the ~~revenues~~quarter isas ~~primarily~~a ~~due~~result toof the addition of ~~CMP's~~RG&E delivery revenues ~~through~~of ~~August~~$166 ~~31,~~million. ~~2001,~~That amount was partially offset by ~~lower~~reductions ~~wholesale~~of ~~deliveries~~$13 ~~and~~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.

~~Operating~~The $99 million increase in operating expenses ~~increased~~for ~~$137~~the ~~million~~quarter was primarily due to ~~the~~ addition of ~~CMP's~~RG&E ~~purchases~~operating ~~for~~expenses ~~retail~~of ~~deliveries~~$136 million and ~~its~~$6 ~~operating~~million ~~costs~~due ~~through~~to ~~August~~lower ~~31,~~noncash ~~2001,~~pension income. Those increases were partially offset by decreases in purchased power of $17 million due to customers choosing alternate suppliers and ~~higher~~$7 million because of lower purchased power ~~costs,~~prices ~~partially~~and ~~offset~~an by$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.

Nine months ended September 30 (Thousands)	2001	2000	Change
Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	1715,~~568~~231	11,~~144~~296	5835%
Operating Revenues	$1,~~904~~398,~~785~~748	$1,~~390~~135,~~501~~404	3723%
Operating Expenses	$1,~~508~~139,~~370~~237	$1905,~~040,168~~289	4526%
Operating Income	$~~396~~259,~~415~~511	$~~350~~230,~~333~~115	13%

~~The~~Operating revenues were $~~514~~263 million ~~increase~~higher infor ~~operating~~the ~~revenues~~six ismonths ~~primarily~~as ~~due~~a toresult of the addition of ~~CMP's~~RG&E delivery revenues ~~through~~of ~~August~~$343 ~~31,~~million ~~2001,~~ and higher retail deliveries of $22 million because of colder winter weather in ~~the first quarter this year~~2003. Those ~~increases~~amounts were partially offset by ~~lower~~decreases ~~wholesale~~of ~~deliveries~~$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.

~~Operating~~The $234 million increase in operating expenses ~~increased~~for ~~$468~~the ~~million~~six months was primarily due to the addition of ~~CMP's~~RG&E operating ~~costs~~expenses ~~through~~of ~~August~~$282 ~~31,~~million ~~2001~~and lower noncash pension income of $13 million. ~~That~~Those ~~increase~~amounts ~~was~~were partially offset by ~~lower~~decreases in purchased power ~~costs,~~of ~~primarily~~$17 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002 and $11 million due to ~~lower~~the ~~wholesale~~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

~~Item~~Management's 2.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 September 30 (Thousands)	2001	2000	Change
Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	2339,~~637~~026	1230,~~660~~352	8729%
Operating Revenues	$~~113~~264,~~356~~054	$90165,~~832~~087	2560%
Operating Expenses	$~~130~~244,~~870~~033	$~~113~~149,~~068~~124	1664%
Operating Loss	$(17,514)	$(22,236)	(21%)
Operating Income	$20,021	$15,963	25%

~~The~~Operating revenues were $2399 million ~~increase~~higher infor ~~operating~~the ~~revenues~~quarter is primarily due to the addition of ~~CNG's~~RG&E ~~and Berkshire Gas'~~ delivery revenues ~~through~~of ~~August~~$62 31million, ~~2001,~~and ~~partially~~increases ~~offset~~of by$34 ~~lower~~million ~~natural~~due to gas cost recovery provisions and $3 million due to an increase in prices for wholesale sales ~~and~~because ~~lower~~of ~~retail~~market ~~deliveries~~conditions.

Operating expenses increased $1895 million for the quarter primarily due to the addition of ~~CNG's~~RG&E ~~and Berkshire's~~ operating ~~costs~~expenses ~~through~~of ~~August~~$56 ~~31,~~million ~~2001,~~and ~~partially~~higher ~~offset~~natural bygas ~~lower~~costs ~~purchased~~of ~~gas~~$32 ~~costs~~million due to ~~favorable~~ market conditions and ~~cost~~after ~~control~~various ~~efforts~~rate case deferrals.

Nine months ended September 30 (Thousands)	2001	2000	Change
Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	~~105~~128,~~575~~242	6586,~~234~~459	6248%
Operating Revenues	$~~808~~904,~~179~~167	$~~407~~510,~~175~~055	9877%
Operating Expenses	$~~746~~751,~~605~~569	$~~366~~413,~~960~~402	~~103~~82%
Operating Income	$61152,~~574~~598	$4096,~~215~~653	5358%

~~The~~Operating revenues were $~~401~~394 million ~~increase~~higher infor ~~operating~~the ~~revenues~~six ismonths primarily due to the addition of ~~SCG's~~RG&E delivery revenues ~~for~~of ~~January~~$213 ~~2001~~million, and ~~CNG's~~increases ~~and~~of ~~Berkshire~~$77 ~~Gas'~~million ~~delivery~~due ~~revenues~~to ~~through August~~higher ~~31,~~retail ~~2001~~deliveries because of colder weather, ~~and~~$96 ~~the~~million due to gas cost recovery ofprovisions ~~increased~~and ~~natural~~$8 million ~~gas~~due ~~costs~~to ~~caused~~an byincrease ~~higher~~in prices for wholesale sales because of market ~~prices~~conditions.

Operating expenses increased $~~380~~338 million for the six months primarily due to the addition of ~~SCG's~~RG&E operating ~~costs~~expenses ~~for~~of ~~January~~$178 ~~2001~~million, and ~~CNG's~~higher ~~and~~natural ~~Berkshire's~~gas ~~operating~~ costs ~~through~~of ~~August~~$102 ~~31,~~million ~~2001,~~due to market conditions and anafter ~~increase~~various inrate ~~retail~~case ~~purchased~~deferrals ~~gas~~and ~~costs~~$45 ~~caused~~million bydue to higher ~~market~~retail ~~prices~~deliveries because of colder winter weather.

Item 1.
Financial Statements

Central Maine Power Company Consolidated Statements of Income - (Unaudited
Three Months Nine Months
Periods Ended Sep. 30 2001 From Acquisition 2000 Predecessor To Acquisition 2000 2001 From Acquisition 2000 Predecessor To Acquisition 2000
(Thousands)
Operating Revenues
Sales and services $200,229 $64,920 $155,121 $622,861 $64,920 $613,475
Operating Expenses
Electricity purchased and fuel used in generation 109,165 34,655 94,225 342,825 34,655 351,112
Other operating expenses 42,937 14,175 44,723 128,476 14,175 151,245
Maintenance 9,594 2,478 6,318 30,342 2,478 24,468
Depreciation and amortization 9,102 3,435 5,168 27,342 3,435 23,661
Other taxes 5,349 1,725 3,052 15,327 1,725 12,961
Total Operating Expenses 176,147 56,468 153,486 544,312 56,468 563,447
Operating Income 24,082 8,452 1,635 78,549 8,452 50,028
Other (Income) and Deductions (157) (1,239) (2,383) (2,240) (1,239) (13,035)
Interest Charges, Net 7,060 2,229 4,111 20,125 2,229 31,072
Recovery of Non- Provided Deferred Income Taxes - (274) (781) - (274) (75,421)
Income Before Income Taxes 17,179 7,736 688 60,664 7,736 107,412
Income Taxes 5,904 3,430 (965) 23,369 3,430 77,534
Net Income 11,275 4,306 1,653 37,295 4,306 29,878
Preferred Stock Dividends 361 186 372 1,082 186 1,490
Earnings Available for Common Stock $10,914 $4,120 $1,281 $36,213 $4,120 $28,388
Item 1.
Central Maine Power Company
Consolidated Balance Sheets - (Unaudited)

	Sep. 30, 2001	Dec. 31, 2000
	June 30, 2003	Dec. 31, 2002
Assets	(Thousands)
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$1229,~~453~~698	$1720,~~933~~415
Accounts receivable, net	~~123~~104,~~014~~499	~~135~~124,~~707~~711
Materials and supplies, at average cost	97,~~030~~086	97,~~052~~096
Accumulated deferred income tax benefits, net	76789	41,~~533~~902
Prepayments	23,099	9,574
Prepayments and other current assets	4,099	6,411
Other	39	38
Total Current Assets	146,171	160,535
Total Current Assets	167,711	176,837
Utility Plant, at Original Cost
Electric	1,~~301~~324,~~302~~575	1,~~392~~316,~~693~~023
Less accumulated depreciation	~~483~~515,~~050~~467	~~571~~499,~~275~~381
Net Utility Plant in Service	~~818~~809,~~252~~108	~~821~~816,~~418~~642
Construction work in progress	174,~~782~~501	162,~~682~~952
Total Utility Plant	~~836~~813,~~034~~609	~~838~~819,~~100~~594
Other Property	65,~~586~~844	65,~~526~~880
Investment in Associated Companies, at Equity	3023,~~267~~674	3327,~~952~~137
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	~~222~~179,~~670~~776	~~234~~211,~~929~~268
Unfunded future income taxes	85104,~~293~~480	80101,~~999~~791
Unamortized loss on debt reacquisitions	109,~~741~~194	129,~~057~~722
Demand-side management program costs	155,~~681~~988	208,~~563~~394
Environmental remediation costs	63,~~492~~840	84,~~217~~440
Other	135,195	118,480
Nonutility generator termination agreement	6,570	7,195
Total regulatory assets	476,072	475,245
Other	55,966	58,259
Total regulatory assets	365,814	401,069
Other assets
Goodwill, net	~~331~~325,~~700~~580	~~342~~325,~~306~~580
Prepaid pension benefits	2930,~~819~~614	3223,~~070~~124
Other	1725,~~425~~480	23,~~761~~404
Total other assets	~~378~~381,~~944~~674	~~398~~372,~~137~~108
Total Regulatory and Other Assets	~~855~~747,~~016~~488	~~873~~773,~~382~~177
Total Assets	$1,~~895~~736,~~614~~786	$1,~~928~~786,~~797~~323

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Item 1.
Central Maine Power Company
Consolidated Balance Sheets - (Unaudited)

	Sep. 30, 2001	Dec. 31, 2000
	June 30, 2003	Dec. 31, 2002
Liabilities	(Thousands)
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$62,~~221~~916	$1252,~~946~~975
Notes payable	38,000	46,500
Accounts payable and accrued liabilities	38,825	45,551
Accounts payable and accrued liabilities	58,842	77,075
Interest accrued	6,056	6,056
Interest accrued	2,410	5,084
Other	51,458	54,693
Other	42,716	57,423
Total Current Liabilities	159,255	159,275
Total Current Liabilities	204,189	199,028
Regulatory and Other Liabilities
Regulatory and Other Liabilities Regulatory liabilities
Regulatory liabilities
Deferred income taxes	43105,~~133~~162	28112,~~812~~119
Deferred income taxes, unfunded future income taxes	34,803	33,051
Gain on sale of generation assets	94,873	112,009
Gain on sale of generation assets	204,298	232,041
Other	14,135	11,926
Pension benefits	44,920	47,632
Total regulatory liabilities	214,170	236,054
Other	26,281	37,796
Total regulatory liabilities	353,435	379,332
Other liabilities
Deferred income taxes	2316,~~133~~992	204,~~065~~605
Nuclear plant obligations	~~222~~179,~~670~~776	~~234~~211,~~929~~268
Other postretirement benefits	6973,~~801~~771	6971,~~808~~236
Environmental remediation costs	32,~~846~~962	42,~~147~~987
Other	93127,~~735~~922	99127,~~710~~986
Total other liabilities	~~413~~401,~~185~~423	~~428~~418,~~659~~082
Total Regulatory and Other Liabilities	~~766~~615,~~620~~593	~~807~~654,~~991~~136
Long-term debt	~~235~~280,~~869~~407	~~222~~291,~~309~~796
Total Liabilities	1,~~206~~055,~~678~~255	1,~~229~~105,~~328~~207
Commitments	-	-
Preferred Stock Preferred stock	35,571	35,571
Capital in excess of par value	(32,~~363~~629)	(32,~~503~~723)
Common Stock Equity Common stock	~~162~~156,~~213~~057	~~162~~156,~~213~~057
Capital in excess of par value	~~498~~485,~~996~~331	~~500~~485,~~897~~297
Retained earnings	1432,~~519~~884	2331,~~291~~682
Treasury stock, at cost	(19,000)	(19,000)
Accumulated other comprehensive (loss)	(25,683)	(24,768)
Total Common Stock Equity	~~656~~648,~~728~~589	~~667~~648,~~401~~268
Total Liabilities and Stockholder's Equity	$1,~~895~~736,~~614~~786	$1,~~928~~786,~~797~~323

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

~~The~~Central ~~notes~~Maine onPower ~~pages~~Company Consolidated 33Statements ~~through 36 are an integral part~~ of ~~the~~Income ~~financial~~- ~~statements.~~(Unaudited
)

Item 1.

	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

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

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

Periods Months Ended Sep. 30	Nine Months 2001	From Acquisition 2000	Predecessor To Acquisition 2000
Six months ended June 30	2003	2002
(Thousands)	~~(Thousands)~~
Operating Activities
Net income	$3726,~~295~~923	$428,~~306~~575	~~$29,878~~
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	2732,~~342~~503	332,~~435~~801	~~23,661~~
Income taxes and investment tax credits deferred, net	194,~~596~~485	18,~~355~~717	~~(9,981)~~
Power supply costs recovered with asset sale	-	257	(8,355)
Pension (income) expense	4,510	3,035
Changes in current operating assets and liabilities
Accounts receivable	12,693	81	29,067
Accounts receivable, net	20,211	20,133
Inventory	2211	~~(78)~~300	~~405~~
Prepayments	(13,525)	(417)	(14,137)
Prepayments and other current assets	2,311	5,576
Accounts payable and accrued liabilities	(1810,~~233~~781)	(2321,~~394~~397)	~~(21,835)~~
Other current liabilities	(14,707)	(4,084)	19,700
Interest accrued	-	(803)
Changes in deferred balances and related carrying costs	(1,080)	(195)	15,170
Taxes accrued	2,101	3,525
Asset sale settlement costs	(12,000)	-	-
Other current liabilities	(5,335)	6,148
Deferred NUG costs	(13,459)	-	-
Asset sale gain amortization	(17,137)	(24,317)
Other, net	(3,194)	(5,457)	14,073
Other assets	(12,042)	(2,642)
Net Cash Provided by (Used in) Operating Activities	20,750	(24,191)	77,646
Other liabilities	1,458	(12,165)
Investing Activities
Net Cash Provided by Operating Activities	49,218	47,486
Utility plant additions	(34,362)	(2,247)	(60,671)
Investing Activities
Contributions in aid of construction, net	-	116	35,896
Utility plant additions	(12,847)	(19,928)
Other property and investments, net	(94)	3	856
Other	119	77
Net Cash Used in Investing Activities	(3412,~~456~~728)	(219,~~128~~851)	~~(23,919)~~
Financing Activities
Long-term note issuances	~~75,000~~-	3075,000	~~125,000~~
Long-term note retirements	(12,207)	(242)	(61,955)
Long-term note repayments	(1,486)	(51,478)
Notes payable, net	(8,500)	-	-
Notes payable three months or less, net	-	(30,000)
Liquidating dividends	-	(190,000)	-
Dividends on common and preferred stock	(25,721)	(31,834)
Dividends on common and preferred stock	(46,067)	-	(35,384)
Net Cash Used in Financing Activities	(27,207)	(38,312)
Net Cash Provided by (Used in) Financing Activities	8,226	(160,242)	27,661
Net Increase (Decrease) in Cash and Cash Equivalents	9,283	(10,677)
Net (Decrease) Increase in Cash and Cash Equivalents	(5,480)	(186,561)	81,388
Cash and Cash Equivalents, Beginning of Period	20,415	20,777
Cash and Cash Equivalents, Beginning of Period	17,933	194,260	112,872
Cash and Cash Equivalents, End of Period	$29,698	$10,100
Cash and Cash Equivalents, End of Period	$12,453	$7,699	$194,260
Supplemental Disclosure of Cash Flows Information
Cash paid during the period:
Interest, net of amounts capitalized	$20,277	$2,099	$10,316
Income taxes	$11,427	$50	$24,553

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Item 1.
Central Maine Power Company
Consolidated Statements of Retained Earnings - (Unaudited)

Periods Ended Sep. 30	Nine Months 2001	From Acquisition 2000	Predecessor To Acquisition 2000
Six months ended June 30	2003	2002
(Thousands)	~~(Thousands)~~
Balance, beginning of period	$23,291	-	$100,754
Balance, Beginning of Period	$31,682	$31,304
Add net income	3726,~~295~~923	$428,~~306~~575	~~29,878~~
	60,586	4,306	130,632
	58,605	59,879
Deduct dividends on capital stock
Deduct Dividends on Capital Stock
Preferred	~~1,082~~721	-721	~~1,676~~
Common	4425,~~985~~000	-31,113	~~33,708~~
Adjustment to retained earnings	-	-	95,075
	25,721	31,834
Amortization of reacquired capital stock	-	15	173
Balance, End of Period	$32,884	$28,045
	46,067	15	130,632
Balance, end of period	$14,519	$4,291	-

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Central Maine Power Company
Consolidated Statements of Comprehensive Income - (Unaudited)

	Three Months		Six Months	~~Nine Months~~
Periods Ended Sep. 30	2001	From Acquisition 2000	Predecessor To Acquisition 2000	2001	From Acquisition 2000	Predecessor To Acquisition 2000
Periods ended June 30	2003	2002	2003	2002
(Thousands)	~~(Thousands)~~
Net income	$112,~~275~~821	$45,~~306~~293	$126,~~653~~923	$3728,~~295~~575	~~$4,306~~	~~$29,878~~
Other comprehensive loss, net of tax
Other comprehensive income, net of tax
Net unrealized loss on investments	(184)	-	-	-	-	-
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 loss	(184)	-	-	-	-	-
Total other comprehensive income	(904)	-	(915)	-
Comprehensive income	$11,091	$4,306	$1,653	$37,295	$4,306	$29,878
Comprehensive Income	$1,917	$5,293	$26,008	$28,575

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

The notes on pages 33 through 36 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.

Regional Transmission Organization
Central Maine Power Electricity Supply Responsibility
MPUC Stranded Cost Proceeding
Other Matters
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.

OnManagement's ~~January~~discussion ~~30,~~and ~~2001,~~analysis ~~$25 million~~ of ~~6.67%~~financial ~~Series~~condition Eand ~~MTNs~~results ~~due~~of ~~January 2006.~~operations

On June 20, 2001, $10 million of 7% Series E MTNs due June 2011.
On July 16, 2001, $5 million of 6 7/8% Series E MTNs due July 2008.
On July 23, 2001, $20 million of 6 3/8% Series E MTNs due July 2005.
On August 14, 2001, $15 million of 7% Series E MTNs due August 15, 2011.
Item 2.
Central Maine Power Company
(b) Results of Operations

Three months ended September 30 (Thousands)	2001	2000	Change
Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	2,~~367~~110	21,~~404~~991	(26%)
Operating Revenues	$~~200~~135,~~229~~259	$~~220~~139,~~041~~208	(93%)
Operating Expenses	$~~176~~124,~~147~~223	$~~209~~129,~~954~~160	(164%)
Operating Income	$2411,~~082~~036	$10,~~087~~048	~~139~~10%
Earnings Available for Common Stock	$102,~~914~~460	$54,~~401~~932	~~102~~(50%)

Earnings for the quarter ~~increased~~decreased ~~about~~ $62 million ~~primarily~~as ~~due~~a toresult ~~cost~~of ~~control~~a ~~efforts,~~$3 ~~partially~~million ~~offset~~increase ~~by a decrease~~ in ~~other~~ income. taxes.

~~Operating~~The ~~revenues~~$4 ~~for~~million ~~the~~decrease ~~quarter~~in ~~decreased~~operating ~~about~~revenues ~~$20~~is ~~million~~ primarily ~~because~~the ~~CMP~~result noof ~~longer~~an ~~supplies~~approximately ~~electricity~~$1 million ~~unless~~decrease itin isaccrued ~~directed~~demand-side bymanagement ~~the~~(DSM) ~~MPUC~~revenues due to belower ~~the~~costs ~~standard~~and ~~offer~~a ~~provider.~~$2 million ~~CMP~~reduction isin ~~currently~~an ~~the~~electric ~~standard~~conservation ~~offer~~assessment ~~provider~~ for ~~commercial~~a ~~and~~low ~~industrial~~income ~~rate classes~~program.

~~Operating~~The ~~expenses decreased~~ $345 million decrease in operating expenses is primarily ~~due~~the toresult ~~decreased~~of ~~purchased~~a ~~power~~$1 ~~expenses,~~million ~~because~~decrease ~~CMP~~in noother ~~longer~~operating ~~supplies~~expenses ~~electricity~~due to ~~certain~~lower ~~customers,~~DSM costs and as a ~~result~~$2 ofmillion ~~cost~~decrease ~~control~~in ~~efforts.~~other taxes.

Item 2.

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%)

~~Central~~Earnings ~~Maine~~for ~~Power~~the ~~Company~~ six months decreased $2 million as a result of a $3 million increase in income taxes.

Nine months ended September 30 (Thousands)	2001	2000	Change
Retail Deliveries - Megawatt-hours	7,006	7,072	(1%)
Operating Revenues	$622,861	$678,395	(8%)
Operating Expenses	$544,312	$619,915	(12%)
Operating Income	$78,549	$58,480	34%
Earnings Available for Common Stock	$36,213	$32,508	11%

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.

~~Earnings~~The ~~for the nine months increased~~ $429 million ~~primarily due to cost control efforts. A~~ decrease in ~~other~~operating ~~income~~expenses ~~was~~is ~~offset~~the byresult ~~a decrease in interest charges. The deregulation~~ of ~~Maine's~~CMP ~~electric~~no ~~industry~~longer ~~affected~~being ~~operating~~the ~~revenues~~standard-offer ~~and~~provider ~~expenses~~ for the ~~period~~supply asof ~~discussed~~electricity ~~below.~~effective ~~CMP~~March no2002, ~~longer~~which ~~supplies~~reduced ~~electricity~~operating ~~unless~~expenses it$17 ismillion, ~~directed~~a bydecrease ~~the~~in ~~MPUC~~wholesale tononutility begenerator ~~the~~purchases ~~standard~~of ~~offer~~$8 million, ~~provider.~~lower ~~CMP~~amortization isof ~~currently~~ice ~~the~~storm ~~standard~~expense ~~offer~~of ~~provider~~$2 ~~for~~million ~~commercial~~ and ~~industrial~~reduced ~~rate classes~~DSM expenses of $2 million.

The $56 million decrease in operating revenues is primarily because CMP no longer supplies electricity to certain retail customers, and a rate reduction that began March 1, 2000. Those decreases were partially offset by higher transmission revenues and asset sale gain amortization.
Operating expenses decreased $76 million primarily due to decreased purchased power expenses, because CMP no longer supplies electricity to certain customers, and as a result of cost control efforts.
Item 1.
Financial Statements

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

	~~Three Months~~	Three Months	~~Nine Months~~		Six Months
Periods Ended September 30	2001	2000	2001	2000
Periods ended June 30		2003		2002	2003	2002
(Thousands)	~~(Thousands)~~
Operating Revenues
Electric	~~$423,676~~	$~~457~~338,~~149~~353	~~$1,281,658~~	$1365,~~327,785~~098	$744,320	$795,472
Natural gas	36,318	41,457	259,337	241,828
Natural Gas		75,011		60,347	244,775	187,227
Total Operating Revenues	~~459,994~~	~~498~~413,~~606~~364	~~1,540,995~~	1425,~~569,613~~445	989,095	982,699
Operating Expenses
Electricity purchased and fuel used in generation	223,243	215,308	618,559	638,291
Electricity purchased		179,603		205,534	398,114	413,251
Natural gas purchased	~~23,226~~	3143,~~462~~569	~~185,742~~	~~140~~32,~~997~~759	150,626	109,675
Other operating expenses	~~59,858~~	7152,~~582~~685	~~176,654~~	~~188~~55,~~786~~411	100,499	108,121
Maintenance	~~21,560~~	1617,~~287~~034	~~62,433~~	6118,~~977~~070	38,430	39,019
Depreciation and amortization	~~25,251~~	2725,~~292~~063	~~76,380~~	8224,~~029~~560	49,995	48,992
Other taxes	~~32,702~~	1725,~~544~~291	~~98,605~~	8727,~~643~~592	60,664	59,190
Total Operating Expenses	~~385,840~~	~~379~~343,~~475~~245	~~1,218,373~~	1363,~~199,723~~926	798,328	778,248
Operating Income	~~74,154~~	~~119~~70,~~131~~119	~~322,622~~	~~369~~61,~~890~~519	190,767	204,451
Interest Charges, Net	25,356	26,660	79,121	76,835
Other (Income)		(184)		(1,778)	(2,108)	(2,566)
Other (Income) and Deductions	(6,408)	1,701	(4,942)	1,954
Other Deductions		(1,553)		16,438	(1,297)	17,251
Income Before Income Taxes	55,206	90,770	248,443	291,101
Interest Charges, Net		21,022		23,350	40,360	48,524
Income Taxes	23,099	48,394	103,520	110,569
Income Before Income Taxes		50,834		23,509	153,812	141,242
Net Income	32,107	42,376	144,923	180,532
Income Taxes		20,911		10,364	63,272	58,476
Preferred Stock Dividends	99	99	297	297
Net Income		29,923		13,145	90,540	82,766
Earnings Available for Common Stock	$32,008	$42,277	$144,626	$180,235
Preferred Stock Dividends		99		99	198	198
Earnings Available for Common Stock		$29,824		$13,046	$90,342	$82,568

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

Item 1.
New York State Electric & Gas Corporation
Balance Sheets - (Unaudited)

	Sep. 30, 2001	Dec. 31, 2000
	June 30, 2003		Dec. 31, 2002
Assets	(Thousands)
(Thousands)
Current Assets
Assets
Cash and cash equivalents	$12,974	$17,618
Current Assets
Special deposits	1,424	21,440
Cash and cash equivalents	$36,208		$11,490
Accounts receivable, net	273,082	200,846
Special deposits	132,973		44,205
Fuel, at average cost	39,649	28,677
Accounts receivable, net	262,782		260,189
Materials and supplies, at average cost	7,033	7,395
Fuel, at average cost	24,354		29,000
Prepayments	36,842	27,893
Materials and supplies, at average cost	6,222		5,573
Accumulated deferred income tax benefits, net	34,~~986~~372	~~3,943~~	4,232
Total Current Assets	374,990	307,812
Prepayments	19,851		26,571
Utility Plant, at Original Cost
Total Current Assets	486,762		381,260
Electric	3,403,732	3,391,619
Utility Plant, at Original Cost
Natural gas	646,868	635,563
Electric	2,569,767		2,551,775
Common	132,935	140,020
Natural gas	674,928		671,321
	4,183,535	4,167,202
Common	119,479		121,661
Less accumulated depreciation	2,163,952	2,116,787
	3,364,174		3,344,757
Net Utility Plant in Service	2,019,583	2,050,415
Less accumulated depreciation	1,406,094		1,371,892
Construction work in progress	21,634	25,006
Net Utility Plant in Service	1,958,080		1,972,865
Total Utility Plant	2,041,217	2,075,421
Construction work in progress	41,884		40,166
Other Property and Investments, Net	80,657	76,737
Total Utility Plant	1,999,964		2,013,031
Regulatory and Other Assets
Other Property and Investments, Net	41,983		41,365
Regulatory assets
Regulatory and Other Assets
Unfunded future income taxes	45,062	44,610
Regulatory assets
Unamortized loss on debt reacquisitions	43,917	46,791
Unfunded future income taxes	21,703		20,467
Demand-side management program costs	10,154	28,366
Unamortized loss on debt reacquisitions	36,993		35,631
Environmental remediation costs	5275,~~900~~334	~~58,200~~	52,434
Other	3052,~~296~~005	~~30,386~~	23,563
Total regulatory assets	~~182~~186,~~329~~035	~~208,353~~	132,095
Other assets
Prepaid pension benefits	313,909	250,826
Goodwill, net	11,199		11,199
Goodwill, net	11,295	11,582
Prepaid pension benefits	423,179		395,586
Other	1993,~~072~~657	~~22,254~~	78,890
Total other assets	~~344~~528,~~276~~035	~~284,662~~	485,675
Total Regulatory and Other Assets	~~526~~714,~~605~~070	~~493,015~~	617,770
Total Assets	$3,~~023~~242,~~469~~779	~~$2,952,985~~	$3,053,426

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Item 1.
New York State Electric & Gas Corporation
Balance Sheets - (Unaudited)

	Sep. 30, 2001	Dec. 31, 2000
	June 30, 2003		Dec. 31, 2002
Liabilities	(Thousands)
(Thousands)
Current Liabilities
Liabilities
Current portion of long-term debt	$292	$1,088
Current Liabilities
Notes payable	23,000	123,000
Current portion of long-term debt	$77,414		$702
Accounts payable and accrued liabilities	101,531	160,654
Notes payable	69,000		64,000
Interest accrued	27,074	15,925
Accounts payable and accrued liabilities	148,811		169,884
Taxes accrued	33,040	9,006
Interest accrued	9,624		12,289
Other	66,583	71,510
Taxes accrued	31,215		11,091
Total Current Liabilities	251,520	381,183
Other	51,348		58,577
Regulatory and Other Liabilities Regulatory liabilities
Total Current Liabilities	387,412		316,543
Deferred income taxes	38,626	50,306
Regulatory and Other Liabilities
Deferred income taxes, unfunded future income taxes	18,848	18,848
Regulatory liabilities
Other	26,906	16,975
Deferred income taxes	44,461		26,199
Total regulatory liabilities	84,380	86,129
Gain on sale of generation assets	41,004		40,638
Other liabilities
Other	25,550		25,036
Deferred income taxes	304,513	287,560
Total regulatory liabilities	111,015		91,873
Other postretirement benefits	190,641	183,666
Other liabilities
Environmental remediation costs	76,500	77,500
Deferred income taxes	362,824		347,355
Derivative liabilities	11,602	-
Other postretirement benefits	201,591		197,193
Other	96,180	100,148
Environmental remediation costs	98,000		75,100
Total other liabilities	679,436	648,874
Other	57,680		56,683
Total Regulatory and Other Liabilities	763,816	735,003
Total other liabilities	720,095		676,331
Long-term debt	1,189,889	1,189,249
Total Regulatory and Other Liabilities	831,110		768,204
Total Liabilities	2,205,225	2,305,435
Long-term debt	1,065,829		1,017,902
Commitments	-	-
Total Liabilities	2,284,351		2,102,649
Preferred Stock Preferred stock redeemable solely at NYSEG's option	10,159	10,159
Commitments	-		-
Common Stock Equity Common stock	430,057	430,057
Preferred Stock Redeemable solely at NYSEG's option	10,159		10,159
Capital in excess of par value	270,835	170,678
Common Stock Equity Common stock	430,057		430,057
Retained earnings	114,413	35,329
Capital in excess of par value	277,430		277,297
Accumulated other comprehensive income (loss)	(7,220)	1,327
Retained earnings	206,861		206,519
Total Common Stock Equity	808,085	637,391
Accumulated other comprehensive income	33,921		26,745
Total Liabilities and Stockholder's Equity	$3,023,469	$2,952,985
Total Common Stock Equity	948,269		940,618
Total Liabilities and Stockholder's Equity	$3,242,779		$3,053,426

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Item 1.
New York State Electric & Gas Corporation
Statements of Cash Flows - (Unaudited
)

Nine Months Ended September 30	2001	2000
Six months ended June 30	2003	2002
Operating Activities	(Thousands)
(Thousands)
Net income	$144,923	$180,532
Operating Activities
Net income	$90,540	$82,766
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	7663,~~380~~400	8264,~~029~~854
Income taxes and investment tax credits deferred, net	928,~~562~~202	(39,~~366)~~723
Pension income	(5322,~~992~~009)	(4835,~~739~~160)
Changes in current operating assets and liabilities
Accounts receivable	79,764	33,838
Accounts receivable, net	(2,593)	60,959
Sale of accounts receivable program	(152,000)	-
Inventory	3,997	15,736
Loan receivable, affiliated company	-	17,789
Prepayments	6,720	6,229
Inventory	(10,610)	(18,873)
Accounts payable and accrued liabilities	(21,073)	(9,627)
Prepayments	(8,949)	5,347
Interest accrued	(2,665)	(2,246)
Accounts payable and accrued liabilities	(59,123)	(26,655)
Taxes accrued	20,124	36,630
Interest accrued	11,149	10,693
Other current liabilities	(7,229)	(20,552)
Taxes accrued	24,034	(4,579)
Other assets	(46,442)	12,936
Other current liabilities	(4,927)	10,936
Other liabilities	(3,882)	(34)
Other, net	30,956	9,540
Net Cash Provided by Operating Activities	107,090	222,214
Net Cash Provided by Operating Activities	87,167	248,492
Investing Activities
Utility plant additions	(5238,~~009~~836)	(5836,~~595~~361)
Other property and investments	4,009	597
Sale of generation assets	-	59,442
Other	22,028	3,398
Proceeds from sale of utility plant	211	6,334
Net Cash Used in Investing Activities	(25,972)	(54,600)
Special deposits	(81,128)	(5,014)
Other	(17)	(977)
Net Cash (Used in) Provided by Investing Activities	(119,770)	23,424
Financing Activities
Equity infusion	100,000	-
Notes payable, three months or less	5,000	-
Notes payable, net	(100,000)	(112,240)
Repayments of first mortgage bonds, including net premiums	(74,390)	(177,025)
Dividends on common and preferred stock	(65,839)	(168,622)
Long-term note issuances	196,986	-
Net Cash Used in Financing Activities	(65,839)	(280,862)
Dividends on common and preferred stock	(90,198)	(60,198)
Net Decrease in Cash and Cash Equivalents	(4,644)	(86,970)
Net Cash Provided by (Used in) Financing Activities	37,398	(237,223)
Cash and Cash Equivalents, Beginning of Period	17,618	114,494
Net Increase in Cash and Cash Equivalents	24,718	8,415
Cash and Cash Equivalents, End of Period	12,974	$27,524
Cash and Cash Equivalents, Beginning of Period	11,490	21,617
Supplemental Disclosure of Cash Flows Information
Cash and Cash Equivalents, End of Period	$36,208	$30,032
Cash paid during the period: Interest, net of amounts capitalized Income taxes	$64,313 $64,112	$62,102 $107,468

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

The notes on pages 33 through 36 are an integral part of the financial statements.
Item 1.
New York State Electric & Gas Corporation
Statements of Retained Earnings - (Unaudited)

Nine Months Ended September 30	2001	2000
Six months ended June 30	2003	2002
(Thousands)	~~(Thousands)~~
Balance, Beginning of Period	$35206,~~329~~519	$26164,~~731~~197
Add net income	~~144~~90,~~923~~540	~~180~~82,~~532~~766
	180,252	207,263
	297,059	246,963
Deduct Dividends on Capital Stock
Preferred	~~297~~198	~~297~~198
Common	6590,~~542~~000	~~168~~60,~~325~~000
	65,839	168,622
	90,198	60,198
Balance, End of Period	$~~114~~206,~~413~~861	$38186,~~641~~765

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

The notes on pages 33 through 36 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Statements of Comprehensive Income - (Unaudited)

	Three Months		~~Nine~~Six Months
Periods Ended September 30	2001	2000	2001	2000
Periods ended June 30	2003	2002	2003	2002
(Thousands)	~~(Thousands)~~
Net income	$3229,~~107~~923	$4213,~~376~~145	$~~144~~90,~~923~~540	$~~180~~82,~~532~~766
Other comprehensive income (loss), net of tax
Other comprehensive income, net of tax
Net unrealized gain (loss) on investments	(27)	390	57	1,284
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)
Minimum pension liability adjustment	-	721	50	(630)
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
Unrealized gains (losses) on derivatives qualified as hedges
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
Unrealized gains on derivatives qualified as hedges arising during the period due to cumulative effect of a change in accounting principle	-	-	54,602	-
Net unrealized (losses) gains on derivatives qualified as hedges	(7,732)	(10,716)	6,926	11,448
Unrealized losses on derivatives qualified as hedges	(3,255)	-	(64,975)	-
Total other comprehensive (loss) income	(7,472)	(10,980)	7,176	10,910
Reclassification adjustment for losses included in net income	14,119	-	1,719	-
Comprehensive Income	$22,451	$2,165	$97,716	$93,676
Net unrealized gains (losses) on derivatives qualified as hedges	10,864	-	(8,654)	-
Total other comprehensive income (loss)	10,837	1,111	(8,547)	654
Comprehensive income	$42,944	$43,487	$136,376	$181,186

The notes 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.

NYSEG Electric Rate Agreement
Retail Access Credit
Independent System Operators
Regional Transmission Organization
Non-utility Generation
New York State Energy Taxes
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.

Other Matters
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.

~~Item~~Management's 2.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 September 30 (Thousands)	2001	2000	Change
Three months ended June 30 (Thousands)	2003	2002	Change
Operating Revenues	$~~459~~413,~~994~~364	$~~498~~425,~~606~~445	(83%)
Operating Income	$7470,~~154~~119	$~~119~~61,~~131~~519	~~(38~~14%)
Earnings Available for Common Stock	$3229,~~008~~824	$4213,~~277~~046	~~(24~~129%)

Earnings for the ~~third~~ quarter ~~decreased~~were $1017 million higher than for the prior year quarter primarily due to ~~higher~~the ~~costs~~effect of ~~electricity~~a ~~purchases~~$10 ~~and~~million loss from the early retirement of debt in 2002, $8 million for lower ~~electric~~purchased ~~transmission~~power ~~revenues~~costs and customers choosing alternate suppliers and $6 million for integration savings and cost control efforts. Those ~~decreases~~increases were partially offset by ~~cost~~reductions ~~control~~to ~~efforts~~earnings of $6 million for lower transmission revenues and ~~favorable~~$3 ~~natural~~million ~~gas~~for ~~purchase~~lower ~~prices~~noncash pension income.

Nine months ended September 30 (Thousands)	2001	2000	Change
Six months ended June 30 (Thousands)	2003	2002	Change
Operating Revenues	$1989,~~540,995~~095	$1982,~~569,613~~699	(21%)
Operating Income	$~~322~~190,~~622~~767	$~~369~~204,~~890~~451	(137%)
Earnings Available for Common Stock	$~~144~~90,~~626~~342	$~~180~~82,~~235~~568	~~(20~~9%)

Earnings increased $8 million for the ~~nine~~six months ~~decreased~~primarily due to increases of $2818 million, ~~excluding~~due ato ~~non-recurring~~higher ~~benefit~~electric inand ~~2000~~natural ~~from~~gas ~~the~~retail ~~sale~~deliveries because of ancolder ~~affiliate's~~winter ~~coal-fired~~weather, ~~generation~~$9 ~~assets.~~million ~~The~~for ~~decrease~~integration issavings ~~primarily~~and ~~due~~cost tocontrol ~~higher~~efforts, ~~prices~~$10 ofmillion ~~natural~~due ~~gas~~to ~~purchased~~the ~~and~~effect ~~lower~~of ~~electric~~a ~~transmission~~loss ~~revenues.~~from ~~Those~~the ~~decreases~~early ~~were~~retirement ~~partially~~of ~~offset~~debt byin ~~higher~~2002, ~~retail~~$4 ~~electricity~~million ~~deliveries~~for ~~because~~the recovery of ~~colder~~natural ~~winter~~gas ~~weather,~~prices ~~and~~through ~~cost~~the ~~control~~gas ~~efforts.~~

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 September 30 (Thousands)	2001	2000	Change
Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Megawatt-hours	3,~~496~~362	3,~~558~~325	(21%)
Operating Revenues	$~~423~~338,~~676~~353	$~~457~~365,~~149~~098	(7%)
Operating Expenses	$~~341~~276,~~001~~011	$~~323~~308,~~831~~109	5(10%)
Operating Income	$8262,~~675~~342	$~~133~~56,~~318~~989	~~(38~~9%)

The $3327 million decrease in operating revenues for the quarter is primarily due to ~~lower~~reductions ~~wholesale~~of ~~deliveries~~$13 ~~and~~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 ~~increased~~decreased $1732 million for the quarter ~~due~~as toa ~~higher~~result of decreases in purchased power ~~costs.~~of ~~That~~$17 ~~increase~~million ~~was~~due ~~partially~~to ~~offset~~customers bychoosing alternate suppliers and $7 million because of lower purchased power ~~volume~~prices, ~~caused~~and bya ~~lower~~decrease ~~wholesale~~of ~~deliveries,~~$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.

Item 2.

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
Nine months ended September 30 (Thousands) 2001 2000 Change
Retail Deliveries - Megawatt-hours 10,563 10,380 2%
Operating Revenues $1,281,658 $1,327,785 (3%)
Operating Expenses $963,785 $983,666 (2%)
Operating Income $317,873 $344,119 (8%)
The $46 million decrease in operating revenues is primarily due to lower wholesale deliveries and lower transmission revenues. Those decreases were partially offset by higher retail deliveries because of colder winter weather earlier this year.
Operating expenses decreased $20 million due to lower purchased power costs primarily due to lower wholesale deliveries, and cost control efforts.
Operating Results for the Natural Gas Delivery Business

Three months ended September 30 (Thousands)	2001	2000	Change
Three months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	611,~~939~~301	710,~~229~~944	(43%)
Operating Revenues	$3675,~~318~~011	$4160,~~457~~347	~~(12~~24%)
Operating Expenses	$4467,~~839~~234	$55,~~644~~817	~~(19~~20%)
Operating Loss	$(8,521)	$(14,187)	(40%)
Operating Income	$7,777	$4,530	72%

The $515 million ~~decrease~~increase in operating revenues for the quarter is primarily due to ~~lower~~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 ~~decreased~~increased $11 million for the quarter primarily due to ~~lower~~a ~~purchased~~$9 ~~natural~~million ~~gas~~increase ~~costs~~in ~~because~~the cost of ~~favorable~~natural ~~market~~gas, ~~conditions~~after ~~and~~various ~~cost~~deferrals ~~control~~of ~~efforts~~gas costs for future recovery.

Nine months ended September 30 (Thousands)	2001	2000	Change
Six months ended June 30 (Thousands)	2003	2002	Change
Retail Deliveries - Dekatherms	4037,~~676~~809	4232,~~030~~783	(315%)
Operating Revenues	$~~259~~244,~~337~~775	$~~241~~187,~~828~~227	731%
Operating Expenses	$~~254~~197,~~588~~575	$~~216~~157,~~057~~915	1825%
Operating Income	$447,~~749~~200	$2529,~~771~~312	~~(82~~61%)

~~The~~Operating revenues increased $1858 million ~~increase~~for inthe ~~operating~~six ~~revenues~~months is primarily due to ~~the~~higher ~~recovery~~retail deliveries of ~~increased~~$32 ~~natural~~million because of colder winter weather, gas ~~costs~~cost ~~for~~recovery ~~non-residential~~of ~~deliveries~~$23 inmillion ~~the~~resulting ~~first~~from ~~quarter~~a ~~this~~natural ~~year,~~gas ~~partially~~supply ~~offset~~charge byand ~~lower~~$8 million due to an increase in prices for wholesale sales ~~and~~because ~~retail~~of ~~deliveries.~~market conditions.

Operating expenses for the six months increased $3940 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 ~~price~~cost of natural gas., ~~That~~after ~~increase~~various ~~was~~deferrals ~~partially~~of ~~offset~~gas bycosts ~~cost~~for ~~control~~future ~~efforts~~recovery.

Item 1.
Financial Statements

~~Notes~~Rochester toGas ~~Financial~~and ~~Statements for Energy~~Electric ~~East~~ Corporation ~~Central~~Balance ~~Maine~~Sheets ~~Power~~- ~~Company New York State Electric & Gas Corporation~~ (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

The notes 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

The notes 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

The notes 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

The notes 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

The notes 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.

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 ~~which are~~ 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, ~~2000~~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. ~~Acquisitions of Connecticut Energy, CMP Group, CTG Resources and Berkshire Energy~~Restructuring

~~Due~~ In tothe ~~completion~~fourth quarter of 2002 the company's ~~merger~~recorded ~~with~~$41 ~~CNE~~million onof ~~February~~restructuring 8expenses, ~~2000~~including $5 million for CMP, $26 million for NYSEG and ~~its~~a ~~mergers~~total ~~with~~of ~~CMP~~$10 ~~Group,~~million ~~CTG~~for ~~Resources~~Berkshire Gas, CNG and ~~Berkshire~~SCG. ~~Energy~~During on2003 ~~September~~the 1,related ~~2000~~involuntary severance liability decreased $9 million. The restructuring expenses would have been $36 million higher, ~~the~~however ~~company's~~RG&E ~~consolidated~~was ~~financial~~required ~~statements~~by ~~include~~an ~~CNE~~NYPSC order approving RGS Energy's ~~results~~merger ~~beginning~~ with ~~February~~the ~~2000~~company ~~and~~to ~~include~~defer ~~CMP~~its ~~Group~~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, ~~CTG~~2002 ~~Resources~~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 ~~Berkshire~~$3 ~~Energy~~million for an involuntary severance program, primarily for salaried employees of the company's ~~results~~six ~~beginning~~operating ~~with~~utilities, ~~September~~and ~~2000.~~$1 million for other associated costs.

~~Amounts~~The ~~presented~~voluntary inearly ~~the~~retirement ~~consolidated~~resulted ~~financial~~in ~~statements~~a ~~for~~decline ~~CMP~~of ~~for~~486 employees in the ~~periods~~first ~~from~~quarter ~~July~~of 12003, ~~2000~~including 34 from CMP, to210 from NYSEG and 176 from RG&E. Collectively the ~~date~~voluntary ofearly ~~acquisition~~retirement and ~~January~~involuntary 1,severance ~~2000,~~programs are expected to ~~the~~result ~~date~~in ofa ~~acquisition,~~decline ~~reflect~~in ~~the~~overall ~~historical~~employee ~~predecessor~~headcount ~~amounts~~of ~~reported~~approximately 650, or 8%, by ~~CMP~~the ~~prior~~end toof ~~its~~2003. ~~acquisition~~That byincludes ~~Energy~~approximately ~~East.~~70 ~~Amounts~~from ~~reported~~CMP, ~~for~~260 ~~the~~from ~~three~~NYSEG, ~~months~~250 ~~and~~from ~~nine~~RG&E ~~months~~and ~~ended~~70 ~~September~~from ~~30,~~Berkshire ~~2001~~Gas, ~~include~~CNG ~~the~~and ~~amortization~~SCG. ofThe ~~goodwill~~employees ~~related~~affected toby the ~~acquisition~~involuntary ofseverance ~~CMP~~program bywere ~~Energy~~notified ~~East~~in January 2003.

~~The~~Note ~~four merger transactions were accounted for using the purchase method~~3. InOther each transaction the purchase price was allocated to the assets acquired and liabilities assumed based on values on the date of purchase. The cost in excess of the fair value of the net assets acquired in each transaction was recorded as goodwill and will be amortized on a straight-line basis over the estimated useful life. (~~See Energy East Corporation's Item 2(a~~Income), ~~Other Matters - Accounting Issues.) The useful life is determined based on the individual characteristics of each acquired company~~ and ~~the~~Other ~~lives range from four to 40 years. Goodwill has been adjusted over the 12 months following the mergers as actual amounts for estimated liabilities became known.~~Deductions

The following pro forma information for the company for the three months and nine months ended September 30, 2000, which is based on unaudited data, gives effect to the company's four mergers as if they had been completed January 1, 2000. This information does not reflect future revenues or cost savings that may result from the mergers and is not indicative of actual results of operations had the mergers occurred at the beginning of the period presented or of results that may occur in the future.

	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

Periods Ended September 30, 2000 (Thousands, except per share amounts) Three Months Nine Months
Revenues $853,143 $2,853,967
Net income $19,535 $205,204
Earnings per share of common stock $.16 $1.69
Note 4. Basic and Diluted Earnings Per Share

~~Pro~~Basic ~~forma~~earnings ~~adjustments~~per ~~reflected~~share in(EPS) ~~the~~is ~~amounts~~determined ~~presented~~by ~~above~~dividing ~~include:~~net ~~(1)~~income ~~additional~~by ~~depreciation~~the ~~and~~weighted-average ~~amortization~~number ~~related~~of toshares ~~adjusting~~of ~~the~~common ~~four~~stock ~~merged~~outstanding ~~companies'~~during ~~non~~the period. The weighted-~~utility~~average ~~assets~~common toshares ~~fair~~outstanding ~~value~~for ~~based~~diluted onEPS aninclude ~~independent~~restricted ~~appraisal,~~stock ~~(2)~~awards ~~amortization~~and the incremental effect of ~~goodwill,~~stock ~~(3)~~options ~~elimination~~issued ofand ~~merger~~exclude ~~costs,~~stock options issued in tandem with stock appreciation rights (4SARs). ~~lower~~However, ~~investment~~all ~~income~~stock ~~due~~options toare ~~the~~issued ~~sale~~in oftandem ~~temporary~~with ~~investments~~SARs toand, ~~complete~~historically, ~~the~~substantially ~~mergers~~all ~~(5)~~stock ~~interest~~option ~~expense~~plan ~~due~~participants tohave exercised the ~~issuance~~SARs instead of ~~merger-related~~the ~~debt~~stock options. The numerator used in calculating basic and ~~(6) adjustments~~diluted EPS for ~~estimated~~each ~~tax~~period ~~effects~~is of the ~~above~~reported ~~adjustments~~net income. The reconciliation of basic and diluted EPS for each period follows:

Note 3. Fair Value of Financial Instruments

	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

~~The~~On ~~company~~February ~~has~~13, ~~been~~2003, ~~evaluating~~ the ~~carrying~~company ~~value~~issued 229,230 shares of ~~CMP~~its ~~Group's~~common ~~$90~~stock ~~million~~to ~~investment~~certain inemployees ~~NEON~~under ~~Communications,~~its ~~Inc.~~Restricted ~~because~~Stock ~~there~~Plan ~~has~~and ~~been~~recorded adeferred ~~significant~~compensation ~~decline~~of in$4.4 million based on the market ~~value~~price of ~~NEON~~$19.20 per share of common ~~shares~~stock ~~over~~on the ~~past~~date ~~twelve~~of ~~months~~the award. ~~That~~An ~~decline~~aggregate isnumber ~~consistent~~of ~~with~~two ~~the~~million ~~market~~shares ~~performance~~may ofbe ~~telecommunications~~granted ~~businesses~~under asthe aRestricted ~~whole.~~Stock ~~During~~Plan, ~~the~~subject ~~third~~to ~~quarter~~adjustment. Shares of ~~2001,~~restricted ~~the~~stock ~~company~~are ~~determined~~awarded ~~that~~in the ~~decline~~name inof ~~NEON's~~the ~~market~~employee, ~~value~~who ~~was~~has ~~other~~all ~~than~~the ~~temporary~~rights ~~and~~of ~~wrote~~a ~~down~~shareholder, ~~the~~subject ~~cost~~to ~~basis~~certain ofrestrictions ~~the~~on ~~investment~~transferability inand ~~NEON~~a ~~Communications~~risk toof ~~$12 million~~forfeiture. The ~~write-down,~~shares ~~which~~vest ~~totaled~~based ~~$46~~on ~~million~~the ~~after~~conditions ~~taxes,~~outlined orin 39the ~~cents~~restricted ~~per~~stock ~~share~~award grants, isincluding ~~reflected~~the inachievement ~~the~~of ~~company's~~targeted ~~earnings~~shareholder ~~for~~returns, ~~the~~but ~~third~~no ~~quarter~~later ofthan ~~2001~~January 1, 2009.

~~Note~~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 ~~Trust~~million ~~Preferred~~in ~~Securities~~ 2002.

InNote ~~July 2001 Energy East Capital Trust I, a Delaware business trust subsidiary of the company, issued $345 million of company-obligated mandatorily redeemable 81/4% Capital Securities~~5. ~~The~~Accounts trust is a 100% owned finance subsidiary of the company. The assets of the trust consist solely of the company's 81/4% junior subordinated debt securities maturing on July 31, 2031. The company has fully and unconditionally guaranteed the trust's payment obligations with respect to the Capital Securities. Receivable

~~Note~~Accounts 5.receivable ~~Segment~~for ~~Information~~ 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.

~~Energy~~Note ~~East's~~6. ~~electric delivery business consists of its regulated transmission, distribution and generation operations in~~ New ~~York~~Accounting and Maine; and its natural gas delivery business consists of its regulated transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts. Other includes: the company's corporate assets, interest costs and operating expenses; intersegment eliminations; and non-utility businesses. Pronouncements
~~CMP's~~Statement ~~electric delivery business consists of its transmission and distribution operations. CMP operates in the State of Maine. Other includes CMP's corporate assets.~~ 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.

~~NYSEG~~The companies's ~~electric~~adoption ~~delivery~~of ~~business~~Statement ~~consists~~143 as of ~~its~~January ~~transmission~~1, ~~distribution~~2003, ~~and~~did ~~generation~~not ~~operations;~~have ~~and~~a ~~its~~material ~~natural~~effect ~~gas~~on ~~segment~~their ~~consists~~respective offinancial ~~its~~position ~~transportation,~~or ~~storage~~results ~~and~~of ~~distribution~~ operations. ~~NYSEG~~There ~~operates~~was no effect on net income. The companies recognized various amounts on their balance sheets. Changes in the ~~State~~assumptions ofunderlying ~~New~~the ~~York.~~items ~~Other~~shown ~~includes~~in ~~NYSEG's~~the ~~corporate~~following ~~assets~~table could affect the balance sheet amounts and future costs related to the obligations.

Selected financial information for Energy East's, CMP's and NYSEG's business segments is presented in the following table.

	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

	Electric Delivery	Natural Gas Delivery	Other	Total
		(Thousands)
Three Months Ended
Sep. 30, 2001
Operating Revenues Energy East CMP NYSEG	$623,997 $200,229 $423,676	$113,356 - $36,318	$61,495 - -	$798,848 $200,229 $459,994
Net Income (Loss) Energy East CMP NYSEG	$45,381 $11,275 $39,213	$(18,005) - $(7,106)	$(48,433) - -	$(21,057) $11,275 $32,107
Sep. 30, 2000
Operating Revenues Energy East CMP (From acquisition) CMP (Predecessor) NYSEG	$519,866 $64,920 $155,121 $457,149	$90,832 - - $41,457	$40,448 - - -	$651,146 $64,920 $155,121 $498,606
Net Income (Loss) Energy East CMP (From acquisition) CMP (Predecessor) NYSEG	$60,021 $4,306 $1,653 $55,804	$(19,725) - - $(13,428)	$(6,947) - - -	$33,349 $4,306 $1,653 $42,376
Nine Months Ended
Sep. 30, 2001
Operating Revenues Energy East CMP NYSEG	$1,904,785 $622,861 $1,281,658	$808,179 - $259,337	$206,033 - -	$2,918,997 $622,861 1,540,995
Net Income (Loss) Energy East CMP NYSEG	$168,720 $37,295 $148,920	$8,292 - $(3,997)	$(55,894) - -	$121,118 $37,295 $144,923
Sep. 30, 2000
Operating Revenues Energy East CMP (From acquisition) CMP (Predecessor) NYSEG	$1,390,501 $64,920 $613,475 $1,327,785	$407,175 - - $241,828	$109,815 - - -	$1,907,491 $64,920 $613,475 $1,569,613
Net Income (Loss) Energy East CMP (From acquisition) CMP (Predecessor) NYSEG	$179,092 $4,306 $29,878 $175,039	$6,010 - - $5,493	$(1,955) - - -	$183,147 $4,306 $29,878 $180,532

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.

Electric Delivery Natural Gas Delivery Other Total
(Thousands)
Total Assets
Sep. 30, 2001 Energy East CMP NYSEG $4,210,317 $1,886,380 $2,181,132 $2,455,506 - $676,035 $444,509 $9,234 $166,302 $7,110,332 $1,895,614 $3,023,469
December 31, 2000 Energy East CMP NYSEG $4,212,623 $1,919,630 $2,116,933 $2,406,848 - $639,684 $394,257 $9,167 $196,368 $7,013,728 $1,928,797 $2,952,985
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 beginning 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 67. ~~Reclassifications~~ Acquisition of RGS Energy Group

~~Certain~~Due ~~amounts~~to ~~have~~the ~~been~~completion ~~reclassified~~of the company's merger with RGS Energy Group, Inc. on June 28, 2002, the ~~unaudited~~company's consolidated financial statements toinclude ~~conform~~RGS Energy's results beginning with ~~the~~July ~~2001~~2002. ~~presentation~~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 ~~rising~~changing energy prices; the operation of the New York Independent System Operator ~~(NYISO)~~ and ISO New England, Inc.; the operation of a regional transmission organization; the ability to ~~control~~recover ~~non-utility~~nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements now that ~~all~~most ~~of the company's coal-fired~~ generation assets have been sold; the company's ability to expand its products and services, including its energy infrastructure in the Northeast; the company's ability to integrate the operations of ~~CNE~~Berkshire Energy Resources, CMP Group, ~~CTG~~Connecticut ~~Resources~~Energy Corporation, ~~Berkshire~~CTG ~~Energy~~Resources and RGS Energy; ~~with~~the ~~its~~company's ~~operations~~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.)

Interest Rate Risk

In July 2001 the company entered into a fixed-to-floating interest rate swap on an 8.05% bond due November 2010. The company will receive a semi-annual fixed rate of 8.05% and will pay a rate based on the six month London Interbank Offered Rate plus 1.875%, on a notional amount of $200 million through November 2010.

Based on current interest rates, the company believes that the market risk for the above arrangements is not material.

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.

~~NYSEG~~RG&E ~~has~~faces ~~hedged~~commodity ~~approximately~~price ~~93%~~risk ofthat ~~its~~relates ~~expected~~to ~~residential~~market ~~natural~~fluctuations ~~gas~~in ~~load~~the ~~through~~price ~~April~~of ~~2002~~electricity ~~with~~and natural gas. inOwned ~~storage,~~electric ~~futures~~generation and ~~option~~long-term supply contracts. ~~For~~significantly reduce RG&E's exposure to market fluctuations for procurement of its ~~remaining~~electric ~~unhedged~~supply. ~~positions~~As ~~through~~of ~~April~~August ~~2002~~1, a2003, 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 ~~dekatherm~~megawatt-hour ~~change~~ in the ~~cost~~price of ~~natural~~on-peak ~~gas~~electricity ~~changes~~would ~~natural~~change ~~gas~~earnings ~~costs~~ by ~~about~~ $10.61 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 ~~uses~~and ~~electricity~~RG&E ~~contracts~~use ~~and~~natural ~~contracts~~gas ~~for~~futures ~~differences~~and ~~(CFDs)~~forwards to manage ~~against~~ fluctuations in ~~the~~natural ~~cost~~gas ofcommodity ~~electricity.~~prices ~~Those~~and ~~contracts~~provide ~~allow~~price ~~NYSEG~~stability to ~~fix margins on the majority of its retail electricity sales~~customers. The cost or benefit of ~~those~~natural ~~contracts~~gas futures and forwards is included in the ~~amount~~commodity ~~expensed~~cost ~~for electricity purchased~~ when the ~~electricity~~related issales ~~sold.~~commitments ~~NYSEG~~are ~~has CFDs, generation and other electricity contracts, which provide for 97% of its expected electric energy requirements for the remainder of 2001, 93% for 2002 and 67% for 2003~~fulfilled.

~~NYSEG~~Item ~~is also exposed to price fluctuations in the price of electricity~~4. In situations where the electricity contracts do not cover requirements, NYSEG must buy electricity in the market. Conversely, when NYSEG has contracts for more electricity than its requirements, it must sell the excess in the market. NYSEG uses a cash flow at risk (CFAR) calculation to measure price risk for electricity. At October 31, 2001, the CFAR for electricity requirements was approximately $9 million for the next 12-month period. The CFAR indicates the amount by which the fair value of NYSEG's net position could vary from its current level over a 12-month period, with a 97.5% certainty, assuming all unhedged positions during that period are filled in the market.
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 - See Exhibit Index.

(ab) ~~Exhibits~~The following reports on Form 8-K ~~See~~were ~~Exhibit~~filed ~~Index.~~during the quarter:

~~(b) Reports~~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."

NoRG&E ~~reports~~filed ona Form 8-K ~~were~~dated ~~filed~~April ~~during~~29, ~~the~~2003, ~~quarter~~to report certain information under Item 5, "Other Events."

Signatures

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

ENERGY EAST CORPORATION (Registrant) Date: November 5, 2001 By /s/Robert E. Rude Robert E. Rude Vice President and Controller (Chief Accounting Officer)

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)

CENTRAL MAINE POWER COMPANY (Registrant) Date: November 5, 2001 By /s/Curtis I. Call Curtis I. Call Treasurer (Chief Accounting Officer)

NEW YORK STATE ELECTRIC & GAS CORPORATION (Registrant) Date: November 5, 2001 By /s/Sherwood J. Rafferty Sherwood J. Rafferty Senior Vice President and Chief Financial Officer (Principal Financial Officer)

EXHIBIT INDEX

The following exhibits are delivered with this report:

Registrant	Exhibit No.	Description of Exhibit
Energy East Corporation	4(A)10-424	~~Subordinated~~Employment ~~Indenture~~Agreement ~~between~~dated ~~the~~as ~~Company~~of April 30, 2003, by and ~~The~~among ~~Chase~~Connecticut ~~Manhattan~~Natural ~~Bank~~Gas Corporation, asEnergy ~~Trustee~~East Management Corporation, ~~dated~~Energy asEast ofCorporation ~~July~~and ~~24,~~Michael ~~2001~~I. German.
Energy East Corporation	4-5	First Supplemental Indenture between the Company and The Chase Manhattan Bank, as Trustee, dated as of July 24, 2001, related to the Subordinated Indenture between the Company and The Chase Manhattan Bank, as Trustee, dated as of July 24, 2001.
	(A)10-25	Director's Charitable Giving Program.
Energy East Corporation	(A) 10-31	First Amendment dated as of August 1, 2001, to Employment Agreement dated as May 19, 2000, for W. W. von Schack.
	(A)10-26	Amended and Restated 2000 Stock Option Plan, effective June 13, 2003.
Energy East Corporation	(A) 10-32	First Amendment dated as of August 1, 2001, to Employment Agreement dated as May 19, 2000, for K. M. Jasinski.
	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002 of Energy East Corporation.
Energy East Corporation	(A) 10-33	Supplemental Executive Retirement Plan.
	32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002 of Energy East Corporation.
Energy East Corporation	(A) 10-34	Energy East Management Corporation Supplemental Executive Retirement Plan.
Central Maine Power Company	31	Certifications under Section 302 of the Sarbanes-Oxley Act of 2002 of Central Maine Power Company.
New York State Electric & Gas Corporation	(A) 10-31	Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001.
	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.

_________________________________ ~~(A) Management contract or compensatory plan or arrangement.~~

(A) Management contract or compensatory plan or arrangement.

	Three Months				Nine Months
Periods Ended Sep. 30	2001	From Acquisition 2000	Predecessor To Acquisition 2000	2001		From Acquisition 2000	Predecessor To Acquisition 2000
	(Thousands)
Operating Revenues
Sales and services	$200,229	$64,920	$155,121	$622,861		$64,920	$613,475
Operating Expenses
Electricity purchased and fuel used in generation	109,165	34,655	94,225	342,825		34,655	351,112
Other operating expenses	42,937	14,175	44,723	128,476		14,175	151,245
Maintenance	9,594	2,478	6,318	30,342		2,478	24,468
Depreciation and amortization	9,102	3,435	5,168	27,342		3,435	23,661
Other taxes	5,349	1,725	3,052	15,327		1,725	12,961
Total Operating Expenses	176,147	56,468	153,486	544,312		56,468	563,447
Operating Income	24,082	8,452	1,635	78,549		8,452	50,028
Other (Income) and Deductions	(157)	(1,239)	(2,383)	(2,240)		(1,239)	(13,035)
Interest Charges, Net	7,060	2,229	4,111	20,125		2,229	31,072
Recovery of Non- Provided Deferred Income Taxes	-	(274)	(781)	-		(274)	(75,421)
Income Before Income Taxes	17,179	7,736	688	60,664		7,736	107,412
Income Taxes	5,904	3,430	(965)	23,369		3,430	77,534
Net Income	11,275	4,306	1,653	37,295		4,306	29,878
Preferred Stock Dividends	361	186	372	1,082		186	1,490
Earnings Available for Common Stock	$10,914	$4,120	$1,281	$36,213		$4,120	$28,388

Filing Compare · CENTRAL MAINE POWER CO