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, 2002~~ 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, 2004

[  ]  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~~5224 ~~Ithaca~~Binghamton, New York ~~14852~~13902-~~3287~~5224 (607) ~~347~~762-~~4131~~7200	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 ~~2002,~~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	Par value $.01 per share	144,741,409
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)

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, 2004, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	146,706,572
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, 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 14
	Energy East Corporation Condensed Consolidated Statements of Income Condensed Consolidated Balance Sheets Condensed Consolidated Statements of Cash Flows Condensed Consolidated Statements of Retained Earnings Condensed 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 16
	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 Condensed Consolidated Statements of Income Condensed Consolidated Balance Sheets Condensed Consolidated Statements of Cash Flows Condensed Consolidated Statements of Retained Earnings Condensed Consolidated Statements of Comprehensive Income Management's Discussion and Analysis of Financial Condition and Results of Operations (a) Liquidity and Capital Resources (b) Results of Operations	19 20 22 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 32
	New York State Electric & Gas Corporation Condensed Statements of Income Condensed Balance Sheets Condensed Statements of Cash Flows Condensed Statements of Retained Earnings Condensed 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
	Rochester Gas and Electric Corporation Statements of Income Balance Sheets 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	35 36 38 39 40 41
	Rochester Gas and Electric Corporation Condensed Statements of Income Condensed Balance Sheets Condensed Statements of Cash Flows Condensed 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	33 34 36 36 37 38
	Notes to Financial Statements Forward-looking Statements	44 54

Item	TABLE OF CONTENTS - continued	Page
3	Quantitative and Qualitative Disclosures About Market Risk	54
1	Notes to Condensed Financial Statements Forward-looking Statements	41 52
4	Controls and Procedures	56
3	Quantitative and Qualitative Disclosures About Market Risk	53
4	Controls and Procedures	54
	PART II - OTHER INFORMATION
6	Exhibits and Reports on Form 8-K (a) Exhibits (b) Reports on Form 8-K	56 56
2	Changes in Securities, Use and Proceeds and Issuer Purchases of Equity Securities	54
Signatures		57
4	Submission of Matters to a Vote of Security Holders	56
Certifications		58
6	Exhibits and Reports on Form 8-K (a) Exhibits (b) Reports on Form 8-K	57
Signatures		58
Exhibit Index		59

PART I - FINANCIAL INFORMATION
Item 1.
Financial Statements

Energy East Corporation Consolidated Statements of Income - (Unaudited

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

Periods ended June 30	2004	2003	2004	2003

(Thousands, except per share amounts)
Operating Revenues
Sales and services	$980,566	$979,113	$2,561,639	$2,483,944
Operating Expenses
Electricity purchased and fuel used in generation	338,253	300,967	734,906	659,334
Natural gas purchased	169,700	178,414	669,549	629,465
Other operating expenses	158,065	199,916	372,072	394,539
Maintenance	42,814	43,309	85,476	89,556
Depreciation and amortization	84,799	73,774	169,934	149,107
Other taxes	58,248	58,382	133,670	143,649
Gain on sale of generation assets	(319,487)	-	(319,487)	-
Deferral of asset sale gain	214,368	-	214,368	-

Total Operating Expenses	746,760	854,762	2,060,488	2,065,650

Operating Income	233,806	124,351	501,151	418,294
Other (Income)	(11,681)	(2,278)	(17,409)	(6,810)
Other Deductions	4,398	1,261	7,675	3,048
Interest Charges, Net	68,822	68,090	138,812	135,825
Preferred Stock Dividends of Subsidiaries	1,791	8,739	2,779	17,157

Income From Continuing Operations Before Income Taxes	170,476	48,539	369,294	269,074
Income Taxes	127,694	20,206	205,803	109,050

Income From Continuing Operations	42,782	28,333	163,491	160,024

Discontinued Operations
(Loss) income from discontinued operations	(4,249)	(901)	(4,527)	5,058
Income taxes (benefits)	467	(285)	346	1,901

(Loss) Income From Discontinued Operations	(4,716)	(616)	(4,873)	3,157

Net Income	$38,066	$27,717	$158,618	$163,181

Earnings Per Share From Continuing Operations, basic	$.29	$.19	$1.12	$1.10

Earnings Per Share From Continuing Operations, diluted	$.29	$.19	$1.11	$1.10

Earnings Per Share From Discontinued Operations, basic	$(.03)	-	$(.03)	$.02

Earnings Per Share From Discontinued Operations, diluted	$(.03)	-	$(.03)	.02

Total Earnings Per Share, basic	$.26	$.19	$1.09	$1.12

Total Earnings Per Share, diluted	$.26	$.19	$1.08	$1.12

Dividends Paid Per Share	$.26	$.25	$.52	$.50

Average Common Shares Outstanding, basic	146,148	145,415	146,116	145,256

Average Common Shares Outstanding, diluted	146,596	145,640	146,512	145,429

The notes on pages 41 through 52 are an integral part of the financial statements.

	Three Months		Nine Months
Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
Periods Ended September 30	2002	2001	2002	2001
	June 30, 2004	Dec. 31, 2003
(Thousands, except per share amounts)
(Thousands)
Operating Revenues
Assets
Sales and services	$1,016,189	$798,848	$2,759,641	$2,918,997
Current Assets
Operating Expenses
Cash and cash equivalents	$461,059	$113,187
Electricity purchased and fuel used in generation	370,413	359,677	961,144	1,051,774
Special deposits	7,273	34,669
Natural gas purchased	81,207	74,100	378,880	588,259
Accounts receivable, net	600,846	753,328
Gasoline, propane and oil purchased	68,098	-	68,098	-
Fuel, at average cost	124,803	159,163
Other operating expenses	198,661	139,552	480,564	425,341
Materials and supplies, at average cost	24,321	22,491
Maintenance	43,123	34,260	109,044	102,714
Accumulated deferred income tax benefits, net	38,289	26,262
Depreciation and amortization	76,693	50,967	170,506	153,480
Prepayments and other current assets	69,366	81,746
Other taxes	64,494	45,725	157,560	150,173
Total Current Assets	1,325,957	1,190,846
Total Operating Expenses	902,689	704,281	2,325,796	2,471,741
Utility Plant, at Original Cost
Operating Income	113,500	94,567	433,845	447,256
Electric	5,209,400	5,992,001
Writedown of Investment	-	78,422	12,209	78,422
Natural gas	2,453,826	2,405,795
Other (Income)	(9,671)	(9,971)	(22,802)	(25,221)
Common	408,831	361,737
Other Deductions	4,631	5,124	25,800	11,279
	8,072,057	8,759,533
Interest Charges, Net	72,942	52,498	180,582	164,771
Less accumulated depreciation	2,523,200	3,216,927
Preferred Stock Dividends of Subsidiaries	8,292	5,835	23,554	6,790
Net Utility Plant in Service	5,548,857	5,542,606
Income (Loss) Before Income Taxes	37,306	(37,341)	214,502	211,215
Construction work in progress	69,042	235,503
Income Taxes (Benefits)	13,564	(16,284)	79,868	90,097
Total Utility Plant	5,617,899	5,778,109
Net Income (Loss)	$23,742	$(21,057)	$134,634	$121,118
Other Property and Investments, Net	190,382	465,609
Earnings (Loss) Per Share, basic and diluted	$.16	$(.18)	$1.06	$1.04
Regulatory and Other Assets
Dividends Paid Per Share	$.24	$.23	$.72	$.69
Regulatory Assets
Average Common Shares Outstanding	144,621	116,436	126,489	116,737
Nuclear plant obligations	379,367	414,432
Unfunded future income taxes	114,542	254,977
Unamortized loss on debt reacquisitions	48,595	47,509
Environmental remediation costs	122,662	122,846
Nonutility generator termination agreements	101,395	106,631
Asset retirement obligation	-	163,530
Other	397,594	407,432
Total regulatory assets	1,164,155	1,517,357
Other Assets
Goodwill, net	1,527,169	1,533,123
Prepaid pension benefits	637,170	608,933
Other	205,296	212,455
Total other assets	2,369,635	2,354,511
Total Regulatory and Other Assets	3,533,790	3,871,868
Total Assets	$10,668,028	$11,306,432

The notes on pages 41 through 52 are an integral part of the financial statements.

Energy East Corporation Consolidated Balance Sheets - (Unaudited)

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003

(Thousands)
Liabilities
Current Liabilities
Current portion of preferred stock of subsidiary subject to mandatory redemption requirements	-	$1,250
Current portion of long-term debt	$24,711	30,989
Notes payable	31,201	308,406
Accounts payable and accrued liabilities	390,469	339,812
Interest accrued	47,395	48,989
Taxes accrued	118,666	43,710
Other	136,869	191,873

Total Current Liabilities	749,311	965,029

Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	735,879	731,621
Deferred income taxes	14,858	181,211
Gain on sale of generation assets	238,887	129,640
Pension benefits	31,728	51,970
Other	123,878	96,509

Total regulatory liabilities	1,145,230	1,190,951

Other liabilities
Deferred income taxes	947,843	853,489
Nuclear plant obligations	265,022	277,643
Other postretirement benefits	424,817	408,903
Asset retirement obligation	3,049	437,076
Environmental remediation costs	147,897	145,446
Other	365,769	346,630

Total other liabilities	2,154,397	2,469,187

Total Regulatory and Other Liabilities	3,299,627	3,660,138

Debt owed to subsidiary holding solely parent debentures	355,670	355,670
Preferred stock of subsidiary subject to mandatory redemption requirements	-	23,750
Other long-term debt	3,552,011	3,638,426

Total long-term debt	3,907,681	4,017,846

Total Liabilities	7,956,619	8,643,013

Commitments	-	-
Preferred Stock of Subsidiaries Redeemable solely at the option of subsidiaries	46,624	91,095
Common Stock Equity Common stock	1,467	1,463
Capital in excess of par value	1,464,528	1,458,802
Retained earnings	1,209,131	1,126,457
Accumulated other comprehensive income (loss)	(2,931)	(11,214)
Deferred compensation	(6,765)	(2,820)
Treasury stock, at cost	(645)	(364)

Total Common Stock Equity	2,664,785	2,572,324

Total Liabilities and Stockholders' Equity	$10,668,028	$11,306,432

	Sept. 30, 2002	Dec. 31, 2001
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$278,356	$437,014
Special deposits	14,511	1,555
Accounts receivable, net	564,616	564,671
Notes receivable	380	12,126
Fuel, at average cost	129,439	92,234
Materials and supplies, at average cost	28,843	21,466
Accumulated deferred income tax benefits, net	6,202	4,170
Prepayments and other current assets	117,215	41,600
Total Current Assets	1,139,562	1,174,836
Utility Plant, at Original Cost
Electric	5,760,380	3,874,972
Natural gas	2,318,559	1,771,636
Common	360,360	213,362
	8,439,299	5,859,970
Less accumulated depreciation	3,827,070	2,270,516
Net Utility Plant in Service	4,612,229	3,589,454
Construction work in progress	195,240	36,978
Total Utility Plant	4,807,469	3,626,432
Other Property and Investments, Net	445,732	216,556
Regulatory and Other Assets
Regulatory assets
Nuclear plant costs	504,758	199,797
Unfunded future income taxes	229,190	164,657
Unamortized loss on debt reacquisitions	42,126	53,965
Demand-side management program costs	9,596	18,137
Environmental remediation costs	89,917	85,835
Nonutility generator termination agreements	170,560	9,480
Other	288,984	239,258
Total regulatory assets	1,335,131	771,129
Other assets
Goodwill, net	1,519,571	897,807
Prepaid pension benefits	581,920	435,901
Other	213,515	146,571
Total other assets	2,315,006	1,480,279
Total Regulatory and Other Assets	3,650,137	2,251,408
Total Assets	$10,042,900	$7,269,232

The

notes on pages 41 through 52 are an integral part of the financial statements.

Energy East Corporation Consolidated Balance Sheets - (Unaudited)

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Six months ended June 30	2004	2003

(Thousands)
Net Cash Provided by Operating Activities	$405,808	$377,971

Investing Activities
Proceeds from sale of generation assets	428,541	-
Refund of excess decommissioning fund	76,593	-
Utility plant additions	(123,554)	(112,955)
Other property and investments additions	(2,045)	(13,631)
Other property and investments sold	7,957	5,054
Special deposits	27,396	(81,134)
Other	(3,501)	(2,377)

Net Cash Provided (Used) in Investing Activities	411,387	(205,043)

Financing Activities
Issuance of common stock	1,252	2,466
Repurchase of common stock	(6,071)	-
Outstanding customer refund, overdraft	57,388	-
Repayments of first mortgage bonds and preferred stock of subsidiaries, including net premiums	(162,053)	(115,270)
Long-term note issuances	12,000	196,986
Long-term note repayments	(12,778)	(6,140)
Notes payable three months or less, net	(279,203)	(128,700)
Notes payable issuances	3,000	-
Notes payable repayments	(16,000)	(91,435)
Dividends on common stock	(66,858)	(63,803)

Net Cash Used in Financing Activities	(469,323)	(205,896)

Net Increase (Decrease) in Cash and Cash Equivalents	347,872	(32,968)
Cash and Cash Equivalents, Beginning of Period	113,187	250,490

Cash and Cash Equivalents, End of Period	$461,059	$217,522

The notes on pages 41 through 52 are an integral part of the financial statements.

	Sept. 30, 2002	Dec. 31, 2001
Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Six months ended June 30	2004	2003
(Thousands)
Liabilities
Balance, Beginning of Period	$1,126,457	$1,061,428
Current Liabilities
Add net income	158,618	163,181
Current portion of long-term debt	$324,196	$225,678
Deduct dividends on common stock	75,944	72,566
Notes payable	178,950	173,383
Balance, End of Period	$1,209,131	$1,152,043
Accounts payable and accrued liabilities	289,950	224,150
Interest accrued	76,969	36,183
Taxes accrued	49,779	7,020
Other	208,109	142,926
Total Current Liabilities	1,127,953	809,340
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes	185,207	157,196
Gain on sale of generation assets	150,020	251,254
Pension benefits	111,728	52,642
Other	100,169	68,879
Total regulatory liabilities	547,124	529,971
Other liabilities
Deferred income taxes	757,776	461,600
Nuclear plant obligations	287,921	199,797
Other postretirement benefits	389,103	282,791
Environmental remediation costs	117,695	102,930
Other	286,393	241,975
Total other liabilities	1,838,888	1,289,093
Total Regulatory and Other Liabilities	2,386,012	1,819,064
Long-term debt	3,596,756	2,471,278
Total Liabilities	7,110,721	5,099,682
Commitments	-	-
Preferred Stock of Subsidiaries Company-obligated mandatorily redeemable trust preferred securities of subsidiary holding solely parent debentures Redeemable solely at the option of subsidiaries Subject to mandatory redemption requirements	345,000 90,509 25,000	345,000 43,373 -
Common Stock Equity Common stock	1,456	1,182
Capital in excess of par value	1,450,057	842,989
Retained earnings	1,042,200	998,281
Accumulated other comprehensive income (loss)	802	(22,335)
Treasury stock, at cost	(22,845)	(38,940)
Total Common Stock Equity	2,471,670	1,781,177
Total Liabilities and Stockholders' Equity	$10,042,900	$7,269,232

The notes on pages 41 through 52 are an integral part of the financial statements.

Energy East Corporation Consolidated Statements of Cash Flows - (Unaudited

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

Periods ended June 30	2004	2003	2004	2003

(Thousands)
Net income	$38,066	$27,717	$158,618	$163,181
Other comprehensive income, net of tax
Net unrealized gains (losses) on investments, net of income tax (expense) for the three months of $- in 2004 and $(391) in 2003 and for the six months of $- in 2004 and $(642) in 2003	(947)	578	(927)	964
Unrealized gains (losses) on derivatives qualified as hedges, net of income tax benefit (expense) for the three months of $(4,712) in 2004 and $4,737 in 2003 and for the six months of $(17,229) in 2004 and $(14,016) in 2003	7,104	(7,012)	25,811	21,808
Reclassification adjustment for derivative (gains) included in net income, net of income tax expense for the three months of $5,710 in 2004 and $2,544 in 2003 and for the six months of $11,010 in 2004 and $11,574 in 2003	(8,609)	(3,836)	(16,601)	(17,454)

Net unrealized (losses) gains on derivatives qualified as hedges	(1,505)	(10,848)	9,210	4,354

Total other comprehensive income (loss)	(2,452)	(10,270)	8,283	5,318

Comprehensive Income	$35,614	$17,447	$166,901	$168,499

The notes on pages 41 through 52 are an integral part of the financial statements.

Nine Months Ended September 30 2002 2001
(Thousands)
Operating Activities
Net income $134,634 $121,118
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization 205,644 198,444
Income taxes and investment tax credits deferred, net 30,453 (10,342)
Pension income (52,385) (56,326)
Writedown of investment 12,209 78,422
Changes in current operating assets and liabilities
Accounts receivable, net 145,495 148,740
Sale of accounts receivable program - (152,000)
Inventory (10,629) (36,422)
Prepayments and other current assets (24,974) (865)
Accounts payable and accrued liabilities (23,792) (105,671)
Interest accrued 29,541 18,615
Taxes accrued 16,415 16,921
Other current liabilities 7,141 (46,526)
Other assets (16,260) (28,847)
Other liabilities (23,917) (32,039)
Net Cash Provided by Operating Activities 429,575 113,222
Investing Activities
Acquisition, net of cash acquired (681,397) -
Utility plant additions (144,765) (142,076)
Note receivable, sale of generation assets 59,442 -
Other property and investments additions (20,759) (34,088)
Other property and investments sold 7,477 15,456
Special deposits (5,058) 19,916
Other 5,430 1,064
Net Cash Used in Investing Activities (779,630) (139,728)
Financing Activities
Issuance of common stock 12,866 3,547
Repurchase of common stock (1,749) (24,116)
Issuance of mandatorily redeemable trust preferred securities - 345,000
Repayments of first mortgage bonds and preferred stock of subsidiaries, including net premiums (178,349) (1,446)
Long-term note issuances 502,500 107,879
Long-term note repayments (68,660) (14,863)
Notes payable three months or less, net 38,102 (212,712)
Notes payable issuances 13,009 -
Notes payable repayments (35,607) (1,100)
Dividends on common stock (90,715) (80,540)
Net Cash Provided by Financing Activities 191,397 121,649
Net (Decrease) Increase in Cash and Cash Equivalents (158,658) 95,143
Cash and Cash Equivalents, Beginning of Period 437,014 143,626
Cash and Cash Equivalents, End of Period $278,356 $238,769
Energy East Corporation Consolidated Statements of Retained Earnings - (Unaudited)
Nine Months Ended September 30 2002 2001
(Thousands)
Balance, Beginning of Period $998,281 $918,016
Add net income 134,634 121,118
Deduct dividends on common stock 90,715 80,540
Balance, End of Period $1,042,200 $958,594
Energy East Corporation Consolidated Statements of Comprehensive Income - (Unaudited)
Three Months Nine Months
Periods Ended September 30 2002 2001 2002 2001
(Thousands)
Net income (loss) $23,742 $(21,057) $134,634 $121,118
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment - - - 86
Net unrealized loss on investments (1,438) (12,208) (10,010) (11,000)
Reclassification adjustment for losses included in net income - 45,748 7,122 45,748
Minimum pension liability adjustment - - - 50
Unrealized gains (losses) on derivatives qualified as hedges
Unrealized gains on derivatives qualified as hedges arising during the period due to cumulative effect of a change in accounting principle - - - 58,250
Unrealized gains (losses) on derivatives qualified as hedges 9,755 (13,138) 13,081 (80,736)
Reclassification adjustment for losses on derivatives qualified as hedges included in net income 1,875 14,436 12,944 1,924
Net unrealized gains (losses) on derivatives qualified as hedges 11,630 1,298 26,025 (20,562)
Total other comprehensive income 10,192 34,838 23,137 14,322
Comprehensive Income $33,934 $13,781 $157,771 $135,440
Item 2.
Management's discussion and analysis of financial condition
and results of operations

Energy East Corporation
~~(a) Liquidity and Capital Resources~~ Overview

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

AsIn aaddition, ~~result~~because ofEnergy ~~the~~East's ~~merger~~primary ~~RGS~~operations ~~Energy~~- ~~became~~its aelectric ~~wholly~~and natural gas utility operations -~~owned~~ ~~subsidiary~~are ofsubject ~~Energy~~to ~~East~~rate regulation, the approved regulatory treatment on various matters could significantly affect the company's operations and, therefore, its financial position and results of operations. In May 2004 Rochester Gas and Electric Corporation (RG&E), ~~continues~~an tooperating becompany of Energy East, received approval for long-term electric and natural gas rate plans. As a ~~wholly~~result, Energy East now has long-~~owned~~term ~~subsidiary~~rate plans for all of ~~RGS~~its ~~Energy~~major ~~and~~utility operating companies including New York State Electric & Gas Corporation (NYSEG), ~~became~~Central aMaine ~~wholly-owned~~Power ~~subsidiary~~Company (CMP), Connecticut Natural Gas Corporation (CNG), The Southern Connecticut Gas Company (SCG) and The Berkshire Gas Company (Berkshire Gas). The plans provide for sharing of ~~RGS~~achieved ~~Energy~~savings among customers and shareholders, allow for recovery of certain costs including exogenous and uncontrollable costs, and provide stable rates for customers and revenue predictability for those six operating companies.

~~Restructuring~~Over ~~Initiative~~the last several years Energy East has focused its strategic efforts on its electric and natural gas delivery operations, rather than on the more volatile electricity generation business, and has sought to rationalize its nonutility businesses to ensure they fit its strategic focus. As discussed below, RG&E successfully completed the sale of its Ginna nuclear generating station (Ginna) to Constellation Generation Group LLC (CGG) on June 10, 2004. In addition, on July 26, 2004, CMP Group, Inc. sold the majority of the assets of its subsidiary, Union Water Power Company (UWP).

InThe ~~addition~~continuing toevolution of the ~~voluntary~~utility ~~early retirement program~~industry, anparticularly ~~involuntary severance program will be utilized by~~ the ~~operating~~electric ~~companies~~utility ~~after~~industry, ~~they~~has ~~determine~~resulted ~~the~~in ~~additional~~several ~~positions~~federal ~~that must be eliminated to achieve optimum organizational efficiency~~ and ~~effectiveness.~~state ~~The~~regulatory ~~employees~~proceedings ~~affected~~that bycould ~~the~~significantly ~~involuntary~~affect ~~program~~operations, ~~will~~although ~~be notified in~~ the ~~first~~outcomes ~~quarter~~ of ~~2003.~~those ~~Energy~~proceedings ~~East~~are ~~expects~~difficult to ~~incur~~predict. aThose ~~one-time~~proceedings ~~restructuring~~could ~~charge~~have ofan ~~between~~effect ~~$50-$100~~on ~~million in~~ the ~~fourth~~nature ~~quarter~~ of ~~2002, including $5-$10 million for CMP, $20-$35 million for NYSEG, $25-$45 million for RG&E and~~ the ~~remainder~~electric ~~for Berkshire Gas, CNG~~ and ~~SCG.~~natural ~~All~~gas orutility aindustry ~~portion~~in ofNew ~~NYSEG's~~York and ~~RG&E's~~New ~~restructuring~~England. ~~costs~~Recent ~~may~~events ~~be deferred~~ in ~~accordance with~~ the ~~NYPSC~~proceedings ~~order~~are ~~approving~~described ~~the RGS Energy merger~~below.

The company engages in various investing and financing activities to meet its strategic objectives. Investing activities are conducted primarily to maintain a reliable energy delivery infrastructure and are funded primarily with internally generated funds. Financing activities, therefore, are focused on maintaining adequate liquidity, improving credit quality and minimizing the cost of capital. As a result of the Ginna sale, the company will have funds available to reduce its outstanding debt as well as that of RG&E.

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

Energy East Corporation

(a) Liquidity and Capital Resources
Restructuring

In the first quarter of 2004 the company completed its consolidation of various accounting and finance functions. Energy East recognized a $4 million total liability for an enhanced severance program for 83 accounting and finance employees who were employed through March 31, 2004. The company recorded approximately $2 million of that liability as of the end of the fourth quarter of 2003 and recorded the remaining $2 million of the liability in the first quarter of 2004. The liability was entirely paid off as of June 30, 2004.

Electric Delivery Business

~~Regional~~The ~~Transmission~~company's ~~Organization~~electric ~~(RTO)~~delivery business consists primarily of its regulated electricity transmission, distribution and generation operations in upstate New York and Maine.

~~NYSEG, CMP and~~ RG&E have consistently advocated the formation of a Northeast/Mid-Atlantic RTO, including PJM, or functionally combined markets throughout the Northeast because they believe that a larger wholesale power market is essential to facilitate greater liquidity and competition. The companies plan to file comments on the joint petition. A FERC decision is expected early in 2003. AElectric Northeast RTO may include one or more independent transmission companies that would be owned by participating transmission owners. The transmission companies would share RTO responsibilities with an independent market administrator and ~~would~~Natural ~~focus~~Gas onRate ~~transmission investment opportunities, instead of energy, capacity and other generation-based markets.~~ Agreements
: In May 2003 RG&E filed a rate case with the New York State Public Service Commission (NYPSC) to recover costs that RG&E has incurred and will continue to incur in providing safe and reliable electric and natural gas service. On May 20, 2004, the NYPSC approved Electric and Natural Gas Joint Proposals (Electric and Natural Gas Rate Agreements) that had been negotiated with Staff of the NYPSC and other interested parties and that address RG&E's electric and natural gas rates through 2008.

InKey ~~October~~features ~~2001 FERC commenced a proceeding to consider national standard market design issues and on July 31, 2002, issued a Notice~~ of ~~Proposed Rulemaking (~~the ~~SMD~~Electric ~~NOPR).~~Rate ~~The~~Agreement SMD NOPR proposes rules that would require, among other things, changes in the wholesale power markets, transmission planning services and charges, market power monitoring and mitigation, and the organization and structure of ISOs. FERC is expected to issue a final rule on the SMD NOPR next year. The companies are analyzing the SMD NOPR and plan to file comments. The proposals in the SMD NOPR include the adoption of an energy market based on locational marginal pricing (LMP), which represents a significant change for some regions of the country. The NYISO already operates a market based on LMP, and ISO-New England is in the process of developing and implementing an LMP system. The company is unable to predict the ultimate effect, if any, of the expected RTO order and the SMD rulemaking on wholesale power markets and the company's transmission system.:

~~Transmission~~Freezing ~~Planning~~electric ~~and~~delivery ~~Expansion~~rates through December 2008, except for the implementation of a retail access surcharge effective May 1, 2004, that will recover $7 million annually.
Allowing RG&E to recover its actual electricity supply costs beginning in May 2004.
Refunding to customers over the term of the plan $110 million of the approximately $357 million net proceeds from the sale of Ginna, including refunding $60 million after the closing, and refunding the remaining $50 million over the following three years. (See Sale of Ginna Station and Note 2 to the Condensed Financial Statements.)
Establishing an Asset Sale Gain Account (ASGA) with the net proceeds from the Ginna sale. Portions of the ASGA will be used as follows:

To cover $6 million of replacement purchased power costs incurred in connection with the 2003 Ginna refueling outage;
To provide the company with revenue equivalent to a $2 million annual increase in electric delivery rates;
To compensate RG&E for maximizing the sale value of Ginna through a credit to RG&E of $3.3 million annually over the term of the settlement;

RG&E estimates that at the end of 2008 approximately $121 million will remain in the ASGA, which may be used at the discretion of the NYPSC for rate moderation, among other things.

Establishing an earnings sharing mechanism to allow customers and stockholders to share equally in earnings above a 12.25% return on equity (ROE) target.
Creating and expanding initiatives to enable energy service companies (ESCOs) in RG&E's service territory to attract new customers. RG&E will be allowed to increase its earnings sharing threshold to 12.50% by meeting to-be-determined standards designed to measure improvements in its retail access program, such as increasing customer awareness of competitive alternatives and increasing customer migration.

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

Energy East Corporation

Ensuring that RG&E continues to maintain the high quality of service and reliability that it currently provides by specifying service quality and reliability standards and capital investment objectives.

Key features of the Natural Gas Rate Agreement include:

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

The Electric and Natural Gas Rate Agreements resolve all outstanding issues in the RG&E Cost Deferral Petitions and the RG&E 2002 Electric and Gas Rate Proceeding. In addition, RG&E has withdrawn its appeal of an order the NYPSC issued in March 2003. (See report on Form 10-Q for Energy East and RG&E for the quarter ended March 31, 2004, Item 2, Electric Delivery Business - RG&E Cost Deferral Petitions and RG&E 2002 Electric and Gas Rate Proceeding.)

Sale of Ginna Station
: On June 10, 2004, after receiving all regulatory approvals, RG&E sold Ginna to CGG. RG&E received at closing $429 million in cash. RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna. On May 20, 2004, the NYPSC issued an order approving the sale of Ginna. RG&E's Electric Rate Agreement provides for an ASGA, established at the time of closing in the amount of approximately $357 million, and addresses the disposition of the asset sale gain. (See RG&E 2003 Electric and Natural Gas Rate Agreements and Note 2 to the Condensed Financial Statements.)

Upon closing of the Ginna sale, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. This amount fully meets the Nuclear Regulatory Commission's decommissioning funding requirements for Ginna. RG&E retained $77 million in excess decommissioning funds, which is part of the ASGA. The sale agreement includes a 10-year, fixed-price power purchase agreement that calls for CGG to provide electricity to RG&E at 90% of the plant's output.

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

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

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

CMP Alternative Rate Plan
: In September 2000 the Maine Public Utilities Commission (MPUC) approved CMP's Alternative Rate Plan (ARP 2000). ARP 2000 applies only to CMP's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services. ARP 2000 began January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007. Effective July 1, 2004, CMP's distribution prices decreased by about 1% as a result of inflation being less than the productivity offset for 2004. In addition, CMP decreased its transmission rates to eliminate billings for congestion costs that have been fully recovered and, pursuant to its formula rate approved by the Federal Energy Regulatory Commission (FERC), to reflect CMP's and the New England Power Pool's actual costs for 2003.

OnNYPSC ~~June~~Collaborative ~~25,~~on ~~2002,~~End ~~the~~State MPUC approved a Stipulation allowing CMP's distribution prices to change effective beginning July 1, 2002. As a result, distribution rates for customers not subject to special contracts decreased by 4.84%. The reduction reflects a decrease of ~~3.03%~~Energy in distribution rates resulting from expiring amortizations and the application of a price cap mechanism, and an additional one-time decrease of 1.81% reflecting over-collections of certain costs, such as demand-side management, and insurance proceeds related to environmental remediation.Competition
: In March 2000 the NYPSC instituted a proceeding to address the future of competitive electricity and natural gas markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets and providing recommendations concerning Provider of Last Resort and related issues. In January 2004 the NYPSC issued a Notice seeking additional comments in light of the passage of time and the evolution of competitive markets. In March and April 2004 NYSEG and RG&E submitted comments supporting periodic assessment of the retail competitive marketplace and opposing the adoption of any policies restricting customer choice of supplier or limiting the availability of supply options from any particular supplier. NYSEG and RG&E believe that the NYPSC should not adopt a single end state vision for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.

~~CMP~~Regional ~~Electricity~~Transmission ~~Supply Responsibility:~~Organization
: ISO New England and the New England transmission owners, including CMP, made a joint regional transmission organization (RTO) filing with FERC in October 2003. On March 24, 2004, the FERC issued an order (RTO Order) accepting the six-state New England RTO filing submitted by ISO New England and the New England transmission owners, subject to certain conditions. FERC approved a proposed 50 basis point incentive adder to the ROE component, to be recovered in RTO New England's rates for regional network service. The FERC accepted a proposed 100 basis point ROE adder to reward new transmission investment for regional network services (RNS) facilities, subject to suspension, hearing and application of the FERC's Pricing Policy Statement when it is issued. The FERC also accepted, subject to suspension and hearing, the transmission owners' proposed base level ROE of 12.8% on RNS facilities but not on local network system (LNS) facilities. To provide parties an opportunity to resolve matters, the FERC instituted settlement procedures covering all matters set for hearing. The initial settlement discussions did not produce a resolution and the parties are conducting discovery of the issues set for hearing. CMP and the other New England transmission owners have requested rehearing on the issue of whether LNS facilities will earn the 12.8% base ROE and incentive adders, and clarification on

Under Maine Law the MPUC can mandate that CMP be a standard-offer provider for supply service if the MPUC should deem bids by competitive suppliers to be unacceptable. CMP has no standard-offer obligations through February 2003. If in the future CMP should have standard-offer obligations there would be no effect on net income because CMP is ensured cost recovery through Maine Law. CMP's revenues and purchased power costs will fluctuate, however, as its status as a standard-offer provider changes. (See Item 2(b) - Energy East Operating Results for the Electric Delivery Business and Central Maine Power Company Results of Operations.)
NYPSC-mandated Contracts with Customers
Lost revenues associated with these long-term electric service contracts are recovered through the asset sale gain account created by NYSEG's sale in 2001 of its interest in the Nine Mile Point 2 nuclear generating station (NMP2) and do not affect earnings. After giving effect to the
Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

~~amortization~~other aspects of the ~~asset~~FERC's ~~sale~~RTO ~~gain~~Order. ~~account~~In toaddition, ~~fund~~ISO ~~the~~New ~~first~~England ~~year~~and of the ~~electric~~New ~~rate~~England ~~reduction~~transmission ~~(See~~owners, ~~report~~including onCMP, ~~Form~~made ~~10-K~~a ~~for~~joint ~~Energy~~compliance ~~East~~filing ~~and~~as ~~NYSEG~~required ~~for~~by ~~fiscal~~the ~~year~~RTO ~~ended~~Order. ~~December~~At ~~31,~~this ~~2001~~time, ~~Item~~CMP 7and -the ~~Liquidity~~other ~~and~~New ~~Capital~~England ~~Resources,~~transmission ~~NYSEG~~owners ~~Electric~~have ~~Rate~~informed ~~Settlement),~~ the ~~remaining~~FERC ~~balance~~that ~~would~~it beneeds ~~entirely consumed by discounts offered~~ to ~~these~~resolve ~~two~~the ~~large~~issues ~~industrial~~in ~~customers. NYSEG believes that~~ the ~~remaining~~request ~~balance should not be used~~ for ~~discounts~~rehearing ~~provided~~and toclarification ~~just~~before ~~two~~the ~~customers,~~New ~~but~~England ~~should~~transmission beowners ~~available~~can tomake ~~fund~~a ~~other~~final ~~economic~~decision ~~development~~regarding ~~projects~~whether and ~~for~~when ~~the~~to ~~recovery~~join ofthe ~~uncontrollable costs~~RTO.

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

~~RG&E~~CMP ~~2002~~Stranded ~~Electric~~Cost ~~and Gas Rate~~ Proceeding
: Through its stranded cost rates, CMP recovers the above-market costs of its purchased power agreements, as well as costs incurred to decommission and dismantle the nuclear facilities in which CMP has an ownership share, pursuant to Maine statute. The current stranded cost rates were set in 2003 and are scheduled to be updated in February 2005. CMP filed revised stranded cost estimates in July 2004, as ordered by the MPUC. CMP expects an MPUC order setting new stranded cost rates in February 2005.

~~Ginna~~CMP ~~Station~~Nuclear Costs
: CMP has ownership interests in three nuclear facilities in New England that have been permanently shutdown, and are in the process of being decommissioned: Maine Yankee Atomic Power Company (38% owned), Connecticut Yankee Atomic Power Company (6% owned) and Yankee Atomic Electric Power Company (9.5% owned) (the Yankee companies). The Yankee companies filed litigation in 1998 charging that the federal government breached contracts it entered into with each of the Yankee companies in 1983 to begin removing spent nuclear fuel from the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear plants, which are owned by the Yankee companies, no later than January 31, 1998, in return for payments by each of the Yankee companies. Two federal courts found that the federal government did breach its contracts with the Yankee companies and other utilities. A trial to determine the monetary damages owed to the Yankee companies for the Department of Energy's (DOE) continued failure to remove spent nuclear fuel began in the U.S. Court of Federal Claims in July 2004. The Yankee companies' individual damage claims are specific to each plant and include costs through 2010, the earliest date the DOE expects that it will begin removing fuel. The Yankee companies' damage claims total approximately $550 million and CMP's sponsor-weighted share is approximately $90 million. The claims also note additional costs that will be incurred for each year that fuel remains at the sites beyond 2010. If the Yankee companies prevail in these cases, any damages awarded by the Court of Federal Claims would be credited to their respective decommissioning or spent fuel trust funds and any remaining funds would be returned to electric customers when decommissioning is complete.

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

Energy East Corporation

~~Ginna~~Pursuant ~~Relicensing~~to a year 2000 settlement (2000 Settlement) in a prior FERC rate case, Connecticut Yankee, on July 1, 2004, filed a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of the costs of decommissioning. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars compared to the April 2000 estimate of $434 million approved by the FERC in the 2000 Settlement. The revised estimate reflects the fact that Connecticut Yankee is now self-performing all work to complete the decommissioning of the plant and the termination of Bechtel Power Corporation (Bechtel), the turnkey decommissioning contractor, in July 2003. In addition, the revised estimate contains increases in the projected costs of spent fuel storage, security, and liability and property insurance. The estimated remaining decommissioning and long-term spent fuel storage costs as of December 31, 2003, are approximately $504 million in 2003 dollars.

Connecticut Yankee is seeking recovery of incremental decommissioning costs and other damages from Bechtel and, if necessary, its surety. In turn, Bechtel has filed a complaint in Connecticut Superior Court seeking damages of $93 million for wrongful termination of the decommissioning contract. Connecticut Yankee has filed counterclaims for excess completion costs and other damages. Discovery is underway and a trial has been scheduled for May 2006.

The revised schedule for decommissioning collections is based on the 2003 estimate. Under the revised schedule, increased collections of $93 million annually would commence in January 2005 and extend through December 2010. Any increase in rates approved by the FERC will be charged to Connecticut Yankee's owners, including CMP, whose share of a $93 million increase would be approximately $6 million. Under prior regulatory settlements, CMP is allowed to defer any increased decommissioning costs for future recovery.

On June 10, 2004, the Connecticut Department of Public Utility Control (DPUC) and the Connecticut Office of Consumer Counsel filed a petition with the FERC asking the FERC to determine that, if it should find any of Connecticut Yankee's decommissioning costs were not prudently incurred, the owners may not recover those costs in rates that are ultimately charged to retail customers but must be borne by the owners of Connecticut Yankee. Connecticut Yankee and its owners, including CMP, filed protests to contest this petition. CMP cannot predict the outcome of these proceedings.

Natural Gas Delivery Business

~~Natural~~The ~~Gas~~company's ~~Supply~~natural ~~Alliance~~gas delivery business consists of its regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts.

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

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

Energy East Corporation
~~On September 13, 2002,~~ NYSEG ~~filed~~Natural ~~with~~Gas ~~the~~Rate NYPSC a joint proposal, which was endorsed by NYPSC Staff, the NY State Consumer Protection Board, large customer groups and numerous gas marketers that proposed to freeze delivery rates from October 1, 2002, through December 31, 2008, and phase in the rate impact of a gas supply charge to collect the actual cost of gas. The joint proposal would resolve issues related to NYSEG's petition to defer the difference in natural gas costs referred to above by allowing NYSEG to defer $14 million in 2002 for recovery. The NYPSC is expected to consider the joint proposal at its open session on November 20, 2002.Plan
: NYSEG's Natural Gas Rate Plan, which became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, implements a natural gas supply charge to collect the actual costs of natural gas and contains an earnings sharing mechanism. The earnings sharing mechanism requires equal sharing of earnings between NYSEG customers and shareholders of ROEs in excess of 11.5% for the 27-month period ended December 31, 2004, and in excess of 12.5% for each of the calendar years from 2005 through 2008. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $250 million.

~~NYPSC~~On ~~Collaborative~~June on30, ~~End~~2004, ~~State~~NYSEG offiled a Joint Proposal executed by NYSEG and other parties, resolving outstanding issues in NYSEG's Natural Gas Rate Plan related to its natural gas delivery rate design, natural gas economic development plan and its natural gas Affordable Energy ~~Competition~~Program. Pursuant to NYSEG's Natural Gas Rate Plan, delivery rate designs in the Joint Proposal were developed for each of the remaining years on an overall revenue neutral manner, consistent with the billing units and firm delivery revenues contained in NYSEG's Natural Gas Rate Plan. The company expects the NYPSC to address the Joint Proposal at its open session on September 22, 2004.

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

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

SCG Request for Recovery of Exogenous Costs
: In December 2003 SCG filed an application with the DPUC to recover approximately $21 million of exogenous costs under its approved Incentive Rate Plan (IRP). The exogenous costs to be recovered include qualified pension and other postretirement benefits expenses, taxes, uncollectible expense and the cost of SCG's Customer Hardship Arrearage Forgiveness Program. Those costs were the result of events that were unanticipated and beyond SCG's control. SCG's IRP decision from the DPUC allows SCG to petition for relief from substantial and material costs resulting from such exogenous events. The DPUC established a docket for this proceeding and hearings were held in April 2004. A DPUC draft decision in this proceeding is now scheduled to be released some time in August. SCG cannot predict the outcome of this proceeding.

CNG's Purchased Gas Adjustment Clause
: In April 2002 the DPUC initiated a semiannual review of CNG's Purchased Gas Adjustment Clause (PGA). The DPUC issued its draft decision in December 2002, disallowing approximately $1 million of natural gas costs that would be returned to customers through the PGA. As a result, on December 31, 2002, CNG set up a reserve to recognize a potential $1 million liability for this disallowance. In May 2004 the DPUC issued its final decision in a subsequent PGA case that clarified a number of issues and allowed CNG to reverse the $1 million reserve.

Connecticut Merger-Enabled Gas Supply Savings and Gas Cost Reduction Plan Filings
: In 2001 CNG and SCG submitted filings to the DPUC regarding merger-enabled gas supply savings (MEGS) and a gas-cost reduction plan, which covered the initial period April 1, 2001, through September 30, 2001. CNG provided calculations for total MEGS of $1.3 million and SCG provided calculations for total MEGS of $2.2 million. In February 2003, based on its understanding of the components of the MEGS, the DPUC issued a draft decision on CNG's and SCG's filed MEGS and gas-cost reduction plan results, modifying the MEGS amounts to

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

Energy East Corporation

$134,000 for CNG and $9,000 for SCG. CNG and SCG filed comments and additional detail with regard to the draft decision. On March 26, 2004, the DPUC issued a notice that encouraged the parties to settle the MEGS issue, which resulted in the assignment of Prosecutorial Staff of the DPUC to assist in the settlement process. The docket was suspended to allow the settlement process to proceed. CNG and SCG are diligently working toward settlement of the issues but cannot predict the final outcome of these proceedings.

Other Businesses

~~Berkshire~~Sale ~~Service~~of ~~Solutions~~Other Businesses
: The company continues to rationalize its nonutility businesses to ensure that they fit its strategic focus. On July 26, 2004, UWP, a subsidiary of CMP Group, Inc., sold all of the assets related to its utility locating and construction businesses. The after tax loss resulting from the sale is estimated at $5 million and includes a reduction in the goodwill that was assigned to UWP at the time of Energy East's purchase of CMP Group.

Other Matters

Accounting Issues

~~Statement~~FIN ~~146~~46R
: In December 2003 the Financial Accounting Standards Board (FASB) issued its revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin (ARB) No. 51 (FIN 46R). FIN 46R addresses consolidation of variable interest entities. A variable interest entity is an entity that is not controllable through voting interests and/or in which the equity investor does not bear the residual economic risks and rewards. The company was required to apply FIN 46R to all entities subject to the interpretation as of March 31, 2004. (See Note 7 to the Condensed Financial Statements.)

FASB Staff Position No. FAS 106-2
: In May 2004 the FASB issued its FASB Staff Position (FSP) No. FAS 106-2, which addresses how and when a plan sponsor should account for the federal subsidy introduced by the Medicare Prescription Drug, Improvement and Modernization Act of 2003 and could require the plan sponsor to change previously reported information. FSP No. FAS 106-2 is effective for the first interim or annual period beginning after June 15, 2004. When FSP No. FAS 106-2 becomes effective it supersedes FSP No. FAS 106-1. The company, CMP, NYSEG and RG&E will apply FSP No. 106-2 beginning July 1, 2004. (See Note 9 to the Condensed Financial Statements.)

Investing and Financing Activities
Investing Activities
: Capital spending for the first six months of 2004 was $124 million, including nuclear fuel. Capital spending is projected to be $345 million for 2004, including nuclear fuel, and is expected to be paid for primarily with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

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

Energy East Corporation
Investing and Financing Activities
The equity markets have experienced significant declines and volatility in 2002. Despite those market conditions, the company's pension plans continue to be well funded with assets exceeding the projected benefit obligation. As a result, the company does not currently anticipate significant funding requirements for its plans. Due to the funded status of the plans and previously favorable investment returns, the company's pension plans generated $78 million in pre-tax pension income in 2001 (net of amounts capitalized). Through the first nine months of 2002 the plans generated $52 million in pre-tax pension income (net of amounts capitalized), $4 million less than the first nine months of 2001. The company is currently unable to predict the effect that an equity market decline, coupled with the voluntary early retirement program and the involuntary severance program (See Item 2(a) Restructuring Initiative), would have on pension income for 2003 and beyond.
Financing Activities
: The financing activities discussed below include those activities necessary for the company and its subsidiaries to maintain adequate liquidity, improve credit quality and ensure access to capital markets. Activities include maintenance of credit facilities, minimal common stock issuances and various medium-term and long-term debt arrangements. They also include the steps taken at RG&E to revise its capital structure as a result of the Ginna sale. (See RG&E Financing Activities.)

OnDuring ~~October~~the 22six months ended June 30, ~~2002~~2004, the company ~~filed~~issued to444,122 ~~amend~~shares ~~its~~of ~~Dividend~~common ~~Reinvestment~~stock, ~~and~~at ~~Stock~~an ~~Purchase~~average ~~Plan~~price toof ~~allow~~$23.15 ~~non-shareholders~~per ~~who reside in Connecticut~~share, ~~Maine,~~through ~~Massachusetts~~its orInvestor ~~New~~Services ~~York~~Program ~~State~~(formerly toknown ~~enroll~~as ~~directly in~~ the ~~Plan~~Dividend byReinvestment ~~making~~and anStock ~~initial~~Purchase ~~cash investment~~Plan). The ~~amendment~~shares ~~will~~issued ~~become~~were ~~effective~~original ~~December~~issue ~~15, 2002~~shares.

~~During~~In ~~the~~July ~~second~~2004 ~~and third quarters of 2002~~ the company ~~and~~replaced ~~certain of~~ its ~~subsidiaries renewed credit agreements with certain banks that provide for borrowing up to~~ $~~410~~150 million ~~as follows: $260 million for~~ 364-day ~~periods,~~revolving ~~which~~credit ~~the~~facility ~~company~~with ~~expects~~a to$150 ~~renew~~million ~~annually,~~five-year ~~and~~revolving ~~$150~~credit ~~million~~facility ~~for~~that aexpires ~~three-year~~in ~~period~~July 2009.

InDuring ~~May~~the ~~2001~~first quarter of 2004 the company ~~filed~~awarded a242,038 ~~shelf~~shares ~~registration~~of ~~statement~~its ~~with~~common ~~the~~stock, ~~Securities~~issued ~~and~~out ~~Exchange~~of ~~Commission~~its totreasury ~~sell~~stock, up to $1certain ~~billion~~employees inthrough anits ~~unspecified~~Restricted ~~combination~~Stock ofPlan ~~debt~~ and ~~trust~~recorded ~~preferred~~deferred ~~securities,~~compensation of ~~which~~ $56 million isbased ~~currently~~on ~~available. Under~~ the ~~shelf~~market ~~registration~~price ~~statement~~per ~~the~~share ~~company~~of ~~issued~~common ~~debt~~stock ~~and~~on ~~trust preferred securities to fund~~ the ~~cash~~dates ~~portion~~ of the ~~consideration for the merger with RGS Energy~~awards, ~~for~~which ~~general~~averaged ~~corporate purposes, such as short-term debt reduction, repurchases of securities and to fund an equity contribution to NYSEG in 2001~~$23. ~~(See Energy East Corporation and RGS Energy Merger~~90.)

InNYSEG ~~June~~Financing ~~2002 the company issued $400 million of 6.75% 10-year notes due June 2012 under the shelf registration statement described above. The proceeds were used to help fund the RGS Energy merger.~~ Activities
: In May 2004 NYSEG entered into forward starting swaps on three adjustable-rate pollution control notes to fix the interest rates on the anniversary dates of the notes. NYSEG will receive the Bond Market Association Municipal Swap rate, an indexed floating rate, and pay fixed rates on the notional amounts as follows: 4.387% on $60 million (anniversary date March 15, 2005), 4.330% on $30 million (anniversary date October 15, 2004) and 4.390% on $42 million (anniversary date December 1, 2004).

In July 2004 NYSEG and RG&E replaced their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-year $230 million revolving credit facility with certain banks. NYSEG is permitted to borrow up to $180 million under the facility, RG&E is permitted to borrow up to $75 million, and NYSEG and RG&E are allowed to issue letters of credit totaling up to $40 million, not to exceed a combined total of $230 million.

In August 2004 NYSEG expects to refund $204 million of tax-exempt fixed-rate pollution control notes that have interest rates ranging from 5.70% to 6.05% with proceeds from the issuance of $204 million of multi-mode tax-exempt pollution control notes, which will initially be in a Dutch Auction mode. In July 2004 NYSEG entered into a forward starting swap to fix the interest rate on one of the tax-exempt pollution control notes in the Dutch Auction mode. NYSEG will pay a fixed rate of 3.80% and will receive 67% of the one-month LIBOR rate on a notional amount of $70 million.

RG&E Financing Activities
: On March 1, 2004, RG&E redeemed, at par, as required by a mandatory sinking fund provision, $1.25 million of 6.60% Series V preferred stock, Par Value $100, using available cash. On May 5, 2004, RG&E redeemed, at par, the remaining $23.75 million of the 6.60% Series V preferred stock, using available cash. The 6.60% Series V preferred stock, because it was mandatorily redeemable, was classified as a liability as of July 1, 2003, in accordance with FASB Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.

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

Energy East Corporation

InOn ~~July~~May ~~2002~~5, ~~the~~2004, ~~company~~RG&E ~~entered~~redeemed ~~into~~its aremaining ~~fixed-to-floating~~preferred ~~interest~~stock, ~~rate~~including: ~~swap~~$12 onmillion ~~the~~of ~~company's~~4% 5Series F (120,000 shares), $8 million of 4.7510% ~~notes~~Series ~~due~~H ~~November~~(80,000 ~~2006~~shares), $6 million of 4 3/4% Series I (60,000 shares), $5 million of 4.10% ~~The~~Series ~~company~~J ~~receives~~(50,000 ashare), ~~fixed~~$6 ~~rate~~million of 54.7595% Series K (60,000 shares) and ~~will~~$10 ~~pay~~million of 4.55% Series M (100,000 shares), all redeemed at a ~~rate~~premium. ~~based~~On onMay ~~the~~6, ~~six~~2004, ~~month~~RG&E ~~London~~redeemed, ~~Interbank~~at ~~Offered~~a ~~Rate~~premium, ~~plus~~$40 1million of 7.~~565~~45% Series first mortgage bonds due July 2023, onand athe ~~notional~~following ~~amount~~Series of first mortgage bonds due March 2023: $~~250~~33 million of 7.64%, $5 million of 7.66%, and $12 million of 7.67%. Those redemptions were financed through ~~November~~available ~~2006~~cash and a short-term credit facility. The short-term credit facility was repaid with proceeds from the sale of Ginna.

In July ~~2002~~2004 ~~the~~RG&E ~~company~~and ~~terminated~~NYSEG areplaced ~~fixed~~their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-~~floating~~year ~~interest~~$230 ~~rate~~million ~~swap~~revolving oncredit ~~the~~facility ~~company's~~with 8certain banks.~~05%~~ ~~notes~~RG&E ~~due~~is ~~November~~permitted ~~2010.~~to ~~The~~borrow ~~company~~up ~~received~~to $1675 million, under the ~~value~~facility, ofNYSEG ~~the~~is ~~swap~~permitted onto ~~the~~borrow ~~date~~up ofto ~~termination~~$180 million, and ~~will~~RG&E ~~amortize~~and ~~about~~NYSEG ~~$15~~are ~~million~~allowed to issue letters of ~~that~~credit ~~gain~~totaling ~~over~~up ~~the~~to ~~remaining~~$40 ~~life~~million, not to exceed a combined total of ~~the~~$230 ~~notes~~million.

~~CMP~~In ~~issued~~August ~~the~~2004 ~~following Series~~ RG&E ~~Medium~~expects ~~Term~~to ~~Notes,~~refund ~~the~~$60 ~~proceeds~~million of ~~which~~fixed-rate ~~were~~tax-exempt ~~used~~mortgage bonds that have rates ranging from 6.35% to ~~repay~~6.5% with proceeds from the issuance of $5060 million of ~~maturing~~multi-mode ~~medium~~tax-~~term~~exempt pollution control notes, ~~short-term~~which ~~debt~~will ~~and~~initially ~~for~~be ~~general~~in ~~corporate~~a ~~purposes:~~Dutch Auction mode.

OnIn ~~May~~the ~~22,~~second ~~2002~~quarter of 2004, RG&E declared common dividends of $~~37.5~~170 million, 6in order to rebalance its capital structure after the Ginna sale.~~50%,~~ ~~due~~These ~~May~~funds ~~2009~~will be used to reduce debt outstanding at Energy East.

OnOther ~~May~~Financing ~~28, 2002, $37.5 million, 6.65%, due May 2012.~~Activities
:

OnIn ~~August~~the ~~29,~~second ~~2002~~quarter of 2004 Berkshire Gas, CNG and SCG renewed their joint $105 million 364-day revolving credit facility. The amounts the companies are permitted to borrow up to: Berkshire Gas - $15 million, ~~5.70%~~CNG - $50 million and SCG - $55 million, ~~due~~not ~~August~~to ~~2012~~exceed a combined total of $105 million.

On September 10, 2002, $15 million, 4.25%, due September 2007.
In May 2002 NYSEG redeemed, at a premium, $150 million of 8 7/8% Series first mortgage bonds due November 1, 2021, and redeemed, at par, the remaining $21.34 million of two 9 7/8% Series first mortgage bonds due 2020. The redemptions were financed with internally generated cash and the proceeds from the prepayment of a promissory note by Constellation Nuclear in April 2002. (See the company's Form 10-Q for the quarter ended March 31, 2002, Item 2(a) Liquidity and Capital Resources - Electric Delivery Business - Sale of Nine Mile Point 2). NYSEG incurred a $10 million reduction to earnings in the second quarter of 2002 as a result of these redemptions, but will save over $16 million each year in interest costs.
Additional financing needed by NYSEG to refund commercial paper that was used in October 2002 to repay $150 million of maturing 6 3/4% Series first mortgage bonds is expected to be completed in November 2002. Through financial instruments issued in June 2002 NYSEG has locked in the five-year treasury rate component of the financing at an average rate of 4.246%.
Over the next several months, NYSEG plans to call its remaining first mortgage bonds: $100 million 8.30% Series first mortgage bonds callable on December 15, 2002, $50 million 7.55% Series first mortgage bonds callable on April 1, 2003, and $100 million 7.45% Series first mortgage bonds callable on July 15, 2003. Additional financing needed by NYSEG to call the $100 million 8.30% Series first mortgage bonds is expected to be completed in November 2002. Through financial instruments issued in August 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.19%. Additional financing needed by NYSEG to call the $50 million 7.55% Series and the $100 million 7.45% Series is expected to be completed in June 2003. Through financial instruments issued in September 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.085%.
In July 2002 CNG retired $10 million of Medium Term Notes that had matured, using short-term debt. In October 2002 CNG redeemed $3.5 million of Series AA first mortgage bonds, including $2.5 million pursuant to a sinking fund provision and $1 million at a premium, using short-term debt.
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)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Operating Revenues	$1,016,189	$798,848	27%
(Thousands, except per share amounts)
Operating Income	$113,500	$94,567	20%
Operating Revenues	$980,566	$979,113	-
Net Income (Loss)	$23,742	$(21,057)	113%
Operating Income	$233,806	$124,351	88%
Average Common Shares Outstanding	144,621	116,436	24%
Income from Continuing Operations	$42,782	$28,333	49%
Earnings (Loss) Per Share, basic and diluted	$.16	$(.18)	89%
Net Income	$38,066	$27,717	37%
Dividends Paid Per Share	$.24	$.23	4%
Average Common Shares Outstanding, basic	146,148	145,415	1%
Earnings Per Share from Continuing Operations, basic and diluted	$.29	$.19	53%
Earnings Per Share, basic and diluted	$.26	$.19	37%
Dividends Paid Per Share	$.26	$.25	4%

Earnings from continuing operations were 29 cents per share for the quarter ended ~~September~~June 30, ~~2002~~2004, ~~were 18 cents per share~~ compared to 2119 cents per share for the ~~prior~~quarter ~~year~~ended ~~quarter~~June 30, ~~excluding~~2003. aThe ~~loss~~increase ofis ~~two~~primarily ~~cents~~due ~~per~~to ~~share~~one-time oneffects from the sale of ~~Berkshire~~Ginna ~~Service Solutions this quarter~~ and athe ~~writedown~~approval of ~~CMP Group, Inc.~~RG&E's ~~investment~~Electric inand ~~NEON~~Natural ~~Communications,~~Gas ~~Inc.~~Rate ~~that~~Agreements, ~~reduced~~which increased earnings 7 cents per share. 39The ~~cents~~one-time ineffects include the ~~third~~flow-through ~~quarter~~ of ~~2001.~~excess ~~(See~~deferred ~~Note~~taxes 9and toinvestment ~~the~~tax ~~company's~~credits ~~consolidated~~and ~~Financial~~the ~~Statements.)~~elimination ~~The~~of ~~decrease~~certain isreserves ~~primarily~~established ~~the~~pending ~~result~~regulatory ofdetermination. anOngoing ~~electric~~effects ~~price~~from ~~reduction~~RG&E's ~~for~~Electric ~~NYSEG~~and ~~effective~~Natural ~~March~~Gas 1,Rate ~~2002,~~Agreements ~~that~~added ~~lowered~~5 ~~earnings~~cents per share 20to ~~cents~~earnings, ~~substantially~~and ~~offset~~include by increases ofas ~~nine~~a ~~cents~~result ~~per~~of ~~share~~RG&E's ~~for higher~~ electric ~~deliveries~~retail ~~(primarily~~access ~~residential~~surcharge and ~~commercial)~~natural ~~due~~gas tomerchant ~~warmer~~function ~~summer weather this year~~charge, ~~five~~and ~~cents~~annual ~~per~~credits ~~share~~to ~~due~~RG&E tofrom the ~~elimination~~ASGA ofas ~~goodwill~~provided ~~amortization~~ in ~~2002~~the ~~and~~Electric ~~two~~Rate ~~cents per share because of cost control efforts~~Agreement. (See

RG&E 2003 Electric and Natural Gas Rate Agreements.) Lower stock-based compensation expenses contributed another 5 cents per share to earnings. Those increases were partially offset by a decrease of 5 cents per share from lower natural gas deliveries due to milder weather.

Nine months ended September 30 (Thousands, except per share amounts)	2002	2001	Change
Six months ended June 30	2004	2003	Change
Operating Revenues	$2,759,641	$2,918,997	(5%)
(Thousands, except per share amounts)
Operating Income	$433,845	$447,256	(3%)
Operating Revenues	$2,561,639	$2,483,944	3%
Net Income	$134,634	$121,118	11%
Operating Income	$501,151	$418,294	20%
Average Common Shares Outstanding	126,489	116,737	8%
Income from Continuing Operations	$163,491	$160,024	2%
Earnings Per Share, basic and diluted	$1.06	$1.04	2%
Net Income	$158,618	$163,181	(3%)
Dividends Paid Per Share	$.72	$.69	4%
Average Common Shares Outstanding, basic	146,116	145,256	1%
Earnings Per Share from Continuing Operations, basic	$1.12	$1.10	2%
Earnings Per Share from Continuing Operations, diluted	$1.11	$1.10	1%
Earnings Per Share, basic	$1.09	$1.12	(3%)
Earnings Per Share, diluted	$1.08	$1.12	(4%)
Dividends Paid Per Share	$.52	$.50	4%

Earnings ~~per~~from ~~share~~continuing ~~for~~operations ~~the nine months~~ were $1.2212 ~~compared~~per toshare ~~$1.43~~ for the ~~same~~six ~~period~~months inended ~~2001~~June 30, ~~excluding~~2004, acompared ~~loss~~to of$1.10 ~~two cents~~ per share onfor the ~~sale~~six ofmonths ~~Berkshire~~ended ~~Service~~June ~~Solutions this quarter~~30, a2003. ~~loss~~The ofincrease ~~eight~~is ~~cents~~primarily ~~per~~the ~~share~~result ~~from NYSEG's early retirement~~ of ~~debt in~~ the second quarter effects of ~~2002 and~~ the ~~writedowns~~sale of ~~CMP~~Ginna ~~Group,~~and ~~Inc.~~RG&E's ~~investment~~Electric inand ~~NEON~~Natural ~~Communications,~~Gas ~~Inc.~~Rate ~~that~~Agreements ~~reduced~~discussed ~~earnings~~above, ~~per~~and ~~share~~because ~~six~~of ~~cents~~integration insavings ~~2002~~ and 39other ~~cents~~cost ~~in 2001~~reductions. ~~(See~~Earnings ~~Note~~were 9reduced to5 ~~the~~cents ~~company's~~per ~~consolidated~~share ~~Financial~~due ~~Statements.)~~to ~~The~~the ~~decrease~~accumulated iseffects ~~primarily~~of ~~the~~stock-based ~~result~~compensation ofexpenses anas ~~electric~~a ~~price~~result ~~reduction~~of ~~for~~the ~~NYSEG~~changes ~~effective~~in ~~March~~the 1,market ~~2002,~~value ~~that~~of ~~lowered~~Energy ~~earnings~~East 37stock ~~cents~~during ~~per~~the ~~share~~first ~~and~~two aquarters ~~decrease~~ of 102004 ~~cents~~as ~~per~~compared ~~share due~~ to ~~fewer~~the ~~wholesale~~same ~~electric~~periods ~~sales~~last ~~at lower market prices~~year. ~~Those~~Earnings ~~decreases~~ were ~~partially~~reduced ~~offset~~another by9 ~~increases of 12~~ cents per share ~~for~~because ~~lower costs~~ of lower natural gas ~~purchases~~deliveries ~~and 16 cents per share~~ due to ~~the~~milder ~~elimination of goodwill amortization in 2002~~weather.

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)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Retail Deliveries - Megawatt-hours	8,049	5,863	37%
(Thousands)
Operating Revenues	$741,338	$623,997	19%
Retail Deliveries - Megawatt-hours	7,295	7,141	2%
Operating Expenses	$612,188	$517,242	18%
Operating Revenues	$641,057	$640,035	-
Operating Income	$129,150	$106,755	21%
Operating Expenses	$425,098	$536,329	(21%)
Operating Income	$215,959	$103,706	108%

~~The~~Operating ~~$117 million increase in operating~~ revenues for the second quarter isof ~~primarily~~2004 ~~the~~decreased ~~result~~$1 ofmillion ~~the~~primarily ~~addition~~as ofa ~~RG&E's~~result ~~delivery~~of lower revenues of $~~198~~10 million ~~and increased retail deliveries of $26 million~~ due to ~~warmer~~a ~~summer~~change ~~weather.~~in ~~Those~~market ~~increases~~structure ~~are~~for ~~partially~~RG&E ~~offset~~that byallows ~~CMP~~ESCOs noto ~~longer~~provide ~~being~~electricity ~~the~~and ~~standard-offer~~$5 ~~provider~~million ~~for~~because ~~the supply~~ of ~~electricity~~lower ~~effective~~prices infor ~~March~~CMP's ~~2002,~~retail ~~which~~customers. ~~reduced~~Those ~~revenues~~decreases bywere ~~$42~~partially ~~million;~~offset aby ~~price~~higher ~~reduction~~retail ~~for~~deliveries ~~NYSEG, effective March 1, 2002,~~ of $4110 million; and ~~lower~~higher wholesale ~~deliveries~~revenues of $219 million. for NYSEG.

Operating expenses ~~increased~~decreased $95111 million ~~for the quarter~~ primarily due to ~~the addition of~~ RG&E's ~~operating~~recognition ~~expenses~~ of ~~$158 million; an $11 million increase in purchased power costs for higher retail deliveries due to warmer summer weather; and~~ a $17319 million ~~increase~~pretax ~~for~~gain ~~purchased~~on ~~power~~the ~~costs~~Ginna ~~to replace energy previously provided by NMP2~~sale, ~~which was~~ partially offset by aRG&E's ~~$10~~deferral ~~million decrease in certain operating expenses primarily due to the sale~~ of ~~NMP2. Those increases were partially offset by a $42 million decrease in electricity purchased because CMP is no longer~~ the ~~standard-offer~~gain ~~provider~~net ~~for the supply~~ of ~~electricity,~~tax ~~a $21 million decrease due to lower wholesale deliveries, $6 million due to the elimination~~ of ~~a regulatory amortization of demand-side management program costs and~~ $2214 million ~~due to the elimination of goodwill amortization in 2002~~.

Nine months ended September 30 (Thousands)	2002	2001	Change
Six months ended June 30	2004	2003	Change
Retail Deliveries - Megawatt-hours	19,345	17,568	10%
(Thousands)
Operating Revenues	$1,876,742	$1,904,785	(1%)
Retail Deliveries - Megawatt-hours	15,345	15,231	1%
Operating Expenses	$1,517,477	$1,508,370	1%
Operating Revenues	$1,371,652	$1,398,748	(2%)
Operating Income	$359,265	$396,415	(9%)
Operating Expenses	$1,012,909	$1,139,237	(11%)
Operating Income	$358,743	$259,511	38%

~~The~~Operating ~~$28 million decrease in operating~~ revenues for the ~~nine~~six months isdecreased ~~primarily~~$27 ~~the~~million. ~~result~~The ofprimary afactors ~~reduction~~were revenue decreases of approximately $~~111~~21 million because of ~~CMP~~rate noreductions ~~longer~~for ~~being~~CMP ~~the~~to ~~standard-offer~~reflect ~~provider~~lower ~~for~~amortization ~~the supply~~ of ~~electricity~~storm ~~effective~~and indemand-side ~~March~~management ~~2002~~costs; and $7722 million due to a ~~price~~change ~~reduction~~in ~~for~~market ~~NYSEG,~~structure ~~effective~~for ~~March~~RG&E 1,that ~~2002;~~allows ~~lower~~ESCOs ~~wholesale~~to ~~revenues~~provide ofelectricity, ~~$53~~resulting ~~million~~in ~~primarily~~lower ~~due~~retail torevenues ~~lower~~offset ~~market~~by ~~prices~~higher ~~for~~wholesale ~~electricity;~~revenues and ~~a $15 million decrease primarily due to~~ lower ~~industrial~~fuel ~~sales~~costs. Those decreases were partially offset by ~~the~~increased ~~addition~~retail deliveries of ~~RG&E's~~$4 ~~delivery~~million, increased wholesale revenues of $~~198~~ 8 million and ~~increased~~an ~~retail deliveries of~~ $268 million ~~due~~increase toin ~~warmer~~transmission ~~summer~~revenues ~~weather~~for NYSEG.

Operating expenses ~~increased $9 million~~ for the ~~nine~~six months. ~~Increases~~decreased ~~include~~$126 ~~the~~million ~~addition~~primarily ofdue to RG&E's ~~operating~~recognition ~~expenses~~ of ~~$158~~a ~~million;~~ $11319 million ~~for~~pretax ~~the~~gain ~~pass-through~~on of the ~~market~~Ginna ~~price~~sale, ofpartially ~~electricity~~offset ~~allowed~~by ~~in NYSEG~~RG&E's ~~electric~~deferral ~~rate~~of ~~settlement;~~the ~~$11~~gain ~~million~~net of ~~purchased~~tax ~~power~~of ~~costs for higher retail deliveries due to warmer summer weather; and~~ $36214 million. ~~for~~In ~~purchased~~addition, ~~power~~operating ~~costs~~expenses tofor ~~replace~~the ~~energy~~first ~~previously~~quarter ~~provided~~of by2004 ~~NMP2,~~decreased ~~which was partially offset by a~~ $3115 million ~~decrease~~primarily ~~in certain operating expenses~~ due to ~~the sale of NMP2. Those increases were partially offset by~~ a ~~$110~~reduction ~~million decrease~~ in ~~electricity~~ purchased ~~because~~power ~~CMP~~costs. ~~is no longer~~

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

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

Three months ended September 30 (Thousands)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Retail Deliveries - Dekatherms	29,859	23,637	26%
(Thousands
Operating Revenues	$132,983	$113,356	17%
Retail Deliveries - Dekatherms	35,952	39,026	(8%)
Operating Expenses	$148,606	$130,870	14%
Operating Revenues	$240,282	$264,054	(9%)
Operating (Loss)	$(15,623)	$(17,514)	11%
Operating Expenses	$232,485	$244,033	(5%)
Operating Income	$7,797	$20,021	(61%)

~~The~~Operating revenues decreased $2024 million ~~increase in operating revenues~~ for the ~~three~~second ~~months~~quarter isof 2004 primarily ~~the~~due ~~result~~to oflower ~~the~~deliveries ~~addition~~that ofreduced ~~RG&E's delivery~~ revenues of $3340 million, partially offset by ~~lower~~higher ~~wholesale deliveries of $8 million and lower market prices of natural~~ gas costs that are passed on to customers ofthat increased revenues $516 million.

Operating expenses ~~increased~~decreased $1812 million ~~for~~compared to the ~~quarter~~prior ~~primarily~~year ~~due~~quarter. toThe ~~the~~primary ~~addition~~cause ofwas ~~RG&E's~~a ~~operating~~decrease ~~expenses~~in volume of ~~$38~~natural ~~million,~~gas ~~partially~~purchases ~~offset~~of ~~by a~~ $1514 million. This decrease inwas ~~purchased~~offset ~~gas costs caused~~ by ~~lower~~higher ~~market~~natural gas prices, ~~reduced purchases~~ of ~~gas of~~ $510 million. ~~due~~Lower ~~to lower~~ wholesale ~~deliveries~~volumes ~~and~~decreased aexpenses $4 million ~~decrease~~for ~~due to~~ the ~~elimination of goodwill amortization in 2002~~quarter.

Nine months ended September 30 (Thousands)	2002	2001	Change
Six months ended June 30	2004	2003	Change
Retail Deliveries - Dekatherms	116,318	105,575	10%
(Thousands
Operating Revenues	$643,038	$808,179	(20%)
Retail Deliveries - Dekatherms	123,549	128,242	(4%)
Operating Expenses	$562,007	$746,605	(25%)
Operating Revenues	$922,006	$904,167	2%
Operating Income	$81,031	$61,574	32%
Operating Expenses	$789,191	$751,569	5%
Operating Income	$132,815	$152,598	(13%)

~~The~~Operating revenues increased $~~165~~18 million ~~decrease~~for inthe ~~operating~~six ~~revenues~~months ~~for~~compared to the ~~nine~~prior ~~months~~year period. The increase is primarily ~~the~~due ~~result~~to ofan a $~~134~~80 million ~~decrease~~increase ~~because~~in ofrevenues ~~lower~~due ~~market~~to ~~prices~~higher ofnatural gas ~~that~~costs, which are passed on to customers, ~~and~~partially ~~decreased~~offset by lower deliveries of $6940 million ~~primarily because of mild winter weather~~. ~~Those~~Other ~~decreases~~items, ~~were~~including ~~partially~~lower ~~offset~~transportation byrevenues ~~the~~and ~~addition~~wholesale ofentitlements ~~RG&E's~~further ~~delivery~~decreased revenues ~~of $33 million~~.

Operating expenses ~~decreased~~increased $~~185~~42 million for the ~~nine~~six months ~~primarily~~ended ~~due~~June to30, a2004, ~~$169~~primarily ~~million~~due ~~decrease~~to inhigher ~~purchased~~natural gas ~~costs~~prices ~~caused~~of by$62 ~~lower~~million, ~~market~~partially ~~prices,~~offset ~~reduced~~by fewer purchases of natural gas of $4128 million ~~due~~as ~~to lower deliveries and~~ a ~~$12~~result ~~million decrease due to the elimination~~ of ~~goodwill~~lower ~~amortization in 2002~~deliveries. ~~Those decreases were partially offset by the addition of RG&E's operating expenses of $38 million.~~

Item 1. Financial Statements

Item 1.

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

Periods ended June 30	2004	2003	2004	2003

(Thousands)
Operating Revenues
Sales and services	$129,748	$135,259	$292,498	$311,676
Operating Expenses
Electricity purchased	57,422	60,048	120,395	120,686
Other operating expenses	37,825	41,817	79,484	88,305
Maintenance	7,016	8,765	14,841	16,135
Depreciation and amortization	13,173	10,145	21,297	20,365
Other taxes	3,317	3,448	8,324	10,404

Total Operating Expenses	118,753	124,223	244,341	255,895

Operating Income	10,995	11,036	48,157	55,781
Other (Income)	(1,032)	(761)	(2,083)	(1,748)
Other Deductions	164	420	299	799
Interest Charges, Net	6,131	6,614	12,272	13,287

Income Before Income Taxes	5,732	4,763	37,669	43,443
Income Taxes	2,302	1,942	13,412	16,520

Net Income	3,430	2,821	24,257	26,923
Preferred Stock Dividends	361	361	721	721

Earnings Available for Common Stock	$3,069	$2,460	$23,536	$26,202

The notes on pages 41 through 52 are an integral part of the financial statements.

Central Maine Power Company Consolidated Statements of Income - (Unaudited

Central Maine Power Company Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003

(Thousands)
Assets
Current Assets
Cash and cash equivalents	$14,970	$11,627
Accounts receivable, net	100,153	113,992
Materials and supplies, at average cost	6,734	6,571
Accumulated deferred income tax benefits, net	1,232	1,232
Prepayments and other current assets	4,153	7,135

Total Current Assets	127,242	140,557

Utility Plant, at Original Cost
Electric	1,358,980	1,337,931
Less accumulated depreciation	466,103	451,407

Net Utility Plant in Service	892,877	886,524
Construction work in progress	14,818	15,953

Total Utility Plant	907,695	902,477

Other Property and Investments, Net	23,975	25,475

Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	160,322	173,548
Unfunded future income taxes	104,276	104,276
Unamortized loss on debt reacquisitions	8,059	8,646
Demand-side management program costs	4,589	5,281
Environmental remediation costs	1,613	2,614
Nonutility generator termination agreement	5,319	5,944
Other	74,390	65,145

Total regulatory assets	358,568	365,454

Other assets
Goodwill, net	324,938	324,938
Prepaid pension benefits	35,897	29,623
Other	10,189	18,329

Total other assets	371,024	372,890

Total Regulatory and Other Assets	729,592	738,344

Total Assets	$1,788,504	$1,806,853

The notes on pages 41 through 52 are an integral part of the financial statements.

	Three Months		Nine Months
Central Maine Power Company Condensed Consolidated Balance Sheets - (Unaudited)
Periods Ended September 30	2002	2001	2002	2001
	June 30, 2004	Dec. 31, 2003
(Thousands)
Operating Revenues
Liabilities
Sales and services	$153,663	$200,229	$493,485	$622,861
Current Liabilities
Operating Expenses
Current portion of long-term debt	$3,007	$2,999
Electricity purchased and fuel used in generation	61,745	109,165	207,162	342,825
Notes payable	25,000	15,000
Other operating expenses	44,006	42,937	133,167	128,476
Accounts payable and accrued liabilities	53,211	45,815
Maintenance	8,828	9,594	28,985	30,342
Interest accrued	5,471	5,397
Depreciation and amortization	10,168	9,102	29,101	27,342
Taxes accrued	2,626	1,206
Other taxes	5,816	5,349	16,977	15,327
Other	24,192	48,322
Total Operating Expenses	130,563	176,147	415,392	544,312
Total Current Liabilities	113,507	118,739
Operating Income	23,100	24,082	78,093	78,549
Regulatory and Other Liabilities
Other (Income)	(1,322)	(1,818)	(3,815)	(5,382)
Regulatory liabilities
Other Deductions	301	1,661	944	3,142
Accrued removal obligation	84,096	80,128
Interest Charges, Net	6,794	7,060	21,735	20,125
Deferred income taxes	78,748	77,849
Income Before Income Taxes	17,327	17,179	59,229	60,664
Gain on sale of generation assets	58,674	76,998
Income Taxes	5,955	5,904	19,282	23,369
Other	21,708	17,127
Net Income	11,372	11,275	39,947	37,295
Total regulatory liabilities	243,226	252,102
Preferred Stock Dividends	361	361	1,082	1,082
Other liabilities
Earnings Available for Common Stock	$11,011	$10,914	$38,865	$36,213
Deferred income taxes	75,272	65,555
Nuclear plant obligations	160,322	173,548
Other postretirement benefits	75,258	73,181
Environmental remediation costs	2,867	3,017
Other	114,062	113,880
Total other liabilities	427,781	429,181
Total Regulatory and Other Liabilities	671,007	681,283
Long-term debt	313,046	314,511
Total Liabilities	1,097,560	1,114,533
Commitments	-	-
Preferred Stock Preferred stock	35,571	35,571
Common Stock Equity Common stock	156,057	156,057
Capital in excess of par value	482,882	482,794
Retained earnings	33,608	35,072
Accumulated other comprehensive (loss)	(17,174)	(17,174)
Total Common Stock Equity	655,373	656,749
Total Liabilities and Stockholder's Equity	$1,788,504	$1,806,853

The notes on pages 41 through 52 are an integral part of the financial statements.

Central Maine Power Company Consolidated Balance Sheets - (Unaudited)

Central Maine Power Company Condensed Consolidated Statements of Cash Flows - (Unaudited )
Six months ended June 30	2004	2003

(Thousands)
Net Cash Provided by Operating Activities	$42,853	$49,218

Investing Activities
Utility plant additions	(24,506)	(12,847)
Other	2,220	119

Net Cash Used in Investing Activities	(22,286)	(12,728)

Financing Activities
Long-term note repayments	(1,503)	(1,486)
Notes payable three months or less, net	10,000	-
Dividends on common and preferred stock	(25,721)	(25,721)

Net Cash Used in Financing Activities	(17,224)	(27,207)

Net (Decrease) Increase in Cash and Cash Equivalents	3,343	9,283
Cash and Cash Equivalents, Beginning of Period	11,627	20,415

Cash and Cash Equivalents, End of Period	$14,970	$29,698

The notes on pages 41 through 52 are an integral part of the financial statements.

	Sept. 30, 2002	Dec. 31, 2001
Central Maine Power Company Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Six months ended June 30	2004	2003
(Thousands)
Assets
Balance, Beginning of Period	$35,072	$31,682
Current Assets
Add net income	24,257	26,923
Cash and cash equivalents	$26,816	$20,777
	59,329	58,605
Accounts receivable, net	101,517	123,615
Deduct Dividends on Capital Stock
Materials and supplies, at average cost	8,634	9,018
Preferred	721	721
Accumulated deferred income tax benefits, net	-	74
Common	25,000	25,000
Prepayments and other current assets	10,962	10,439
	25,721	25,721
Total Current Assets	147,929	163,923
Balance, End of Period	$33,608	$32,884
Utility Plant, at Original Cost
Electric	1,316,910	1,312,778
Less accumulated depreciation	501,745	488,159
Net Utility Plant in Service	815,165	824,619
Construction work in progress	4,090	5,546
Total Utility Plant	819,255	830,165
Other Property	6,108	5,988
Investment in Associated Companies, at Equity	28,816	29,868
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	185,602	199,797
Unfunded future income taxes	95,453	90,471
Unamortized loss on debt reacquisitions	10,014	11,006
Demand-side management program costs	9,596	14,054
Environmental remediation costs	4,702	6,075
Nonutility generator termination agreement	7,508	7,619
Other	58,827	132,368
Total regulatory assets	371,702	461,390
Other assets
Goodwill, net	325,174	325,174
Prepaid pension benefits	26,803	29,886
Other	17,547	19,406
Total other assets	369,524	374,466
Total Regulatory and Other Assets	741,226	835,856
Total Assets	$1,743,334	$1,865,800

The notes on pages 41 through 52 are an integral part of the financial statements.

Central Maine Power Company Consolidated Balance Sheets - (Unaudited)

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

Periods ended June 30	2004	2003	2004	2003

(Thousands)
Net income	$3,430	$2,821	$24,257	$26,923
Other comprehensive income, net of tax
Net unrealized (losses) on derivatives qualified as hedges, net of income tax benefit of $- for the three months in 2004 and $624 in 2003, and $- for the six months in 2004 and $631 in 2003	-	(904)	-	(915)

Total other comprehensive income	-	(904)	-	(915)

Comprehensive Income	$3,430	$1,917	$24,257	$26,008

The notes on pages 41 through 52 are an integral part of the financial statements.

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

Sept. 30, 2002 Dec. 31, 2001
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt $63,073 $52,959
Notes payable 15,000 46,500
Accounts payable and accrued liabilities 39,011 64,104
Interest accrued 2,391 5,181
Taxes accrued 10,796 -
Other 42,420 40,206
Total Current Liabilities 172,691 208,950
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes 92,794 92,630
Gain on sale of generation assets 119,840 190,779
Pension benefits 6,903 7,355
Other 11,690 21,840
Total regulatory liabilities 231,227 312,604
Other liabilities
Deferred income taxes 32,762 17,385
Nuclear plant obligations 185,603 199,797
Other postretirement benefits 70,641 66,801
Environmental remediation costs 2,324 2,790
Other 81,808 119,575
Total other liabilities 373,138 406,348
Total Regulatory and Other Liabilities 604,365 718,952
Long-term debt 277,620 235,133
Total Liabilities 1,054,676 1,163,035
Commitments - -
Preferred Stock Redeemable solely at CMP's option Capital in excess of par value 35,571 (3,175) 35,571 (3,316)
Common Stock Equity Common stock 156,057 162,213
Capital in excess of par value 485,297 498,141
Retained earnings 17,056 31,304
Accumulated other comprehensive (loss) (2,148) (2,148)
Treasury stock, at cost - (19,000)
Total Common Stock Equity 656,262 670,510
Total Liabilities and Stockholder's Equity $1,743,334 $1,865,800
Central Maine Power Company Consolidated Statements of Cash Flows - (Unaudited
Nine Months Ended September 30 2002 2001
(Thousands)
Operating Activities
Net income $39,947 $37,295
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization 17,974 17,405
Income taxes and investment tax credits deferred, net 10,635 19,596
Pension expense 1,849 40
Changes in current operating assets and liabilities
Accounts receivable, net 24,662 12,693
Inventory 384 21
Prepayments and other current assets (523) (10,705)
Accounts payable and accrued liabilities (22,190) (13,647)
Interest accrued (2,790) (2,674)
Taxes accrued 10,796 -
Other current liabilities 6,965 (6,148)
Other assets (6,699) (19,212)
Other liabilities (15,127) (15,232)
Net Cash Provided by Operating Activities 65,883 19,432
Investing Activities
Utility plant additions (28,390) (34,362)
Other 128 (97)
Net Cash Used in Investing Activities (28,262) (34,459)
Financing Activities
Long-term note issuances 105,000 75,000
Long-term note repayments (50,887) (10,887)
Notes payable three months or less, net (13,000) (8,500)
Notes payable issuances 5,000 -
Notes payable repayments (23,500) -
Dividends on common and preferred stock (54,195) (46,067)
Net Cash (Used in) Provided by Financing Activities (31,582) 9,546
Net Increase (Decrease) in Cash and Cash Equivalents 6,039 (5,481)
Cash and Cash Equivalents, Beginning of Period 20,777 17,933
Cash and Cash Equivalents, End of Period $26,816 $12,452
Central Maine Power Company Consolidated Statements of Retained Earnings - (Unaudited)
Nine Months Ended September 30 2002 2001
(Thousands)
Balance, Beginning of Period $31,304 $23,291
Add net income 39,947 37,295
71,251 60,586
Deduct Dividends on Capital Stock
Preferred 1,082 1,082
Common 53,113 44,985
54,195 46,067
Balance, End of Period $17,056 $14,519
Central Maine Power Company Consolidated Statements of Comprehensive Income - (Unaudited)
Three Months Nine Months
Periods Ended September 30 2002 2001 2002 2001
(Thousands)
Net income $11,372 $11,275 $39,947 $37,295
Other comprehensive (loss), net of tax
Net unrealized (loss) on investments - (184) - -
Total other comprehensive (loss) - (184) - -
Comprehensive Income $11,372 $11,091 $39,947 $37,295
Item 2.
Central Maine Power Company
(a) Liquidity and Capital Resources
Restructuring ~~Initiative~~

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

Electric Delivery Business

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

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

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

CMP Collective Bargaining Agreement: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

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

CMP Nuclear Costs: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

Other Matters

~~Investing~~Accounting ~~and Financing Activities~~ Issues

~~(See~~FIN Energy East Corporation's Item 2(a), Investing Activities.) CMP's pension plans generated less than a million in pre-tax pension expense in 2001 (net of amounts capitalized). Through the first nine months of 2002, the plans generated $2 million in pre-tax pension expense (net of amounts capitalized), $2 million more than the first nine months of 2001.46R
: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 7 to the Condensed Financial Statements.)

~~Financing~~FASB ~~Activities~~Staff Position No. FAS 106-2
: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 9 to the Condensed Financial Statements.)

Investing Activities

Capital spending for the first six months of 2004 was $25 million. Capital spending is projected to be $50

million for 2004, and is expected to be paid for primarily with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

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

Central Maine Power Company
~~CMP~~(b) ~~issued~~Results ~~the following Series E Medium Term Notes, the proceeds~~ of ~~which were used to repay $50 million of maturing medium-term notes, as well as short-term debt and for general corporate purposes:~~Operations

On May 22, 2002, $37.5 million, 6.50%, due May 2009.

Three months ended June 30	2004	2003	Change

(Thousands)
Retail Deliveries - Megawatt-hours	2,124	2,110	1%
Operating Revenues	$129,748	$135,259	(4%)
Operating Expenses	$118,753	$124,223	(4%)
Operating Income	$10,995	$11,036	-
Earnings Available for Common Stock	$3,069	$2,460	25%

OnEarnings ~~May~~for ~~28,~~the ~~2002,~~quarter increased less than $~~37.5~~1 million~~, 6~~.~~65%,~~ ~~due~~A ~~May~~slight ~~2012~~decrease in operating income was offset by higher other income and lower interest expense.

OnOperating ~~August~~revenues ~~29,~~for ~~2002,~~the quarter decreased by $156 million, due primarily to rate reductions totaling $5~~.70%,~~ ~~due~~million ~~August~~reflecting ~~2012~~lower amortization of storm and demand-side management costs.

OnOperating ~~September~~expenses ~~10,~~decreased ~~2002,~~ $155 million, ~~4.25%,~~for the quarter primarily due ~~September~~to ~~2007~~lower amortization of ice storm and other costs of $4 million and lower NUG costs of $2 million.

Results of Operations

Six months ended June 30	2004	2003	Change

(Thousands)
Retail Deliveries - Megawatt-hours	4,459	4,373	2%
Operating Revenues	$292,498	$311,676	(6%)
Operating Expenses	$244,341	$255,895	(5%)
Operating Income	$48,157	$55,781	(14%)
Earnings Available for Common Stock	$23,536	$26,202	(10%)

Three months ended September 30 (Thousands)	2002	2001	Change
Retail Deliveries - Megawatt-hours	2,267	2,367	(4%)
Operating Revenues	$153,663	$200,229	(23%)
Operating Expenses	$130,563	$176,147	(26%)
Operating Income	$23,100	$24,082	(4%)
Earnings Available for Common Stock	$11,011	$10,914	1%

Earnings for the six months decreased $3 million compared to the prior year period primarily as a result of lower operating revenues.

~~CMP's~~Operating ~~earnings~~revenues for the ~~quarter~~six ~~were~~months ~~nearly~~decreased ~~unchanged~~$19 ~~compared~~million due primarily to ~~the~~a ~~prior~~$23 ~~year~~million decrease because of rate reductions reflecting mainly lower amortization of storm and demand-side management costs. That decrease was partially offset by an increase of $4 million for higher deliveries resulting from economic growth.

~~The~~Operating ~~$47~~expenses ~~million~~for ~~decrease~~the insix ~~operating~~months ~~revenues~~decreased ~~for~~$12 ~~the~~million ~~quarter~~primarily isdue ~~primarily~~to ~~the~~lower ~~result~~amortization of ~~CMP~~ice ~~not~~storm ~~being~~and ~~the~~other ~~standard-offer~~costs ~~provider~~of ~~for~~$8 ~~the~~million ~~supply~~and ofa ~~electricity~~decrease ~~effective~~ in ~~March~~other ~~2002,~~taxes ~~which~~of ~~reduced revenues by~~ $42 2 million.

Operating expenses decreased $46 million for the quarter, primarily due to a $42 million decrease in electricity purchased as a result of CMP not being the standard-offer provider for the supply of electricity effective in March 2002. Operating expenses also decreased $2 million due to the elimination of goodwill amortization in 2002.
Management's discussion and analysis of financial condition and results of operations
Central Maine Power Company
Nine months ended September 30 (Thousands) 2002 2001 Change
Retail Deliveries - Megawatt-hours 6,502 7,006 (7%)
Operating Revenues $493,485 $622,861 (21%)
Operating Expenses $415,392 $544,312 (24%)
Operating Income $78,093 $78,549 (1%)
Earnings Available for Common Stock $38,865 $36,213 7%
Earnings for the nine months increased approximately $3 million, primarily due to the elimination of goodwill amortization in 2002 of $6 million.
The $129 million decrease in operating revenues for the nine months is primarily the result of CMP not being the standard-offer provider for the supply of electricity effective in March 2002, which reduced revenues $111 million, and a $15 million decrease primarily due to lower industrial sales.
Operating expenses also decreased $129 million for the nine months, primarily due to a decrease in electricity purchased of $110 million as a result of CMP no longer being the standard-offer provider for the supply of electricity effective in March 2002 and $24 million primarily due to fewer purchases as a result of lower industrial sales. Operating expenses also decreased $6 million due to the elimination of goodwill amortization in 2002.
Item 1.
Financial Statements

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

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

Periods ended June 30	2004	2003	2004	2003

(Thousands)
Operating Revenues
Electric	$358,521	$338,353	$762,505	$744,320
Natural Gas	69,974	75,011	258,204	244,775

Total Operating Revenues	428,495	413,364	1,020,709	989,095

Operating Expenses
Electricity purchased	193,753	179,603	422,430	398,114
Natural gas purchased	41,452	43,569	173,747	150,626
Other operating expenses	51,642	52,685	110,984	100,499
Maintenance	19,195	17,034	34,095	38,430
Depreciation and amortization	25,849	25,063	51,214	49,995
Other taxes	25,669	25,291	56,081	60,664

Total Operating Expenses	357,560	343,245	848,551	798,328

Operating Income	70,935	70,119	172,158	190,767
Other (Income)	(216)	(184)	(172)	(2,108)
Other Deductions	454	(1,553)	172	(1,297)
Interest Charges, Net	18,597	21,022	37,398	40,360

Income Before Income Taxes	52,100	50,834	134,760	153,812
Income Taxes	21,204	20,911	50,947	63,272

Net Income	30,896	29,923	83,813	90,540
Preferred Stock Dividends	99	99	198	198

Earnings Available for Common Stock	$30,797	$29,824	$83,615	$90,342

The notes on pages 41 through 52 are an integral part of the financial statements.

	Three Months		Nine Months
New York State Electric & Gas Corporation Condensed Balance Sheets - (Unaudited)
Periods Ended September 30	2002	2001	2002	2001
	June 30, 2004		Dec. 31, 2003
(Thousands)
Operating Revenues
Assets
Electric	$389,216	$423,676	$1,184,687	$1,281,658
Current Assets
Natural gas	35,675	36,318	222,902	259,337
Cash and cash equivalents	$17,460		$14,458
Total Operating Revenues	424,891	459,994	1,407,589	1,540,995
Special deposits	5,094		30,353
Operating Expenses
Accounts receivable, net	237,317		290,166
Electricity purchased and fuel used in generation	229,019	223,243	642,269	618,559
Fuel, at average cost	26,815		43,207
Natural gas purchased	19,854	23,226	129,529	185,742
Materials and supplies, at average cost	6,052		5,893
Other operating expenses	42,259	59,858	150,380	176,654
Accumulated deferred income tax benefits, net	5,415		5,500
Maintenance	19,799	21,560	58,818	62,433
Prepayments	21,981		28,917
Depreciation and amortization	24,624	25,251	73,616	76,380
Total Current Assets	320,134		418,494
Other taxes	28,996	32,702	88,187	98,605
Utility Plant, at Original Cost
Total Operating Expenses	364,551	385,840	1,142,799	1,218,373
Electric	2,652,953		2,593,090
Operating Income	60,340	74,154	264,790	322,622
Natural gas	698,092		688,705
Other (Income)	(1,804)	(7,185)	(4,369)	(9,190)
Common	139,745		120,584
Other Deductions	3,142	777	20,393	4,248
	3,490,790		3,402,379
Interest Charges, Net	20,879	25,356	69,402	79,121
Less accumulated depreciation	1,183,927		1,144,385
Income Before Income Taxes	38,123	55,206	179,364	248,443
Net Utility Plant in Service	2,306,863		2,257,994
Income Taxes	14,827	23,099	73,303	103,520
Construction work in progress	12,749		55,638
Net Income	23,296	32,107	106,061	144,923
Total Utility Plant	2,319,612		2,313,632
Preferred Stock Dividends	99	99	297	297
Other Property and Investments, Net	37,886		37,872
Earnings Available for Common Stock	$23,197	$32,008	$105,764	$144,626
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes	44,261		42,366
Unamortized loss on debt reacquisitions	36,996		38,863
Environmental remediation costs	74,409		74,734
Deferred income taxes	63,794		71,095
Other	41,827		53,238
Total regulatory assets	261,287		280,296
Other assets
Goodwill, net	11,199		11,199
Prepaid pension benefits	474,770		450,817
Other	99,097		75,255
Total other assets	585,066		537,271
Total Regulatory and Other Assets	846,353		817,567
Total Assets	$3,523,985		$3,587,565

The notes on pages 41 through 52 are an integral part of the financial statements.

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

New York State Electric & Gas Corporation Condensed Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003

(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$338	$710
Notes payable	6,197	41,400
Accounts payable and accrued liabilities	143,611	148,918
Interest accrued	8,748	10,068
Taxes accrued	13,350	15,367
Other	27,904	74,819

Total Current Liabilities	200,148	291,282

Regulatory and Other Liabilities
Regulatory liabilities
Gain on sale of generation assets	52,809	52,642
Accrued removal obligation	314,463	304,065
Other	21,363	21,571

Total regulatory liabilities	388,635	378,278

Other liabilities
Deferred income taxes	532,176	522,919
Other postretirement benefits	214,795	208,393
Asset retirement obligation	382	377
Environmental remediation costs	97,075	97,400
Other	59,386	50,840

Total other liabilities	903,814	879,929

Total Regulatory and Other Liabilities	1,292,449	1,258,207

Long-term debt	1,065,829	1,065,590

Total Liabilities	2,558,426	2,615,079

Commitments	-	-
Preferred Stock Redeemable solely at NYSEG's option	10,159	10,159
Common Stock Equity Common stock	430,057	430,057
Capital in excess of par value	277,543	277,462
Retained earnings	212,663	229,048
Accumulated other comprehensive income	35,137	25,760

Total Common Stock Equity	955,400	962,327

Total Liabilities and Stockholder's Equity	$3,523,985	$3,587,565

The notes on pages 41 through 52 are an integral part of the financial statements.

	Sept. 30, 2002	Dec. 31, 2001
New York State Electric & Gas Corporation Condensed Statements of Cash Flows - (Unaudited)
Six months ended June 30	2004	2003
(Thousands)
Assets
Net Cash Provided by Operating Activities	$164,178	$107,090
Current Assets
Investing Activities
Cash and cash equivalents	$38,671	$21,617
Utility plant additions	(50,662)	(38,836)
Special deposits	14,388	1,432
Proceeds from sale of utility plant	-	211
Accounts receivable, net	215,532	292,687
Special deposits	25,259	(81,128)
Note receivable	-	12,126
Other	1	(17)
Fuel, at average cost	30,207	32,094
Net Cash Used in Investing Activities	(25,402)	(119,770)
Materials and supplies, at average cost	6,136	7,027
Financing Activities
Accumulated deferred income tax benefits, net	3,993	3,930
Notes payable three months or less, net	(35,203)	5,000
Prepayments	36,827	26,421
Repayments of first mortgage bonds, including net premiums	-	(74,390)
Total Current Assets	345,754	397,334
Long-term note issuances	(373)	196,986
Utility Plant, at Original Cost
Dividends on common and preferred stock	(100,198)	(90,198)
Electric	2,542,199	2,562,194
Net Cash Used in Financing Activities	(135,774)	37,398
Natural gas	665,901	654,224
Net Increase (Decrease) in Cash and Cash Equivalents	3,002	24,718
Common	121,099	132,928
Cash and Cash Equivalents, Beginning of Period	14,458	11,490
	3,329,199	3,349,346
Cash and Cash Equivalents, End of Period	$17,460	$36,208
Less accumulated depreciation	1,351,749	1,341,964
Net Utility Plant in Service	1,977,450	2,007,382
Construction work in progress	32,403	22,885
Total Utility Plant	2,009,853	2,030,267
Other Property and Investments, Net	41,846	43,242
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes	6,725	12,984
Unamortized loss on debt reacquisitions	32,113	42,959
Demand-side management program costs	-	4,083
Environmental remediation costs	52,667	53,167
Other	10,921	17,917
Total regulatory assets	102,426	131,110
Other assets
Goodwill, net	11,199	11,199
Prepaid pension benefits	396,820	334,769
Note receivable	-	47,553
Other	41,046	18,949
Total other assets	449,065	412,470
Total Regulatory and Other Assets	551,491	543,580
Total Assets	$2,948,944	$3,014,423

The notes on pages 41 through 52 are an integral part of the financial statements.

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

New York State Electric & Gas Corporation Condensed Statements of Retained Earnings - (Unaudited)
Six months ended June 30	2004	2003

(Thousands)
Balance, Beginning of Period	$229,048	$206,519
Add net income	83,813	90,540

	312,861	297,059
Deduct Dividends on Capital Stock
Preferred	198	198
Common	100,000	90,000

	100,198	90,198
Balance, End of Period	$212,663	$206,861

The notes on pages 41 through 52 are an integral part of the financial statements.

	Sept. 30, 2002	Dec. 31, 2001
New York State Electric & Gas Corporation Condensed Statements of Comprehensive Income - (Unaudited)
(Thousands)
	Three Months		Six Months
Liabilities
Periods ended June 30	2004	2003	2004	2003
Current Liabilities
(Thousands)
Current portion of long-term debt	$150,167	$150,873
Net income	$30,896	$29,923	$83,813	$90,540
Accounts payable and accrued liabilities	145,458	109,476
Other comprehensive income, net of tax
Interest accrued	19,661	15,967
Net unrealized gains on investments, net of income tax benefit for the three months of $- in 2004 and $(173) in 2003 and for the six months of $- in 2004 and $(166) in 2003	-	260	-	250
Taxes accrued	19,925	7,499
Unrealized (losses) gains on derivatives qualified as hedges, net of income tax benefit (expense) for the three months of $(4,712) in 2004 and $2,565 in 2003 and for the six months of $(17,229) in 2004 and $(16,184) in 2003	7,105	(3,868)	25,979	24,402
Other	72,884	65,268
Reclassification adjustment for derivative (gains) included in net income, net of income tax expense for the three months of $5,710 in 2004 and $2,563 in 2003 and for the six months of $11,010 in 2004 and $11,590 in 2003	(8,609)	(3,864)	(16,601)	(17,476)
Total Current Liabilities	408,095	349,083
Net unrealized (losses) gains on derivatives qualified as hedges	(1,504)	(7,732)	9,378	6,926
Regulatory and Other Liabilities
Total other comprehensive income	(1,504)	(7,472)	9,378	7,176
Regulatory liabilities
Comprehensive Income	$29,392	$22,451	$93,191	$97,716
Deferred income taxes	14,212	17,308
Gain on sale of generation assets	30,180	60,476
Other	33,672	29,810
Total regulatory liabilities	78,064	107,594
Other liabilities
Deferred income taxes	345,628	310,456
Other postretirement benefits	195,659	187,916
Environmental remediation costs	75,600	76,100
Other	74,874	85,126
Total other liabilities	691,761	659,598
Total Regulatory and Other Liabilities	769,825	767,192
Long-term debt	869,806	1,039,135
Total Liabilities	2,047,726	2,155,410
Commitments	-	-
Preferred Stock Redeemable solely at NYSEG's option	10,159	10,159
Common Stock Equity Common stock	430,057	430,057
Capital in excess of par value	277,297	270,835
Retained earnings	179,961	164,197
Accumulated other comprehensive income (loss)	3,744	(16,235)
Total Common Stock Equity	891,059	848,854
Total Liabilities and Stockholder's Equity	$2,948,944	$3,014,423

The notes on pages 41 through 52 are an integral part of the financial statements.

New York State Electric & Gas Corporation Statements of Cash Flows - (Unaudited
Nine Months Ended September 30 2002 2001
(Thousands)
Operating Activities
Net income $106,061 $144,923
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization 90,245 121,751
Income taxes and investment tax credits deferred, net 24,201 9,562
Pension income (53,116) (53,992)
Changes in current operating assets and liabilities
Accounts receivable, net 77,155 79,764
Sale of accounts receivable program - (152,000)
Inventory 2,778 (10,610)
Prepayments (10,406) (8,949)
Accounts payable and accrued liabilities 5,982 (59,123)
Interest accrued 3,694 11,149
Taxes accrued 12,426 24,034
Other current liabilities 7,616 (4,927)
Other assets (7,967) (4,446)
Other liabilities (5,343) (7,658)
Net Cash Provided by Operating Activities 253,326 89,478
Investing Activities
Utility plant additions (62,480) (52,009)
Note receivable, sale of generation assets 59,442 -
Proceeds from sale of utility plant 6,348 336
Special deposits (5,058) 19,916
Other 2,798 3,474
Net Cash Provided by (Used in) Investing Activities 1,050 (28,283)
Financing Activities
Equity contribution from parent - 100,000
Notes payable three months or less, net - (100,000)
Repayments of first mortgage bonds, including net premiums (177,025) -
Dividends on common and preferred stock (60,297) (65,839)
Net Cash Used in Financing Activities (237,322) (65,839)
Net Increase (Decrease) in Cash and Cash Equivalents 17,054 (4,644)
Cash and Cash Equivalents, Beginning of Period 21,617 17,618
Cash and Cash Equivalents, End of Period $38,671 $12,974
New York State Electric & Gas Corporation Statements of Retained Earnings - (Unaudited)
Nine Months Ended September 30 2002 2001
(Thousands)
Balance, Beginning of Period $164,197 $35,329
Add net income 106,061 144,923
270,258 180,252
Deduct Dividends on Capital Stock
Preferred 297 297
Common 90,000 65,542
90,297 65,839
Balance, End of Period $179,961 $114,413
New York State Electric & Gas Corporation Statements of Comprehensive Income - (Unaudited)
Three Months Nine Months
Periods Ended September 30 2002 2001 2002 2001
(Thousands)
Net income $23,296 $32,107 $106,061 $144,923
Other comprehensive income (loss), net of tax
Net unrealized (loss) gain on investments (653) (27) (1,191) 57
Minimum pension liability adjustment - - - 50
Unrealized gains (losses) on derivatives qualified as hedges
Unrealized gains on derivatives qualified as hedges arising during the period due to cumulative effect of a change in accounting principle - - - 54,602
Unrealized gains (losses) on derivatives qualified as hedges 7,541 (3,255) 11,792 (64,975)
Reclassification adjustment for losses on derivatives qualified as hedges included in net income 2,181 14,119 9,378 1,719
Net unrealized gains (losses) on derivatives qualified as hedges 9,722 10,864 21,170 (8,654)
Total other comprehensive income (loss) 9,069 10,837 19,979 (8,547)
Comprehensive Income $32,365 $42,944 $126,040 $136,376
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
~~Energy~~Restructuring ~~East Corporation and RGS Energy Merger~~

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

Electric Delivery Business

~~Transmission~~NYSEG's ~~Planning~~electric delivery business principally consists of its regulated transmission and ~~Expansion~~distribution operations. It also generates electricity primarily from its hydroelectric stations.

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

NYPSC-mandated Contracts with Customers
Nonutility Generation
Natural Gas Delivery Business

NYSEG's ~~Natural~~natural ~~Gas~~gas ~~Rate~~delivery ~~Filings~~business consists of its regulated transportation, storage and distribution operations.

Natural Gas Supply Agreements: See Energy East's Item 2(a), Natural Gas Delivery Business, for this discussion.

NYSEG Natural Gas Rate Plan: See Energy East's Item 2(a), Natural Gas Delivery Business, for this discussion.

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

NYPSC Collaborative on End State of Energy Competition
Other Matters

Accounting Issues

FIN 46R
: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 7 to the Condensed Financial Statements.)

FASB Staff Position No. FAS 106-2
: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 9 to the Condensed Financial Statements.)

Investing and Financing Activities
~~Management's~~Investing ~~discussion~~Activities: ~~and analysis of financial condition and results of operations~~
Capital spending for the first six months of 2004 was $51 million. Capital spending is projected to be $113 million for 2004 and is expected to be paid for primarily 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.

New York State Electric & Gas Corporation
(See Energy East Corporation's Item 2(a), Investing Activities.) NYSEG's pension plans generated $72 million in pre-tax pension income in 2001 (net of amounts capitalized). Through the first nine months of 2002 the plans generated $53 million in pre-tax pension income (net of amounts capitalized), $1 million less than the first nine months of 2001.
Financing Activities
: See Energy East's Item 2(a), NYSEG Financing Activities, for this discussion.

Additional financing needed by NYSEG to refund commercial paper that was used in October 2002 to repay $150 million of maturing 6 3/4% Series first mortgage bonds, is expected to be completed in November 2002. Through financial instruments issued in June 2002 NYSEG has locked in the five-year treasury rate component of the financing at an average rate of 4.246%.
Over the next several months, NYSEG plans to call its remaining first mortgage bonds: $100 million 8.30% Series first mortgage bonds callable on December 15, 2002, $50 million 7.55% Series first mortgage bonds callable on April 1, 2003, and $100 million 7.45% Series first mortgage bonds callable on July 15, 2003. Additional financing needed by NYSEG to call the $100 million 8.30% Series first mortgage bonds is expected to be completed in November 2002. Through financial instruments issued in August 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.19%. Additional financing needed by NYSEG to call the $50 million 7.55% Series and the $100 million 7.45% Series is expected to be completed in June 2003. Through financial instruments issued in September 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.085%.
Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation
(b) Results of Operations

Three months ended September 30 (Thousands)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Operating Revenues	$424,891	$459,994	(8%)
(Thousands)
Operating Income	$60,340	$74,154	(19%)
Operating Revenues	$428,495	$413,364	4%
Earnings Available for Common Stock	$23,197	$32,008	(28%)
Operating Income	$70,935	$70,119	1%
Earnings Available for Common Stock	$30,797	$29,824	3%

~~Earnings~~Second ~~for~~quarter ~~the~~2004 ~~quarter~~earnings ~~were~~increased $91 million ~~lower~~as ~~than~~compared ~~for~~to the prior year. ~~quarter~~An ~~primarily~~increase ~~due~~in ~~to an electric price reduction, effective March 1, 2002, that decreased~~ earnings ~~$25~~as ~~million.~~a ~~That~~result ~~decrease~~of ~~was partially offset by~~ higher ~~electric~~electricity deliveries ~~of $9 million~~ due to ~~warmer~~weather ~~summer~~was ~~weather~~substantially ~~and~~offset by $4a ~~million~~decrease ~~because~~in ofearnings ~~the~~due ~~elimination~~to oflower ~~regulatory~~natural ~~amortization~~gas ofwholesale ~~demand-side management program costs~~deliveries.

Nine months ended September 30 (Thousands)	2002	2001	Change
Six months ended June 30	2004	2003	Change
Operating Revenues	$1,407,589	$1,540,995	(9%)
(Thousands)
Operating Income	$264,790	$322,622	(18%)
Operating Revenues	$1,020,709	$989,095	3%
Earnings Available for Common Stock	$105,764	$144,626	(27%)
Operating Income	$172,158	$190,767	(10%)
Earnings Available for Common Stock	$83,615	$90,342	(7%)

Earnings ~~for~~decreased ~~the nine months were~~ $397 million ~~lower than~~ for the ~~same~~six ~~period~~months ~~last year~~ primarily due to anlower ~~electric~~deliveries ~~price~~in ~~reduction, effective March 1, 2002, that decreased earnings $47 million and a $10 million loss from~~ the ~~early~~first ~~retirement~~quarter ofbecause ~~debt. (See Note 7 to NYSEG's Financial Statements.) Those decreases were partially offset by lower costs~~ of ~~natural gas purchases of $10 million, higher electric deliveries of $9 million due to~~ warmer ~~summer~~winter weather ~~and~~in ~~$4 million of interest savings due to the early retirement of debt~~2004. ~~(See Financing Activities.)~~

Management's discussion and analysis of financial condition and results of operations
New York State Electric & Gas Corporation
Operating Results for the Electric Delivery Business

Three months ended September 30 (Thousands)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Retail Deliveries - Megawatt-hours	3,752	3,496	7%
(Thousands)
Operating Revenues	$389,216	$423,676	(8%)
Retail Deliveries - Megawatt-hours	3,472	3,362	3%
Operating Expenses	$323,493	$341,001	(5%)
Operating Revenues	$358,521	$338,353	6%
Operating Income	$65,723	$82,675	(21%)
Operating Expenses	$293,592	$276,011	6%
Operating Income	$64,929	$62,342	4%

The $3420 million ~~decrease~~increase in operating revenues for the quarter iswas primarily due to aincreased ~~price~~retail ~~reduction,~~deliveries ~~effective~~of ~~March 1, 2002, that decreased revenues~~ $4110 million and ~~lower~~higher wholesale ~~deliveries~~revenues of $219 million. ~~Those decreases were partially offset by increased retail deliveries of $26 million due to warmer summer weather.~~

Operating expenses ~~for~~increased ~~the quarter decreased~~ $18 million. ~~Expenses~~for ~~were~~the ~~reduced~~quarter ~~$21~~primarily ~~million~~ due to ~~lower~~higher ~~wholesale deliveries and $6 million due to the elimination of a regulatory amortization of demand-side management program costs, partially offset by an $11 million increase in~~ purchased power costs ~~for~~of ~~higher retail deliveries due to warmer summer weather. A~~ $1714 million ~~increase~~as ~~for purchased power costs to replace energy previously provided by NMP2 was partially offset by~~ a ~~$10~~result ~~million~~of ~~decrease~~higher inretail ~~certain~~and ~~operating~~wholesale ~~expenses primarily due to the sale of NMP2~~sales.

Nine months ended September 30 (Thousands) 2002 2001 Change
Retail Deliveries - Megawatt-hours 10,813 10,563 2%
Operating Revenues $1,184,687 $1,281,658 (8%)
Operating Expenses $943,825 $963,785 (2%)
Operating Income $240,862 $317,873 (24%)
The $97 million decrease in operating revenues for the nine months is primarily due to a price reduction, effective March 1, 2002, that decreased revenues $77 million and lower wholesale revenues of $53 million due to lower market prices and lower deliveries. Those decreases were partially offset by increased retail deliveries of $26 million due to warmer summer weather.
Operating expenses decreased $20 million for the nine months due to lower market prices for electricity of $30 million and $14 million due to the elimination of a regulatory amortization of demand-side management program costs. Those decreases were partially offset by $11 million for electricity purchased that was deferred in accordance with the electric rate settlement and by an $11 million increase in purchased power costs for higher retail deliveries due to warmer summer weather. A $36 million increase for purchased power costs to replace energy previously provided by NMP2 was partially offset by a $31 million decrease in certain operating expenses due to the sale of NMP2.
Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Six months ended June 30	2004	2003	Change

(Thousands)
Retail Deliveries - Megawatt-hours	7,448	7,408	1%
Operating Revenues	$762,505	$744,320	2%
Operating Expenses	$626,937	$600,753	4%
Operating Income	$135,568	$143,567	(6%)

The $18 million increase in operating revenues for the six months was primarily due to higher retail deliveries of $4 million, increased wholesale revenues of $8 million and an $8 million increase in transmission revenues.

Operating expenses increased $26 million for the six months primarily due to higher purchased power costs of $21 million as a result of higher deliveries.

Operating Results for the Natural Gas Delivery Business

Three months ended September 30 (Thousands)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Retail Deliveries - Dekatherms	6,653	6,939	(4%)
(Thousands)
Operating Revenues	$35,675	$36,318	(2%)
Retail Deliveries - Dekatherms	10,096	11,301	(11%)
Operating Expenses	$41,058	$44,839	(8%)
Operating Revenues	$69,974	$75,011	(7%)
Operating Income	$(5,383)	$(8,521)	37%
Operating Expenses	$63,968	$67,234	(5%)
Operating Income	$6,006	$7,777	(23%)

Operating revenues decreased $5 million for the quarter ~~did~~primarily ~~not~~as ~~change~~a ~~significantly~~result ~~compared~~of an $8 million reduction due to ~~the~~lower ~~prior~~retail ~~year~~deliveries and an $5 million decrease in wholesale revenues. Those decreases were partially offset by higher revenues of $8 million as a result of higher market prices that were passed on to customers.

Operating expenses decreased $43 million for the quarter, primarily due to alower ~~decrease in the cost of~~ natural gas ~~purchased~~purchases ~~as a result~~ of ~~lower~~$2 ~~natural gas prices due to market conditions~~million.

Nine months ended September 30 (Thousands)	2002	2001	Change
Six months ended June 30	2004	2003	Change
Retail Deliveries - Dekatherms	39,435	40,676	(3%)
(Thousands)
Operating Revenues	$222,902	$259,337	(14%)
Retail Deliveries - Dekatherms	35,440	37,809	(6%)
Operating Expenses	$198,974	$254,588	(22%)
Operating Revenues	$258,204	$244,775	5%
Operating Income	$23,928	$4,749	404%
Operating Expenses	$221,614	$197,575	12%
Operating Income	$36,590	$47,200	(22%)

~~The~~Operating revenues increased $3613 million ~~decrease in operating revenues~~ for the ~~nine~~six months is primarily due to ~~lower~~higher ~~market~~natural gas prices of ~~gas~~$43 million that ~~are~~were passed on to ~~nonresidential~~customers. ~~and~~This ~~wholesale~~increase ~~customers~~was ofsomewhat offset by a $31 15 million decrease because of lower wholesale sales, and ~~decreased~~a ~~deliveries~~$15 ~~because~~million ofdecrease ~~mild~~due ~~winter~~to ~~weather~~lower retail deliveries because of $9warmer ~~million~~weather.

Operating expenses ~~decreased $56 million~~ for the ~~nine~~six months increased $24 million primarily due to ahigher ~~decrease in the cost of~~ natural gas ~~purchased~~purchases of $4723 million; asreflecting ahigher ~~result of lower natural gas~~ prices ~~due~~offset toby ~~market conditions and a decrease in gas purchases of $9 million for~~ lower ~~deliveries~~purchase volumes.

Item 1.
Financial Statements

Rochester Gas and Electric Corporation Statements of Income - (Unaudited

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

Periods ended June 30	2004	2003	2004	2003

(Thousands)
Operating Revenues
Electric	$160,209	$166,384	$324,393	$342,678
Natural Gas	63,520	62,228	212,682	212,628

Total Operating Revenues	223,729	228,612	537,075	555,306

Operating Expenses
Electricity purchased and fuel used in generation	43,161	34,025	69,792	76,458
Natural gas purchased	35,092	33,545	134,174	131,250
Other operating expenses	34,266	64,846	90,736	155,328
Maintenance	13,183	14,017	28,461	27,450
Depreciation and amortization	31,984	25,688	67,977	52,913
Other taxes	18,929	19,457	38,969	43,792
Gain on sale of generation assets	(319,487)	-	(319,487)	-
Deferral of asset sale gain	214,368	-	214,368	-

Total Operating Expenses	71,496	191,578	324,990	487,191

Operating Income	152,233	37,034	212,085	68,115
Other (Income)	(7,437)	(423)	(8,100)	(2,541)
Other Deductions	1,570	815	1,943	963
Interest Charges, Net	13,696	12,405	27,800	46,387

Income Before Income Taxes	144,404	24,237	190,442	23,306
Income Taxes	115,475	9,564	135,573	7,143

Net Income	28,929	14,673	54,869	16,163
Preferred Stock Dividends	1,315	925	1,828	1,850

Earnings Available for Common Stock	$27,614	$13,748	$53,041	$14,313

The notes on pages 41 through 52 are an integral part of the financial statements.

	Three Months		Nine Months
Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
Periods Ended September 30	2002	2001	2002	2001
	June 30, 2004	Dec. 31, 2003
(Thousands)
Operating Revenues
Assets
Electric	$198,429	$194,201	$534,986	$559,819
Current Assets
Natural gas	32,939	34,639	193,480	225,604
Cash and cash equivalents	$265,626	$13,596
Total Operating Revenues	231,368	228,840	728,466	785,423
Special deposits	-	3,706
Operating Expenses
Accounts receivable, net	121,075	156,038
Electricity purchased and fuel used in generation	57,707	48,153	153,427	115,226
Advance to affiliate	25,000	-
Natural gas purchased	15,692	20,694	108,794	140,532
Fuel, at average cost	28,727	29,310
Other operating expenses	65,155	86,911	202,241	195,824
Materials and supplies, at average cost	8,683	7,016
Maintenance	10,368	13,122	42,545	41,452
Accumulated deferred income tax benefits, net	20,831	12,154
Depreciation and amortization	25,990	29,064	76,120	86,033
Prepayments and other current assets	9,323	13,232
Other taxes	21,034	20,109	67,540	67,362
Total Current Assets	479,265	235,052
Total Operating Expenses	195,946	218,053	650,667	646,429
Utility Plant, at Original Cost
Operating Income	35,422	10,787	77,799	138,994
Electric	1,197,468	2,060,980
Other (Income)	(5,590)	(3,510)	(13,411)	(10,317)
Natural gas	548,144	522,409
Other Deductions	318	5,824	6,154	17,483
Common	174,283	158,804
Interest Charges, Net	15,319	15,771	42,523	46,531
	1,919,895	2,742,193
Income (Loss) Before Income Taxes	25,375	(7,298)	42,533	85,297
Less accumulated depreciation	505,687	1,271,462
Income Taxes (Benefit)	8,088	(13,634)	21,527	24,558
Net Utility Plant in Service	1,414,208	1,470,731
Net Income	17,287	6,336	21,006	60,739
Construction work in progress	38,005	160,595
Preferred Stock Dividends	925	925	2,775	2,775
Total Utility Plant	1,452,213	1,631,326
Earnings Available for Common Stock	$16,362	$5,411	$18,231	$57,964
Other Property and Investments, Net	13,280	287,385
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	218,556	240,884
Unfunded future income taxes	-	50,265
Environmental remediation costs	12,247	11,475
Unamortized loss on debt reacquisitions	3,541	-
Nonutility generator termination agreement	96,076	100,687
Asset retirement obligation	-	163,530
Other	152,172	174,998
Total regulatory assets	482,592	741,839
Other assets
Prepaid pension benefits	28,033	16,524
Other	36,796	48,704
Total other assets	64,829	65,228
Total Regulatory and Other Assets	547,421	807,067
Total Assets	$2,492,179	$2,960,830

The notes on pages 41 through 52 are an integral part of the financial statements.

Rochester Gas and Electric Corporation Balance Sheets - (Unaudited)

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	June 30, 2004	Dec. 31, 2003

(Thousands)
Liabilities
Current Liabilities
Current portion of preferred stock subject to mandatory redemption requirements	-	$1,250
Accounts payable and accrued liabilities	$131,065	77,476
Interest accrued	10,552	11,540
Taxes accrued	71,976	24,130
Other	52,806	29,642

Total Current Liabilities	266,399	144,038

Regulatory and Other Liabilities
Regulatory liabilities
Unfunded future income taxes	87,379	-
Accrued removal obligation	169,618	185,472
Deferred income taxes	5,471	186,571
Gain from sale of generation assets	127,403	-
Other	37,851	46,173

Total regulatory liabilities	427,722	418,216

Other liabilities
Deferred income taxes	170,865	72,568
Nuclear waste disposal	104,699	104,095
Other postretirement benefits	73,664	71,956
Environmental remediation costs	26,357	22,356
Asset retirement obligation	2,171	436,096
Other	45,925	39,831

Total other liabilities	423,681	746,902

Total Regulatory and Other Liabilities	851,403	1,165,118

Preferred stock subject to mandatory redemption requirements	-	23,750
Other long-term debt	736,563	826,511

Total long-term debt	736,563	850,261

Total Liabilities	1,854,365	2,159,417

Commitments	-	-
Preferred Stock
Redeemable solely at the option of RG&E	-	47,000
Common Stock Equity
Common stock	194,429	194,429
Capital in excess of par value	556,550	556,190
Retained earnings	4,073	121,032
Treasury stock, at cost	(117,238)	(117,238)

Total Common Stock Equity	637,814	754,413

Total Liabilities and Stockholder's Equity	$2,492,179	$2,960,830

The notes on pages 41 through 52 are an integral part of the financial statements.

	Sept. 30, 2002	Dec. 31, 2001
Rochester Gas and Electric Corporation Condensed Statements of Cash Flows - (Unaudited)
Six months ended June 30	2004	2003
(Thousands)
Assets
Net Cash Provided by Operating Activities	$85,551	$139,955
Current Assets
Investing Activities
Cash and cash equivalents	$33,655	$20,631
Proceeds from sale of generation assets	428,541	-
Accounts receivable, net	95,820	114,768
Refund of excess decommissioning fund	76,593	-
Notes receivable	-	10,097
Advance to affiliate	(25,000)	-
Affiliate receivable	14,457	87,139
Utility plant additions	(32,361)	(40,044)
Fuel, at average cost	25,705	27,005
Nuclear generating plant decommissioning fund	(8,560)	(8,662)
Materials and supplies, at average cost	9,003	5,244
Other	3,706	(2,052)
Prepayments and other current assets	49,425	22,153
Net Cash Provided by (Used in) Investing Activities	442,919	(50,758)
Total Current Assets	228,065	287,037
Financing Activities
Utility Plant, at Original Cost
Repayments of first mortgage bonds and preferred stock	(162,000)	(40,000)
Electric	1,901,270	1,862,805
Outstanding customer refund, overdraft	57,388	-
Natural gas	507,538	496,594
Repayment of promissory notes	-	(79,935)
Common	158,173	133,825
Dividends on common and preferred stock	(171,828)	(31,850)
	2,566,981	2,493,224
Net Cash Used in Financing Activities	(276,440)	(151,785)
Less accumulated depreciation	1,507,558	1,454,283
Net Increase (Decrease) in Cash and Cash Equivalents	252,030	(62,588)
Net Utility Plant in Service	1,059,423	1,038,941
Cash and Cash Equivalents, Beginning of Period	13,596	86,385
Construction work in progress	153,541	141,591
Cash and Cash Equivalents, End of Period	$265,626	$23,797
Total Utility Plant	1,212,964	1,180,532
Other Property and Investments, Net	211,886	222,860
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	319,155	327,221
Unfunded future income taxes	64,406	64,203
Environmental remediation costs	11,618	12,588
Nonutility generator termination agreement	163,052	169,838
Other	121,467	122,910
Total regulatory assets	679,698	696,760
Other assets
Prepaid pension benefits	23,570	-
Note receivable	-	40,387
Other	55,669	37,085
Total other assets	79,239	77,472
Total Regulatory and Other Assets	758,937	774,232
Total Assets	$2,411,852	$2,464,661

The notes on pages 41 through 52 are an integral part of the financial statements.

Rochester Gas and Electric Corporation Balance Sheets - (Unaudited)

Rochester Gas and Electric Corporation Condensed Statements of Retained Earnings - (Unaudited)
Six months ended June 30	2004	2003

(Thousands)
Balance, Beginning of Period	$121,032	$154,267
Add net income	54,869	16,163

	175,901	170,430
Deduct Dividends on Capital Stock
Preferred	1,828	1,850
Common	170,000	30,000

	171,828	31,850
Balance, End of Period	$4,073	$138,580

The notes on pages 41 through 52 are an integral part of the financial statements.

Sept. 30, 2002 Dec. 31, 2001
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt $84,639 $104,387
Accounts payable and accrued liabilities 73,864 75,885
Affiliate payable 2,408 26,871
Interest accrued 16,910 12,338
Taxes accrued 1,696 4,381
Other 43,656 49,617
Total Current Liabilities 223,173 273,479
Regulatory and Other Liabilities
Regulatory liabilities
Deferred income taxes 29,747 30,393
Other 43,473 27,645
Total regulatory liabilities 73,220 58,038
Other liabilities
Deferred income taxes 231,590 223,659
Nuclear waste disposal 102,319 101,268
Other postretirement benefits 64,265 60,238
Environmental remediation costs 22,356 22,356
Other 84,924 109,246
Total other liabilities 505,454 516,767
Total Regulatory and Other Liabilities 578,674 574,805
Long-term debt 828,794 787,243
Total Liabilities 1,630,641 1,635,527
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 505,889 505,889
Retained earnings 126,131 174,054
Treasury stock, at cost (117,238) (117,238)
Total Common Stock Equity 709,211 757,134
Total Liabilities and Stockholder's Equity $2,411,852 $2,464,661
Rochester Gas and Electric Corporation Statements of Cash Flows - (Unaudited)
Nine Months Ended September 30 2002 2001
(Thousands)
Operating Activities
Net income $21,006 $60,739
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization 120,903 119,573
Income taxes and investment tax credits deferred, net (6,925) 664
Pension income (15,768) (16,837)
Writedown of investments 13,718 -
Changes in current operating assets and liabilities
Accounts receivable, net 34,564 57,007
Notes receivable, current - (19,954)
Inventory (2,459) (4,692)
Prepayments (27,272) (13,567)
Accounts payable and accrued liabilities 1,996 19,162
Interest accrued 4,572 2,381
Taxes accrued (2,685) (2,556)
Other current liabilities (6,599) (14,116)
Other assets (30,971) (8,318)
Other liabilities 10,253 13,191
Net Cash Provided by Operating Activities 114,333 192,677
Investing Activities
Utility plant additions (96,583) (93,437)
Note receivable, sale of generation assets 50,484 -
Other property and investments additions (13,012) (15,661)
Other (5,996) (6,224)
Net Cash Used in Investing Activities (65,107) (115,322)
Financing Activities
Repayments of first mortgage bonds and preferred stock of subsidiaries, including net premiums (100,000) (104,470)
Long-term debt issuances, net of discount or premiums 125,000 199,534
Notes payable three months or less, net - (98,000)
Notes payable repayments (3,260) (3,026)
Dividends on common and preferred stock (57,942) (49,423)
Other - 190
Net Cash Used in Financing Activities (36,202) (55,195)
Net Increase in Cash and Cash Equivalents 13,024 22,160
Cash and Cash Equivalents, Beginning of Period 20,631 4,851
Cash and Cash Equivalents, End of Period $33,655 $27,011
Rochester Gas and Electric Corporation Statements of Retained Earnings - (Unaudited)
Nine Months Ended September 30 2002 2001
(Thousands)
Balance, Beginning of Period $174,054 $166,184
Add net income 21,006 60,739
195,060 226,923
Deduct Dividends on Capital Stock
Preferred 2,775 2,775
Common 66,154 46,648
68,929 49,423
Adjustment - 190
Balance, End of Period $126,131 $177,690
Item 2.
Management's discussion and analysis of financial condition
and results of operations

Rochester Gas and Electric Corporation
(a) Liquidity and Capital Resources

~~Energy East Corporation and RGS Energy Merger~~ Restructuring

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

Electric Delivery Business

~~Transmission~~RG&E's ~~Planning~~electric delivery business consists of its regulated transmission and ~~Expansion~~distribution operations. It also generates electricity from its one coal-fired plant, three gas turbines and several smaller hydroelectric stations.

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

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

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

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

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

RG&E 2002 Electric and Gas Rate Proceeding
Ginna Station
Ginna Relicensing
Natural Gas Delivery Business

~~NYPSC~~RG&E's ~~Collaborative~~natural ongas ~~End~~delivery ~~State~~business consists of ~~Energy~~its ~~Competition~~regulated transportation, storage and distribution operations.

Natural Gas Supply Agreements: See Energy East's Item 2(a), Natural Gas Delivery Business, for this discussion.

RG&E 2003 Electric and Natural Gas Rate Agreements

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

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

Other Matters

Accounting Issues

FASB Staff Position No. FAS 106-2
: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 9 to the Condensed Financial Statements.)

Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation

after June 15, 2002. RG&E is currently in the process of measuring any asset retirement obligations. The adoption of Statement 143 is not expected to have a material effect on RG&E's results of operations.
Statement 146
Investing and Financing Activities
~~(See Energy East Corporation's Item 2(a),~~ Investing Activities.) RG&E's pension plans generated $23 million in pre-tax pension income in 2001 (net of amounts capitalized). Through the first nine months of 2002 the plans generated $16 million in pre-tax pension income (net of amounts capitalized), $1 million less than the first nine months of 2001.
: Capital spending for the first six months of 2004 was $32 million, including nuclear fuel. Capital spending is projected to be $123 million for 2004, including nuclear fuel, and is expected to be paid for primarily with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

Financing Activities
: See Energy East's Item 2(a), RG&E Financing Activities, for this discussion.

(b) Results of Operations

Three months ended September 30 (Thousands)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Operating Revenues	$231,368	$228,840	1%
(Thousands)
Operating Income	$35,422	$10,787	228%
Operating Revenues	$223,729	$228,612	(2%)
Earnings Available for Common Stock	$16,362	$5,411	202%
Operating Income	$152,233	$37,034	311%
Earnings Available for Common Stock	$27,614	$13,748	101%

Earnings increased $14 million for the ~~third~~ quarter primarily due to one-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements, which increased earnings $1110 million. ~~primarily~~The ~~due~~one-time toeffects ~~increased~~include ~~electric~~the ~~retail~~flow-through ~~deliveries~~of excess deferred taxes and investment tax credits and the elimination of $6certain ~~million~~reserves ~~due~~established topending ~~warmer~~regulatory ~~summer~~determination. ~~weather~~Ongoing effects from RG&E's Electric and aNatural Gas Rate Agreements added $47 million ~~reduction~~to ~~because~~earnings, and include increases as a result of ~~merger~~RG&E's ~~costs~~electric ~~incurred~~retail access surcharge and natural gas merchant function charge, and annual credits to RG&E from the ASGA as provided in the ~~prior~~Electric ~~year~~Rate ~~quarter~~Agreement. (See

RG&E 2003 Electric and Natural Gas Rate Agreements.)

Nine months ended September 30 (Thousands)	2002	2001	Change
Six months ended June 30	2004	2003	Change
Operating Revenues	$728,466	$785,423	(7%)
(Thousands)
Operating Income	$77,799	$138,994	(44%)
Operating Revenues	$537,075	$555,306	(3%)
Earnings Available for Common Stock	$18,231	$57,964	(69%)
Operating Income	$212,085	$68,115	211%
Earnings Available for Common Stock	$53,041	$14,313	271%

Earnings for the ~~nine~~six months ~~ended~~increased ~~September 30, 2002 decreased~~ $4039 million primarily due to ~~lower~~ ~~wholesale~~the ~~electric~~second ~~revenues~~quarter effects of ~~$18~~the ~~million~~sale ~~largely~~of ~~due~~Ginna toand ~~lower~~RG&E's ~~wholesale~~Electric ~~market~~and ~~prices,~~Natural anGas ~~electric~~Rate ~~price~~Agreements ~~reduction,~~discussed ~~effective~~above ~~July~~that 1,added ~~2001,~~$17 ~~that~~million ~~decreased~~to earnings $8and ~~million,~~the arecognition $9of ~~million~~the ~~writedown~~terms and conditions of ~~software~~the ~~development~~NYPSC ~~costs~~rate ~~that~~order ~~management~~for ~~determined~~RG&E, towhich ~~have~~became noeffective ~~future~~in ~~economic~~January ~~value~~2003, and ~~higher~~reduced ~~replacement~~earnings ~~power~~by ~~costs of~~ $730 million ~~due~~in tothe afirst ~~scheduled~~quarter ~~refueling~~of ~~outage~~2003. atThe ~~the~~January ~~Ginna~~2003 ~~nuclear~~rate ~~plant.~~order ~~There~~included ~~was~~$26 nomillion ~~refueling~~for ~~outage~~excess inearnings ~~2001~~and related interest.

Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Operating Results for the Electric Delivery Business

Three months ended September 30 (Thousands)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Retail Deliveries - Megawatt-hours	2,031	1,875	8%
(Thousands)
Operating Revenues	$198,429	$194,201	2%
Retail Deliveries - Megawatt-hours	1,699	1,669	2%
Operating Expenses	$158,095	$175,924	(10%)
Operating Revenues	$160,209	$166,384	(4%)
Operating Income	$40,334	$18,277	121%
Operating Expenses	$14,603	$136,048	(89%)
Operating Income	$145,606	$30,336	380%

The $46 million ~~increase~~decrease in operating revenues for the quarter is primarily due to ~~increased~~a ~~retail~~change ~~deliveries~~in ofmarket ~~$10~~structure ~~million~~that ~~due~~allows ESCOs to ~~warmer~~provide ~~summer~~electricity, ~~weather~~which ~~partially~~reduced ~~offset~~retail revenues by ~~lower~~$41 million and increased wholesale revenues ofby $527 million. ~~primarily~~That ~~due~~decrease towas ~~lower~~partially ~~market~~offset ~~prices~~by higher retail deliveries that added $3 million to revenues.

Operating expenses decreased $18121 million for the quarter primarily due to aRG&E's ~~$20~~recognition ~~million~~of ~~decrease in accelerated amortization associated with~~ a ~~NMP2 regulatory asset, lower nonfuel operating expenses of~~ $5319 million ~~associated~~pretax ~~with~~gain on the Ginna sale, ofpartially offset by RG&E's ~~interest~~deferral inof ~~NMP2~~the ingain ~~November~~net ~~2001,~~of ~~and~~tax ~~lower operating expenses~~ of $3214 million. ~~associated~~The ~~with~~remaining ~~the~~$16 ~~establishment~~million ofreduction awas ~~regulatory~~primarily ~~asset~~the ~~related~~result toof ~~RG&E's~~lower ~~property~~electricity ~~tax~~purchases ~~sharing~~as ~~mechanisms~~a ~~and~~result $2of ~~million due to~~ the ~~elimination~~change ofin ~~certain~~market ~~regulatory~~structure ~~asset~~and ~~amortizations~~the ~~effective~~net ~~July~~effects 1,of ~~2002.~~the ~~Those~~Ginna ~~decreases~~sale ~~were~~that ~~partially~~reduced ~~offset~~operating byexpenses ~~higher~~and increased purchased power costs ~~of $13 million~~.

Nine months ended September 30 (Thousands)	2002	2001	Change
Six months ended June 30	2004	2003	Change
Retail Deliveries - Megawatt-hours	5,468	5,243	4%
(Thousands)
Operating Revenues	$534,986	$559,819	(4%)
Retail Deliveries - Megawatt-hours	3,439	3,450	-
Operating Expenses	$471,598	$439,138	7%
Operating Revenues	$324,393	$342,678	(5%)
Operating Income	$63,388	$120,681	(47%)
Operating Expenses	$144,345	$309,196	(53%)
Operating Income	$180,048	$33,482	438%

~~The~~Operating ~~$25 million decrease in operating~~ revenues for the ~~nine~~six months isdecreased ~~primarily due to lower wholesale revenues of~~ $2818 million ~~largely~~ due toa ~~lower~~change in market ~~prices~~structure ~~and~~that aallows ~~price~~ESCOs ~~reduction,~~to ~~effective~~provide ~~July 1~~electricity, ~~2001,~~which ~~that~~ reduced retail revenues by $1277 million. ~~Those~~and ~~decreases~~increased ~~are~~wholesale ~~partially~~revenues ~~offset~~ by ~~increased retail deliveries of~~ $1555 million ~~primarily due to warmer summer weather~~.

~~The~~Operating expenses decreased $32165 million ~~increase~~for inthe ~~operating~~six ~~expenses is~~ primarily due to ~~higher~~RG&E's ~~purchased~~recognition ~~power costs~~ of a $44319 million aspretax again ~~result~~on ofthe ~~electricity~~Ginna ~~now~~sale, ~~being~~partially ~~purchased~~offset ~~instead~~by ofRG&E's ~~generated~~deferral ~~due~~of to the ~~sale~~gain net of ~~NMP2~~tax inof ~~November~~$214 ~~2001~~million. ~~and~~An ~~replacement~~additional ~~power~~decrease ~~that~~of ~~was~~$30 ~~needed~~million ~~during~~resulted from the ~~scheduled~~recognition ~~refueling~~ of the ~~Ginna~~terms ~~nuclear~~and ~~plant~~conditions ~~earlier~~of ~~this~~the ~~year.~~NYPSC ~~There~~rate ~~was~~order nofor ~~refueling~~RG&E, ~~outage~~which inbecame ~~2001.~~effective Ain ~~$10~~January ~~million~~2003, ~~writedown~~and ofincreased ~~software~~operating ~~development~~expenses ~~costs~~by ~~that~~$30 ~~management~~million ~~determined~~in to2003. ~~have~~The noremaining ~~future~~$25 ~~economic~~million ~~value~~reduction ~~also~~was ~~contributed~~primarily to the ~~increase.~~result ~~Those~~of ~~increases~~lower ~~were~~electricity ~~partially~~purchases ~~offset~~as by a ~~$20~~result ~~million~~of ~~decrease~~the change in ~~accelerated~~market ~~amortization~~structure, ~~associated~~and ~~with~~the anet ~~NMP2~~effects ~~regulatory~~of ~~asset~~the ~~and~~Ginna asale ~~$13~~that ~~million~~reduced ~~decrease in other~~ operating expenses ~~due~~and toincreased ~~the~~purchased ~~sale~~power ~~of NMP2~~costs.

Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Operating Results for the Natural Gas Delivery Business

Three months ended September 30 (Thousands)	2002	2001	Change
Three months ended June 30	2004	2003	Change
Retail Deliveries - Dekatherms	5,067	5,109	(1%)
(Thousands)
Operating Revenues	$32,939	$34,639	(5%)
Retail Deliveries - Dekatherms	8,529	9,314	(8%)
Operating Expenses	$37,851	$42,129	(10%)
Operating Revenues	$63,520	$62,228	2%
Operating (Loss)	$(4,912)	$(7,490)	34%
Operating Expenses	$56,893	$55,530	2%
Operating Income	$6,627	$6,698	(1%)

Operating revenues ~~decreased~~increased $21 million for the quarter. ~~primarily~~Higher ~~due~~market toprices afor $1natural ~~million~~gas ~~decrease~~purchased ~~because~~ of ~~lower~~$9 ~~market~~million ~~prices of gas~~ that ~~are~~were passed on to customers ~~and~~were ~~lower~~offset ~~retail~~by lower deliveries ~~because~~that ofreduced ~~warmer~~revenues ~~weather of~~ $17 million.

Operating expenses ~~decreased~~increased $41 million for the quarter primarily due to ahigher $5market ~~million~~prices ~~decrease~~for inpurchased ~~the~~natural ~~cost~~gas ofthat ~~purchased~~were ~~natural~~offset ~~gas~~by fewer purchases because of lower deliveries.

Nine months ended September 30 (Thousands)	2002	2001	Change
Six months ended June 30	2004	2003	Change
Retail Deliveries - Dekatherms	34,957	35,292	(1%)
(Thousands)
Operating Revenues	$193,480	$225,604	(14%)
Retail Deliveries - Dekatherms	32,677	34,347	(5%)
Operating Expenses	$179,069	$207,291	(14%)
Operating Revenues	$212,682	$212,628	-
Operating Income	$14,411	$18,313	(21%)
Operating Expenses	$180,645	$177,995	1%
Operating Income	$32,037	$34,633	(7%)

~~The~~Operating ~~$32~~revenues ~~million~~remained ~~decrease~~relatively inflat ~~operating revenues~~ for the ~~nine~~six months. isHigher ~~primarily~~market ~~due~~prices tofor anatural ~~$29 million~~gas ~~decrease~~purchased ~~because~~ of ~~lower~~$13 ~~market~~million ~~prices of gas~~ that ~~are~~were passed on to customers ~~and~~were ~~lower~~offset ~~retail~~by lower deliveries ~~because~~that ofreduced ~~warmer~~revenues ~~weather of~~ $313 million.

Operating expenses ~~decreased~~increased $283 million for the quarter primarily due to ahigher ~~decrease~~market inprices ~~the~~for ~~cost of~~ purchased natural gas ofthat ~~$32~~were ~~million mainly due to lower natural gas prices, which was partially~~ offset by alower $4operating ~~million writedown of software development~~ costs ~~that management determined to have no future economic value~~.

Item 1.
Financial Statements
Notes to Condensed Financial Statements for Energy East Corporation Central Maine Power Company New York State Electric & Gas Corporation Rochester Gas and Electric Corporation

Notes to Condensed Financial Statements of Registrants:

Registrant	Applicable Notes
Energy East	1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11~~, 12~~
CMP	1, 2, 3, 4, 7, 8, 109, 1110, 1211
NYSEG	1, 2, 3, 4, 5, 7, 8, 109, 1110, 1211
RG&E	1, 2, 3, 4, 58, 79, 8, 10, 11~~, 12, 13~~

Note 1. Unaudited Condensed Financial Statements

The accompanying unaudited condensed 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. The year-end condensed balance sheet data presented in this quarterly report was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

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

The accompanying unaudited financial statements for each registrant should be read in conjunction with the financial statements and notes contained in the report on Form 10-K filed by each registrant for the year ended December 31, ~~2001~~2003. 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. Subsequent Event - Restructuring Initiative~~ Reclassifications
: Certain amounts have been reclassified in the company's unaudited financial statements to conform to the 2004 presentation and to reflect discontinued operations.

~~The~~Note ~~company announced on October 24, 2002, a voluntary early retirement program for salaried employees of its six operating utilities~~2. ~~Approximately~~Sale ~~550 employees are eligible for the program, including about 220 from NYSEG, 190 from RG&E, 60 from CMP, and a total~~ of ~~about~~Ginna 80Nuclear ~~from~~Generating Berkshire Gas, CNG and SCG. The savings from this initiative are essential for the company to meet the rate reduction or efficiency targets imputed in utility rates by regulators, as well as to meet the expectations of customers and investors.Station

InOn ~~addition~~June to10, ~~the voluntary early retirement program~~2004, ~~an involuntary severance program will be utilized by the operating companies~~ after ~~they~~receiving ~~determine~~all ~~the~~regulatory ~~additional~~approvals, ~~positions~~RG&E ~~that~~sold ~~must~~Ginna ~~be eliminated~~ to ~~achieve optimum organizational efficiency and effectiveness~~CGG. ~~The~~RG&E ~~employees~~received ~~affected~~at byclosing ~~the~~$429 ~~involuntary~~million ~~program~~in ~~will~~cash. beThe ~~notified~~gain inon the ~~first~~sale ~~quarter~~ of ~~2003.~~Ginna ~~Energy East expects to incur a one-time restructuring charge~~ of ~~between~~ $~~50-$100~~319 million innet ~~the~~of ~~fourth~~income ~~quarter~~taxes of ~~2002, including~~ $~~5-$10~~105 million ~~for~~equals ~~CMP,~~the $~~20-$35~~214 million ~~for~~deferral ~~NYSEG,~~of ~~$25-$45~~asset ~~million~~sale ~~for RG&E and the remainder for Berkshire Gas~~gain, ~~CNG~~as ~~and~~reflected ~~SCG.~~on ~~All or a portion of NYSEG's and~~ RG&E's ~~restructuring~~statement ~~costs~~of ~~may be deferred in accordance with the NYPSC order approving the RGS Energy merger~~income.

~~Note~~RG&E's 3Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna, including providing for an ASGA, established at the time of closing in the amount of $357 million, and addressing the disposition of the asset sale gain. ~~Accounts~~Upon ~~Receivable~~ closing of the Ginna sale, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. RG&E retained $77 million in excess decommissioning funds, which was credited to customers as part of the ASGA.

~~Accounts~~A ~~receivable~~summary onof ~~the~~information ~~balance~~on ~~sheets for~~ the ~~companies~~sale ~~include unbilled revenues as follows: Energy East - consolidated unbilled revenues~~ of ~~$135~~Ginna ~~million at September 30, 2002,~~ and ~~$143~~the ~~million~~related atASGA ~~December 31, 2001; CMP - consolidated unbilled revenues of $26 million~~ at ~~September~~the ~~30,~~time ~~2002, and $32 million at December 31, 2001; NYSEG - unbilled revenues~~ of ~~$49 million~~the atsale ~~September~~follows ~~30,~~(in ~~2002, and $74 million at December 31, 2001; RG&E - unbilled revenues of $34 million at September 30, 2002, and $51 million at December 31, 2001.~~thousands):

Note 4. Supplemental Disclosure of Cash Flows Information

Cash proceeds	$428,541
Net book value of property sold, excluding decommissioning reserve	(184,564)
Decommissioning reserve	311,571
Decommissioning funds	(277,113)
Excess decommissioning funds retained	76,593
Miscellaneous assets and liabilities, including deferred selling costs	(35,541)

Gain on sale of generation assets, deferred	319,487
Income taxes payable	(105,119)

Deferral of asset sale gain	214,368
Regulatory liability equal to deferred income taxes on the deferred asset sale gain	143,000

Balance at closing, Gain from sale of generation assets, deferred	$357,368

	2002	2001
(Thousands)
Cash paid during the nine months ended September 30:
Interest, net of amounts capitalized Energy East CMP NYSEG RG&E	$138,577 $21,523 $60,927 $35,793	$139,871 $20,277 $64,313 $42,500
Income taxes, net of benefits received Energy East CMP NYSEG RG&E	$20,744 $(6,405) $44,113 $39,947	$87,690 $11,427 $64,112 $47,818
RG&E's dividend declared to pay off net intercompany accounts receivable/payable	$26,586	-
Energy East's Acquisition of RGS Energy:
Fair value of assets acquired	$3,264,093	-
Liabilities assumed	(1,826,528)	-
Preferred stock of subsidiary	(72,000)	-
Common stock issued	(612,082)	-
Cash acquired	(72,086)	-
Net cash paid for acquisition	$681,397	-

The ASGA was adjusted subsequent to the sale to reflect provisions of RG&E's Electric Rate Agreement, including refunds due to customers. Adjustments to the ASGA to reconcile to the balance of the deferred regulatory liability as of June 30, 2004, were as follows (in thousands):

Note 5. Acquisition of RGS Energy Group

Gain from sale of generation assets, deferred	$357,368
Regulatory liability equal to deferred income taxes on the deferred asset sale gain	(143,000)
Refund to customers June 2004	(60,003)
Refund to customers January 2005 - Other current liability	(24,997)
Other	(1,965)

Balance at June 30, 2004, Gain from sale of generation assets	$127,403

OnIn ~~June 28~~addition, ~~2002,~~ the company's ~~acquired~~and ~~all~~RG&E's ofeffective ~~the~~tax ~~outstanding~~rate ~~common~~was ~~stock~~significantly ofaffected ~~RGS~~by ~~Energy~~the ~~Group,~~sale ~~Inc. for a combination~~ of ~~cash and Energy East common stock~~Ginna. ~~The~~Due ~~company's~~to ~~consolidated~~the ~~balance~~regulatory ~~sheet~~accounting ~~included~~for ~~RGS~~the ~~Energy's~~gain ~~consolidated~~on ~~balance~~the ~~sheet at June 30~~sale, ~~2002.~~any ~~The~~gain ~~company's~~in ~~consolidated~~excess ~~statements~~ of ~~income~~what ~~and~~was ~~cash~~required ~~flows~~to ~~include~~offset ~~RGS~~income ~~Energy's~~taxes ~~results~~payable ofon ~~operations~~the ~~beginning~~sale ~~with~~was ~~July~~required ~~2002.~~to ~~RGS~~be ~~Energy~~deferred. Therefore, ~~through~~RG&E ~~its~~recorded ~~regulated~~pretax ~~subsidiary~~income ~~Rochester~~of ~~Gas~~$105,119 and ~~Electric~~income ~~Corporation,~~tax ~~engages~~expense inof ~~generating~~$105,119 ~~purchasing,~~resulting ~~and delivering electricity and purchasing and delivering natural gas~~ in ana ~~area~~100% ~~centered~~effective ~~around~~tax ~~the~~rate ~~city~~on ofthis ~~Rochester~~income, ~~New~~increasing ~~York.~~the ~~Through~~effective ~~its~~tax ~~unregulated~~rate ~~subsidiary,~~from ~~Energetix,~~an ~~Inc.,~~expected ~~RGS~~rate ~~Energy~~of ~~engages~~39% infor ~~retail~~the ~~electric,~~company ~~natural gas~~ and ~~liquid~~41% ~~fuel~~for ~~businesses~~RG&E, ~~throughout~~to ~~upstate~~an ~~New~~effective ~~York.~~rate Inof ~~connection~~56% ~~with~~for ~~Energy~~the ~~East's~~company ~~merger~~and ~~with~~71% ~~RGS~~for ~~Energy, NYSEG became a wholly-owned subsidiary of RGS Energy~~RG&E.

~~The~~Note ~~company's merger with RGS Energy results in the company serving over half of upstate New York~~3. The company believes that the complementary operations of its companies and their common vision for upstate New York will lead to attractive returns for its shareholders and a stable energy supply and excellent service for its customers. The company expects that annual cost savings for anticipated synergies resulting from joint management of procurement, information technology and other administrative and general areas can be obtained to the benefit of both customers and investors.Restructuring

~~Under~~The ~~the~~company ~~merger~~recognized ~~agreement~~a ~~45%~~$4 ofmillion ~~the~~total ~~RGS~~liability ~~Energy~~for ~~common~~an ~~stock~~enhanced ~~(15.6~~severance ~~million~~program ~~shares)~~for ~~was~~83 ~~converted~~accounting ~~into~~and 27finance employees who were employed through March 31, 2004.5 ~~million~~During ~~shares~~the offourth ~~Energy~~quarter ~~East~~of ~~common~~2003, ~~stock~~40%, ~~valued~~or atapproximately $~~612~~2 million., ~~The value~~ of the ~~shares~~estimated ~~issued~~liability was ~~determined~~charged ~~based~~to onother ~~the~~operating ~~market~~expenses ~~price~~and ofrepresented ~~Energy~~the ~~East~~company's ~~stock~~cumulative atexpense ~~the~~and ~~end~~liability as of ~~the~~December ~~day on June 27~~31, ~~2002~~2003. The remaining ~~55%~~$2 million of the ~~RGS~~liability ~~Energy~~was ~~common~~charged ~~stock~~to ~~was~~other ~~exchanged~~operating ~~for~~expenses in the first quarter of 2004. The total liability includes $~~753~~0.9 million infor ~~cash~~CMP, ($390.509 ~~per~~million ~~RGS~~for ~~Energy~~NYSEG ~~share)~~and $1.4 ~~The~~million ~~purchase~~for ~~price~~RG&E. Approximately $3 million of the total cost was ~~about~~incurred by the electric delivery business and $1 million by the natural gas delivery business.4 ~~billion,~~The ~~which~~liability ~~includes~~was ~~$11~~paid ~~million~~off as of ~~merger-related~~June ~~costs~~30, 2004.

~~The~~Note following table summarizes the components of the purchase price and preliminary allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition4. ~~RGS~~Other ~~Energy~~(Income) did not push goodwill down to its subsidiaries. As of June 30, 2002, $29 million was allocated to intangible assets based on a preliminary appraisal. The allocation of the purchase price will be adjusted when final appraisals are received, RG&E's electric and ~~gas~~Other ~~rate~~Deductions ~~cases are finalized and actual amounts for estimated liabilities become known.~~

Calculation of purchase price for assets acquired
	Three Months		Six Months
(Thousands)
Periods ended June 30	2004	2003	2004	2003
Cash paid for stock purchased	$753,483
(Thousands)
Stock issued	612,082
Energy East
Merger-related fees and expenses	11,000
Interest income	$(959)	$(1,086)	$(1,365)	$(2,355)
Total purchase price for common equity	1,376,565
Allowance for funds used during construction	(160)	(422)	(262)	(966)
Plus fair market value of liabilities and preferred stock assumed
Gains from the sale of nonutility property	(1,159)	(5)	(1,236)	(59)
Current and other liabilities	883,502
Earnings from equity investments	(852)	(884)	(2,557)	(2,542)
Long-term debt	932,026
2003 RG&E Electric and Natural Gas Rate Agreement	(6,117)	-	(6,117)	-
Preferred stock	72,000
Miscellaneous	(2,434)	119	(5,872)	(888)
Total liabilities and preferred stock	1,887,528
Total other (income)	$(11,681)	$(2,278)	$(17,409)	$(6,810)
Total purchase price for assets acquired	$3,264,093
Losses from disposition of property	$3,474	-	$4,048	-
Allocation of purchase price for assets acquired
Miscellaneous	924	$1,261	3,627	$3,048
Property, plant and equipment	$1,203,282
Total other deductions	$4,398	$1,261	$7,675	$3,048
Goodwill	633,736
CMP
All other assets, including working capital and intangibles	1,427,075
Interest income	$(20)	$(162)	$(34)	$(418)
Total	$3,264,093
Earnings from equity investments	(217)	(480)	(513)	(1,018)
Miscellaneous	(795)	(119)	(1,536)	(312)
Total other (income)	$(1,032)	$(761)	$(2,083)	$(1,748)
Miscellaneous	$164	$420	$299	$799
Total other deductions	$164	$420	$299	$799
NYSEG
Interest income	$(58)	$(274)	$(119)	$(652)
Miscellaneous	(158)	90	(53)	(1,456)
Total other (income)	$(216)	$(184)	$(172)	$(2,108)
Miscellaneous	$454	$(1,553)	$172	$(1,297)
Total other deductions	$454	$(1,553)	$172	$(1,297)
RG&E
Interest income	$(794)	$(236)	$(462)	$(1,947)
2003 RG&E Electric and Natural Gas Rate Agreement	(6,117)	-	(6,117)	-
Miscellaneous	(526)	(187)	(1,521)	(594)
Total other (income)	$(7,437)	$(423)	$(8,100)	$(2,541)
Losses from disposition of property	$3,158	-	$3,158	-
Miscellaneous	(1,588)	$815	(1,215)	$963
Total other deductions	$1,570	$815	$1,943	$963

~~The~~Note following pro forma information for the company for the nine months ended September 30, 2002 and for the three months and nine months ended September 30, 2001, which is based on unaudited data, gives effect to the company's merger with RGS Energy as if it had been completed at the beginning of each period presented5. ~~This~~Basic ~~information does not reflect future revenues or cost savings that may result from the merger~~ and isDiluted ~~not~~Earnings ~~indicative~~per ~~of actual results of operations had the merger occurred at the beginning of the periods presented or of results that may occur in the future.~~Share

	Three Months		Nine Months
Periods ended September 30	2002	2001	2002	2001
(Thousands, except per share amounts)
Operating revenues	$1,016,189	$1,124,612	$3,449,661	$4,100,977
Net income (loss)	$23,742	$(15,248)	$149,402	$186,389
Earnings per share of common stock	$.16	$(.11)	$1.03	$1.29

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

~~Pro~~The ~~forma~~reconciliation ~~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~~basic to the accounting base recognized in recording the combination, (3) elimination of amortization of goodwill, (4) amortization of other intangible assets with finite lives, (5) elimination of merger costs, (6) additional interest expense and ~~preferred~~dilutive ~~stock~~average ~~dividends due to the issuance of merger-related debt and securities, (7) adjustments for estimated tax effects of the above adjustments and (8) additional~~ common shares issued in connection with the merger. The pro forma results include losses of two cents per share on the sale of Berkshire Service Solutions in the third quarter of 2002 and eight cents per share from NYSEG's early retirement of debt during the nine months ended September 30, 2002, and losses from the writedown of CMP Group's investment in NEON Communications of six cents per share during the nine months ended September 30, 2002, and 39 cents per share during the nine months ended September 30, 2001. The pro forma results of operations for ~~the~~each ~~nine~~period ~~months ended September 30, 2002, include the results of operations of RGS Energy for the six months ended June 30, 2002, as~~ follows: ~~Operating revenues - $681,571; Operating expenses - $615,851, Operating income - $65,720; Income before income taxes - $36,850; and Net income - $15,550.~~

Note 6. Basic and Diluted Earnings per Share

	Three Months		Six Months

Periods ended June 30	2004	2003	2004	2003

(Thousands)
Basic average common shares outstanding	146,148	145,415	146,116	145,256
Restricted stock awards	448	225	396	173
Potentially dilutive common shares	302	107	266	127
Options issued with SARs	(302)	(107)	(266)	(127)

Dilutive average common shares outstanding	146,596	145,640	146,512	145,429

~~Basic~~Options ~~earnings~~to ~~per~~purchase ~~share (EPS) is determined by dividing net income by the weighted-average number of~~ shares of common stock ~~outstanding~~are ~~during~~excluded from the ~~period.~~determination ~~The~~of ~~weighted-average common shares outstanding for diluted~~ EPS ~~include~~when the ~~incremental~~exercise ~~effect~~price of ~~stock~~an ~~options~~option ~~issued~~is ~~and~~greater ~~exclude~~than ~~stock~~the ~~options~~average ~~issued~~market inprice ~~tandem~~of ~~with~~a ~~stock~~common ~~appreciation~~share ~~rights~~during ~~(SARs)~~the period. ~~All~~Shares ~~stock~~excluded ~~options~~from ~~are~~the ~~issued~~EPS incalculation ~~tandem~~for ~~with~~the ~~SARs~~three ~~and,~~months ~~historically,~~ended ~~substantially~~June ~~all~~30 ~~stock~~were: ~~option~~0.7 ~~plan~~million ~~participants~~in ~~have~~2004 ~~exercised~~and ~~the SARs instead of the stock options~~5.2 ~~The~~million ~~numerator used~~ in ~~calculating~~2003, ~~both basic~~ and ~~diluted EPS~~ for ~~each~~the ~~period~~six ismonths ~~the~~ended ~~reported~~June ~~net~~30 ~~income~~were: 1.3 ~~The~~million ~~reconciliation~~in of2004 ~~basic~~ and ~~diluted~~5.2 ~~EPS~~million ~~for~~in ~~each period follows:~~2003.

	Three Months		Nine Months
Periods Ended September 30	2002	2001	2002	2001
(Thousands)
Numerator
Net Income (Loss)	$23,742	$(21,057)	$134,634	$121,118
Denominator
Basic average common shares outstanding	144,621	116,436	126,489	116,737
Potentially dilutive common shares	391	298	368	170
Options issued with SARs	(391)	(298)	(368)	(170)
Dilutive average common shares	144,621	116,436	126,489	116,737
EPS - basic	$.16	$(.18)	$1.06	$1.04
EPS - diluted	$.16	$(.18)	$1.06	$1.04

During the first quarter of 2004 the company awarded 242,038 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of $6 million based on the market price per share of common stock on the dates of the awards, which averaged $23.90.

~~Options~~Note ~~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~~6. ~~Shares~~Discontinued excluded from the EPS calculation for the periods ended September 30 were: for the quarter, 2.1 million in 2002 and 1.9 million in 2001; and for the nine months, 2.1 million in 2002 and 2.4 million in 2001.Operations

~~Note~~In 7keeping with its focus on regulated electric and natural gas delivery businesses, during recent years the company has been systematically exiting certain noncore businesses. ~~Other~~In ~~(Income)~~June 2004 UWP, a subsidiary of CMP Group, Inc., reached an agreement to sell the assets associated with its utility locating and construction divisions. The sale was completed on July 26, 2004. In 2003 Berkshire Propane, Inc., a subsidiary of Berkshire Energy Resources, sold its assets and Energetix, a subsidiary of RGS Energy Group, Inc. which is a wholly-owned subsidiary of Energy East, sold its Griffith Oil Co., Inc. All three businesses were previously reported in the company's Other ~~Deductions~~business segment. Certain financial information concerning the businesses for the three months and six months ended June 30, 2004 and 2003, is shown in the table below.

	Three Months		Six Months	~~Nine Months~~
Periods Ended September 30	2002	2001		2002	2001
Periods ended June 30	2004	2003	2004	2003
(Thousands)
Energy East
Certain Divisions of Union Water Power Co.
Interest income	$(3,698)	$(4,583)		$(11,611)	$(10,231)
Revenues	$8,157	$6,969	$13,175	$10,432
Non-cash return	(2,316)	(538)		(4,433)	(1,516)
Income (loss) from businesses held for sale (including estimated loss on disposal in 2004 of $5,500)	$(4,249)	$619	$(4,527)	$(1,375)
Allowance for Funds Used During Construction	(1,083)	(183)		(1,222)	(461)
Income taxes (benefits)	467	100	346	(712)
Gains from the sale of nonutility property	(7)	(417)		(219)	(3,350)
Income (loss) from discontinued operations	$(4,716)	$519	$(4,873)	$(663)
Earnings from equity investments	(1,196)	(1,087)		(3,607)	(5,840)
Griffith Oil Co., Inc.
Miscellaneous	(1,371)	(3,163)		(1,710)	(3,823)
Revenues	-	$83,922	-	$211,544
Other (income)	$(9,671)	$(9,971)		$(22,802)	$(25,221)
Income (loss) from businesses sold	-	$(1,503)	-	$5,916
NYSEG early retirement of debt	-	-		$16,145	-
Income taxes (benefits)	-	(671)	-	2,107
Fees on sale of accounts receivable	-	$48		-	$2,494
Income (loss) from discontinued operations	-	$(832)	-	$3,809
Miscellaneous	$4,631	5,076		9,655	8,785
Berkshire Propane, Inc.
Other deductions	$4,631	$5,124		$25,800	$11,279
Revenues	-	$1,041	-	$4,472
CMP
Income (loss) from businesses sold	-	$(17)	-	$517
Interest income	$(461)	$(376)		$(883)	$(1,506)
Income taxes	-	286	-	506
Earnings from equity investments	(702)	(645)		(1,903)	(1,906)
Income (loss) from discontinued operations	-	$(303)	-	$11
Miscellaneous	(159)	(797)		(1,029)	(1,970)
Other (income)	$(1,322)	$(1,818)		$(3,815)	$(5,382)
Miscellaneous	$301	$1,661		$944	$3,142
Other deductions	$301	$1,661		$944	$3,142
NYSEG
Interest income	$(765)	$(1,355)		$(4,052)	$(2,582)
Dividend income	-	(1,844)		-	(1,844)
Miscellaneous	(1,039)	(3,986)		(317)	(4,764)
Other (income)	$(1,804)	$(7,185)		$(4,369)	$(9,190)
Early retirement of debt	-	-		$16,145	-
Fees on sale of accounts receivable	-	$48		-	$2,494
Miscellaneous	$3,142	729		4,248	1,754
Other deductions	$3,142	$777		$20,393	$4,248
RG&E
Interest income	$(1,192)	$(1,087)		$(3,841)	$(3,003)
Non-cash return	(2,159)	(2,183)		(6,495)	(6,567)
Miscellaneous	(2,239)	(240)		(3,075)	(747)
Other (income)	$(5,590)	$(3,510)		$(13,411)	$(10,317)
Merger costs	$221	$5,314		$4,314	$13,393
Miscellaneous	97	510		1,840	4,090
Other deductions	$318	$5,824		$6,154	$17,483

Note 87. ~~Goodwill~~FIN ~~and Other Intangible Assets~~ 46R

~~Effective~~In ~~January~~December 1,2003 ~~2002,~~the ~~Energy~~FASB ~~East,~~issued ~~CMP~~its ~~and~~revised ~~NYSEG~~FASB ~~adopted~~Interpretation ~~Statement~~No. 46, Consolidation of ~~Financial~~Variable ~~Accounting~~Interest ~~Standards~~Entities, an interpretation of ARB No. ~~142,~~51 ~~Goodwill~~(FIN ~~and~~46R). ~~Other~~FIN ~~Intangible~~46R ~~Assets~~addresses consolidation of variable interest entities. AsA ~~required~~variable byinterest ~~Statement~~entity ~~142~~is ~~the~~an ~~companies~~entity ~~are~~that nois ~~longer~~not ~~amortizing~~controllable ~~goodwill~~through voting interests and/or ~~are~~in ~~not~~which ~~amortizing~~the ~~intangible~~equity ~~assets~~investor ~~with~~does ~~indefinite~~not ~~lives~~bear ~~(unamortized~~the ~~intangible~~residual ~~assets)~~economic risks and rewards. ~~Both~~FIN ~~goodwill~~46R ~~and~~requires ~~unamortized~~a ~~intangible~~business ~~assets~~enterprise ~~are~~to ~~tested~~consolidate ata ~~least~~variable ~~annually~~interest ~~for~~entity ~~impairment.~~if ~~Intangible~~that ~~assets~~enterprise ~~with~~has ~~finite~~a ~~lives~~variable ~~are~~interest ~~amortized~~that ~~(amortized~~will ~~intangible~~absorb ~~assets)~~a ~~and~~majority ~~are~~of ~~reviewed~~the ~~for~~entity's ~~impairment~~expected losses. ~~RG&E~~The ~~has~~company nowas ~~goodwill~~required to apply FIN 46R to all entities subject to the interpretation as of March 31, 2004.

~~The~~CMP ~~companies~~and ~~determined~~NYSEG ~~that~~have ~~there~~independent, ~~was~~ongoing, nopower ~~impairment~~purchase ofcontracts ~~goodwill~~with various nonutility generators (NUGs). (See report on Form 10-K for Energy East, CMP orand NYSEG asfor offiscal ~~January~~year 1ended December 31, ~~2002.~~2003, ~~There~~Item ~~was~~7 no- ~~reclassification~~Liquidity ofand ~~goodwill~~Capital toResources, ~~intangible~~Contractual ~~assets~~Obligations and noCommercial ~~reclassification~~Commitments.) ofCMP ~~intangible~~and ~~assets~~NYSEG towere ~~goodwill~~not asinvolved in the formation of ~~January~~and 1,do ~~2002.~~not ~~Annual~~have ~~impairment~~ownership ~~testing~~interests ~~was~~in ~~also~~any ~~completed~~NUGs. ~~for~~The ~~Energy~~company ~~East,~~evaluated each of CMP's and NYSEG's ~~and~~power itpurchase ~~was~~contracts with NUGs with respect to FIN 46R. Most of the power purchase contracts were determined ~~that~~not ~~there~~to ~~was~~be novariable ~~impairment~~interests due to one of ~~goodwill~~the following reasons: the contract is based on a fixed price or ~~unamortized~~a ~~intangible~~market ~~assets~~price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for ~~any~~a minor portion of ~~those~~the ~~three~~NUG's ~~companies~~capacity ator ~~September~~the ~~30,~~NUGs ~~2002~~are either governmental organizations or individuals.

The ~~carrying~~companies ~~amount~~are ofnot ~~goodwill~~able onto apply FIN 46R to seven remaining NUGs because they are unable to obtain the ~~companies'~~information ~~balance~~necessary ~~sheets,~~to: by(1) ~~operating~~determine ~~segment~~if the NUGs are variable interest entities, as(2) determine if either CMP or NYSEG is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of ~~September~~the ~~30,~~seven ~~2002~~NUGs. CMP requested necessary information from four NUGs and NYSEG requested information from three NUGs. Three of the NUGs responded but none provided the requested information. The companies will continue to make efforts to obtain information, ~~is:~~including from the four NUGs that did not respond to the request.

(Thousands)	Electric Delivery	Natural Gas Delivery	Other	Total
Energy East	$825,109	$665,467	$28,995	$1,519,571
CMP	$325,174	-	-	$325,174
NYSEG	-	$11,199	-	$11,199

The companies purchase electricity from the seven NUGs at above-market prices. CMP and NYSEG are not exposed to any loss as a result of their involvement with NUGs because they are allowed to recover through rates the cost of their purchases. Also, they are under no obligation to a NUG if it decides not to operate for any reason. The combined contractual capacity for the four NUGS from which CMP purchases electricity is approximately 22 MW. CMP's purchases from the four NUGs totaled $7 million for the six months ended June 30, 2004, and $5 million for the six months ended June 30, 2003. The combined contractual capacity for the three NUGS from which NYSEG purchases electricity is approximately 494 MW. NYSEG's purchases from the three NUGs totaled $172 million for the six months ended June 30, 2004, and $169 million for the six months ended June 30, 2003.

~~Other~~CMP ~~Intangible~~and ~~Assets:~~NYSEG did not consolidate any NUGs as of June 30, 2004.

~~CMP's~~Note ~~amortized intangible assets primarily consist of technology rights, and had a gross carrying amount and accumulated amortization of less than $0~~8.3 ~~million~~Accounts ~~at September 30, 2002, and December 31, 2001.~~ Receivable

~~NYSEG's~~Accounts ~~unamortized~~receivable ~~intangible~~for ~~assets~~the ~~primarily~~companies ~~consist~~include ofunbilled ~~franchises~~revenues ~~and~~as ~~consents,~~follows: ~~and~~Energy ~~had~~East a- ~~carrying~~consolidated ~~amount~~unbilled revenues of $~~0.9~~86 million at ~~September~~June 30, ~~2002~~2004, and $219 million at December 31, ~~2001.~~2003; ~~NYSEG's~~CMP ~~amortized~~- ~~intangible~~consolidated ~~assets~~unbilled ~~consist~~revenues of ~~hydroelectric~~$13 ~~licenses~~million at June 30, 2004, and ~~had~~$25 amillion ~~gross~~at ~~carrying~~December ~~amount~~31, 2003; NYSEG - unbilled revenues of $~~1.5~~43 million at June 30, 2004, and ~~accumulated~~$72 ~~amortization~~million at December 31, 2003; RG&E - unbilled revenues of $~~0.9~~ 20 million at ~~September~~June 30, ~~2002~~2004, and $50 million at December 31, ~~2001~~2003.

~~RG&E's~~Note ~~amortized intangible assets consist of water rights, and had a gross carrying amount of $3~~9.1 ~~million~~Retirement ~~and accumulated amortization of about $2 million at September 30, 2002, and December 31, 2001.~~Benefits

~~Estimated~~Components ~~intangible assets amortization expense for each~~ of ~~the~~net ~~next~~periodic ~~five~~benefit ~~years ending December 31 is:~~ cost

(Thousands)	2003	2004	2005	2006	2007
	Pension Benefits		Postretirement Benefits
Energy East	$4,617	$4,540	$3,767	$2,980	$2,922
Three months ended June 30	2004	2003	2004	2003
CMP	$9	$9	$9	$9	$9
(Thousands)
NYSEG	$48	$48	$48	$31	$31
Energy East
Service cost	$7,807	$7,606	$1,407	$1,501
Interest cost	32,931	33,008	8,987	9,446
Expected return on plan assets	(51,742)	(51,309)	(672)	(786)
Amortization of prior service cost	1,161	1,246	(1,713)	(1,723)
Recognized net actuarial (gain) loss	(210)	(596)	1,583	2,254
Amortization of transition (asset) obligation	(307)	(1,809)	1,984	2,016
Curtailment	-	202	-	(307)
Net periodic benefit cost	$(10,360)	$(11,652)	$11,576	$12,401
CMP
Service cost	$1,017	$1,107	$353	$399
Interest cost	3,506	3,429	2,067	1,976
Expected return on plan assets	(3,852)	(3,688)	(265)	(379)
Amortization of prior service cost	50	61	(157)	(164)
Recognized net actuarial (gain) loss	1,277	1,103	695	539
Curtailment	-	202	-	(307)
Net periodic benefit cost	$1,998	$2,214	$2,693	$2,064
NYSEG
Service cost	$4,471	$4,053	$793	$777
Interest cost	17,421	17,072	4,506	5,012
Expected return on plan assets	(30,968)	(30,231)	-	-
Amortization of prior service cost	1,084	1,166	(1,532)	(1,540)
Recognized net actuarial (gain) loss	(2,758)	(4,071)	808	1,431
Amortization of transition (asset) obligation	(307)	(1,809)	1,983	2,016
Net periodic benefit cost	$(11,057)	$(13,820)	$6,558	$7,696
RG&E
Service cost	$1,234	$1,572	$243	$292
Interest cost	7,435	8,086	1,502	1,562
Expected return on plan assets	(12,136)	(12,823)	-	-
Unrecognized transition obligation	-	-	514	621
Amortization of prior service cost	306	365	277	335
Recognized net actuarial (gain) loss	(1,788)	(2,062)	(110)	(69)
Net periodic benefit cost	$(4,949)	$(4,862)	$2,426	$2,741

Transitional Information:

	Pension Benefits		Postretirement Benefits
Six months ended June 30	2004	2003	2004	2003

(Thousands)
Energy East
Service cost	$16,055	$15,608	$3,250	$3,343
Interest cost	65,492	66,245	18,369	18,356
Expected return on plan assets	(103,060)	(102,087)	(1,336)	(1,400)
Amortization of prior service cost	2,325	2,493	(3,424)	(3,440)
Recognized net actuarial (gain) loss	(535)	(3,093)	3,795	3,365
Amortization of transition (asset) obligation	(615)	(3,619)	4,001	4,033
Curtailment	-	202	-	(307)

Net periodic benefit cost	$(20,338)	$(24,251)	$24,655	$23,950

CMP
Service cost	$2,118	$2,206	$839	$907
Interest cost	6,968	6,787	4,110	3,957
Expected return on plan assets	(7,444)	(7,053)	(520)	(582)
Amortization of prior service cost	99	109	(314)	(321)
Recognized net actuarial (gain) loss	2,420	2,000	1,271	1,047
Curtailment	-	202	-	(307)

Net periodic benefit cost	$4,161	$4,251	$5,386	$4,701

NYSEG
Service cost	$9,054	$8,434	$1,745	$1,616
Interest cost	34,435	33,928	9,413	9,413
Expected return on plan assets	(61,908)	(60,333)	-	-
Amortization of prior service cost	2,167	2,329	(3,065)	(3,079)
Recognized net actuarial (gain) loss	(6,144)	(8,355)	2,227	1,885
Amortization of transition (asset) obligation	(615)	(3,619)	4,000	4,033

Net periodic benefit cost	$(23,011)	$(27,616)	$14,320	$13,868

RG&E
Service cost	$2,740	$3,143	$515	$584
Interest cost	14,902	16,172	3,027	3,124
Expected return on plan assets	(24,592)	(25,646)	-	-
Unrecognized transition obligation	-	-	1,059	1,242
Amortization of prior service cost	631	731	571	670
Recognized net actuarial (gain) loss	(3,453)	(4,124)	(132)	(138)

Net periodic benefit cost	$(9,772)	$(9,724)	$5,040	$5,482

Periods Ended Sept. 30	Reported net income (loss)	Add back: Goodwill amortization	Adjusted net income (loss)	Reported basic and diluted earnings per share	Add back: Goodwill amortization	Adjusted basic and diluted earnings per share
(Thousands, except per share data)
Three months
Energy East 2002 2001	$23,742 $(21,057)	- $6,145	$23,742 $(14,912)	$.16 $(.18)	- $.05	$.16 $.(13)
CMP 2002 2001	$11,372 $11,275	- $2,145	$11,372 $13,420
NYSEG 2002 2001	$23,296 $32,107	- $96	$23,296 $32,203
Nine months
Energy East 2002 2001	$134,634 $121,118	- $18,475	$134,634 $139,593	$1.06 $1.04	- $.16	$1.06 $1.20
CMP 2002 2001	$39,947 $37,295	- $6,453	$39,947 $43,748
NYSEG 2002 2001	$106,061 $144,923	- $288	$106,061 $145,211
12 Months Ended Dec. 31
Energy East 2001 2000 1999	$187,607 $235,034 $218,751	$25,387 $18,486 $2,487	$212,994 $253,520 $221,238	$1.61 $2.06 $1.88	$.22 $.16 $.02	$1.83 $2.22 $1.90
CMP 2001 2000 1999	$54,440 $53,529 $68,740	$8,575 $2,949 -	$63,015 $56,478 $68,740
NYSEG 2001 2000 1999	$194,807 $219,595 $206,134	$383 $383 $383	$195,190 $219,978 $206,517

In April of 2004 Energy East contributed $19 million to its retirement benefit plans, including $11 million for CMP.

~~Note~~In 9December 2003 President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). ~~Fair~~The ~~Value~~Act introduces a federal subsidy to sponsors of ~~Financial~~retiree ~~Instruments~~health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

~~The~~In ~~company~~May ~~evaluated~~2004 the ~~carrying~~FASB ~~value~~issued ofits ~~CMP~~FASB ~~Group's~~Staff ~~investment~~Position in(FSP) ~~NEON~~No. ~~Communications~~FAS 106-2, ~~Inc.~~which ~~because~~addresses ~~there~~how ~~had~~and ~~been~~when a ~~significant~~plan ~~decline~~sponsor inshould account for the ~~market~~federal ~~value~~subsidy ofintroduced ~~NEON~~by ~~common~~the ~~shares~~Act ~~prior~~and tocould require the ~~writedown~~plan sponsor to change previously reported information. ~~That~~FSP ~~decline~~No. ~~was~~FAS ~~consistent~~106-2 ~~with~~is effective for the ~~market~~first ~~performance~~interim ofor ~~telecommunications~~annual ~~businesses~~period asbeginning aafter ~~whole~~June 15, 2004. AWhen ~~decline~~FSP ~~was~~No. ~~determined~~FAS 106-2 becomes effective it supersedes FSP No. FAS 106-1. The company, CMP, NYSEG and RG&E will apply FSP No. 106-2 beginning July 1, 2004. However, since detailed regulations necessary to beimplement ~~other~~the ~~than~~Act ~~temporary~~have ~~during~~not been issued, the ~~third~~companies ~~quarter~~are unable to conclude whether the benefits provided by their plans are actuarially equivalent to Medicare Part D under the Act. Any measures of ~~2001~~the ~~and~~accumulated pension benefit obligation or net periodic postretirement benefit cost in the ~~investment~~companies' ~~was~~financial ~~written~~statements ~~down~~or accompanying notes do not reflect any amount associated with the subsidy because the companies' are unable to ~~its~~conclude ~~fair~~whether ~~market~~the ~~value~~benefits atprovided ~~September~~by ~~30,~~their ~~2001~~plans are actuarially equivalent to Medicare Part D. ~~That~~The ~~writedown~~companies ~~totaled~~have ~~$46~~not ~~million~~yet ~~after~~determined ~~taxes~~the potential effects of the Act on their future postretirement costs, including the participation rates in their benefit plans, or 39whether ~~cents~~any ~~per~~amendments ~~share~~to their benefit plans are appropriate given the provisions of the Act.

~~During~~Note the first quarter of 2002 the company determined that an additional decline in NEON's market value was other than temporary and wrote down the cost basis of the investment in NEON to $2 million, based on the closing market price of NEON common shares on March 31, 200210. ~~The~~Goodwill writedown, which totaled $6 million after taxes, or five cents per share, was reflected in the company's earnings for the first quarter of 2002. In the second quarter of 2002, the NEON common shares were delisted from NASDAQ and ~~NEON~~Intangible filed a reorganization plan under the U.S. Bankruptcy Code. The company wrote off its remaining $2 million investment, and the writedown of $1.2 million after taxes, or one cent per share, was reflected in the company's earnings for the second quarter of 2002.Assets

The ~~investment~~companies inno ~~NEON~~longer ~~was~~amortize ~~classified~~goodwill aseffective ~~available-for-sale~~January 1, ~~accounted~~2002, ~~for~~and bydo ~~the~~not ~~cost~~amortize ~~method~~intangible assets with indefinite lives (unamortized intangible assets). RG&E has no goodwill or intangible assets with indefinite lives. The companies test both goodwill and ~~carried~~unamortized intangible assets for impairment at ~~its~~least ~~fair~~annually. ~~value,~~The companies amortize intangible assets with ~~changes~~finite inlives ~~fair~~(amortized ~~value~~intangible ~~recognized~~assets) inand ~~other~~review ~~comprehensive~~them ~~income~~for impairment. NoAnnual ~~income~~impairment ortesting ~~loss~~was ~~related~~completed toand ~~the~~it ~~investment~~was indetermined ~~NEON~~that there was ~~included~~no inimpairment ~~the~~of ~~company's~~goodwill ~~operating~~or ~~income~~unamortized inintangible ~~earlier~~assets ~~periods~~for the companies at September 30, 2003.

~~Note~~Changes ~~10.~~in ~~Segment~~the ~~Information~~ carrying amounts of Energy East's goodwill, by operating segment, from January 1, 2004, to June 30, 2004, are shown in the table below.

Energy East's electric delivery business consists of its regulated transmission, distribution and generation operations in Maine and New York; 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 income, interest expense and operating expenses; intersegment eliminations; and nonutility businesses.

	Electric Delivery	Natural Gas Delivery	Other	Total

(Thousands)
Balance, January 1, 2004	$844,531	$677,119	$11,473	$1,533,123
Goodwill related to businesses held for sale	-	-	(5,500)	(5,500)
Preacquisition income tax adjustment	(40)	(531)	117	(454)

Balance, June 30, 2004	$844,491	$676,588	$6,090	$1,527,169

The carrying amount of CMP's ~~electric delivery business~~goodwill, which itis ~~conducts~~included in ~~the~~its ~~State~~electric ofdelivery ~~Maine~~operating segment, ~~consists~~was $325 million as of ~~its~~June ~~regulated~~30, ~~transmission~~2004, and ~~distribution~~January ~~operations~~1, 2004. ~~Other~~The ~~consists~~carrying amount of ~~CMP~~NYSEG's ~~corporate~~goodwill, ~~assets.~~which is included in its natural gas delivery operating segment, was $11 million as of June 30, 2004, and January 1, 2004.

~~NYSEG~~The company's ~~electric~~unamortized ~~delivery~~intangible ~~business~~assets ~~consists~~had a carrying amount of ~~its~~$10 ~~regulated~~million ~~transmission~~at June 30, ~~distribution~~2004, and ~~generation~~December ~~operations~~31, 2003, and primarily consisted of pension assets. ~~Its~~The ~~natural~~company's ~~gas~~amortized ~~delivery~~intangible ~~business~~assets ~~consists~~had a gross carrying amount of ~~its~~$31 ~~regulated~~million ~~transportation~~at June 30, ~~storage~~2004, and ~~distribution~~December ~~operations.~~31, ~~NYSEG~~2003, ~~operates~~and primarily consisted of investments in ~~the~~pipelines. ~~State~~Accumulated ofamortization ~~New~~was ~~York~~$13 million at June 30, 2004, and $12 million at December 31, 2003. ~~Other~~Estimated ~~consists~~amortization ofexpense ~~NYSEG's~~for ~~corporate~~intangible assets. for the next five years is approximately $3 million for 2004, $2 million for 2005, and $1 million each year for 2006 through 2008.

~~RG&E~~CMP's ~~electric~~unamortized ~~delivery~~intangible ~~business~~assets ~~consists~~consist of ~~its~~pension ~~regulated~~assets ~~transmission~~and had a carrying amount of $2 million at June 30, ~~distribution~~2004, and ~~generation~~December ~~operations~~31, 2003. ~~Its~~CMP's ~~natural~~amortized ~~gas~~intangible ~~delivery~~assets ~~business~~had ~~consists~~a gross carrying amount and accumulated amortization of ~~its~~less ~~regulated~~than ~~transportation~~$0.3 million at June 30, ~~storage~~2004, and ~~distribution~~December ~~operations.~~31, ~~RG&E~~2003, ~~operates~~and inprimarily ~~the~~consisted ~~State~~ of ~~New~~technology ~~York~~rights. ~~Other~~Estimated ~~consists~~amortization ofexpense ~~RG&E's~~for ~~corporate~~intangible assets is $26 thousand for the years 2004 through 2006, and $8 thousand for 2007, after which amortization will be complete.

NYSEG's unamortized intangible assets had a carrying amount of $1.4 million at June 30, 2004, and December 31, 2003, and primarily consisted of pension assets, franchises and consents. NYSEG's amortized intangible assets had a gross carrying amount of $1.8 million at June 30, 2004, and $1.5 million at December 31, 2003, and accumulated amortization of $1 million at June 30, 2004, and December 31, 2003, and consisted of hydroelectric licenses. Estimated amortization expense for intangible assets for the next five years is $41 thousand for the years 2004 through 2006, $38 thousand for 2007 and $35 thousand for 2008.

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

Note 11. Segment Information

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

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

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 the State of New York. Other includes 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 the State of New York. Other includes RG&E's corporate assets.

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

	Electric Delivery	Natural Gas Delivery	Other	Total
(Thousands)
Three Months Ended
Sept. 30, 2002
June 30, 2004
Operating Revenues Energy East CMP NYSEG RG&E	$~~741~~641,~~338~~057 $~~153~~129,~~663~~748 $~~389~~358,~~216~~521 $~~198~~160,~~429~~209	$~~132~~240,~~983~~282 - $3569,~~675~~974 $3263,~~939~~520	$~~141~~99,~~868~~227 - - -	$1980,~~016,189~~566 $~~153~~129,~~663~~748 $~~424~~428,~~891~~495 $~~231~~223,~~368~~729
Net Income (Loss) Energy East CMP NYSEG RG&E	$5041,~~136~~986 $113,~~372~~430 $2930,~~401~~184 $2127,~~605~~464	$(2012,~~544~~431) - $~~(6,105)~~712 $(41,~~318)~~465	$(58,~~850)~~511 - - -	$2338,~~742~~066 $113,~~372~~430 $2330,~~296~~896 $1728,~~287~~929
Sept. 30, 2001
June 30, 2003
Operating Revenues Energy East CMP NYSEG RG&E	$~~623~~640,~~997~~035 $~~200~~135,~~229~~259 $~~423~~338,~~676~~353 $~~194~~166,~~201~~384	$~~113~~264,~~356~~054 - $3675,~~318~~011 $3462,~~639~~228	$6175,~~495~~024 - - -	$~~798~~979,~~848~~113 $~~200~~135,~~229~~259 $~~459~~413,~~994~~364 $228,~~840~~612
Net Income (Loss) Energy East CMP NYSEG RG&E	$4529,~~381~~900 $112,~~275~~821 $3928,~~213~~130 $12,~~014~~030	$(~~18,005~~602) - $(71,~~106)~~793 $(52,~~678)~~643	$(481,~~433~~581) - - -	$~~(21~~27,~~057)~~717 $112,~~275~~821 $3229,~~107~~923 $614,~~336~~673
Nine Months Ended
Sept. 30, 2002
Operating Revenues Energy East CMP NYSEG RG&E	$1,876,742 $493,485 $1,184,687 $534,986	$643,038 - $222,902 $193,480	$239,861 - - -	$2,759,641 $493,485 $1,407,589 $728,466
Net Income (Loss) Energy East CMP NYSEG RG&E	$144,732 $39,947 $104,211 $18,218	$18,601 - $1,850 $2,788	$(28,699) - - -	$134,634 $39,947 $106,061 $21,006
Sept. 30, 2001
Operating Revenues Energy East CMP NYSEG RG&E	$1,904,785 $622,861 $1,281,658 $559,819	$808,179 - $259,337 $225,604	$206,033 - - -	$2,918,997 $622,861 $1,540,995 $785,423
Net Income (Loss) Energy East CMP NYSEG RG&E	$168,720 $37,295 $148,920 $56,148	$8,292 - $(3,997) $4,591	$(55,894) - - -	$121,118 $37,295 $144,923 $60,739

- continued	Electric Delivery	Natural Gas Delivery	Other	Total
	Electric Delivery	Natural Gas Delivery	Other	Total
(Thousands)
Six Months Ended
June 30, 2004
Operating Revenues Energy East CMP NYSEG RG&E	$1,371,652 $292,498 $762,505 $324,393	$922,006 - $258,204 $212,682	$267,981 - - -	$2,561,639 $292,498 $1,020,709 $537,075
Net Income (Loss) Energy East CMP NYSEG RG&E	$113,512 $24,257 $67,161 $41,143	$54,171 - $16,652 $13,726	$(9,065) - - -	$158,618 $24,257 $83,813 $54,869
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	$181,029 - - -	$2,483,944 $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	$158,618 - - -	$163,181 $26,923 $90,540 $16,163
Total Assets
Sept. 30, 2002 Energy East CMP NYSEG RG&E	$6,405,772 $1,734,510 $2,152,443 $1,862,266	$3,011,080 - $701,596 $471,741	$626,048 $8,824 $94,905 $77,845	$10,042,900 $1,743,334 $2,948,944 $2,411,852
June 30, 2004 Energy East CMP NYSEG RG&E	$6,736,575 $1,788,504 $2,466,720 $1,923,840	$3,644,236 - $1,057,265 $568,339	$287,217 - - -	$10,668,028 $1,788,504 $3,523,985 $2,492,179
December 31, 2001 Energy East CMP NYSEG RG&E	$4,175,280 $1,857,157 $2,250,852 $1,853,846	$2,467,647 - $697,280 $479,311	$626,305 $8,643 $66,291 $131,504	$7,269,232 $1,865,800 $3,014,423 $2,464,661
December 31, 2003 Energy East CMP NYSEG RG&E	$7,293,829 $1,806,853 $2,664,449 $2,288,175	$3,536,280 - $870,464 $590,555	$476,323 - $52,652 $82,100	$11,306,432 $1,806,853 $3,587,565 $2,960,830

Note 11. Reclassifications
Certain amounts have been reclassified on the unaudited financial statements to conform with the 2002 presentation.
Note 12. Statement 146
In June 2002 the FASB issued Statement No. 146, Accounting for Costs Associated with Exit or Disposal Activities. Statement 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than at a plan or commitment date for the exit or disposal activity. It establishes fair value as the objective for initial measurement of the liability. The provisions of Statement 146 are effective for exit or disposal activities initiated after December 31, 2002. The company and its subsidiaries are evaluating the effect that adopting Statement 146 may have on their results of operations or financial position.
Note 13. Statement 143
In June 2001 the FASB issued Statement 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. Statement 143 is effective for fiscal years beginning after June 15, 2002. RG&E is currently in the process of measuring any asset retirement obligations. The adoption of Statement 143 is not expected to have a material effect on RG&E's results of operations.
Forward-looking Statements

InThis ~~addition~~Form to10-Q ~~the~~contains ~~assumptions~~certain 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,~~that ~~among~~are ~~others:~~based ~~the~~upon ~~deregulation and continued regulatory unbundling of a vertically integrated industry; the companies~~management's ~~ability~~current toexpectations ~~compete in the rapidly changing~~ and ~~increasingly~~information ~~competitive~~that ~~electricity~~is ~~and~~currently ~~natural~~available. ~~gas~~The ~~utility~~Private ~~markets;~~Securities ~~regulatory~~Litigation ~~uncertainty~~Reform inAct ~~a politically-charged environment~~ of ~~changing~~1995 ~~energy~~provides ~~prices;~~a ~~the~~safe ~~operation~~harbor offor ~~the~~forward-looking ~~New~~statements ~~York~~in ~~Independent~~certain ~~System Operator and ISO New England, Inc~~circumstances.; ~~the~~Whenever ~~operation~~used ~~of a RTO; the ability to control NUG and other costs; changes~~ in ~~fuel~~this ~~supply or cost and the success of strategies to satisfy power requirements now that most coal-fired generation assets have been sold; the company's ability to expand its products and services~~report, ~~including its energy infrastructure in~~ the ~~Northeast;~~words ~~the company's ability to integrate the operations of Connecticut Energy Corporation~~"estimate," ~~CMP Group~~"expect," ~~CTG Resources~~"believe," ~~Inc., Berkshire Energy Resources and RGS Energy with its operations; market risk; the ability to obtain adequate and timely rate relief; nuclear, terrorist~~ or ~~environmental~~similar ~~incidents;~~expressions ~~legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which the companies~~ are ~~doing~~intended ~~business; weather variations affecting customer energy usage; authoritative accounting guidance; and other considerations that may be disclosed from time~~ to ~~time~~identify insuch ~~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~~.

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

Item 3.
Quantitative and Qualitative Disclosures About Market Risk

(See report on Form 10-K for Energy East, CMP, NYSEG and RG&E for fiscal year ended December 31, 2003, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

Commodity Price Risk

: NYSEG and RG&E use electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity. The cost or benefit of those contracts is included in the amount expensed for electricity purchased when the electricity is sold.

NYSEG's ~~and~~current ~~RG&E~~electric ~~use~~rate plan offers retail customers choice in their electricity ~~contracts~~supply ~~and~~including ~~contracts~~a ~~for~~variable ~~differences~~rate option, ~~which~~an ~~are~~option ~~financial~~to ~~contracts~~purchase ~~with~~electricity ~~features~~supply ~~similar~~from toan ~~commodity~~alternative ~~swap~~energy ~~agreements~~company, toand ~~manage~~a ~~against~~bundled rate option. Approximately 38% 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 ~~cost~~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. ~~The~~For 2004 the customer supply cost orcomponent ~~benefit~~is ofbased ~~those~~on ~~contracts~~average electricity forward prices for 2003 and 2004 available during September 2002, plus 35% to cover the costs and risk that NYSEG is ~~included~~assuming inby providing a bundled rate option to retail customers. NYSEG actively hedges the ~~amount~~load ~~expensed~~required to serve customers who select the bundled rate option. As of July 30, 2004, NYSEG's load was 98% hedged for ~~electricity~~on-peak ~~purchased~~periods ~~when~~and 92% hedged for off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.25 million for August through December 2004. The percentage of NYSEG's hedged load is ~~sold~~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's~~Under ~~electric~~the ~~rate~~terms ~~settlement~~of ~~agreement~~its ~~offers~~Electric Rate Agreement RG&E is allowed to recover its actual fuel expenses effective May 1, 2004, and the earnings risks related to changes in market value of electricity are eliminated. Beginning January 1, 2005, in accordance with its Electric Rate Agreement, RG&E will offer its retail customers choice in their electricity supply including a variable ~~rate~~price option, an option to purchase electricity supply from an alternative energy company, and a ~~bundled~~fixed ~~rate~~price option. ~~NYSEG~~RG&E's exposure to fluctuations in the market price of electricity iswill be limited to the load required to serve those customers who select the ~~bundled~~fixed rate option, which combines delivery and supply service at a ~~fixed~~bundled price. ~~For calendar years 2003 and 2004 the supply component is based on average electricity prices during September 2002 plus a 35% margin to cover the costs and risk that NYSEG is assuming~~

byNYSEG ~~providing~~and aRG&E ~~bundled~~use ~~rate~~natural ~~option~~gas futures and forwards to ~~retail~~manage ~~customers.~~fluctuations ~~NYSEG~~in isnatural ~~actively~~gas ~~hedging~~commodity ~~the~~prices ~~load~~and ~~required~~provide toprice ~~serve~~stability to customers. ~~who~~The ~~select~~cost ~~the~~or ~~bundled~~benefit ~~rate~~of ~~option,~~natural gas futures and ~~intends~~forwards tois ~~fully~~included ~~hedge~~in ~~its~~the ~~expected~~commodity ~~load~~cost bywhen the ~~end~~related ofsales ~~2002,~~commitments ~~which~~are ~~coincides~~fulfilled. ~~with~~NYSEG ~~the~~and ~~end~~RG&E ofare ~~the~~allowed ~~customer~~to ~~choice~~pass ~~period.~~all actual natural gas commodity costs through to customers.

NYSEG's electric rate settlement provides for a reconciliation and true-up of certain actual power supply costs during 2002; therefore, the supply cost risk for 2002 is substantially eliminated. (See report on Form 10-K for Energy East and NYSEG for fiscal year ended December 31, 2001, Item 7 - Liquidity and Capital Resources, NYSEG Electric Rate Settlement.)
RG&E faces commodity price risk that relates to market fluctuations in the price of natural gas and electricity. Under its electric settlement, RG&E's electric rates were capped at specified levels through June 30, 2002. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. RG&E has filed a request with the NYPSC for new electric rates commencing in January 2003. The rate request proposes offering electric customers a choice between one-year fixed price and monthly variable price offerings. Both pricing options will further reduce RG&E's exposure to market price fluctuations in the electric wholesale market. The NYPSC has not ruled on the rate request, therefore, RG&E's current fixed electric rates will likely remain in effect until a new rate order is issued by the NYPSC. A new rate order is expected to be issued in February 2003, for electric rates retroactive to January 2003. (See Item 2(a) - Liquidity and Capital Resources, RG&E 2002 Electric and Gas Rate Proposal.)
While owned generation provides RG&E with a natural hedge against electric price risk, it also subjects it to operating risk. Operating risk is managed through a combination of strict operating and maintenance practices and the use of generation insurance and derivative contracts. In the event RG&E's generation assets fail to perform as planned, generation insurance reduces RG&E's exposure to electric price spikes.
The broad and continued decline in credit quality across the energy supply and marketing industries combined with the withdrawal of many entities from energy trading operations , including RG&E's generation insurer, could limit the company's ability to purchase electricity and place financial hedges with counterparties that meet its credit requirements. While the company has been successful in implementing its hedging strategies by finding credit-worthy counterparties or requiring adequate financial assurances, continued contraction and credit deterioration across the energy supply and marketing industries may adversely affect the company's ability to effectively implement its hedging strategies going forward.
Item 4.
Controls and Procedures

The principal executive officers and principal financial officers of Energy East, CMP, NYSEG and RG&E evaluated the effectiveness of their respective company's disclosure controls and procedures as of athe ~~date~~end ~~within~~of 90the ~~days~~period ofcovered ~~filing~~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 ~~controls~~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 ~~controls~~control over financial reporting contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. There were no ~~significant~~ changes in the companies' internal ~~controls~~control orover infinancial ~~other~~reporting ~~factors~~that occurred during each company's most recent fiscal quarter that ~~could~~has ~~significantly~~materially ~~affect~~affected, ~~these~~or ~~controls~~is ~~subsequent~~reasonably likely to materially affect, the ~~date~~respective ofcompany's ~~the~~internal ~~evaluations~~control over financial reporting. On January 1, ~~including~~2004, ~~any~~Energy ~~corrective~~East ~~actions~~commenced ~~with~~using ~~regard~~a new accounting system to ~~significant~~record ~~deficiencies~~and report financial transactions. The system change was undertaken to standardize accounting systems and ~~material~~to ~~weaknesses~~consolidate the accounting functions for Energy East's principal operating companies, including CMP, NYSEG and RG&E.

PART II - OTHER INFORMATION

Item 2.
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

(a) Changes in Rights of Holders of Energy East Common Stock

On June 18, 2004, the stockholders of the company approved amendments to the Certificate of Incorporation to eliminate the classification of the Board of Directors and to eliminate cumulative voting in the election of directors. On June 21, 2004, the company filed an Amendment to the Certificate of Incorporation to reflect the changes. All directors will be elected annually beginning at the 2005 Annual Meeting.

(e) Issuer Purchases of Equity Securities

Energy East Corporation
Period	(a) Total number of shares purchased	(b) Average price paid per share	(c) Total number of shares purchased as part of publicly announced plans or programs		(d) Maximum number of shares that may yet be purchased under the plans or programs

Month #1 (April 1, 2004 to April 30, 2004)	4,034⁽¹⁾	$24.30	-	-

Month #2 (May 1, 2004 to May 31, 2004)	6,503⁽¹⁾	$22.60	-	-

Month #3 (June 1, 2004 to June 30, 2004)	9,721⁽²⁾	$23.54	-	-

Total	20,258	$23.39	-	-

⁽¹⁾ Represents shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan.
⁽²⁾ Includes 4,549 shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan; and 5,172 shares of the company's common stock (Par Value $.01) that were awarded through the company's Restricted Stock Plan and upon vesting of shares of restricted stock were withheld to satisfy tax withholding obligations.

Rochester Gas and Electric Corporation
Period	(a) Total number of shares purchased	(b) Average price paid per share	(c) Total number of shares purchased as part of publicly announced plans or programs	(d) Maximum number of shares that may yet be purchased under the plans or programs

Month #1 (April 1, 2004 to April 30, 2004)	None

Month #2 (May 1, 2004 to May 31, 2004)	470,000 ⁽¹⁾	$102.31	-	-

Month #3 (June 1, 2004 to June 30, 2004)	None

Total	470,000	$102.31	-	-

⁽¹⁾ These share purchases were a redemption of all of RG&E's remaining preferred stock, all Par Value $100. (See Energy East's Part I, Item 2(a) - RG&E Financing Activities.)

CMP and NYSEG had no issuer purchases of equity securities during the quarter ended June 30, 2004.

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 18, 2004. The following matters were voted on:

(a) The election of four directors:

Nominees	Votes For	Votes Withheld
Richard Aurelio	126,363,429	4,134,624
James A. Carrigg	126,050,963	4,447,090
David M. Jagger	125,642,840	4,855,213
Ben E. Lynch	125,253,822	5,244,231

(b) Approval of an amendment to the Certificate of Incorporation to eliminate the classification of the Board of Directors:

Shares For:	123,959,588
Shares Against:	4,664,053
Shares Abstain:	1,874,412

(c) Approval of an amendment to the Certificate of Incorporation to eliminate cumulative voting in the election of directors:

Shares For:	80,144,510
Shares Against:	26,967,131
Shares Abstain:	1,881,723
Broker Nonvoted:	21,504,689

(d) Approval of an existing employee stock purchase plan:

Shares For:	103,745,975
Shares Against:	3,712,018
Shares Abstain:	1,535,371
Broker Nonvoted:	21,504,689

(e) Ratification of the appointment of PricewaterhouseCoopers LLP as independent public accountants:

Shares For:	126,296,571
Shares Against:	3,107,602
Shares Abstain:	1,093,880

Central Maine Power Company

CMP's Annual Meeting of Stockholders was held on June 18, 2004. 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 18, 2004, 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, Wesley W. von Schack and Denis Wickham directors of NYSEG. Mr. Wickham retired on July 1, 2004, in accordance with his previously announced plans.

Rochester Gas and Electric Corporation

On June 18, 2004, 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 Denis Wickham directors of RG&E. Mr. Wickham retired on July 1, 2004, in accordance with his previously announced plans.

Item 6.
Exhibits and Reports on Form 8-K

(ba) ~~The~~Exhibits ~~following report on Form 8~~-K ~~was~~See ~~filed during the quarter:~~

Exhibit Index.

~~Energy~~(b) The ~~East~~following ~~filed~~reports aon Form 8-K ~~dated~~were ~~August~~filed 7,or ~~2002,~~furnished toduring ~~report~~the ~~certain information under Item 9, "Regulation FD Disclosure."~~quarter:

Energy East filed four reports on Form 8-K. One report, dated May 7, 2004, was furnished to report certain information under Item 7, "Financial Statements and Exhibits," Item 9, "Regulation FD Disclosure," and Item 12, " Results of Operation and Financial Condition," Two other reports, dated May 19, 2004, and May 24, 2004, were filed to report certain information under Item 5, "Other Events," and Item 7, "Financial Statements and Exhibits." Another report, dated June 10, 2004, was filed to report certain information under Item 5, "Other Events."

RG&E filed three reports on Form 8-K. Two reports, dated May 19, 2004, and May 24, 2004, were filed to report certain information under Item 5, "Other Events," and Item 7, "Financial Statements and Exhibits." Another report, dated June 10, 2004, was filed to report certain information under Item 5, "Other Events."

Signatures

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

Date: November 12, 2002	ENERGY EAST CORPORATION (Registrant) By /s/Robert E. Rude Robert E. Rude Vice President and Controller (Principal Accounting Officer)
Date: August 5, 2004	ENERGY EAST CORPORATION (Registrant) By /s/Robert E. Rude Robert E. Rude Vice President and Controller (Principal Accounting Officer)
Date: November 12, 2002	CENTRAL MAINE POWER COMPANY (Registrant) By /s/Curtis I. Call Curtis I. Call Vice President, Controller & Treasurer (Principal Financial Officer)
Date: August 5, 2004	CENTRAL MAINE POWER COMPANY (Registrant) By /s/Robert S. Mahoney Robert S. Mahoney Vice President - Controller & Treasurer, Clerk (Principal Financial Officer)
Date: November 12, 2002	NEW YORK STATE ELECTRIC & GAS CORPORATION (Registrant) By /s/Sherwood J. Rafferty Sherwood J. Rafferty Senior Vice President and Chief Financial Officer (Principal Financial Officer)
Date: August 5, 2004	NEW YORK STATE ELECTRIC & GAS CORPORATION (Registrant) By /s/Joseph J. Syta Joseph J. Syta Vice President - Controller & Treasurer (Principal Financial Officer)
Date: November 12, 2002	ROCHESTER GAS AND ELECTRIC CORPORATION (Registrant) By /s/Mark Keogh Mark Keogh Vice President, Treasurer & Secretary (Principal Financial Officer)
Date: August 5, 2004	ROCHESTER GAS AND ELECTRIC CORPORATION (Registrant) By /s/Joseph J. Syta Joseph J. Syta Vice President - Controller & Treasurer (Principal Financial Officer)

~~Certifications~~EXHIBIT INDEX

I,(a) ~~Wesley~~(1) W.The ~~von~~following ~~Schack,~~exhibits ~~certify~~are ~~that~~delivered with this report:

1. I have reviewed this quarterly report on Form 10-Q of Energy East Corporation;

Registrant	Exhibit No.	Description of Exhibit
Energy East Corporation	3-5 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on June 21, 2004.
	(A)10-21 -	Amended and Restated Employment Agreement dated as of July 1, 2004, by an among the Company, Energy East Management Corporation and W. W. von Schack.
	(A)10-22 -	Supplemental Executive Retirement Plan Amendment No. 2.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32* -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Central Maine Power	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
Company	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32* -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
New York State Electric	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
& Gas Corporation	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32* -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Rochester Gas and	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
Electric Corporation	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32* -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

2.*Furnished ~~Based~~pursuant ~~on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit~~ to ~~state~~Regulation aS-K ~~material~~Item ~~fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;~~601(b)(32).

3.(a) ~~Based~~(2) onThe myfollowing ~~knowledge,~~exhibits ~~the~~are ~~financial~~incorporated ~~statements,~~herein ~~and~~by other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;reference:

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

Registrant	Exhibit No.	Filed in	As Exhibit No.
Energy East Corporation	3-1 -	Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on April 23, 1998 - Post-effective Amendment No.1 to Registration No. 033-54155	4-1
	3-2 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on April 26, 1999 - Company's 10-Q for the quarter ended March 31, 1999 - File No. 1-14766	3-3
Central Maine Power Company	(A)10-27 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766	10-22
New York State Electric & Gas Corporation	(A)10-34 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766	10-22

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

Registrant	Exhibit No.	Filed in	As Exhibit No.
Rochester Gas and Electric Corporation	(A)10-27 -	Energy East Corporation's Supplemental Executive Retirement Plan - Energy East Corporation's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766	10-33
	(A)10-28 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-5
	(A)10-29 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766	10-22

b_________________________________ (A) Management ~~evaluated~~contract ~~the~~or ~~effectiveness~~compensatory ofplan ~~the~~or ~~registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and~~arrangement.

c)Energy ~~presented~~East inagrees ~~this~~to ~~quarterly~~furnish ~~report~~to ~~our~~the ~~conclusions~~Commission, ~~about~~upon request, a copy of (i) the ~~effectiveness~~Five-Year Revolving Credit Agreement among Energy East, certain lenders, Wachovia Bank, National Association, as Administrative Agent, JP Morgan Chase Bank, as Syndication Agent and Citibank, N.A., KeyBank N.A. and UBS Loan Finance, LLC, as Co-Documentation Agents, dated as of July 21, 2004; and (ii) the ~~disclosure~~Revolving ~~controls~~Credit Agreement among NYSEG, RG&E, certain lenders, JP Morgan Chase Bank, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent and ~~procedures~~Citibank, ~~based~~N.A., onKeyBank ~~our~~N.A. ~~evaluation~~and UBS Loan Finance, LLC, as Co-Documentation Agents, dated as of July 21, 2004 (the ~~Evaluation~~"Joint ~~Date;~~Revolving Credit Agreement"). The total amount of securities under each such document does not exceed 10% of the total assets of Energy East.

5.NYSEG ~~The~~agrees ~~registrant's~~to ~~other~~furnish ~~certifying~~to ~~officers~~the ~~and~~Commission, Iupon ~~have disclosed~~request, ~~based~~a oncopy ~~our~~of ~~most~~the ~~recent~~Joint ~~evaluation,~~Revolving toCredit ~~the~~Agreement. ~~registrant's~~The ~~auditors~~total ~~and~~amount ~~the~~of ~~audit~~securities ~~committee~~issuable ofby ~~registrant's~~NYSEG ~~board~~under ofthe ~~directors~~Joint ~~(or~~Revolving ~~persons~~Credit ~~performing~~Agreement does not exceed 10% of the ~~equivalent~~total ~~function):~~assets of NYSEG.

a)RG&E ~~all~~agrees ~~significant~~to ~~deficiencies~~furnish into the ~~design~~Commission, orupon ~~operation~~request, ofa ~~internal~~copy ~~controls~~of ~~which~~the ~~could~~Joint ~~adversely~~Revolving ~~affect~~Credit ~~the~~Agreement. ~~registrant's~~The ~~ability~~total toamount ~~record,~~of ~~process,~~securities ~~summarize~~issuable ~~and~~by ~~report~~RG&E ~~financial~~under ~~data~~the ~~and~~Joint ~~have~~Revolving ~~identified~~Credit ~~for~~Agreement ~~the~~does ~~registrant's~~not ~~auditors~~exceed ~~any~~10% ~~material~~of ~~weaknesses~~the intotal ~~internal~~assets ~~controls;~~of ~~and~~RG&E.

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 12, 2002 /s/Wesley W. von Schack Wesley W. von Schack Chairman, President & Chief Executive Officer

Certifications

I, Kenneth M. Jasinski, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy East Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: November 12, 2002 /s/Kenneth M. Jasinski Kenneth M. Jasinski Executive Vice President and Chief Financial Officer

Certifications

I, Sara J. Burns, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Central Maine Power Company;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: November 12, 2002 /s/Sara J. Burns Sara J. Burns President

Certifications

I, Curtis I. Call, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Central Maine Power Company;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: November 12, 2002 /s/Curtis I. Call Curtis I. Call Vice President, Controller & Treasurer

Certifications

I, Ralph R. Tedesco, certify that:

1. I have reviewed this quarterly report on Form 10-Q of New York State Electric & Gas Corporation;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: November 12, 2002 /s/Ralph R. Tedesco Ralph R. Tedesco President

Certifications

I, Sherwood J. Rafferty, certify that:

1. I have reviewed this quarterly report on Form 10-Q of New York State Electric & Gas Corporation;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: November 12, 2002 /s/Sherwood J. Rafferty Sherwood J. Rafferty Senior Vice President and Chief Financial Officer

Certifications

I, Paul C. Wilkens, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Rochester Gas and Electric Corporation;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: November 12, 2002 /s/Paul C. Wilkens Paul C. Wilkens President

Certifications

I, Mark Keogh, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Rochester Gas and Electric Corporation;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: November 12, 2002 /s/Mark Keogh Mark Keogh Vice President, Treasurer & Secretary

Nine Months Ended September 30	2002	2001
(Thousands)
Operating Activities
Net income	$134,634	$121,118
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	205,644	198,444
Income taxes and investment tax credits deferred, net	30,453	(10,342)
Pension income	(52,385)	(56,326)
Writedown of investment	12,209	78,422
Changes in current operating assets and liabilities
Accounts receivable, net	145,495	148,740
Sale of accounts receivable program	-	(152,000)
Inventory	(10,629)	(36,422)
Prepayments and other current assets	(24,974)	(865)
Accounts payable and accrued liabilities	(23,792)	(105,671)
Interest accrued	29,541	18,615
Taxes accrued	16,415	16,921
Other current liabilities	7,141	(46,526)
Other assets	(16,260)	(28,847)
Other liabilities	(23,917)	(32,039)
Net Cash Provided by Operating Activities	429,575	113,222
Investing Activities
Acquisition, net of cash acquired	(681,397)	-
Utility plant additions	(144,765)	(142,076)
Note receivable, sale of generation assets	59,442	-
Other property and investments additions	(20,759)	(34,088)
Other property and investments sold	7,477	15,456
Special deposits	(5,058)	19,916
Other	5,430	1,064
Net Cash Used in Investing Activities	(779,630)	(139,728)
Financing Activities
Issuance of common stock	12,866	3,547
Repurchase of common stock	(1,749)	(24,116)
Issuance of mandatorily redeemable trust preferred securities	-	345,000
Repayments of first mortgage bonds and preferred stock of subsidiaries, including net premiums	(178,349)	(1,446)
Long-term note issuances	502,500	107,879
Long-term note repayments	(68,660)	(14,863)
Notes payable three months or less, net	38,102	(212,712)
Notes payable issuances	13,009	-
Notes payable repayments	(35,607)	(1,100)
Dividends on common stock	(90,715)	(80,540)
Net Cash Provided by Financing Activities	191,397	121,649
Net (Decrease) Increase in Cash and Cash Equivalents	(158,658)	95,143
Cash and Cash Equivalents, Beginning of Period	437,014	143,626
Cash and Cash Equivalents, End of Period	$278,356	$238,769

Filing Compare · ROCHESTER GAS & ELECTRIC CORP