Energy East (EAS) 10-Q 2004 Q3 Quarterly report

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

FORM 10-Q

(Mark One)
[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934
      For the quarterly period ended  September 30, 2004

OR

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

Commission file number	Exact name of Registrant as specified in its charter, State of incorporation, Address and Telephone number	IRS Employer Identification No.
1-14766	Energy East Corporation(A New York Corporation) P. O. Box 12904 Albany, New York 12212-2904 (518) 434-3049 www.energyeast.com	14-1798693
1-5139	Central Maine Power Company(A Maine Corporation) 83 Edison Drive Augusta, Maine 04336 (207) 623-3521	01-0042740
1-3103-2	New York State Electric & Gas Corporation(A New York Corporation) P. O. Box 5224 Binghamton, New York 13902-5224 (607) 762-7200	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        

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

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

As of October 31, 2004, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	146,910,271
Central Maine Power Company	Par value $5 per share	31,211,471(1)
New York State Electric & Gas Corporation	Par value $6.66 2/3 per share	64,508,477(2)
Rochester Gas and Electric Corporation	Par value $5 per share	34,506,513(2)

(1) All shares are owned by CMP Group, Inc., a wholly-owned subsidiary of Energy East Corporation.
⁽²⁾ All shares are owned by RGS Energy Group, Inc. a wholly-owned subsidiary of Energy East Corporation.

This combined Form 10-Q is separately filed byEnergy East Corporation, Central Maine Power Company, New York State Electric & Gas Corporation andRochester Gas and Electric Corporation. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

Item	TABLE OF CONTENTS	Page
	PART I - FINANCIAL INFORMATION
1 2	Financial Statements Management's Discussion and Analysis of Financial Condition     and Results of Operations
	Energy East Corporation   Condensed Consolidated Statements of IncomeCondensed Consolidated Balance SheetsCondensed Consolidated Statements of Cash FlowsCondensed Consolidated Statements of Retained EarningsCondensed Consolidated Statements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	1 2 4 5 5 6 18
	Central Maine Power Company   Condensed Consolidated Statements of IncomeCondensed Consolidated Balance SheetsCondensed Consolidated Statements of Cash FlowsCondensed Consolidated Statements of Retained EarningsCondensed Consolidated Statements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	21 22 24 25 25 26 27
	New York State Electric & Gas Corporation   Condensed Balance SheetsCondensed Statements of IncomeCondensed Statements of Cash FlowsCondensed Statements of Retained EarningsCondensed Statements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	28 30 31 32 32 33 34
	Rochester Gas and Electric Corporation   Condensed Balance SheetsCondensed Statements of IncomeCondensed Statements of Cash FlowsCondensed Statements of Retained Earnings   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	36 38 39 39 40 41

Item	TABLE OF CONTENTS - continued	Page
1	Notes to Condensed Financial StatementsForward-looking Statements	44 57
3	Quantitative and Qualitative Disclosures About Market Risk	57
4	Controls and Procedures	59
	PART II - OTHER INFORMATION
2	Unregistered Sales of Equity Securities and Use of Proceeds	60
6	Exhibits	60
Signatures		61
Exhibit Index		62

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Energy East Corporation Condensed Consolidated Statements of Income- (Unaudited)
	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands, except per share amounts)
Operating Revenues
Sales and services	$967,805	$890,276	$3,488,099	$3,343,026
Operating Expenses
Electricity purchased and fuel used in generation	424,392	352,089	1,159,299	1,015,282
Natural gas purchased	83,880	79,846	711,706	676,621
Other operating expenses	202,984	210,822	593,936	604,085
Maintenance	42,088	38,941	127,563	128,497
Depreciation and amortization	71,861	74,899	224,130	224,000
Other taxes	56,016	61,409	188,435	204,242
Gain on sale of generation assets	(21,252)	-	(340,739)	-
Deferral of asset sale gain	16,414	-	230,783	-
Total Operating Expenses	876,383	818,006	2,895,113	2,852,727
Operating Income	91,422	72,270	592,986	490,299
Other (Income)	(9,874)	(3,490)	(27,294)	(10,287)
Other Deductions	(670)	1,034	7,005	4,082
Interest Charges, Net	69,675	76,229	208,487	212,052
Preferred Stock Dividends of Subsidiaries	437	988	3,215	18,145
Income From Continuing Operations   Before Income Taxes	31,854	(2,491)	401,573	266,307
Income Taxes (Benefits)	14,354	(4,637)	220,319	104,308
Income From Continuing Operations	17,500	2,146	181,254	161,999
Discontinued Operations
Loss from discontinued operations	(670)	(15,652)	(5,623)	(10,318)
Income taxes (benefits)	857	(7,527)	1,040	(5,521)
Loss From Discontinued Operations	(1,527)	(8,125)	(6,663)	(4,797)
Net Income (Loss)	$15,973	$(5,979)	$174,591	$157,202
Earnings Per Share From Continuing   Operations, basic and diluted	$.12	$.01	$1.24	$1.11
Loss Per Share From Discontinued   Operations, basic and diluted	$(.01)	$(.05)	$(.05)	$(.03)
Total Earnings (Loss) Per Share,   basic and diluted	$.11	$(.04)	$1.19	$1.08
Dividends Paid Per Share	$.26	$.25	$.78	$.75
Average Common Shares Outstanding, basic	146,385	145,684	146,207	145,400
Average Common Shares Outstanding, diluted	146,807	145,901	146,611	145,588

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	Sept. 30, 2004	Dec. 31, 2003
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$300,604	$113,187
Special deposits	13,616	34,669
Accounts receivable, net	554,907	753,328
Fuel, at average cost	225,663	159,163
Materials and supplies, at average cost	22,915	22,491
Accumulated deferred income tax benefits, net	35,370	26,262
Prepayments and other current assets	108,848	81,746
Total Current Assets	1,261,923	1,190,846
Utility Plant, at Original Cost
Electric	5,236,309	5,992,001
Natural gas	2,470,335	2,405,795
Common	414,656	361,737
	8,121,300	8,759,533
Less accumulated depreciation	2,560,183	3,216,927
Net Utility Plant in Service	5,561,117	5,542,606
Construction work in progress	72,049	235,503
Total Utility Plant	5,633,166	5,778,109
Other Property and Investments, Net	189,718	465,609
Regulatory and Other Assets
Regulatory Assets
Nuclear plant obligations	368,771	414,432
Unfunded future income taxes	108,447	254,977
Unamortized loss on debt reacquisitions	65,313	47,509
Environmental remediation costs	121,638	122,846
Nonutility generator termination agreements	98,776	106,631
Asset retirement obligation	-	163,530
Other	383,406	407,432
Total regulatory assets	1,146,351	1,517,357
Other Assets
Goodwill, net	1,525,840	1,533,123
Prepaid pension benefits	646,060	608,933
Other	314,290	212,455
Total other assets	2,486,190	2,354,511
Total Regulatory and Other Assets	3,632,541	3,871,868
Total Assets	$10,717,348	$11,306,432

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	Sept. 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	$14,077	30,989
Notes payable	104,304	308,406
Accounts payable and accrued liabilities	341,083	339,812
Interest accrued	58,224	48,989
Taxes accrued	74,054	43,710
Other	215,971	191,873
Total Current Liabilities	807,713	965,029
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	750,113	731,621
Deferred income taxes	25,220	181,211
Gain on sale of generation assets	239,380	129,640
Pension benefits	27,516	51,970
Other	76,289	96,509
Total regulatory liabilities	1,118,518	1,190,951
Other liabilities
Deferred income taxes	973,675	853,489
Nuclear plant obligations	257,813	277,643
Other postretirement benefits	430,339	408,903
Asset retirement obligation	2,998	437,076
Environmental remediation costs	147,680	145,446
Other	397,989	346,630
Total other liabilities	2,210,494	2,469,187
Total Regulatory and Other Liabilities	3,329,012	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	3,507,792	3,638,426
Total long-term debt	3,863,462	4,017,846
Total Liabilities	8,000,187	8,643,013
Commitments	-	-
Preferred Stock of Subsidiaries  Redeemable solely at the option of subsidiaries	46,671	91,095
Common Stock Equity  Common stock	1,469	1,463
Capital in excess of par value	1,469,589	1,458,802
Retained earnings	1,187,072	1,126,457
Accumulated other comprehensive income (loss)	18,849	(11,214)
Deferred compensation	(5,810)	(2,820)
Treasury stock, at cost	(679)	(364)
Total Common Stock Equity	2,670,490	2,572,324
Total Liabilities and Stockholders' Equity	$10,717,348	$11,306,432

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Energy East Corporation CondensedConsolidated Statements of Cash Flows - (Unaudited)
Nine months ended September 30	2004	2003
(Thousands)
Net Cash Provided by Operating Activities	$330,019	$445,687
Investing Activities
Proceeds from sale of generation assets	453,678	-
Refund of excess decommissioning fund	76,593	-
Utility plant additions	(216,814)	(187,267)
Other property and investments additions	(5,453)	(24,773)
Other property and investments sold	2,255	9,532
Special deposits	21,067	5,150
Other	9,561	(3,615)
Net Cash Provided (Used) in Investing Activities	340,887	(200,973)
Financing Activities
Issuance of common stock	1,908	3,330
Repurchase of common stock	(6,306)	-
Repayments of first mortgage bonds and preferred stock of   subsidiaries, including net premiums	(261,506)	(242,066)
Long-term note issuances	276,500	505,596
Long-term note repayments	(231,401)	(247,582)
Notes payable three months or less, net	(191,101)	(146,900)
Notes payable issuances	3,000	7,000
Notes payable repayments	(16,000)	(91,435)
Book overdraft	41,910	-
Dividends on common stock	(100,493)	(95,832)
Net Cash Used in Financing Activities	(483,489)	(307,889)
Net Increase (Decrease) in Cash and Cash Equivalents	187,417	(63,175)
Cash and Cash Equivalents, Beginning of Period	113,187	250,490
Cash and Cash Equivalents, End of Period	$300,604	$187,315

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Energy East Corporation CondensedConsolidated Statements of Retained Earnings - (Unaudited)
Nine months ended September 30	2004	2003
(Thousands)
Balance, Beginning of Period	$1,126,457	$1,061,428
Add net income	174,591	157,202
Deduct dividends on common stock	113,976	108,960
Balance, End of Period	$1,187,072	$1,109,670

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Energy East Corporation CondensedConsolidated Statements of Comprehensive Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Net income (loss)	$15,973	$(5,979)	$174,591	$157,202
Other comprehensive income, net of tax
Net unrealized gains on investments,    net of income tax (expense) for the    three months of $(688) in 2004 and $(87) in    2003 and for the nine months of $(114) in    2004 and $(730) in 2003	1,176	132	249	1,096
Minimum pension liability adjustment, net of    income tax (expense) for the three and    nine months in 2004 of $(47) and for the    three and nine months in 2003 of $(73)	71	111	71	111
Unrealized gains (losses) on derivatives    qualified as hedges, net of income tax    benefit (expense) for the three months of    $(14,679) in 2004 and $8,840 in 2003 and    for the nine months of $(31,908) in 2004    and $(5,176) in 2003	20,826	(14,046)	46,637	7,762
Reclassification adjustment for derivative    (gains) included in net income, net of    income tax expense for the three    months of $195 in 2004 and $1,345 in    2003 and for the nine months of $11,205    in 2004 and $12,919 in 2003	(293)	(2,032)	(16,894)	(19,486)
Net unrealized gains (losses) on derivatives    qualified as hedges	20,533	(16,078)	29,743	(11,724)
Total other comprehensive income (loss)	21,780	(15,835)	30,063	(10,517)
Comprehensive Income (Loss)	$37,753	$(21,814)	$204,654	$146,685

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Item 2.  Management's Discussion and Analysis of Financial Condition
             and Results of Operations

Energy East Corporation

Overview

Energy East Corporation's (Energy East or 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. Management continues to implement plans to achieve savings through a company-wide restructuring, consolidation of utility support services and other changes.

Because Energy East's primary operations - its electric and natural gas utility operations - are subject to rate regulation, the regulatory treatment of 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), an operating company of Energy East, received approval for long-term electric and natural gas rate plans. As a result, Energy East now has long-term rate plans for all of its major utility operating companies including New York State Electric & Gas Corporation (NYSEG), Central Maine Power 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 integration savings among customers and shareholders, allow for recovery of certain costs including exogenous and uncontrollable costs, and provide stable rates for customers and revenue predicta bility for those six operating companies.

Over 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 the 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), and on October 1, 2004, Energy East Solutions, Inc., a subsidiary of The Energy Network, Inc., completed the sale of its New England and Pennsylvania natural gas customer contracts and related assets.

The continuing evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings. Although the outcomes of those proceedings are difficult to predict, the proceedings could have an effect on the nature of the electric and natural gas utility industry in New York and New England. Recent events in the proceedings are described 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. The company is reducing its outstanding debt as well as that of RG&E with proceeds from the sale of Ginna.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

(a) Liquidity and Capital Resources

Electric Delivery Business

The company's electric delivery business consists primarily of its regulated electricity transmission, distribution and generation operations in upstate New York and Maine.

RG&E 2003 Electric and Natural Gas Rate 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 had incurred and would 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.

Key features of the Electric Rate Agreement include:

• Freezing electric delivery 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 during the period May 1, 2004, through December 31, 2004, through an Electric Supply Reconciliation (ESR).
• Refunding to customers over the term of the plan $110 million of the approximately $378 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. (SeeSale of Ginna Station and Note 2 to the Condensed Financial Statements.)
• Establishing an Asset Sale Gain Account (ASGA) with the net proceeds from the sale of Ginna. 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;

• 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.
• 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.
  

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.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

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.

Upon closing of the sale of Ginna, RG&E transferred $201 million of decommissioning funds to CGG. This amount fully meets the Nuclear Regulatory Commission's decommissioning funding requirements for Ginna. RG&E retained $77 million in excess decommissioning funds, which was credited to the ASGA. CGG is now responsible for all future decommissioning funding. 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.

On September 9, 2004, RG&E received an additional $25 million from CGG for certain post closing adjustments, resulting in a $20 million increase to the ASGA. (SeeRG&E 2003 Electric and Natural Gas Rate Agreementsand Note 2 to the Condensed Financial Statements.)

RG&E Electric Rate Unbundling: In June 2003, as required by the 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. Customers began to enroll in these new commodity options on October 1, 2004.

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.

On September 28, 2004, RG&E executed a Joint Proposal with Staff of the NYPSC, the New York State Department of Environmental Conservation and the New York State Department of Agriculture & Markets, requesting that the NYPSC issue a Certificate of Environmental Compatibility and Public Need for the project subject to certain terms and conditions. The administrative law judge in this proceeding had given other parties until October 25, 2004, to submit statements in opposition to the Joint Proposal. RG&E has not received any statements in opposition.

NYPSC Collaborative on End State of Energy 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 (POLR) 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 th at 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.

On August 25, 2004, the NYPSC issued a Statement of Policy (Statement of Policy) on Further Steps Toward Competition in Retail Energy Markets recommending that all potentially competitive utility functions be opened to competition and that regulated utilities be replaced by ESCOs when markets become workably competitive. While it is not possible to determine when markets will become workably competitive, all utilities will be required to prepare plans to implement the Statement of Policy and encourage customer migration and development of retail competitive markets. The plans can vary by individual utility, and NYSEG and RG&E do not expect the Statement of Policy, under their current rate plans, to affect their commodity service options.

In a separate phase of this proceeding, on August 25, 2004, the NYPSC issued a Statement of Policy on Unbundling and Order Directing Tariff Filings. Utilities are directed to file embedded cost studies and competitive rates in future rate plans or requests for extensions and begin tracking the costs of and revenues generated by competitive energy services. The order also allows parties to file comments and replies on rate design issues discussed in the order.

NYSEG and RG&E are not able to predict what effect, if any, these latest developments will have on future operations.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

NYSEG Collective Bargaining Agreement: The contract between NYSEG and the local unions of the International Brotherhood of Electrical Workers was scheduled to expire effective July 1, 2005. On October 19, 2004, the union membership voted to accept NYSEG's offer to extend the contract until June 30, 2010. The contract provides for annual 3% wage increases for 2005 through 2009. It includes provisions for active employees to contribute to medical insurance plans at a level reflecting NYSEG's cost-sharing philosophy for all such plans by the end of the contract period.

Regional Transmission Organization: ISO New England and the New England transmission owners, including CMP, made a joint regional transmission organization (RTO) filing with the Federal Energy Regulatory Commission (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 other aspects of the FERC's RTO Order. In addition, ISO New England and the New England transmission owners, including CMP, made a joint compliance filing as required by the RTO Order. At this time, CMP and the other New England transmission owners have informed the FERC that it needs to resolve the issues in the request for rehearing and clarification before the New England transmission owners can make a final decision regarding whether and when to join the RTO.

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 2% 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 FERC, to reflect CMP's and the New England Power Pool's actual costs for 2003.

CMP 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

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

or after July 1, 2005, to contribute toward the cost of medical insurance according to a predetermined schedule.

CMP Stranded Cost 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. The MPUC Staff and other parties to the proceeding filed responsive testimony in September 2004. In October 2004 CMP filed its rebuttal to this testimony and filed its sales and revenue forecast for the 2005 through 2008 stranded cost period. CMP expects an MPUC order setting new stranded cost rates in February 2005.

CMP 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 commenced 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 $543 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.

Pursuant 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 Decemb er 31, 2003, are approximately $504 million in 2003 dollars.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

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. On August 30, 2004, the FERC rejected the DPUC's petition; approved Connecticut Yankee's rate increase effective February 1, 2005, subject to refund; and set for hearing the remaining issues. The DPUC has requested rehearing of the FERC's August 30, 2004 Order. CMP cannot predict the outcome of these proceedings.

Natural Gas Delivery Business

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

Natural Gas Supply 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, that gives these companies the right to acquire natural gas supply and optimizes transportation and storage services.

NYSEG Natural Gas Rate 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.

On June 30, 2004, NYSEG filed 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 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,

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

consistent with the billing units and firm delivery revenues contained in NYSEG's Natural Gas Rate Plan. The NYPSC approved all provisions of the Joint Proposal effective September 23, 2004. The first year of a five year phase-in of delivery rates for nonresidential customers went into effect October 1, 2004. The first of four annual changes to residential rates will become effective October 1, 2005.

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.

NYSEG Collective Bargaining Agreement: 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. On October 27, 2004, the DPUC issued a final decision that denied current recovery of exogenous costs but recognized that the costs would be reviewed in SCG's next rate case. SCG is reviewing the decision and may pursue an appeal of certain aspects of the decision.

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 $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 procee d. On September 22, 2004, Prosecutorial Staff reported that the parties had reached an agreement in principle to settle these proceedings. CNG and SCG are working toward a settlement of the issues but cannot predict the final outcome of these proceedings.

Berkshire Gas Rate Plan: In July 2004 Berkshire Gas submitted a filing to the Massachusetts Department of Telecommunications and Energy (DTE) pursuant to its 10-year price cap mechanism plan. This plan, after a 31-month rate freeze, allows for an annual rate increase at the rate of inflation less a 1% productivity offset. Berkshire Gas' filing requested the recovery of certain exogenous costs as well as a rate increase based on the predetermined formula. In September the DTE issued an Order allowing for an increase in rates as provided for in the price cap mechanism plan. The DTE did not allow the requested recovery of exogenous costs.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

Other Businesses

Sale of 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 was approximately $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. On October 1, 2004, Energy East Solutions, Inc., a subsidiary of The Energy Network, Inc., completed the sale of its New England and Pennsylvania natural gas customer contracts and related assets.

Other Matters

Accounting Issues

FIN 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, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 [the Act], which provides guidance on the accounting for the effects of the Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. It also requires certain disclosures regarding the effect of a federal subsidy provided by the Act. FSP No. FAS 106-2 became effective for the company in the interim period beginning July 1, 2004. (See Note 9 to the Condensed Financial Statements.)

Investing and Financing Activities

Investing Activities: Capital spending for the first nine months of 2004 was $217 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.

Investing activities include the sale of Ginna, which resulted in proceeds from the sale of generation assets of $454 million for the first nine months of 2004. Uses of cash related to this sale, including the $60 million refund paid to RG&E customers in June 2004 and tax payments related to the gain on the sale of Ginna of approximately $45 million, are reflected as a reduction in net cash provided by operating activities in the cash flow statement for the nine months ended September 30, 2004.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

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 in connection with the Investor Services Program (formerly known as the Dividend Reinvestment and Stock Purchase Plan) and employee benefit plans, 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 sale of Ginna. (SeeRG&E Financing Activities.)

During the nine months ended September 30, 2004, the company issued 653,747 shares of common stock, at an average price of $23.45 per share, through its Investor Services Program (formerly known as the Dividend Reinvestment and Stock Purchase Plan). The shares issued were original issue shares.

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.

The company raised its common stock dividend 6% in October 2004 to an annual rate of $1.10 per share. In addition it raised its long-term common stock dividend payment ratio target to 65% to 75% of earnings.

In July 2004 the company replaced its $150 million 364-day revolving credit facility with a $150 million five-year revolving credit facility that expires in July 2009.

In July 2004 the company cancelled one-half of a fixed-to-floating interest rate swap ($125 million) on its 8 1/4% junior subordinated debt securities due July 2031. The company paid $1.7 million, the value of the swap on the date cancelled, which it will amortize over the remaining life of the junior subordinated debt securities.

In August 2004 the company entered into a fixed-to-floating interest rate swap on RG&E's 6.65% first mortgage bonds. The company receives a fixed rate of 6.65% and will pay a rate based on the three-month London Interbank Offered Rate (LIBOR) plus 0.49% on a notional amount of $125 million through June 2032. The underlying security is callable at par in June 2007 and the company has a matching option to terminate the swap if the underlying security is called.

In September 2004 Energy East entered into a fixed payer forward starting swap in anticipation of refinancing needs for $150 million of 30-year debt in 2006. The swap, which is based on payment at a fixed rate of 5.60% and receipt of six-month LIBOR, has a mandatory termination date in July 2006.

CMP Financing Activities: In August 2004 CMP entered into a Treasury hedge in anticipation of refinancing needs for $25 million of 30-year debt in March 2005. The hedge locked in the
30-year treasury rate component of that financing at a rate of 5.20%. Also in August 2004 CMP entered into a fixed payer forward starting swap in anticipation of refinancing needs for $22 million of 30-year debt in July 2005. The swap, which is based on payment at a fixed rate of 5.645% and receipt of six-month LIBOR, has a mandatory termination date in July 2005.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

NYSEG Financing 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. The aggregate borrowings and letters of credit may not exceed a combined total of $230 million.

In August 2004 NYSEG refunded $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 were initially set 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 with a seven-day auction period. 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.

In August 2004 NYSEG entered into a forward starting swap to fix the interest rate on a $65 million tax-exempt pollution control note that becomes callable at 102% in July 2005. NYSEG will pay a fixed rate of 3.80% and will receive 67% at the one-month LIBOR rate on a notional amount of $65 million.

In October 2004 NYSEG fixed the interest rate at 4% through maturity on $30 million tax-exempt pollution control notes due October 2015, which had previously paid a one-year floating rate of interest. NYSEG paid $2.3 million, the value on the date of termination of the forward starting swap associated with fixing the interest rate, which it will amortize over the remaining life of the notes.

In October 2004 NYSEG informed holders of a $100 million tax-exempt pollution control note with a seven-day Dutch auction period of its intent to change to a special rate period of 5 years in December 2004.

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

On May 5, 2004, RG&E redeemed its remaining preferred stock, including: $12 million of 4% Series F (120,000 shares), $8 million of 4.10% Series H (80,000 shares), $6 million of 4 3/4% Series I (60,000 shares), $5 million of 4.10% Series J (50,000 shares), $6 million of 4.95% Series K (60,000 shares) and $10 million of 4.55% Series M (100,000 shares), all redeemed at a premium. On May 6, 2004, RG&E redeemed, at a premium, $40 million of 7.45% Series first mortgage bonds due July 2023, and the following Series of first mortgage bonds due March 2023: $33 million of 7.64%, $5 million of 7.66%, and $12 million of 7.67%. Those redemptions were financed through available cash and a short-term credit facility. The short-term credit facility was repaid with proceeds from the sale of Ginna.

In July 2004 RG&E and NYSEG 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. RG&E is permitted to borrow up to $75 million under the facility, NYSEG is permitted to borrow up to $180 million, and RG&E and NYSEG are allowed to issue letters of credit totaling up to $40 million. The aggregate borrowings and letters of credit may not exceed a combined total of $230 million.

In August 2004 RG&E refunded $60 million of fixed-rate tax-exempt mortgage bonds that have rates ranging from 6.35% to 6.5% with proceeds from the issuance of $60 million of multi-mode tax-exempt pollution control notes, which were initially set in a Dutch auction mode with a seven-day auction period.

In September 2004 RG&E repurchased at a premium $39 million of Series TT 6.95% first mortgage bonds, due April 1, 2011, with proceeds from the sale of Ginna.

In the second quarter of 2004, RG&E declared common dividends of $170 million in order to rebalance its capital structure after the sale of Ginna. These funds will be used to reduce debt outstanding at Energy East.

Other Financing Activities: In the second quarter of 2004 Berkshire Gas, CNG and SCG renewed their joint $105 million 364-day revolving credit facility. The borrowing limit for each company is: Berkshire Gas - $15 million, CNG - $50 million and SCG - $55 million, not to exceed a combined total of $105 million.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

(b)Results of Operations

Three months ended September 30	2004	2003	Change
(Thousands, except per share amounts)
Operating Revenues	$967,805	$890,276	9%
Operating Income	$91,422	$72,270	27%
Income from Continuing Operations	$17,500	$2,146	715%
Net Income (Loss)	$15,973	$(5,979)	*
Average Common Shares Outstanding, basic	146,385	145,684	-
Average Common Shares Outstanding, diluted	146,807	145,901	1%
Earnings Per Share from Continuing Operations, basic and diluted	$.12	$.01	*
Earnings (Loss) Per Share, basic and diluted	$.11	$(.04)	*
Dividends Paid Per Share	$.26	$.25	4%

*Change is not meaningful.

Earnings from continuing operations were 12 cents per share for the quarter ended September 30, 2004, compared to 1 cent per share for the quarter ended September 30, 2003. Earnings increased 6 cents per share due to higher margins on electric deliveries and increased 3 cents per share as a result of lower interest expense.

Nine months ended September 30	2004	2003	Change
(Thousands, except per share amounts)
Operating Revenues	$3,488,099	$3,343,026	4%
Operating Income	$592,986	$490,299	21%
Income from Continuing Operations	$181,254	$161,999	12%
Net Income	$174,591	$157,202	11%
Average Common Shares Outstanding, basic	146,207	145,400	1%
Average Common Shares Outstanding, diluted	146,611	145,588	1%
Earnings Per Share from Continuing Operations, basic and diluted	$1.24	$1.11	12%
Earnings Per Share, basic and diluted	$1.19	$1.08	10%
Dividends Paid Per Share	$.78	$.75	4%

Earnings from continuing operations were $1.24 per share for the nine months ended September 30, 2004, compared to $1.11 per share for the nine months ended September 30, 2003. The increase is due to a number of factors. Earnings increased 7 cents per share due to one-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements in the second quarter of 2004. The one-time effects include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory determination. Ongoing effects from RG&E's Electric and Natural Gas Rate Agreements added 6 cents per share to earnings, and include increases as a result of RG&E's electric retail access surcharge and natural gas merchant function charge, and annual credits to RG&E from the ASGA as provided in the Electric Rate Agreement. (SeeRG&E 2003 Electric and Natural Gas Rate Agr eements.) Lower financing costs added 8 cents per share to earnings and higher margins on electric deliveries and sales added another 6 cents per share. Earnings were reduced 4 cents per share due to the accumulated effects of stock-based compensation because of changes in the market value of Energy East stock during the nine months of 2004 as compared to the same period last year. Earnings were reduced another 9 cents per share because of lower natural gas deliveries due to milder weather in the first half of 2004.

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	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	7,896	7,841	1%
Operating Revenues	$722,802	$680,206	6%
Operating Expenses	$618,669	$589,619	5%
Operating Income	$104,133	$90,587	15%

Operating revenues for the third quarter of 2004 increased $43 million primarily due to RG&E's recovery of $23 million of incremental electricity supply costs through its ESR, as allowed in RG&E's Electric Rate Agreement. (SeeRG&E 2003 Electric and Natural Gas Rate Agreements.) Operating revenues also increased as a result of increased wholesale revenues of $13 million for NYSEG, and higher retail sales of $4 million and increased other revenues of $3 million for CMP.

Operating expenses increased $29 million for the quarter, resulting from a $13 million increase for RG&E primarily due to the net effects of higher purchased power costs to replace energy previously provided by Ginna, partially offset by reduced operating costs as a result of the sale of Ginna. Operating expenses also increased because of higher operating and maintenance costs as a result of NYSEG's deferral of significant storm related costs, which reduced expenses $7 million in 2003. Higher purchased power costs due to CMP's increased purchases from NUGs also added to operating expenses.

Nine months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	23,243	23,072	1%
Operating Revenues	$2,094,454	$2,078,953	1%
Operating Expenses	$1,631,578	$1,728,856	(6%)
Operating Income	$462,876	$350,097	32%

Operating revenues for the nine months increased $16 million, primarily due to RG&E's recovery of $19 million of incremental electricity supply costs through its ESR, as described above. Higher wholesale and other revenues for NYSEG added another $35 million to revenues. Those increases were partially offset by decreases of approximately $12 million for CMP, primarily due to rate reductions reflecting lower stranded costs and lower amortization of storm and demand-side management costs, and $28 million for RG&E due to a change in market structure that allows ESCOs to provide electricity, resulting in lower retail revenues offset by higher wholesale revenues.

Operating expenses for the nine months decreased $97 million, primarily due to RG&E's recognition of a $341 million pretax gain on the sale of Ginna, partially offset by RG&E's deferral of the gain net of tax of $231 million. That decrease was partially offset by higher purchased power costs for RG&E resulting from the Ginna sale and higher operating and maintenance costs for NYSEG.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Energy East Corporation

Operating Results for the Natural Gas Delivery Business

Three months ended September 30	2004	2003	Change
(Thousands
Retail Deliveries - Dekatherms	25,555	26,550	(4%)
Operating Revenues	$156,216	$148,504	5%
Operating Expenses	$175,413	$166,355	5%
Operating (Loss)	$(19,197)	$(17,851)	8%

Operating revenues increased $8 million for the third quarter of 2004 primarily due to higher market prices of $4 million that were passed on to customers.

Operating expenses increased $9 million primarily due to an increase in natural gas prices of $4 million.

Nine months ended September 30	2004	2003	Change
(Thousands
Retail Deliveries - Dekatherms	149,104	154,792	(4%)
Operating Revenues	$1,078,222	$1,052,672	2%
Operating Expenses	$964,604	$917,924	5%
Operating Income	$113,618	$134,748	(16%)

Operating revenues increased $26 million for the nine months compared to the prior year period. That increase is primarily due to an increase of $35 million due to higher market prices, which are passed on to customers, partially offset by lower deliveries of $9 million. Other items, including lower transportation revenues and wholesale entitlements further reduced revenues.

Operating expenses increased $47 million for the nine months primarily due to higher natural gas prices of $35 million.

Item 1.  Financial Statements

Central Maine Power Company Condensed Consolidated Statements of Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Operating Revenues
Sales and services	$152,964	$145,715	$445,462	$457,391
Operating Expenses
Electricity purchased	63,208	59,104	183,603	179,790
Other operating expenses	45,991	44,238	125,476	132,543
Maintenance	6,682	6,249	21,522	22,384
Depreciation and amortization	9,449	10,282	30,746	30,647
Other taxes	4,174	4,869	12,497	15,273
Total Operating Expenses	129,504	124,742	373,844	380,637
Operating Income	23,460	20,973	71,618	76,754
Other (Income)	(964)	(1,195)	(3,047)	(2,943)
Other Deductions	213	331	513	1,130
Interest Charges, Net	6,322	6,531	18,594	19,818
Income Before Income Taxes	17,889	15,306	55,558	58,749
Income Taxes	6,354	5,737	19,766	22,257
Net Income	11,535	9,569	35,792	36,492
Preferred Stock Dividends	361	361	1,082	1,082
Earnings Available for Common Stock	$11,174	$9,208	$34,710	$35,410

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Central Maine Power Company Condensed Consolidated Balance Sheets - (Unaudited)
	Sept. 30, 2004	Dec. 31,   2003
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$16,250	$11,627
Accounts receivable, net	96,419	113,992
Materials and supplies, at average cost	6,687	6,571
Accumulated deferred income tax benefits, net	1,152	1,232
Prepayments and other current assets	7,179	7,135
Total Current Assets	127,687	140,557
Utility Plant, at Original Cost
Electric	1,373,040	1,337,931
Less accumulated depreciation	472,565	451,407
Net Utility Plant in Service	900,475	886,524
Construction work in progress	10,038	15,953
Total Utility Plant	910,513	902,477
Other Property and Investments, Net	24,258	25,475
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	152,559	173,548
Unfunded future income taxes	104,276	104,276
Unamortized loss on debt reacquisitions	7,766	8,646
Demand-side management program costs	4,221	5,281
Environmental remediation costs	1,091	2,614
Nonutility generator termination agreement	5,005	5,944
Other	78,279	65,145
Total regulatory assets	353,197	365,454
Other assets
Goodwill, net	324,939	324,938
Prepaid pension benefits	33,839	29,623
Other	14,533	18,329
Total other assets	373,311	372,890
Total Regulatory and Other Assets	726,508	738,344
Total Assets	$1,788,966	$1,806,853

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Central Maine Power Company Condensed Consolidated Balance Sheets - (Unaudited)
	Sept. 30, 2004	Dec. 31,   2003
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$3,011	$2,999
Notes payable	37,000	15,000
Accounts payable and accrued liabilities	51,849	45,815
Interest accrued	2,026	5,397
Taxes accrued	3,020	1,206
Other	26,328	48,322
Total Current Liabilities	123,234	118,739
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	85,589	80,128
Deferred income taxes	77,900	77,849
Gain on sale of generation assets	49,400	76,998
Other	23,509	17,127
Total regulatory liabilities	236,398	252,102
Other liabilities
Deferred income taxes	85,283	65,555
Nuclear plant obligations	152,559	173,548
Other postretirement benefits	75,555	73,181
Environmental remediation costs	2,782	3,017
Other	116,674	113,880
Total other liabilities	432,853	429,181
Total Regulatory and Other Liabilities	669,251	681,283
Long-term debt	312,287	314,511
Total Liabilities	1,104,772	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	482,933	482,794
Retained earnings	27,782	35,072
Accumulated other comprehensive (loss)	(18,149)	(17,174)
Total Common Stock Equity	648,623	656,749
Total Liabilities and Stockholder's Equity	$1,788,966	$1,806,853

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Central Maine Power Company Condensed Consolidated Statements of Cash Flows - (Unaudited)
Nine months ended September 30	2004	2003
(Thousands)
Net Cash Provided by Operating Activities	$62,582	$65,169
Investing Activities
Utility plant additions	(42,848)	(18,489)
Other	6,627	222
Net Cash Used in Investing Activities	(36,221)	(18,267)
Financing Activities
Long-term note issuances	-	35,700
Long-term note repayments	(2,269)	(52,235)
Notes payable three months or less, net	22,000	10,000
Book overdraft	1,613	-
Dividends on common and preferred stock	(43,082)	(46,082)
Net Cash Used in Financing Activities	(21,738)	(52,617)
Net (Decrease) Increase in Cash and Cash Equivalents	4,623	(5,715)
Cash and Cash Equivalents, Beginning of Period	11,627	20,415
Cash and Cash Equivalents, End of Period	$16,250	$14,700

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Central Maine Power Company Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Nine months ended September 30	2004	2003
(Thousands)
Balance, Beginning of Period	$35,072	$31,682
Add net income	35,792	36,492
	70,864	68,174
Deduct Dividends on Capital Stock
Preferred	1,082	1,082
Common	42,000	45,000
	43,082	46,082
Balance, End of Period	$27,782	$22,092

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Central Maine Power Company Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Net income	$11,535	$9,569	$35,792	$36,492
Other comprehensive income, net of tax
Net unrealized (losses) gains on derivatives    qualified as hedges, net of income tax benefit    (expense) of $670 for the three months in 2004    and $(631) in 2003, and $670 for the nine    months in 2004 and $ - in 2003	(975)	915	(975)	- -
Total other comprehensive income	(975)	915	(975)	-
Comprehensive Income	$10,560	$10,484	$34,817	$36,492

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Item 2.  Management's Discussion and Analysis of Financial Condition
             and Results of Operations

Central Maine Power Company

(a)Liquidity and Capital Resources

Electric Delivery Business

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

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

CMP Alternative Rate Plan: 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

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

Investing Activities: Capital spending for the first nine months of 2004 was $43 million. Capital spending is projected to be $50million 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.

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

Management's Discussion and Analysis of Financial Condition and Results of Operations

Central Maine Power Company

(b)Results of Operations

Three months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	2,384	2,310	3%
Operating Revenues	$152,964	$145,715	5%
Operating Expenses	$129,504	$124,742	4%
Operating Income	$23,460	$20,973	12%
Earnings Available for Common Stock	$11,174	$9,208	21%

Earnings for the quarter increased $2 million primarily due to an increase in operating income because of higher revenues, partially offset by higher purchased power costs.

Operating revenues for the quarter increased $7 million due to higher retail sales of $4 million and increased other revenues of $3 million.

Operating expenses increased $5 million for the quarter primarily because of higher purchased power costs due to increased purchases from NUGs.

Nine months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	6,844	6,684	2%
Operating Revenues	$445,462	$457,391	(3%)
Operating Expenses	$373,844	$380,637	(2%)
Operating Income	$71,618	$76,754	(7%)
Earnings Available for Common Stock	$34,710	$35,410	(2%)

Earnings for the nine months decreased $1 million primarily as a result of lower operating revenues, partially offset by lower operating expenses.

Operating revenues for the nine months decreased $12 million primarily due to rate reductions of $20 million reflecting lower stranded costs and lower amortization of storm and demand-side management costs. That decrease was partially offset by an increase of $7 million for higher deliveries resulting from higher retail sales.

Operating expenses for the nine months decreased $7 million primarily due to lower amortization of ice storm and other costs of $8 million.

Item 1.  Financial Statements

New York State Electric & Gas Corporation Condensed Balance Sheets - (Unaudited)
	Sept. 30, 2004	Dec. 31,   2003
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$12,066	$14,458
Special deposits	8,004	30,353
Accounts receivable, net	226,369	290,166
Fuel, at average cost	56,299	43,207
Materials and supplies, at average cost	6,254	5,893
Accumulated deferred income tax benefits, net	5,346	5,500
Prepayments	36,410	28,917
Total Current Assets	350,748	418,494
Utility Plant, at Original Cost
Electric	2,655,641	2,593,090
Natural gas	701,474	688,705
Common	143,246	120,584
	3,500,361	3,402,379
Less accumulated depreciation	1,196,863	1,144,385
Net Utility Plant in Service	2,303,498	2,257,994
Construction work in progress	15,897	55,638
Total Utility Plant	2,319,395	2,313,632
Other Property and Investments, Net	37,895	37,872
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes	42,245	42,366
Unamortized loss on debt reacquisitions	45,928	38,863
Environmental remediation costs	74,409	74,734
Deferred income taxes	60,022	71,095
Other	48,336	53,238
Total regulatory assets	270,940	280,296
Other assets
Goodwill, net	11,199	11,199
Prepaid pension benefits	485,628	450,817
Other	182,518	75,255
Total other assets	679,345	537,271
Total Regulatory and Other Assets	950,285	817,567
Total Assets	$3,658,323	$3,587,565

Thenotes on pages 44 through 56 are an integral part of the financial statements.

New York State Electric & Gas Corporation Condensed Balance Sheets - (Unaudited)
	Sept. 30,  2004	Dec. 31,   2003
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$166	$710
Notes payable	2,299	41,400
Accounts payable and accrued liabilities	147,405	148,918
Interest accrued	12,626	10,068
Taxes accrued	16,875	15,367
Other	89,370	74,819
Total Current Liabilities	268,741	291,282
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	319,684	304,065
Gain on sale of generation assets	56,307	52,642
Other	13,556	21,571
Total regulatory liabilities	389,547	378,278
Other liabilities
Deferred income taxes	538,028	522,919
Other postretirement benefits	219,022	208,393
Asset retirement obligation	387	377
Environmental remediation costs	97,075	97,400
Other	65,846	50,840
Total other liabilities	920,358	879,929
Total Regulatory and Other Liabilities	1,309,905	1,258,207
Long-term debt	1,065,235	1,065,590
Total Liabilities	2,643,881	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	277,715	277,462
Retained earnings	238,449	229,048
Accumulated other comprehensive income	58,062	25,760
Total Common Stock Equity	1,004,283	962,327
Total Liabilities and Stockholder's Equity	$3,658,323	$3,587,565

Thenotes on pages 44 through 56 are an integral part of the financial statements.

New York State Electric & Gas Corporation Condensed Statements of Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Operating Revenues
Electric	$383,824	$367,457	$1,146,329	$1,111,777
Natural Gas	40,166	39,170	298,370	283,945
Total Operating Revenues	423,990	406,627	1,444,699	1,395,722
Operating Expenses
Electricity purchased	211,372	214,811	633,801	612,924
Natural gas purchased	16,147	21,772	189,894	172,398
Other operating expenses	67,411	57,855	178,395	158,354
Maintenance	20,854	14,489	54,950	52,919
Depreciation and amortization	26,371	25,136	77,585	75,132
Other taxes	26,590	29,297	82,671	89,961
Total Operating Expenses	368,745	363,360	1,217,296	1,161,688
Operating Income	55,245	43,267	227,403	234,034
Other (Income)	(4,395)	836	(4,567)	(1,273)
Other Deductions	(120)	224	51	(1,072)
Interest Charges, Net	18,554	19,546	55,952	59,906
Income Before Income Taxes	41,206	22,661	175,967	176,473
Income Taxes	15,321	2,408	66,269	65,681
Net Income	25,885	20,253	109,698	110,792
Preferred Stock Dividends	99	99	297	297
Earnings Available for Common Stock	$25,786	$20,154	$109,401	$110,495

Thenotes on pages 44 through 56 are an integral part of the financial statements.

New York State Electric & Gas Corporation Condensed Statements of Cash Flows - (Unaudited)
Nine months ended September 30	2004	2003
(Thousands)
Net Cash Provided by Operating Activities	$171,996	$166,083
Investing Activities
Proceeds from sale of utility plant	-	379
Utility plant additions	(79,609)	(63,574)
Special deposits	22,349	5,156
Other	-	271
Net Cash Used in Investing Activities	(57,260)	(57,768)
Financing Activities
Repayments of first mortgage bonds, including net premiums	-	(154,085)
Long-term note issuances	204,000	196,986
Long-term note repayments	(204,000)	-
Notes payable three months or less, net	(39,101)	(55,000)
Book overdraft	22,270	-
Dividends on common and preferred stock	(100,297)	(90,297)
Net Cash Used in Financing Activities	(117,128)	(102,396)
Net Increase (Decrease) in Cash and Cash Equivalents	(2,392)	5,919
Cash and Cash Equivalents, Beginning of Period	14,458	11,490
Cash and Cash Equivalents, End of Period	$12,066	$17,409

Thenotes on pages 44 through 56 are an integral part of the financial statements.

New York State Electric & Gas Corporation Condensed Statements of Retained Earnings - (Unaudited)
Nine months ended September 30	2004	2003
(Thousands)
Balance, Beginning of Period	$229,048	$206,519
Add net income	109,698	110,792
	338,746	317,311
Deduct Dividends on Capital Stock
Preferred	297	297
Common	100,000	90,000
	100,297	90,297
Balance, End of Period	$238,449	$227,014

Thenotes on pages 44 through 56 are an integral part of the financial statements.

New York State Electric & Gas Corporation Condensed Statements of Comprehensive Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Net income	$25,885	$20,253	$109,698	$110,792
Other comprehensive income, net of tax
Net unrealized gains on investments,    net of income tax (expense) for the three months    of $ - in 2004 and $(180) in 2003 and for the    nine months of $ - in 2004 and $(345) in 2003	-	271	-	520
Minimum pension liability adjustment, net of    income tax (expense) for the three months    of $(47) and for the nine months of $(47) in    2004 and for the three and nine months in    2003 of $(73)	71	111	71	111
Unrealized (losses) gains on derivatives qualified    as hedges, net of income tax benefit (expense)    for the three months of $(15,351) in 2004 and    $9,390 in 2003 and for the nine months of    $(32,580) in 2004 and $(6,793) in 2003	23,147	(14,159)	49,125	10,243
Reclassification adjustment for derivative (gains)    included in net income, net of income tax    expense for the three months of $195 in 2004    and $1,377 in 2003 and for the nine months of    $11,205 in 2004 and $12,966 in 2003	(293)	(2,076)	(16,894)	(19,551)
Net unrealized gains (losses) on derivatives    qualified as hedges	22,854	(16,235)	32,231	(9,308)
Total other comprehensive income (loss)	22,925	(15,853)	32,302	(8,677)
Comprehensive Income	$48,810	$4,400	$142,000	$102,115

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Item 2.  Management's Discussion and Analysis of Financial Condition
             and Results of Operations

New York State Electric & Gas Corporation

(a)Liquidity and Capital Resources

Electric Delivery Business

NYSEG's electric delivery business principally consists of its regulated transmission and 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.

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

Natural Gas Delivery Business

NYSEG's natural gas delivery 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.

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

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

Investing Activities:Capital spending for the first nine months of 2004 was $80 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.

Management's Discussion and Analysis of Financial Condition and Results of Operations

New York State Electric & Gas Corporation

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

(b)Results of Operations

Three months ended September 30	2004	2003	Change
(Thousands)
Operating Revenues	$423,990	$406,627	4%
Operating Income	$55,245	$43,267	28%
Earnings Available for Common Stock	$25,786	$20,154	28%

Third quarter 2004 earnings increased $5 million primarily due to higher margins on electricity and natural gas deliveries, and a change in estimate of income taxes to reflect actual 2002 taxes and revisions to the estimated effective tax rate for 2003 that reduced earnings $3 million in 2003. Those increases were partially offset by higher operating and maintenance costs.

Nine months ended September 30	2004	2003	Change
(Thousands)
Operating Revenues	$1,444,699	$1,395,722	4%
Operating Income	$227,403	$234,034	(3%)
Earnings Available for Common Stock	$109,401	$110,495	(1%)

Earnings decreased $1 million for the nine-month period primarily due to lower deliveries in the first quarter because of warmer winter weather in 2004 and higher operating and maintenance costs. Those decreases were partially offset by higher margins on electricity and natural gas deliveries.

Operating Results for the Electric Delivery Business

Three months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	3,673	3,672	-
Operating Revenues	$383,824	$367,457	4%
Operating Expenses	$329,164	$317,559	4%
Operating Income	$54,660	$49,898	10%

The $16 million increase in operating revenues for the quarter was primarily due to increases in wholesale revenues of $13 million.

Operating expenses increased $16 million for the quarter primarily due to a $7 million increase in operating and maintenance costs as a result of the deferral of significant storm related costs, which reduced expenses in 2003.

Management's Discussion and Analysis of Financial Condition and Results of Operations

New York State Electric & Gas Corporation

Nine months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	11,120	11,079	-
Operating Revenues	$1,146,329	$1,111,777	3%
Operating Expenses	$956,101	$918,310	4%
Operating Income	$190,228	$193,467	(2%)

The $35 million increase in operating revenues for the nine months was primarily due to increased wholesale revenues of $12 million and higher other revenues of $26 million.

Operating expenses increased $38 million for the nine months primarily due to higher purchased power costs of $21 million because of increased wholesale sales and $20 million for higher operating and maintenance costs, including $7 million as a result of the deferral of significant storm related costs, which reduced expenses in 2003.

Operating Results for the Natural Gas Delivery Business

Three months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Dekatherms	6,480	6,620	(2%)
Operating Revenues	$40,166	$39,170	3%
Operating Expenses	$39,581	$45,801	(14%)
Operating Income (Loss)	$585	$(6,631)	*

*Change is not meaningful.

Operating revenues increased $1 million for the quarter primarily as a result of higher market prices that were passed on to customers.

Operating expenses decreased $6 million for the quarter, primarily due to the effect of natural gas cost deferrals recorded in 2003.

Nine months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Dekatherms	41,920	44,429	(6%)
Operating Revenues	$298,370	$283,945	5%
Operating Expenses	$261,195	$243,378	7%
Operating Income	$37,175	$40,567	(8%)

Operating revenues increased $14 million for the nine months. Higher market prices of $45 million that were passed on to customers were partially offset by a $15 million decrease because of lower wholesale sales, and a $14 million decrease due to lower retail deliveries because of warmer weather.

Operating expenses for the nine months increased $18 million primarily due to a $17 million increase in natural gas purchased. That increase reflects higher natural gas prices of $33 million, partially offset by lower volumes of $21 million for retail deliveries and wholesale sales.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	Sept. 30,  2004	Dec. 31,   2003
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$148,167	$13,596
Special deposits	1,070	3,706
Accounts receivable, net	105,692	156,038
Fuel, at average cost	49,708	29,310
Materials and supplies, at average cost	7,298	7,016
Accumulated deferred income tax benefits, net	16,985	12,154
Prepayments and other current assets	31,516	13,232
Total Current Assets	360,436	235,052
Utility Plant, at Original Cost
Electric	1,207,628	2,060,980
Natural gas	551,116	522,409
Common	184,960	158,804
	1,943,704	2,742,193
Less accumulated depreciation	519,208	1,271,462
Net Utility Plant in Service	1,424,496	1,470,731
Construction work in progress	40,212	160,595
Total Utility Plant	1,464,708	1,631,326
Other Property and Investments, Net	13,280	287,385
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	215,720	240,884
Unfunded future income taxes	-	50,265
Environmental remediation costs	11,679	11,475
Unamortized loss on debt reacquisitions	11,619	-
Nonutility generator termination agreement	93,771	100,687
Asset retirement obligation	-	163,530
Other	150,193	174,998
Total regulatory assets	482,982	741,839
Other assets
Prepaid pension benefits	32,965	16,524
Other	43,231	48,704
Total other assets	76,196	65,228
Total Regulatory and Other Assets	559,178	807,067
Total Assets	$2,397,602	$2,960,830

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	Sept. 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	$76,203	77,476
Interest accrued	7,864	11,540
Taxes accrued	35,713	24,130
Other	64,922	29,642
Total Current Liabilities	184,702	144,038
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	171,199	185,472
Deferred income taxes	10,039	186,571
Unfunded future income taxes	91,458	-
Gain from sale of generation assets	133,672	-
Other	32,713	46,173
Total regulatory liabilities	439,081	418,216
Other liabilities
Deferred income taxes	177,774	72,568
Nuclear waste disposal	105,254	104,095
Other postretirement benefits	75,436	71,956
Asset retirement obligation	2,198	436,096
Environmental remediation costs	26,357	22,356
Other	45,945	39,831
Total other liabilities	432,964	746,902
Total Regulatory and Other Liabilities	872,045	1,165,118
Preferred stock subject to mandatory redemption requirements	-	23,750
Other long-term debt	697,436	826,511
Total long-term debt	697,436	850,261
Total Liabilities	1,754,183	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	556,701	556,190
Retained earnings	9,527	121,032
Treasury stock, at cost	(117,238)	(117,238)
Total Common Stock Equity	643,419	754,413
Total Liabilities and Stockholder's Equity	$2,397,602	$2,960,830

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Operating Revenues
Electric	$187,419	$167,016	$511,811	$509,694
Natural Gas	46,681	36,622	259,364	249,250
Total Operating Revenues	234,100	203,638	771,175	758,944
Operating Expenses
Electricity purchased and fuel used in generation	92,851	43,215	162,643	119,673
Natural gas purchased	24,957	17,687	159,130	148,937
Other operating expenses	44,418	67,387	152,727	222,716
Maintenance	12,129	15,141	40,590	42,591
Depreciation and amortization	22,747	26,464	73,152	79,377
Other taxes	17,205	18,572	56,173	62,363
Gain on sale of generation assets	(21,252)	-	(340,739)	-
Deferral of asset sale gain	16,414	-	230,783	-
Total Operating Expenses	209,469	188,466	534,459	675,657
Operating Income	24,631	15,172	236,716	83,287
Other (Income)	(610)	(1,274)	(8,710)	(3,815)
Other Deductions	(4,022)	423	(2,078)	1,386
Interest Charges, Net	13,992	15,307	41,791	61,694
Income Before Income Taxes	15,271	716	205,713	24,022
Income Taxes	9,855	3,577	145,429	10,720
Net Income (Loss)	5,416	(2,861)	60,284	13,302
Preferred Stock Dividends	(39)	513	1,789	2,363
Earnings (Loss) Available for Common Stock	$5,455	$(3,374)	$58,495	$10,939

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Cash Flows - (Unaudited)
Nine months ended September 30	2004	2003
(Thousands)
Net Cash Provided by Operating Activities	$24,438	$158,305
Investing Activities
Proceeds from sale of generation assets	453,678	-
Refund of excess decommissioning fund	76,593	-
Utility plant additions	(60,038)	(74,115)
Nuclear generating plant decommissioning fund	(8,560)	(13,012)
Other	3,222	(2,781)
Net Cash Provided by (Used in) Investing Activities	464,895	(89,908)
Financing Activities
Repayments of first mortgage bonds and preferred stock	(261,500)	(80,000)
Long-term note issuances	60,500	75,000
Repayment of promissory notes	-	(79,935)
Book overdraft	18,027	-
Dividends on common and preferred stock	(171,789)	(37,775)
Net Cash Used in Financing Activities	(354,762)	(122,710)
Net Increase (Decrease) in Cash and Cash Equivalents	134,571	(54,313)
Cash and Cash Equivalents, Beginning of Period	13,596	86,385
Cash and Cash Equivalents, End of Period	$148,167	$32,072

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Retained Earnings - (Unaudited)
Nine months ended September 30	2004	2003
(Thousands)
Balance, Beginning of Period	$121,032	$154,267
Add net income	60,284	13,302
	181,316	167,569
Deduct Dividends on Capital Stock
Preferred	1,789	2,363
Common	170,000	35,000
	171,789	37,363
Balance, End of Period	$9,527	$130,206

Thenotes on pages 44 through 56 are an integral part of the financial statements.

Item 2.  Management's Discussion and Analysis of Financial Condition
             and Results of Operations

Rochester Gas and Electric Corporation

(a)Liquidity and Capital Resources

Electric Delivery Business

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

Natural Gas Delivery Business

RG&E's natural gas delivery 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.

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

Investing and Financing Activities

Investing Activities: Capital spending for the first nine months of 2004 was $60 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.

Investing activities include the sale of Ginna, which resulted in proceeds from the sale of generation assets of $454 million for the first nine months of 2004. Uses of cash related to this sale, including the $60 million refund paid to RG&E customers in June 2004 and tax payments related to the gain on the sale of Ginna of approximately $45 million, are reflected as a reduction in net cash provided by operating activities in the cash flow statement for the nine months ended September 30, 2004.

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	2004	2003	Change
(Thousands)
Operating Revenues	$234,100	$203,638	15%
Operating Income	$24,631	$15,172	62%
Earnings Available for Common Stock	$5,455	$(3,374)	*

*Change is not meaningful.

Earnings increased $9 million for the quarter primarily due to an increase of $4 million resulting from a reduction in RG&E's allowance for doubtful accounts. (See Note 8 to the Condensed Financial Statements.) RG&E's electric retail access surcharge and natural gas merchant function charge, as provided in the Electric Rate Agreement added $2 million to earnings. (SeeRG&E 2003 Electric and Natural Gas Rate Agreements.) Earnings also increased for the quarter because of a change in estimate of income taxes to reflect actual 2002 taxes that reduced earnings $3 million in 2003.

Nine months ended September 30	2004	2003	Change
(Thousands)
Operating Revenues	$771,175	$758,944	2%
Operating Income	$236,716	$83,287	184%
Earnings Available for Common Stock	$58,495	$10,939	435%

Earnings for the nine months increased $48 million 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 $10 million in the second quarter of 2004. The one-time effects include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory determination. Ongoing effects from RG&E's Electric and Natural Gas Rate Agreements added $9 million to year-to-date earnings. Earnings also increased due to the recognition in 2003 of the terms and conditions of an NYPSC rate order

Management's Discussion and Analysis of Financial Condition and Results of Operations

Rochester Gas and Electric Corporation

for RG&E, which became effective in January 2003, and reduced earnings $30 million in the first quarter of 2003. The January 2003 rate order included recovery of $26 million for excess earnings and related interest.

Operating Results for the Electric Delivery Business

Three months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	1,840	1,859	(1%)
Operating Revenues	$187,419	$167,016	12%
Operating Expenses	$160,517	$147,279	9%
Operating Income	$26,902	$19,737	36%

The $20 million increase in operating revenues for the quarter is primarily due to the recovery of $23 million of incremental electricity supply costs through the ESR, as allowed in RG&E's Electric Rate Agreement. (SeeRG&E 2003 Electric and Natural Gas Rate Agreements.) Also, a change in market structure that allows ESCOs to provide electricity reduced retail revenues $30 million and increased wholesale revenues $25 million.

Operating expenses increased $13 million for the quarter primarily due to the net effects of higher purchased power costs to replace energy previously provided by Ginna, partially offset by reduced operating costs as a result of the sale of Ginna. Operating expenses decreased $7 million as a result of a reduction in RG&E's allowance for doubtful accounts.

Nine months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Megawatt-hours	5,278	5,309	(1%)
Operating Revenues	$511,811	$509,694	-
Operating Expenses	$304,862	$456,476	(33%)
Operating Income	$206,949	$53,218	289%

Operating revenues for the nine months increased $2 million, primarily due to the recovery of $19 million of electricity supply costs through the ESR described above. A change in market structure that allows ESCOs to provide electricity reduced retail revenues $100 million and increased wholesale revenues $84 million.

Operating expenses decreased $152 million for the nine months primarily due to RG&E's recognition of a $341 million pretax gain on the sale of Ginna, partially offset by RG&E's deferral of the gain net of tax of $231 million. An additional decrease resulted from the recognition of the terms and conditions of the NYPSC rate order for RG&E, which became effective in January 2003, and increased operating expenses $30 million in 2003. Operating expenses decreased $7 million as a result of a reduction in RG&E's allowance for doubtful accounts.

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	2004	2003	Change
(Thousands)
Retail Deliveries - Dekatherms	5,150	4,845	6%
Operating Revenues	$46,681	$36,622	27%
Operating Expenses	$48,952	$41,187	19%
Operating Loss	$(2,271)	$(4,565)	(50%)

Operating revenues increased $10 million for the quarter, which resulted from higher deliveries of $8 million and higher market prices for natural gas purchased of $2 million that were passed on to customers.

Operating expenses increased $8 million for the quarter primarily due to an increase in purchases of natural gas because of higher deliveries.

Nine months ended September 30	2004	2003	Change
(Thousands)
Retail Deliveries - Dekatherms	37,828	39,192	(3%)
Operating Revenues	$259,364	$249,250	4%
Operating Expenses	$229,597	$219,181	5%
Operating Income	$29,767	$30,069	(1%)

Operating revenues increased $10 million for the nine months reflecting higher market prices for natural gas purchased of $15 million that were passed on to customers. That increase was partially offset by lower deliveries that reduced revenues $5 million.

Operating expenses increased $10 million for the nine months primarily due to higher market prices for natural gas purchased.

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
CMP	1, 3, 4, 7, 8, 9, 10, 11
NYSEG	1, 3, 4, 7, 8, 9, 10, 11
RG&E	1, 2, 3, 4, 8, 9, 10, 11

Note 1. Unaudited Condensed Financial Statements

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

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

The accompanying unaudited financial statements for each registrant should be read in conjunction with the financial statements and notes contained in the report on Form 10-K filed by each registrant for the year ended December 31, 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.

Reclassifications: Certain amounts have been reclassified in the company's unaudited financial statements to conform to the 2004 presentation and to reflect discontinued operations.

Note 2. Sale of Ginna Nuclear Generating 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. The gain on the sale of Ginna of $319 million net of income taxes of $105 million resulted in a $214 million deferral of asset sale gain, as reflected on Energy East's and RG&E's statements of income for the six months ended June 30, 2004. On September 9, 2004, RG&E received an additional $25 million from CGG for post closing adjustments. As a result, Energy East's and RG&E's statements of income reflect gains on the sale of Ginna of $21 million for the three months ended September 30, 2004, and $341 million for the nine months ended September 30, 2004. The total deferral of the asset sale gain, after related taxes of $110 million, is $231 million for the nine months ended September 30, 2004.

RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna, including providing for an ASGA of $378 million after the post closing adjustments, and addressing the disposition of the asset sale gain. Upon closing of the sale of Ginna, 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 were credited to customers as part of the ASGA.

A summary of the effects of the sale of Ginna and the related ASGA for the periods in 2004 follows (in thousands):

	Six Months Ended June 30, 2004	Three Months Ended Sept. 30, 2004	Nine Months Ended Sept. 30, 2004
Cash proceeds	$428,541	$25,137	$453,678
Net book value of property sold, excluding  decommissioning reserve	(184,564)	(2,981)	(187,545)
Decommissioning reserve	311,571	-	311,571
Decommissioning funds	(277,113)	-	(277,113)
Excess decommissioning funds retained	76,593	-	76,593
Miscellaneous assets and liabilities, including  deferred selling costs	(35,541)	(904)	(36,445)
Gain on sale of generation assets, deferred	319,487	21,252	340,739
Income taxes payable	(105,119)	(4,837)	(109,956)
Deferral of asset sale gain	214,368	16,415	230,783
Regulatory liability equal to deferred income taxes  on the deferred asset sale gain	143,000	4,079	147,079
Balance at closing, Gain from sale of generation  assets, deferred	$357,368	$20,494	$377,862

The ASGA was adjusted subsequent to the sale to reflect provisions of RG&E's Electric Rate Agreement, including refunds due to customers and an ESR that allows RG&E to recover its actual electricity supply costs. Adjustments to the ASGA to reconcile to the balance of the deferred regulatory liability as of June 30, 2004, and September 30, 2004, are as follows (in thousands):

Initial 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
Additional gain due to post closing adjustments	20,493
Regulatory liability equal to deferred income taxes on the incremental  deferred asset sale gain	(4,079)
Other, principally Electric Supply Reconciliation	(10,145)
Balance at September 30, 2004, Gain from sale of generation assets	$133,672

In addition, the company's and RG&E's effective tax rate was significantly affected by the sale of Ginna. Due to the regulatory accounting for the gain on the sale, any gain in excess of what was required to offset income taxes payable on the sale was required to be deferred. (See Note 3 to the Condensed Financial Statements.)

Note 3. Income Taxes

The company's effective tax rate differed from the expected annual effective tax rate primarily as a result of the deferred gain from RG&E's sale of Ginna. RG&E recorded pretax income of $110 million and income tax expense of $110 million, resulting in a 100% effective tax rate on the gain. (See Note 2 to the Condensed Financial Statements.) Other factors contributing to the increase in the effective tax rate were increases in prior year taxes of $5 million, a change in estimate to reflect actual federal and New York State income taxes in connection with filing the 2003 income tax returns and the year-to-date effect of revising the estimated effective tax rate for 2004. Those adjustments increased the effective tax rate to 44% for the third quarter of 2004. Those adjustments, coupled with the asset sale gain deferral, increased the company's 2004 year-to-date effective tax rate to 54%.

CMP and NYSEG have provided for taxes for the quarter and nine months of 2004 at the expected annual effective tax rate.

RG&E's effective tax rate differed from the expected annual effective tax rate primarily as a result of the deferred gain from the sale of Ginna. RG&E recorded pretax income of $110 million and income tax expense of $110 million, resulting in a 100% effective tax rate on the gain. Other factors contributing to the increase in the effective tax rate were increases in prior year taxes of $5 million, a change in estimate to reflect actual federal and New York State income taxes in connection with filing 2003 the income tax returns and the year-to-date effect of revising the estimated effective tax rate for 2004. Those adjustments increased RG&E's effective tax rate to 65% for the third quarter of 2004. Those adjustments, coupled with the asset sale gain deferral, increased RG&E's 2004 year-to-date effective tax rate to 71%.

Note 4. Other (Income) and Other Deductions

	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Energy East
Interest income	$(5,011)	$(1,602)	$(6,376)	$(3,957)
Allowance for funds used during construction	(161)	(531)	(423)	(1,497)
Gains from the sale of nonutility property	(2,397)	(148)	(3,633)	(207)
Earnings from equity investments	(880)	(1,006)	(3,482)	(3,549)
2003 RG&E Electric and Natural Gas   Rate Agreement	- -	- -	(6,117)	- -
Miscellaneous	(1,425)	(203)	(7,263)	(1,077)
Total other (income)	$(9,874)	$(3,490)	$(27,294)	$(10,287)
Losses from disposition of property	$(3,015)	-	$1,033	-
Miscellaneous	2,345	1,034	5,972	4,082
Total other deductions	$(670)	$1,034	$7,005	$4,082
CMP
Interest income	$(23)	$(142)	$(57)	$(560)
Earnings from equity investments	(203)	(475)	(716)	(1,494)
Miscellaneous	(738)	(578)	(2,274)	(889)
Total other (income)	$(964)	$(1,195)	$(3,047)	$(2,943)
Miscellaneous	$213	$331	$513	$1,130
Total other deductions	$213	$331	$513	$1,130
NYSEG
Interest income	$(3,784)	$(276)	$(3,939)	$(928)
Miscellaneous	(611)	1,112	(628)	(345)
Total other (income)	$(4,395)	$836	$(4,567)	$(1,273)
Miscellaneous	$(120)	$224	$51	$(1,072)
Total other deductions	$(120)	$224	$51	$(1,072)
RG&E
Interest income	$(534)	$(852)	$(996)	$(2,798)
2003 RG&E Electric and Natural Gas   Rate Agreement	- -	- -	(6,117)	- -
Miscellaneous	(76)	(422)	(1,597)	(1,017)
Total other (income)	$(610)	$(1,274)	$(8,710)	$(3,815)
Losses from disposition of property	$(3,238)	-	$(80)	-
Miscellaneous	(784)	423	(1,998)	1,386
Total other deductions	$(4,022)	$423	$(2,078)	$1,386

Note 5. Basic and Diluted Earnings per Share

Basic earnings per share (EPS) is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the period. The weighted-average common shares outstanding for diluted EPS include the incremental effect of restricted stock and stock options issued and exclude stock options issued in tandem with stock appreciation rights (SARs). Historically, all stock options are issued in tandem with SARs and 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.

The reconciliation of basic and dilutive average common shares for each period follows:

	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Basic average common shares outstanding	146,385	145,684	146,207	145,400
Restricted stock awards	422	217	404	188
Potentially dilutive common shares	355	275	312	142
Options issued with SARs	(355)	(275)	(312)	(142)
Dilutive average common shares outstanding	146,807	145,901	146,611	145,588

Options to purchase shares of common stock are excluded from the determination of EPS when the exercise price of an option is greater than the average market price of a common share during the period. Shares excluded from the EPS calculation for the three months ended September 30 were: 1.2 million in 2004 and 2.4 million in 2003, and for the nine months ended September 30 were: 1.2 million in 2004 and 4.5 million in 2003.

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.

Note 6. Discontinued Operations

In keeping with its focus on regulated electric and natural gas delivery businesses, during recent years the company has been systematically exiting certain noncore businesses. On October 1, 2004, Energy East Solutions, Inc., a subsidiary of The Energy Network, Inc., completed the sale of its New England and Pennsylvania natural gas customer constructs and related assets. In July 2004 UWP, a subsidiary of CMP Group, Inc., sold the assets associated with its utility locating and construction divisions. In 2003 Berkshire Propane, Inc., a subsidiary of Berkshire Energy Resources, sold its assets and Energetix, a subsidiary of RGS Energy, Inc. sold its subsidiary, Griffith Oil Co., Inc. During the third quarter of 2004, a change in estimated taxes for the sale of Griffith Oil Co., Inc. was recorded to reflect actual taxes in accordance with the filing of the 2003 Federal and New York State income tax returns. All four businesses were previously reported in the company's Other business segment. Certain financi al information concerning the businesses for the three months and nine months ended September 30, 2004 and 2003, is provided in the table below.

	Three Months		Nine Months
Periods ended September 30	2004	2003	2004	2003
(Thousands)
Component of Energy East Solutions, Inc.
Revenues	$7,643	$6,947	$48,988	$38,143
(Loss) income from operations of    component held for sale	$(113)	$(228)	$(539)	$50
Income taxes (benefits)	(43)	(87)	(206)	20
(Loss) income from component held for sale	$(70)	$(141)	$(333)	$30
Certain Divisions of Union Water Power Co.
Revenues	$(19)	$5,901	$13,156	$16,332
Income (loss) from operations of    discontinued businesses (including    loss on disposal of $5,500 in 2004)	$(557)	$133	$(5,084)	$(1,243)
Income taxes (benefits)	276	54	622	(659)
(Loss) income on discontinued operations	$(833)	$79	$(5,706)	$(584)
Griffith Oil Co., Inc.
Revenues	-	$85,142	-	$296,685
Loss from operations of    discontinued businesses	- -	$(13,041)	- -	$(7,125)
Income taxes (benefits)	$624	(7,313)	$624	(5,206)
Loss on discontinued operations	$(624)	$(5,728)	$(624)	$(1,919)
Berkshire Propane, Inc.
Revenues	-	$630	-	$5,102
Loss from operations of    discontinued businesses	- -	$(2,516)	- -	$(2,000)
Income taxes (benefits)	-	(181)	-	324
Loss on discontinued operations	-	$(2,335)	-	$(2,324)

Note 7. FIN 46R

In December 2003 the FASB issued its revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of 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. FIN 46R requires a business enterprise to consolidate a variable interest entity if that enterprise has a variable interest that will absorb a majority of the entity's expected losses. The company was required to apply FIN 46R to all entities subject to the interpretation as of March 31, 2004.

CMP and NYSEG have independent, ongoing, power purchase contracts with various nonutility generators (NUGs). (See report on Form 10-K for Energy East, CMP and NYSEG for fiscal year ended December 31, 2003, Item 7 - Liquidity and Capital Resources, Contractual Obligations and Commercial Commitments.) CMP and NYSEG were not involved in the formation of and do not have ownership interests in any NUGs. The company evaluated each of CMP's and NYSEG's power purchase contracts with NUGs with respect to FIN 46R. Most of the power purchase contracts were determined not to be variable interests due to one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUGs are either governmental organizations or individuals.

The companies are not able to apply FIN 46R to seven remaining NUGs because they are unable to obtain the information necessary to: (1) determine if the NUGs are variable interest entities, (2) determine if either CMP or NYSEG is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of the seven NUGs. CMP requested necessary information from four NUGs and NYSEG requested information from three NUGs. None of the NUGs provided the requested information. CMP and NYSEG will continue to make efforts to obtain information from the seven NUGs.

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 $10 million for the nine months ended September 30, 2004, and $7 million for the nine months ended September 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 $265 million for the nine months ended September 30, 2004, and $257 million for the nine months ended September 30, 2003.

CMP and NYSEG did not consolidate any NUGs as of September 30, 2004.

Note 8. Accounts Receivable

Accounts receivable for the companies include unbilled revenues as follows: Energy East - consolidated unbilled revenues of $105 million at September 30, 2004, and $219 million at December 31, 2003; CMP - consolidated unbilled revenues of $16 million at September 30, 2004, and $25 million at December 31, 2003; NYSEG - unbilled revenues of $48 million at September 30, 2004, and $72 million at December 31, 2003; RG&E - unbilled revenues of $19 million at September 30, 2004, and $50 million at December 31, 2003.

RG&E reduced its allowance for doubtful accounts $7 million at September 30, 2004, as a result of the customer refunds from the proceeds of the sale of Ginna. (See Note 2 to the Condensed Financial Statements.) In its recent Electric Rate Agreement, approved by the NYPSC in May 2004, RG&E agreed to refund to customers $110 million of the net proceeds from the sale of Ginna, including $60 million in June 2004, and the remaining $50 million over the next three years, beginning in January 2005. The refund to customers was allowed to be applied to accounts receivable in arrears. RG&E's bad debt expense for the three months ended September 30 was $(3) million in 2004 and $4 million in 2003, and for the nine months ended September 30 was $2 million in 2004 and $8 million in 2003.

Note 9. Retirement Benefits

Components of net periodic benefit cost

	Pension Benefits		Postretirement Benefits
Three months ended September 30	2004	2003	2004	2003
(Thousands)
Energy East
Service cost	$8,028	$7,804	$1,462	$1,671
Interest cost	32,746	33,123	8,220	9,178
Expected return on plan assets	(51,530)	(51,043)	(573)	(701)
Amortization of prior service cost	1,163	1,246	(1,711)	(1,719)
Recognized net actuarial (gain) loss	(268)	(1,546)	575	1,682
Amortization of transition (asset) obligation	(308)	(1,809)	2,000	2,017
Curtailment	-	100	-	(154)
Net periodic benefit cost	$(10,169)	$(12,125)	$9,973	$11,974
CMP
Service cost	$1,059	$1,103	$374	$453
Interest cost	3,483	3,394	1,832	1,979
Expected return on plan assets	(3,721)	(3,527)	(192)	(291)
Amortization of prior service cost	50	55	(157)	(160)
Recognized net actuarial (gain) loss	1,210	1,000	377	524
Curtailment	-	100	-	(154)
Net periodic benefit cost	$2,081	$2,125	$2,234	$2,351
NYSEG
Service cost	$4,527	$4,217	$771	$809
Interest cost	17,218	16,964	4,108	4,706
Expected return on plan assets	(30,953)	(30,166)	-	-
Amortization of prior service cost	1,083	1,165	(1,533)	(1,539)
Recognized net actuarial (gain) loss	(3,071)	(4,177)	114	942
Amortization of transition (asset) obligation	(308)	(1,810)	2,017	2,016
Net periodic benefit cost	$(11,504)	$(13,807)	$5,477	$6,934
RG&E
Service cost	1,234	$1,571	$258	$292
Interest cost	7,435	8,087	1,513	1,562
Expected return on plan assets	(12,136)	(12,824)	-	-
Unrecognized transition obligation	-	-	529	622
Amortization of prior service cost	306	366	285	334
Recognized net actuarial (gain) loss	(1,788)	(2,062)	(66)	(69)
Net periodic benefit cost	$(4,949)	$(4,862)	$2,519	$2,741

	Pension Benefits		Postretirement Benefits
Nine months ended September 30	2004	2003	2004	2003
(Thousands)
Energy East
Service cost	$24,083	$23,412	$4,712	$5,014
Interest cost	98,238	99,368	26,590	27,534
Expected return on plan assets	(154,590)	(153,130)	(1,909)	(2,101)
Amortization of prior service cost	3,488	3,739	(5,135)	(5,159)
Recognized net actuarial (gain) loss	(803)	(4,639)	4,369	5,047
Amortization of transition (asset) obligation	(923)	(5,428)	6,001	6,050
Curtailment	-	302	-	(461)
Net periodic benefit cost	$(30,507)	$(36,376)	$34,628	$35,924
CMP
Service cost	$3,177	$3,309	$1,213	$1,360
Interest cost	10,451	10,181	5,942	5,936
Expected return on plan assets	(11,165)	(10,580)	(712)	(873)
Amortization of prior service cost	149	164	(471)	(481)
Recognized net actuarial (gain) loss	3,630	3,000	1,648	1,571
Curtailment	-	302	-	(461)
Net periodic benefit cost	$6,242	$6,376	$7,620	$7,052
NYSEG
Service cost	$13,581	$12,651	$2,516	$2,425
Interest cost	51,653	50,892	13,521	14,119
Expected return on plan assets	(92,861)	(90,499)	-	-
Amortization of prior service cost	3,250	3,494	(4,598)	(4,618)
Recognized net actuarial (gain) loss	(9,215)	(12,532)	2,341	2,827
Amortization of transition (asset) obligation	(923)	(5,429)	6,001	6,049
Net periodic benefit cost	$(34,515)	$(41,423)	$19,781	$20,802
RG&E
Service cost	$3,974	$4,714	$258	$876
Interest cost	22,337	24,259	1,513	4,686
Expected return on plan assets	(36,728)	(38,470)	-	-
Unrecognized transition obligation	-	-	529	1,864
Amortization of prior service cost	937	1,097	285	1,004
Recognized net actuarial (gain) loss	(5,241)	(6,186)	(66)	(207)
Net periodic benefit cost	$(14,721)	$(14,586)	$2,519	$8,223

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

In December 2003 President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a federal subsidy (the subsidy) to sponsors of single-employer defined benefit postretirement health care plans that provide to some or all participants prescription drug benefits that are at least actuarially equivalent to Medicare Part D.

In May 2004 the FASB issued its FSP No. FAS 106-2, which provides guidance on the accounting for the effects of the Act and requires certain disclosures regarding the effect of the subsidy. FSP No. FAS 106-2 supersedes FSP No. FAS 106-1. Energy East, CMP and NYSEG adopted FSP No. FAS 106-2 prospectively in the third quarter of 2004 and remeasured their plan assets and accumulated postretirement benefit obligations (APBOs) as of July 1, 2004, including the effects of the Act and the subsidy. Based on information available as of the date of adoption of FSP No. FAS 106-2, Energy East, CMP and NYSEG concluded that the prescription drug benefits provided by their postretirement health care plans are actuarially equivalent to Medicare Part D benefits to be provided under the Act. The effects of the Act and the subsidy for RG&E were determined to be insignificant because of employer caps and limited employee participation in RG&E's plans that provide postretirement prescription drug benefits.

As of July 1, 2004, the reduction in the APBO for the subsidy related to benefits attributed to past service was $43 million for Energy East, $13 million for CMP and $25 million for NYSEG. The following table provides information concerning the effects of the subsidy on Energy East's, CMP's and NYSEG's measurement of net periodic postretirement benefit cost for the three months ended September 30, 2004:

	Energy East	CMP	NYSEG
(Thousands)
Service cost	$(55)	$(39)	$(14)
Interest cost	(693)	(216)	(407)
Recognized net actuarial (gain) loss	(899)	(211)	(651)
Net periodic benefit cost	$(1,647)	$(466)	$(1,072)

Pursuant to its current rate agreements, the cost reductions for NYSEG have been deferred.

Note 10. Goodwill and Intangible Assets

The companies no longer amortize goodwill effective January 1, 2002, and do not amortize 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 unamortized intangible assets for impairment at least annually. The companies amortize intangible assets with finite lives (amortized intangible assets) and review them for impairment. Annual impairment testing was completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for the companies at September 30, 2004.

Changes in the carrying amounts of Energy East's goodwill, by operating segment, from January 1, 2004, to September 30, 2004, are shown in the table below.

	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 sold	- -	- -	(6,829)	(6,829)
Preacquisition income tax   adjustment	(40)	(531)	117	(454)
Balance, September 30, 2004	$844,491	$676,588	$4,761	$1,525,840

The carrying amount of CMP's goodwill, which is included in its electric delivery operating segment, was $325 million as of September 30, 2004, and January 1, 2004. The carrying amount of NYSEG's goodwill, which is included in its natural gas delivery operating segment, was $11 million as of September 30, 2004, and January 1, 2004.

The company's unamortized intangible assets had a carrying amount of $10 million at September 30, 2004, and December 31, 2003, and primarily consisted of pension assets. The company's amortized intangible assets had a gross carrying amount of $31 million at September 30, 2004, and December 31, 2003, and primarily consisted of investments in pipelines. Accumulated amortization was $13 million at September 30, 2004, and $12 million at December 31, 2003. Estimated amortization expense for 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.

CMP's unamortized intangible assets consist of pension assets and had a carrying amount of $2 million at September 30, 2004, and December 31, 2003. CMP's amortized intangible assets had a gross carrying amount and accumulated amortization of less than $0.3 million at September 30, 2004, and December 31, 2003, and primarily consisted of technology rights. Estimated amortization expense for 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 September 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 September 30, 2004, and $1.5 million at December 31, 2003, and accumulated amortization of approximately $1 million at September 30, 2004, and at 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 September 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. The company measures segment profitability based on net income. 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
September 30, 2004
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$722,802  $152,964  $383,824  $187,419	$156,216  - -       $40,166  $46,681	$88,787  - -       - -       - -	$967,805  $152,964  $423,990  $234,100
Net Income    Energy East    CMP    NYSEG    RG&E	$35,473  $11,535  $28,425  $7,063	$(24,771) - -      $(2,540) $(1,647)	$5,271 - -       - -       - -	$15,973  $11,535  $25,885  $5,416
September 30, 2003
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$680,206  $145,715  $367,457  $167,016	$148,504  - -       $39,170  $36,622	$61,566  - -       - -       - -	$890,276  $145,715  $406,627  $203,638
Net Income    Energy East    CMP    NYSEG    RG&E	$27,693  $9,569  $25,592  $5,172	$(23,366) - -       $(5,339) $(8,033)	$(10,306) - -       - -       - -	$(5,979) $9,569  $20,253  $(2,861)

	Electric      Delivery	Natural Gas     Delivery	Other	Total
(Thousands)
Nine Months Ended
September 30, 2004
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$2,094,454  $445,462  $1,146,329  $511,811	$1,078,222  - -       $298,370  $259,364	$315,423  - -       - -       - -	$3,488,099  $445,462  $1,444,699  $771,175
Net Income    Energy East    CMP    NYSEG    RG&E	$140,488  $35,792  $95,586  $48,206	$26,220  - -       $14,112  $12,078	$7,883  - -       - -       - -	$174,591  $35,792  $109,698  $60,284
September 30, 2003
Operating Revenues    Energy East    CMP    NYSEG    RG&E	$2,078,953  $457,391  $1,111,777  $509,694	$1,052,672  - -       $283,945  $249,250	$211,401  - -       - -       - -	$3,343,026  $457,391  $1,395,722  $758,944
Net Income (Loss)    Energy East    CMP    NYSEG    RG&E	$120,268  $36,492  $93,315  $2,852	$42,257  - -       $17,477  $10,450	$(5,323) - -       - -       - -	$157,202  $36,492  $110,792  $13,302
Total Assets
September 30, 2004    Energy East    CMP    NYSEG    RG&E	$6,780,169  $1,788,966  $2,743,742  $1,726,274	$3,703,801  - -       $914,581  $671,328	$233,378  - -       - -       - -	$10,717,348  $1,788,966  $3,658,323  $2,397,602
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

Forward-looking Statements

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

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties and that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated industry; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of changing energy prices; the operation of the New York Independent System Operator and ISO New England, Inc.; the operation of a regional transmission organization; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements; the company's ability to expand its products and services, including its energy infrastructure in the Northeast; the compa ny'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; the inability of our internal control framework to provide absolute assurance that all incidents of fraud will be detected and prevented; 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 forw ard-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 current electric rate plan offers retail customers choice in their electricity supply including a bundled rate option, an option to purchase electricity supply from an alternative energy company, and a variable rate option. Approximately 35% of NYSEG's total electric load is now provided by an alternative energy company or at the market price. NYSEG's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the bundled rate option, which combines delivery and supply service at a fixed price. For 2004 the customer supply cost component is based on average electricity forward prices for 2003 and 2004 during September 2002, plus 35% to cover the costs and risk that NYSEG is assuming by providing a bundled rate option to retail customers. NYSEG actively hedges the load required to serve customers who select the bundled rate option. As of October 31, 2004, NYSEG's load was 100% hedged for on-peak periods and 96% hedged for off-peak periods from November through December 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would have an immaterial effect on earnings for the period November through December 2004. As of October 31, 2004, NYSEG's load was 90% hedged for on-peak periods and 95% hedged for off-peak periods for 2005. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings approximately $0.7 million in 2005. The percentage of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

RG&E's 2004 rate agreement includes an ESR for the period May through December 2004, and as a result, RG&E has no commodity price risk related to market fluctuations in the price of electricity. Even without the ESR, RG&E-owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. As of October 31, 2004, RG&E's load was fully hedged for on-peak and off-peak periods from November through December 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would have an immaterial effect on earnings for the period November through December 2004. As of October 31, 2004, RG&E's load was 87% hedged for on-peak periods and fully hedged for off-peak periods for 2005. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings approximately $0.1 million in 2005. The percentage of RG&E's hedged load is based on RG&E's load forecasts, which in clude certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast. 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 bundled rate option, an option to purchase electricity supply from an alternative energy company, and a variable rate option. RG&E's exposure to fluctuations in the market price of electricity will be limited to the load required to serve those customers who select the fixed rate option, which combines delivery and supply service at a bundled price.

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

Item 4.  Controls and Procedures

The principal executive officers and principal financial officers of Energy East, CMP, NYSEG and RG&E evaluated the effectiveness of their respective company's disclosure controls and procedures as of the end of the period covered by this report. "Disclosure controls and procedures" are controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms, 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 at the reasonable assurance level.

Energy East, CMP, NYSEG and RG&E each maintain a system of internal control over financial reporting designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. These internal controls over financial reporting include policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the registrants; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the registrants are being recorded only in accordance with authorizations of management and directors of the registrants; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acqu isition, use or disposition of the registrants' assets that could have a material effect on the financial statements. Each company's system of internal control over financial reporting contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. There were no changes in the companies' internal control over financial reporting that occurred during each company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the respective company's internal control over financial reporting. On January 1, 2004, Energy East commenced using a new accounting system to record and report financial transactions. The system change was undertaken to standardize accounting systems and to consolidate the accounting functions for Energy East's principal operating companies, including CMP, NYSEG and RG&E.

PART II - OTHER INFORMATION

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

(c) 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   (July 1, 2004 to   July 31, 2004)	8,007(1)	$24.13	- -	- -
Month #2   (August 1, 2004 to   August 31, 2004)	2,375(2)	$24.12	- -	- -
Month #3   (September 1, 2004 to   September 30, 2004)	7,148(3)	$24.48	- -	- -
Total	17,530	$24.27	-	-

(1) Includes 3,849 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 4,158 shares of the company's common stock (Par Value $.01) that were withheld to satisfy tax withholding obligations upon vesting of shares of restricted stock awarded through the company's Restricted Stock Plan.

(2) 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.
⁽³⁾ Includes 4,861 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 2,287 shares of the company's common stock (Par Value $.01) that were withheld to satisfy tax withholding obligations upon vesting of shares of restricted stock awarded through the company's Restricted Stock Plan.

CMP, NYSEG and RG&E had no issuer purchases of equity securities during the quarter ended September 30, 2004.

Item 6.  Exhibits

SeeExhibit Index.

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 4, 2004	ENERGY EAST CORPORATION                   (Registrant) By   /s/Robert E. Rude                                                         Robert E. Rude            Vice President and Controller            (Principal Accounting Officer)
Date:  November 4, 2004	CENTRAL MAINE POWER COMPANY                   (Registrant) By   /s/R. Scott Mahoney                                                      R. Scott Mahoney            Vice President - Controller             & Treasurer, Clerk            (Principal Financial Officer)
Date:  November 4, 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 4, 2004	ROCHESTER GAS AND ELECTRIC CORPORATION                   (Registrant) By   /s/Joseph J. Syta                                                          Joseph J. Syta            Vice President - Controller & Treasurer            (Principal Financial Officer)

EXHIBIT INDEX

(a) (1) The following exhibits are delivered with this report:

Registrant	Exhibit No.	Description of Exhibit
Energy East Corporation	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  Company	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.
New York State Electric  & Gas Corporation	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.
Rochester Gas and  Electric Corporation	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.

*Furnished pursuant to Regulation S-K Item 601(b)(32).

NYSEG agrees to furnish, upon request, a copy of each of the Participation Agreements dated as of August 1, 2004, between NYSEG and the New York State Energy Research and Development Authority (NYSERDA) relating to Pollution Control Revenue Bonds (2004 Series A) (2004 Series B) and (2004 Series C). The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of NYSEG.

RG&E agrees to furnish, upon request, a copy of the Participation Agreements dated as of August 1, 2004, between RG&E and NYSERDA relating to Pollution Control Revenue Bonds (2004 Series A) and (2004 Series B). The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of RG&E.