Energy East (EAS) 10-Q 2005 Q2 Quarterly report

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

FORM 10-Q

(Mark One)
[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934
      For the quarterly period ended  June 30, 2005

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(Incorporated in New York) 52 Farm View Drive New Gloucester, Maine 04260-5116 (207) 688-6300 www.energyeast.com	14-1798693
1-672	Rochester Gas and Electric Corporation(Incorporated in New York) 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
Rochester Gas and Electric Corporation	Yes	No     X

As of July 31, 2005, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	147,512,219
Rochester Gas and Electric Corporation	Par value $5 per share	34,506,513	(1)

(1) 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 CorporationandRochester Gas and Electric Corporation. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Neither registrant makes any representations as to information relating to the other registrant.

Item	TABLE OF CONTENTS	Page
	Glossary of Terms	ii
	Forward-looking Statements	iii
	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 11 13
	Rochester Gas and Electric 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	18 20 20 21 21 22 23
	Notes to Condensed Financial Statements	26
3	Quantitative and Qualitative Disclosures About Market Risk	35
4	Controls and Procedures	36
	PART II - OTHER INFORMATION
2	Unregistered Sales of Equity Securities and Use of Proceeds	37
4	Submission of Matters to a Vote of Security Holders	38
6	Exhibits	38
Signatures		39
Exhibit Index		40

GLOSSARY OF TERMS

Abbreviations or acronyms frequently used in this report:

Energy East Companies
CMP	Central Maine Power Company
CMP Group	CMP Group, Inc.
CNG	Connecticut Natural Gas Corporation
Energy Eastor the company	Energy East Corporation
NYSEG	New York State Electric & Gas Corporation
RG&E	Rochester Gas and Electric Corporation
SCG	The Southern Connecticut Gas Company
Third Parties
CGG	Constellation Generation Group, LLC
ISO	Independent system operator
ISO New England	ISO New England, Inc.
NYISO	New York Independent System Operator
NYTOs	New York Transmission Owners
RTO	Regional Transmission Organization
Regulatory Agencies
DPUC	Connecticut Department of Public Utility Control
FERC	Federal Energy Regulatory Commission
MPUC	Maine Public Utilities Commission
NYPSC	New York State Public Service Commission
SEC	United States Securities and Exchange Commission
Other
ARP 2000	Alternative Rate Plan 2000
ASGA	Asset Sale Gain Account
Electric Rate Agreement	the electric portion of the RG&E 2004 Electric and   Natural Gas Rate Agreements
EPS	earnings per share
ESCO	energy service company
FASB	Financial Accounting Standards Board
FIN 46(R)	FASB Interpretation No. 46 (revised December 2003),   Consolidation of Variable Interest Entities, an   interpretation of Accounting Research Bulletin No. 51
FIN 47	FASB Interpretation No. 47, Accounting for Conditional   Asset Retirement Obligations, an interpretation of   FASB Statement No. 143
Ginna	Ginna nuclear generation station, a nuclear power   plant formerly owned by RG&E (sold in June 2004)
IRP	Incentive Rate Plan
Natural Gas Rate Agreement	the natural gas portion of the RG&E 2004 Electric and   Natural Gas Rate Agreements
NUG	nonutility generator
ROE	return on equity
SARs	stock appreciation rights
Statement 123	Statement of Financial Accounting Standards   No. 123, Accounting for Stock-Based Compensation
Statement 123(R)	Statement of Financial Accounting Standards   No. 123 (revised 2004), Share-Based Payment
Statement 143	Statement of Financial Accounting Standards   No. 143, Accounting for Asset Retirement Obligations

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," "anticipate," 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 utility 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 volatile energy prices, including the enactment of the Domenici-Barton Energy Policy Act of 2005; the operation of the NYISO; the operation of ISO New England, Inc. as an RTO; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements; the company's ability to expand its products and services, including its energy infrastructure in the Northeast; the company's ability to integrate the operations of Berkshire Energy Resources, CMP Group, Inc., Connecticut Energy Corporation, CTG Resources, Inc. and RGS Energy Group, Inc.; the company's ability to achieve and maintain enterprise-wide integration synergies; market risk; the ability to obtain adequate and timely rate relief and/or the extension of current rate plans; the continuation of fixed price supply programs; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; economic growth in the areas in which the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; the effect of the volatility in the equity and fixed income markets on pension benefit cost; the inability of the companies' internal control framework to provide absolute assurance that all incidents of fraud or error will be detected and prevented; and other considerations that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Energy East Corporation Condensed Consolidated Statements of Income- (Unaudited)
	Three Months		Six Months
Periods ended June 30	2005	2004	2005	2004
(Thousands, except per share amounts)
Operating Revenues
Sales and services	$1,081,945	$968,938	$2,719,223	$2,520,294
Operating Expenses
Electricity purchased and fuel used in generation	436,779	338,253	873,970	734,906
Natural gas purchased	180,993	144,312	700,123	627,827
Other operating expenses	184,772	185,164	364,414	392,952
Maintenance	53,236	42,814	97,782	85,475
Depreciation and amortization	68,121	74,994	136,042	153,507
Other taxes	59,743	57,885	127,774	132,419
Gain on sale of generation assets	-	(319,487)	-	(319,487)
Deferral of asset sale gain	-	214,368	-	214,368
Total Operating Expenses	983,644	738,303	2,300,105	2,021,967
Operating Income	98,301	230,635	419,118	498,327
Other (Income)	(8,996)	(11,680)	(19,063)	(17,420)
Other Deductions	6,984	1,159	11,202	4,437
Interest Charges, Net	72,282	68,822	142,018	138,812
Preferred Stock Dividends of Subsidiaries	432	1,791	908	2,779
Income From Continuing Operations   Before Income Taxes	27,599	170,543	284,053	369,719
Income Taxes	10,234	127,720	112,322	205,966
Income From Continuing Operations	17,365	42,823	171,731	163,753
Discontinued Operations
Loss from discontinued operations	-	(4,316)	-	(4,952)
Income taxes	-	441	-	183
Loss From Discontinued Operations	-	(4,757)	-	(5,135)
Net Income	$17,365	$38,066	$171,731	$158,618
Earnings per Share From Continuing   Operations, basic	$.12	$.29	$1.17	$1.12
Earnings per Share From Continuing   Operations, diluted	$.12	$.29	$1.17	$1.11
Earnings per Share From Discontinued   Operations, basic and diluted	- -	$(.03)	- -	$(.03)
Earnings per Share, basic	$.12	$.26	$1.17	$1.09
Earnings per Share, diluted	$.12	$.26	$1.17	$1.08
Dividends Paid per Share	$.275	$.26	$.55	$.52
Average Common Shares Outstanding, basic	146,831	146,148	146,853	146,116
Average Common Shares Outstanding, diluted	147,390	146,596	147,294	146,512

Thenotes on pages 26 through 34are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30,   2005	Dec. 31,   2004
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$303,067	$247,120
Accounts receivable, net	714,421	821,556
Fuel and natural gas in storage	143,221	198,640
Materials and supplies, at average cost	30,198	26,592
Accumulated deferred income tax benefits, net	22,257	33,969
Derivative asset	86,699	9,323
Prepayments and other current assets	73,812	86,306
Total Current Assets	1,373,675	1,423,506
Utility Plant, at Original Cost
Electric	5,326,882	5,282,828
Natural gas	2,516,931	2,493,455
Common	435,392	420,372
	8,279,205	8,196,655
Less accumulated depreciation	2,681,010	2,602,013
Net Utility Plant in Service	5,598,195	5,594,642
Construction work in progress	100,643	67,526
Total Utility Plant	5,698,838	5,662,168
Other Property and Investments, Net	209,142	190,148
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	327,262	356,072
Deferred income taxes	15,259	-
Unfunded future income taxes	116,745	115,446
Unamortized loss on debt reacquisitions	54,575	58,345
Environmental remediation costs	128,990	122,052
Nonutility generator termination agreements	92,551	96,158
Other	311,686	419,214
Total regulatory assets	1,047,068	1,167,287
Other assets
Goodwill, net	1,525,353	1,525,353
Prepaid pension benefits	726,448	657,402
Other	251,465	170,249
Total other assets	2,503,266	2,353,004
Total Regulatory and Other Assets	3,550,334	3,520,291
Total Assets	$10,831,989	$10,796,113

Thenotes on pages 26 through 34are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30,   2005	Dec. 31,   2004
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$57,126	$59,231
Notes payable	77,404	206,472
Accounts payable and accrued liabilities	395,805	454,876
Interest accrued	42,370	43,469
Taxes accrued	56,893	8,568
Other	143,705	184,227
Total Current Liabilities	773,303	956,843
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	790,258	762,520
Deferred income taxes	-	21,487
Gain on sale of generation assets	178,573	233,378
Pension benefits	19,899	25,354
Other	120,586	107,932
Total regulatory liabilities	1,109,316	1,150,671
Other liabilities
Deferred income taxes	1,032,470	973,599
Nuclear plant obligations	237,635	251,753
Other postretirement benefits	424,496	419,885
Environmental remediation costs	152,992	150,263
Other	487,613	417,485
Total other liabilities	2,335,206	2,212,985
Total Regulatory and Other Liabilities	3,444,522	3,363,656
Debt owed to subsidiary holding solely parent debentures	355,670	355,670
Other long-term debt	3,458,137	3,442,015
Total long-term debt	3,813,807	3,797,685
Total Liabilities	8,031,632	8,118,184
Commitments and Contingencies	-	-
Preferred Stock of Subsidiaries  Redeemable solely at the option of subsidiaries	24,671	46,671
Common Stock Equity  Common stock	1,476	1,471
Capital in excess of par value	1,488,569	1,477,518
Retained earnings	1,292,549	1,201,533
Accumulated other comprehensive income (loss)	3,818	(43,561)
Deferred compensation	(8,860)	(5,020)
Treasury stock, at cost	(1,866)	(683)
Total Common Stock Equity	2,775,686	2,631,258
Total Liabilities and Stockholders' Equity	$10,831,989	$10,796,113

Thenotes on pages 26 through 34are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Six months ended June 30	2005	2004
(Thousands)
Net Cash Provided by Operating Activities	$404,251	$405,821
Investing Activities
Proceeds from sale of generation assets	-	428,541
Refund of excess decommissioning fund	-	76,593
Utility plant additions	(147,658)	(123,921)
Other property and investments additions	(386)	(1,678)
Other property and investments sold	14,925	7,957
Other	108	(3,514)
Net Cash (Used in) Provided by Investing Activities	(133,011)	383,978
Financing Activities
Issuance of common stock	2,194	1,252
Repurchase of common stock	(7,420)	(6,071)
Book overdraft	(173)	57,388
Repayments of first mortgage bonds and preferred stock of   subsidiaries, including net premiums	(22,220)	(162,053)
Long-term note issuances	270,000	12,000
Long-term note repayments	(256,892)	(12,778)
Notes payable three months or less, net	(129,068)	(279,203)
Notes payable issuances	-	3,000
Notes payable repayments	-	(16,000)
Dividends on common stock	(71,714)	(66,858)
Net Cash Used in Financing Activities	(215,293)	(469,323)
Net Increase in Cash and Cash Equivalents	55,947	320,476
Cash and Cash Equivalents, Beginning of Period	247,120	147,856
Cash and Cash Equivalents, End of Period	$303,067	$468,332

Thenotes on pages 26 through 34are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Six months ended June 30	2005	2004
(Thousands)
Balance, Beginning of Period	$1,201,533	$1,126,457
Add net income	171,731	158,618
Deduct dividends on common stock	80,715	75,944
Balance, End of Period	$1,292,549	$1,209,131

Thenotes on pages 26 through 34are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30	2005	2004	2005	2004
(Thousands)
Net income	$17,365	$38,066	$171,731	$158,618
Other comprehensive income, net of tax
Net unrealized gains (losses) on investments, net of    income tax expense for the three months and six months    of $- in 2005 and 2004	19	(947)	(4)	(927)
Minimum pension liability adjustment net of income tax    expense for the three months and six months of $7 in    2005 and $- in 2004	(11)	- -	(11)	- -
Unrealized (losses) gains on derivatives qualified as    hedges, net of income tax benefit (expense) for the three    months of $22,586 in 2005 and $(4,712) in 2004 and for    the six months of $(6,283) in 2005 and $(17,229) in 2004	(32,365)	7,104	15,991	25,811
Reclassification adjustment for (gains) losses included in    net income, net of income tax expense (benefit) for the    three months of $601 in 2005 and $5,710 in 2004 and for    the six months of $(20,769) in 2005 and $11,010 in 2004	(940)	(8,609)	31,403	(16,601)
Net unrealized (losses) gains on derivatives qualified    as hedges	(33,316)	(1,505)	47,383	9,210
Total other comprehensive (loss) income	(33,297)	(2,452)	47,379	8,283
Comprehensive (Loss) Income	$(15,932)	$35,614	$219,110	$166,901

Thenotes on pages 26 through 34are an integral part of the condensed consolidated financial statements.

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

Energy East Corporation

Overview

Energy East's primary operations, its electric and natural gas utility operations, are subject to rate regulation. The approved regulatory treatment on various matters could significantly affect the company's financial position and results of operations. Energy East has long-term rate plans for New York State Electric & Gas Corporation, Rochester Gas & Electric Corporation, Central Maine Power Company, Connecticut Natural Gas Corporation, The Southern Connecticut Gas Company and The Berkshire Gas Company. The plans presently provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including exogenous and stranded costs, and provide stable rates for customers and revenue predictability for those six operating companies. The CNG and SCG plans expire at the end of September 2005, and SCG has filed a one-year rate case while CNG intends to operate with the rates established in its current long-term plan, after that plan expires.

Energy East's management focuses its strategic efforts on those areas of the company that it believes would have the greatest effect on shareholder value. Efficient operations are a key aspect of increasing shareholder value. Management has implemented plans to achieve savings through a company-wide restructuring that was completed in early 2004 and continued consolidation of utility support services, including front office functions.

The continuing uncertainty in the evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings that could significantly affect operations, although the outcomes of the proceedings are difficult to predict. Those proceedings, which are discussed below, could affect the nature of the electric and natural gas utility industries in New York and New England.

The company engages in various investing and financing activities to meet its strategic objectives. The primary goal of investing activities is to maintain a reliable energy delivery infrastructure. Investing activities are funded primarily with internally generated funds. The company plans to invest over $1 billion in its energy delivery infrastructure during 2005 through 2007, including approximately $600 million dedicated to electric reliability. Financing activities are focused on maintaining adequate liquidity, improving credit quality and minimizing the cost of capital.

The accompanying Management's Discussion and Analysis of Financial Condition and Results of Operation for each registrant should be read in conjunction with the Management's Discussion and Analysis of Financial Condition and Results of Operation, financial statements and notes contained in the report on Form 10-K filed by each registrant for the year ended December 31, 2004. 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.

Strategy

Energy East has maintained a consistent energy delivery services strategy over the past several years, focusing on the transmission and distribution of electricity and natural gas rather than the more volatile generation and energy trading businesses. Achieving operating excellence and efficiencies throughout the company is central to this strategy. While Energy East has sold certain noncore businesses and the last of its substantial regulated generation assets, investment in infrastructure that supports the electric and natural gas delivery systems will continue.

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

Energy East Corporation

Utility Shared Services Corporation, a subsidiary of Energy East, has improved efficiencies and achieved savings through the integration of the companies' information systems, purchasing, accounting and finance functions.

The company's long-term rate plans continue to be a critical component of its success. While specific provisions may vary among the company's public utility subsidiaries, the overall strategy includes creating stable rate environments that allow the companies to earn a fair return while minimizing price increases and sharing achieved savings with customers.

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 Electric Rate Unbundling: In June 2003, as required by an NYPSC Order issued in March 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. Effective January 1, 2005, customers have an opportunity to annually 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 enrolled in the new commodity options between October 1, 2004, and December 31, 2004. Customers who did not make a choice are served under RG&E's variable price option. Approximately 77% of those customers who made a choice selected RG&E's fixed price option for 2005. About 25% of RG&E's overal l load is now served under that option.

Errant Voltage: In January 2005 the NYPSC issued an Order Instituting Safety Standards in response to a pedestrian being electrocuted from contact with an energized service box cover in New York City. The incident occurred outside the company's service territory. All New York utilities were directed to respond to that order by February 19, 2005, with a report that provided a detailed voltage testing program, an inspection program and schedule, safety criteria applied to each program, a quality assurance program, a training program for testing and inspections and a description of current or planned research and development activities related to errant voltage and safety issues. The Order Instituting Safety Standards also denies utility requests for recovery of implementation costs and establishes criteria for utilities seeking authorization to recover costs as an incremental expense. The order also established penalties for failure to achieve annual performance targets for testing and inspections at 75 basis points each.

NYSEG and RG&E have reviewed the NYPSC order and jointly filed in early February 2005, with two other New York State utilities, a petition for rehearing that focuses on several areas including the impracticability of the timetable established in the order. In addition, NYSEG and RG&E filed a separate petition for rehearing dealing with the recovery of incremental costs of complying with the order. In response to the order, in late February 2005 NYSEG and RG&E filed a testing and inspection plan that is consistent with the timetable identified in the above noted joint petition for rehearing. NYSEG and RG&E have begun to implement their plans, including testing of equipment. The NYPSC issued a press release following its session on June 15, 2005, indicating it would provide some relief in the testing schedule. On July 21, 2005, the NYPSC issued an

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

Energy East Corporation

order detailing the revised requirements, which NYSEG and RG&E are reviewing. NYSEG and RG&E have incurred costs of less than $1 million to date and estimate that they will incur total costs of approximately $10 million to comply with the order during 2005. The company is unable to predict what effect, if any, these developments will have on its results of operations, financial position or cash flows.

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive electric and natural gas markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets and providing recommendations concerning provider of last resort and related issues. In January 2004 the NYPSC issued a notice seeking additional comments in light of the passage of time and the evolution of competitive markets. In March and April 2004 NYSEG and RG&E submitted comments supporting periodic assessment of the retail competitive marketplace and opposing the adoption of any policies restricting customer choice of supplier or limiting the availability of supply options from any particular supplier. NYSEG and RG&E believe that the NYPSC should not adopt a single end-state vision for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.

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

NYSEG and RG&E filed their retail access plans with the NYPSC on April 14, 2005. As part of its filing, NYSEG requested NYPSC approval, by September 30, 2005, to continue offering its current commodity options to customers, with new two-year commodity offerings beginning January 1, 2007, that are the same as its current program except for the addition of a program to facilitate ESCO market participation by NYSEG billing and collecting directly from ESCO customers.

NYSEG and RG&E believe that their current commodity option programs are the most comprehensive in New York State, providing a full menu of electric supply choices, including a fixed price option for customers who do not want to be subjected to volatile wholesale electricity prices. Experience has shown that the vast majority of customers want their utility to remain a supply option and prefer a fixed price option. NYSEG's and RG&E's believe that their programs are also among the most successful of any retail access plans in New York State in terms of active participation and customer migration.

In June and July 2005 parties filed comments both in support of and in opposition to NYSEG's and RG&E's retail access plans. Parties also filed comments on a motion NYSEG and RG&E filed on April 1, 2005, asking the NYPSC to open an investigation to establish market monitoring measures and affiliate rules to prevent potential gaming of the energy markets by companies that both own generation and sell electricity in the New York retail markets.

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

Energy East Corporation

NYSEG and RG&E have also supplied comments in NYPSC proceedings regarding other investor-owned utility programs that are designed to encourage customers to migrate from utilities to ESCOs. NYSEG and RG&E believe that the "PowerSwitch" program implemented by Orange and Rockland Utilities, Inc., which is being touted as a model for the rest of the state, is flawed. In their filing, NYSEG and RG&E have questioned whether the program is consistent with the NYPSC's Uniform Business Practices. NYSEG and RG&E believe the program results may be suspect and should not be used as a basis to expand the program to other utilities. On June 1, 2005, the NYPSC approved Central Hudson Gas & Electric Corporation's retail access plan and rejected NYSEG's and RG&E's comments requesting the NYPSC to not take action on Central Hudson's plan and to suspend the development of new retail access initiatives that are based on flawed models.

NYSEG and RG&E are not able to predict what effect, if any, these latest developments will have on their results of operations, financial positions or cash flows.

CMP Alternative Rate Plan: ARP 2000 began on January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007. On March 15, 2005, CMP submitted its annual compliance filing under ARP 2000. On June 30, 2005, the MPUC approved a settlement by which CMP's distribution prices decreased approximately $3 million for the year effective July 1, 2005. In addition, CMP's transmission rates increased approximately $15 million for the year effective July 1, 2005, to reflect updates to the formula rates for 2004 costs as well as its share of ISO New England reliability charges. This increase enables CMP to recover the actual increases resulting from its share of ISO New England regional transmission costs and its local transmission costs.

New England RTO: In March 2004 the FERC issued an order that accepted a six-state New England RTO as proposed by ISO New England and the New England transmission owners. The order approved a 50 basis point and a 100 basis point ROE incentive adders, but limited application of the 100 basis point adder to regional facilities, subject to suspension, hearing and application of the FERC's Pricing Policy Statement, when it is issued. The order also accepted, subject to suspension and hearing, the New England transmission owner's proposed base level ROE of 12.8% applicable to rates for local and regional transmission service. These rates became effective, subject to refund February 1, 2005. Evidentiary hearings on the final base level ROE and the incentive for new transmission investment were conducted by the FERC in January and February 2005. An initial decision was issued in May 2005 recommending a base level ROE of 10.72%, plus the 50 basis point adder. The New England transmission owners have filed exceptions to the initial decision. A final decision from the FERC on those issues is not expected until the end of 2005. The New England transmission owners and ISO New England implemented the New England RTO effective February 1, 2005. (See Energy East's report on Form 10-K for fiscal year ended December 31, 2004, Item 7, New England RTO.)

NYISO Billing Adjustment: The NYISO frequently bills transmission owners on a retroactive basis when adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission revenue or expense as appropriate when revised amounts can be estimated. On January 25, 2005, the NYISO notified the NYTOs, including NYSEG and RG&E, of errors related to transmission congestion contract billings for periods including May 2000 through October 2002. NYSEG's retroactive billing was approximately $0.7 million and RG&E's was less than $0.1 million for the periods in question. Both amounts were expensed during the first two quarters of 2005.

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

Energy East Corporation

In a separate issue in March 2005 the FERC issued an order directing the NYISO to modify certain energy prices for May 8 and 9, 2000, and to back bill NYISO market participants, including NYSEG and RG&E. The NYISO and many market participants filed requests for rehearing with the FERC concerning that order. While the FERC has not ruled on these requests for rehearing, on July 8, 2005, the NYISO issued back billings that addressed a number of the May 8 and 9, 2000, issues. NYSEG's back billing was $2.3 million and RGE's was $1.4 million. Both amounts were expensed during the second quarter of 2005.

Locational Installed Capacity Markets (LICAP): The FERC administrative law judge in this proceeding issued a recommended decision in June 2005 essentially adopting the ISO New England LICAP market proposal. CMP and other parties that oppose the ISO New England LICAP market proposal filed exceptions to the recommended decision in July 2005. The FERC is expected to issue a final decision by the end of 2005. CMP cannot predict how the FERC will rule or what modifications the FERC might make to the filing. (See Energy East's report on Form 10-K for fiscal year ended December 31, 2004, Item 7, Locational Installed Capacity Markets.)

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.

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

SCG Request for Recovery of Exogenous Costs: In December 2003 SCG filed an application with the DPUC to recover approximately $21 million of exogenous costs under its approved 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, approved by the DPUC, allows SCG to petition the DPUC 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. In October 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. In December 2004 SCG filed an appeal with the Connecticut Superior Court concerning certain aspects of the DPUC's dec ision. SCG filed its brief on May 11, 2005. On June 27, 2005, the DPUC filed a motion to dismiss SCG's appeal as a result of SCG's rate case filing, which is discussed below. The current schedule calls for SCG to file its response to the DPUC motion on August 19, 2005, with a hearing on the motion to occur on August 24, 2005.

SCG Regulatory Proceeding: SCG's IRP expires September 30, 2005. As a result of the DPUC's decision denying recovery of exogenous costs, SCG filed a one-year rate case on April 29, 2005, requesting approximately $35 million of additional revenues, which represents an increase of approximately 11% compared to revenues based on current rates. The rate filing requests, among other items, greater recovery of deferred costs similar to SCG's request for recovery of exogenous costs.

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

Energy East Corporation

On June 28, 2005, hearings commenced on SCG's filing. On July 1, 2005, the Office of Consumer Counsel filed testimony recommending a rate increase of $0.2 million for SCG. The DPUC is scheduled to rule on SCG's rate request in September 2005. The company is unable to predict the outcome of the proceeding.

Other Matters

New Accounting Standards

Statement 123(R):In December 2004 the FASB issued Statement 123(R), which is a revision of Statement No. 123. Statement 123(R) requires a public entity to measure the cost of employee services that it receives in exchange for an award of equity instruments based on the grant-date fair value of the award and recognize that cost over the period during which the employee is required to provide service in exchange for the award. Statement 123(R) also requires a public entity to initially measure the cost of employee services received in exchange for an award of liability instruments, (i.e. instruments that are settled in cash), based on the award's current fair value, subsequently remeasure the fair value of the award at each reporting date through the settlement date and recognize changes in fair value during the required service period as compensation cost over that period. The company is evaluating the expected effects of the adoption of Statement 123(R) on its financial position, res ults of operations and cash flows, but does not expect that the effects will be material. (SeeNote 6 to the Condensed Financial Statements.)

FIN 47: In March 2005 the FASB issued FIN 47. FIN 47 clarifies that the term "conditional asset retirement obligation" as used in Statement 143 refers to an entity's "legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity." FIN 47 requires that if an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional asset retirement obligation, it must recognize that liability at the time the liability is incurred. The company does not expect that its application of FIN 47 effective December 31, 2005, will have a material effect on its financial position, results of operations or cash flows. (See Note 6 to the Condensed Financial Statements.)

(a) Liquidity and Capital Resources

Operating Activities:Significant operating activities that affected liquidity and cash flows during the first six months of 2005 included the following:

• A $25 million refund to RG&E customers using proceeds from the sale of Ginna, pursuant to RG&E's Electric Rate Agreement. RG&E's Electric Rate Agreement requires additional refunds of $15 million in 2006 and $10 million in 2007.
• Contributions of $54 million to certain of the company's pension plans to bring these plans closer to a fully-funded position. No additional contributions are anticipated during 2005. (See Energy East's report on Form 10-K for fiscal year ended December 31, 2004, Item 8, Financial Statements and Supplementary Data.)
• Natural gas inventories decreased by $55 million as they were drawn down during the heating season.
• Accounts receivable declined by $107 million reflecting collections of higher winter bills.

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

Energy East Corporation

Investing Activities: Capital spending for the first six months of 2005 was $148 million. Capital spending is projected to be $388 million for 2005 and is expected to be paid for principally with internally generated funds. The company plans to invest over $1 billion in its energy delivery infrastructure during 2005 through 2007, including approximately $600 million dedicated to electric reliability. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates, a customer care system and an Infrastructure Replacement Program.

Financing Activities: The financing activities discussed below include those activities necessary for the company and its principal subsidiaries to maintain adequate liquidity, improve credit quality and ensure access to capital markets. Activities include maintenance of credit facilities, minimal common stock issuances and various medium-term and long-term debt arrangements.

During the six months ended June 30, 2005, the company issued 404,317 shares of common stock, at an average price of $26.52 per share, through its Investor Services Program. The shares issued were original issue shares.

During the second quarter of 2005 the company awarded 241,493 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of approximately $6 million based on the average market price of $26.16 per share of common stock on the dates of the awards.

On March 24, 2005, NYSEG filed a Form 15 with the SEC and on June 20, 2005, CMP filed a Form 15 with the SEC, terminating their status as registrants under the Securities Exchange Act of 1934 (Exchange Act). NYSEG and CMP will no longer file Exchange Act reports including Forms 10-K, 10-Q and 8-K, and proxy statements or information statements.The company does not expect that the termination of either NYSEG's or CMP's Exchange Act registration will materially affect their access to or cost of capital.

During the first quarter of 2005 NYSEG auctioned $100 million of Series 2004C pollution control revenue bonds for a period of five years through January 2010, at 3.245%. NYSEG also converted $60 million of Series 1985A pollution control revenue bonds from an annual term put mode to a fixed rate of 4.10% through maturity on March 15, 2015. In May 2005 NYSEG refunded a $65 million 6.15% fixed-rate tax-exempt pollution control note with proceeds from the issuance of $65 million of multi-mode tax-exempt pollution control notes due in 2026.

In March 2005 CMP redeemed at par $25 million of its Series E, 8.125% medium-term notes with proceeds from the issuance of short-term debt. In April 2005 CMP issued $25 million of Series F medium-term notes at 5.78% due in 2035 to repay the short-term debt. In June 2005 CMP redeemed all $22 million of its 3.50% Series Preferred Stock, par value of $100 per share at a redemption price of $101 per share. In June 2005 CMP issued $20 million of Series F medium-term notes at 5.375% due in 2035 to finance the 3.50% Series Preferred Stock redemption. In July 2005 CMP issued $25 million of Series F medium-term notes at 5.43% due in 2035 to fund maturing medium-term notes.

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

Energy East Corporation

In June 2005 the company and its operating utilities replaced their existing revolving credit agreements with two new revolving credit facilities. Energy East Corporation is the sole borrower in a facility providing maximum borrowings of up to $300 million and the company's operating utilities are joint borrowers in a facility providing maximum borrowings of up to $425 million in aggregate. Sublimits that total to the aggregate limit apply to each joint borrower. The sublimits can be altered within the constraints imposed by maximum limits that apply to each joint borrower. Both facilities have expiration dates in 2010 and require fees in lieu of compensating balances. The prior agreements provided for maximum borrowings of $740 million at December 31, 2004, and $700 million at December 31, 2003. The new facilities contain various covenants and conditions on borrowings, including a limit on each borrower's indebtedness to total capitalization of 0.65 to 1.0 and a restriction on the amount of sec ured indebtedness that each borrower may maintain. No borrower is in default, or is expected to be in default, under the applicable facility.

(b)Results of Operations

Earnings per Share

Three months ended June 30	2005	2004
(Thousands, except per share amounts)
Operating Revenues	$1,081,945	$968,938
Operating Income	$98,301	$230,635
Income from Continuing Operations	$17,365	$42,823
Net Income	$17,365	$38,066
Average Common Shares Outstanding, basic	146,831	146,148
Average Common Shares Outstanding, diluted	147,390	146,596
Earnings per Share from Continuing Operations, basic and diluted	$.12	$.29
Earnings per Share, basic and diluted	$.12	$.26
Dividends Paid per Share	$.275	$.26

Earnings per share from continuing operations for the quarter ended June 30, 2005, decreased 17 cents compared to the quarter ended June 30, 2004, primarily because of:

• The effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements that increased earnings 9 cents per share in 2004. The one-time effects, which contributed 7 cents per share in 2004, include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory treatment. An additional 2 cents per share was recognized in the second quarter of 2004 related to annual credits from the ASGA, for a Ginna incentive and for a revenue increase offset. (See Energy East's report on Form 10-K for the fiscal year ended December 31, 2004, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations). Pursuant to the terms of RG&E's Electric Rate Agreement these credits will occur in different periods in 2005 than in 2004.
• A decrease of 5 cents per share due to higher stock option expense,
• A decrease of 3 cents per share due to higher operating and maintenance expenses, including approximately 2 cents per share for storm-related repairs and maintenance, and
• A decrease of 1 cent per share due to NYISO back billings received by NYSEG and RG&E due to modification of energy prices for May 2000.

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

Energy East Corporation

Six months ended June 30	2005	2004
(Thousands, except per share amounts)
Operating Revenues	$2,719,223	$2,520,294
Operating Income	$419,118	$498,327
Income from Continuing Operations	$171,731	$163,753
Net Income	$171,731	$158,618
Average Common Shares Outstanding, basic	146,853	146,116
Average Common Shares Outstanding, diluted	147,294	146,512
Earnings per Share from Continuing Operations, basic	$1.17	$1.12
Earnings per Share from Continuing Operations, diluted	$1.17	$1.11
Earnings per Share, basic	$1.17	$1.09
Earnings per Share, diluted	$1.17	$1.08
Dividends Paid per Share	$.55	$.52

Earnings per share from continuing operations, basic for the six months ended June 30, 2005, increased 5 cents compared to the six months ended June 30, 2004, primarily because of:

• An increase of 12 cents per share due to higher margins on electric sales resulting from electric commodity programs in New York,
• An increase of 2 cents per share due to a nonrecurring incentive credit provided for under CMP's ARP 2000 when it achieves savings for customers by restructuring NUG contracts, and
• An increase of 2 cents per share due to higher net revenues on natural gas sales.

These increases were offset by:

• One-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements, as discussed above, that increased earnings 7 cents per share in 2004,
• A decrease of 3 cents per share resulting from an increase in operating and maintenance expenses, including approximately 2 cents per share for storm-related repairs and maintenance, and
• A decrease of 2 cents per share due to NYISO back billings received by NYSEG and RG&E due to modification of energy prices for May 2000.

Operating Results for the Electric Delivery Business

Three months ended June 30	2005	2004
(Thousands)
Retail Deliveries - Megawatt-hours	7,341	7,295
Operating Revenues	$687,627	$641,057
Operating Expenses	$598,061	$428,336
Operating Income	$89,566	$212,721

Operating Revenues:The $47 million increase in operating revenues for the second quarter of 2005 was primarily the result of:

• An increase of $13 million due to higher prices for retail electric energy supplied by NYSEG and RG&E under various commodity options. Higher prices became effective January 1, 2005, for customers who continue to purchase electricity from NYSEG and reflect higher market prices for electricity,

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

Energy East Corporation

• An increase of $50 million in wholesale revenues. $12 million of this increase resulted from higher prices on the sale of CMP's NUG entitlements that increased on March 1, 2005. The remainder resulted primarily from NYSEG's power supply activities,
• An increase of $8 million resulting from higher retail deliveries, and
• An increase of $3 million in other electric revenues.

Those increases were partially offset by:

• A decrease of $17 million as a result of lower sales of electric energy due to customer migration to ESCOs, and
• A decrease of $7 million as a result of lower prices on retail electric deliveries.

Operating Expenses: The $170 million increase in operating expenses for the second quarter of 2005 was primarily the result of:

• An increase of $105 million as a result of the regulatory treatment in 2004 of RG&E's gain on the sale of Ginna, which included RG&E's recognition of a $319 million pretax gain partially offset by the after tax deferral of the gain of $214 million,
• An increase of $35 million in power purchases largely resulting from increased wholesale sales and higher prices for electric supply purchased for NYSEG's and RG&E's electric commodity customers, including $4 million due to NYISO billing adjustments,
• An increase of $6 million due to higher stock option expense,
• A net increase of $5 million in operating expenses as a result of the sale of Ginna, including an increase in purchased power costs of $30 million, partially offset by decreases of $15 million in other operating and maintenance expenses, $8 million in depreciation and $2 million in other taxes,
• An increase of $9 million due to certain credits to other operating expenses that resulted from RG&E's Electric Rate Agreement and reduced expenses in the second quarter of 2004. These items were primarily the elimination of reserves that had been established pending regulatory treatment, and
• Increases in various other operating and maintenance expenses, excluding Ginna, totaling $11 million. Higher storm costs accounted for approximately $5 million of this increase and higher transmission-related expenses accounted for an additional $4 million. The majority of the increase in transmission expenses resulted from regional cost increases that were allocated to all New England transmission owners.

Six months ended June 30	2005	2004
(Thousands)
Retail Deliveries - Megawatt-hours	15,417	15,345
Operating Revenues	$1,455,949	$1,371,652
Operating Expenses	$1,182,497	$1,016,147
Operating Income	$273,452	$355,505

Operating Revenues:The $84 million increase in operating revenues for the first six months of 2005 was primarily the result of:

• An increase of $42 million due to higher prices for retail electric energy supplied by NYSEG and RG&E under various commodity options,
• An increase of $30 million in other electric revenues including $6 million for CMP's NUG restructuring incentive, and $8 million for RG&E's amortization of the ASGA to offset the incremental cost of power as a result of the Ginna sale,

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

Energy East Corporation

• An increase of $48 million in wholesale revenues. $15 million of this increase resulted from higher prices on the sale of CMP's NUG entitlements that increased on March 1, 2005. The remainder resulted primarily from NYSEG's power supply activities, and
• An increase of $12 million for increased retail deliveries.

Those increases were partially offset by:

• A decrease of $20 million as a result of lower sales of electric energy due to customer migration to ESCOs, and
• A decrease of $28 million resulting from lower retail prices.

Operating Expenses: The $166 million increase in operating expenses for the first six months of 2005 was primarily the result of:

• An increase of $105 million as a result of the regulatory treatment in 2004 of RG&E's gain on the sale of Ginna, which included RG&E's recognition of a $319 million pretax gain partially offset by the after tax deferral of the gain of $214 million,
• A net increase of $2 million in operating expenses as a result of the sale of Ginna, reflecting an increase in purchased power costs of $63 million, partially offset by decreases of $36 million in other operating and maintenance expenses, $21 million in depreciation and $4 million in other taxes,
• An increase of $40 million in power purchases largely resulting from increased wholesale sales and higher prices for electric supply purchased for the company's electric commodity customers, including $4 million due to NYISO billing adjustments,
• An increase of $4 million in depreciation, excluding Ginna,
• An increase of $9 million due to certain credits to other operating expenses that resulted from RG&E's Electric Rate Agreement and reduced expenses in the second quarter of 2004, and
• Increases in various other operating and maintenance expenses, excluding Ginna, totaling $6 million. Higher storm costs accounted for approximately $6 million of this increase and higher transmission-related expenses accounted for an additional $4 million. Reductions in RG&E's bad debt expense offset these increases by $8 million.

Operating Results for the Natural Gas Delivery Business

Three months ended June 30	2005	2004
(Thousands)
Retail Deliveries - Dekatherms	37,188	35,952
Operating Revenues	$282,450	$240,282
Operating Expenses	$271,899	$232,485
Operating Income	$10,551	$7,797

Operating Revenues:The $42 million increase in operating revenues for the second quarter of 2005 was primarily the result of:

• An increase of $27 million as a result of higher market prices of natural gas that were passed on to customers,
• An increase of $10 million in wholesale revenues, and
• An increase of $5 million resulting from higher natural gas retail deliveries.

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

Energy East Corporation

Operating Expenses: The $39 million increase in operating expenses for the second quarter of 2005 was primarily the result of:

• An increase of $30 million due to purchased natural gas costs, $29 million of which was related to higher prices that were passed on to customers, and
• An increase of $9 million in other operating and maintenance costs, including $3 million related to higher stock option expense and $2 million related to increased maintenance.

Six months ended June 30	2005	2004
(Thousands)
Retail Deliveries - Dekatherms	123,444	123,549
Operating Revenues	$1,003,646	$922,006
Operating Expenses	$858,964	$789,191
Operating Income	$144,682	$132,815

Operating Revenues:The $82 million increase in operating revenues for the first six months of 2005 was primarily the result of:

• An increase of $76 million as a result of higher market prices of natural gas that were passed on to customers,
• An increase of $5 million in other natural gas revenues, and
• An increase of $7 million in wholesale sales.

Those increases were partially offset by:

• Decreases in natural gas retail deliveries of $7 million.

Operating Expenses: The $70 million increase in operating expenses for the first six months of 2005 was primarily the result of:

• An increase of $75 million due to higher market prices of purchased natural gas, and
• An increase of $2 million in other operating and maintenance costs.

Those increases were partially offset by:

• A reduction of $7 million because of lower volumes of natural gas purchases.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	June 30,   2005	Dec. 31,   2004
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$109,257	$71,259
Accounts receivable, net	137,957	149,602
Fuel and natural gas in storage	30,297	38,955
Materials and supplies, at average cost	11,916	7,850
Accumulated deferred income tax benefits, net	8,036	15,344
Prepayments and other current assets	25,385	23,719
Total Current Assets	322,848	306,729
Utility Plant, at Original Cost
Electric	1,245,088	1,231,128
Natural gas	562,969	557,472
Common	189,258	185,901
	1,997,315	1,974,501
Less accumulated depreciation	560,637	534,465
Net Utility Plant in Service	1,436,678	1,440,036
Construction work in progress	30,519	28,623
Total Utility Plant	1,467,197	1,468,659
Other Property and Investments, Net	12,559	12,649
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	196,126	209,345
Deferred income taxes	6,819	1,673
Unamortized loss on debt reacquisitions	9,606	10,979
Environmental remediation costs	11,350	11,814
Nonutility generator termination agreement	86,855	91,465
Other	136,833	143,638
Total regulatory assets	447,589	468,914
Other assets
Prepaid pension benefits	47,070	37,896
Other	22,732	25,275
Total other assets	69,802	63,171
Total Regulatory and Other Assets	517,391	532,085
Total Assets	$2,319,995	$2,320,122

Thenotes on pages 26 through 34 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	June 30,   2005	Dec. 31,   2004
(Thousands)
Liabilities
Current Liabilities
Accounts payable and accrued liabilities	$78,555	$86,765
Interest accrued	9,378	9,294
Taxes accrued	12,732	12,448
Other	47,556	52,014
Total Current Liabilities	148,221	160,521
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	176,551	172,505
Unfunded future income taxes	103,226	101,873
Gain on sale of generation assets	123,056	139,229
Other	43,987	32,425
Total regulatory liabilities	446,820	446,032
Other liabilities
Deferred income taxes	179,450	180,696
Nuclear waste disposal	106,742	105,391
Other postretirement benefits	77,978	76,396
Environmental remediation costs	22,357	26,357
Other	59,828	48,786
Total other liabilities	446,355	437,626
Total Regulatory and Other Liabilities	893,175	883,658
Other long-term debt	697,521	697,465
Total Liabilities	1,738,917	1,741,644
Commitments and Contingencies	-	-
Common Stock Equity
Common stock	194,429	194,429
Capital in excess of par value	481,935	481,753
Retained earnings	26,464	19,560
Treasury stock, at cost	(117,238)	(117,238)
Accumulated other comprehensive income (loss)	(4,512)	(26)
Total Common Stock Equity	581,078	578,478
Total Liabilities and Stockholder's Equity	$2,319,995	$2,320,122

Thenotes on pages 26 through 34 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30	2005	2004	2005	2004
(Thousands)
Operating Revenues
Electric	$158,902	$160,209	$319,057	$324,393
Natural Gas	66,915	63,520	222,479	212,682
Total Operating Revenues	225,817	223,729	541,536	537,075
Operating Expenses
Electricity purchased and fuel used in generation	71,457	43,161	135,496	69,792
Natural gas purchased	38,579	35,092	142,727	134,174
Other operating expenses	35,866	47,264	74,598	110,309
Maintenance	12,820	13,183	23,795	28,461
Depreciation and amortization	17,712	22,224	35,483	51,642
Other taxes	16,648	18,929	31,825	38,969
Gain on sale of generation assets	-	(319,487)	-	(319,487)
Deferral of asset sale gain	-	214,368	-	214,368
Total Operating Expenses	193,082	74,734	443,924	328,228
Operating Income	32,735	148,995	97,612	208,847
Other (Income)	(459)	(7,437)	(2,013)	(8,100)
Other Deductions	139	(1,668)	267	(1,295)
Interest Charges, Net	14,763	13,696	28,744	27,800
Income Before Income Taxes	18,292	144,404	70,614	190,442
Income Taxes	7,316	115,475	28,710	135,573
Net Income	10,976	28,929	41,904	54,869
Preferred Stock Dividends	-	1,315	-	1,828
Earnings Available for Common Stock	$10,976	$27,614	$41,904	$53,041

Thenotes on pages 26 through 34 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Cash Flows - (Unaudited)
Six months ended June 30	2005	2004
(Thousands)
Net Cash Provided by Operating Activities	$103,197	$85,551
Investing Activities
Proceeds from sale of generation assets	-	428,541
Refund of excess decommissioning fund	-	76,593
Advance to affiliate	-	(25,000)
Utility plant additions	(29,666)	(32,361)
Nuclear generating plant decommissioning fund	-	(8,560)
Other	108	-
Net Cash (Used in) Provided by Investing Activities	(29,558)	439,213
Financing Activities
Repayments of first mortgage bonds and preferred stock	-	(162,000)
Book overdraft	(641)	57,388
Dividends on common and preferred stock	(35,000)	(171,828)
Net Cash Used in Financing Activities	(35,641)	(276,440)
Net Increase in Cash and Cash Equivalents	37,998	248,324
Cash and Cash Equivalents, Beginning of Period	71,259	17,302
Cash and Cash Equivalents, End of Period	$109,257	$265,626

Thenotes on pages 26 through 34 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Retained Earnings - (Unaudited)
Six months ended June 30	2005	2004
(Thousands)
Balance, Beginning of Period	$19,560	$121,032
Add net income	41,904	54,869
	61,464	175,901
Deduct Dividends on Capital Stock
Preferred	-	1,828
Common	35,000	170,000
	35,000	171,828
Balance, End of Period	$26,464	$4,073

Thenotes on pages 26 through 34 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Comprehensive Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30	2005	2004	2005	2004
(Thousands)
Net income	$10,976	$28,929	$41,904	$54,869
Other comprehensive income, net of tax
Net unrealized (losses) on derivatives qualified    as hedges, net of income tax benefit for the    three months of $4,209 in 2005 and $- in 2004    and for the six months of $2,623 in 2005 and    $- in 2004	(6,346)	- -	(3,929)	- -
Reclassification adjustment for derivative losses    (gains) included in net income, net of income    tax expense (benefit) for the three months of    $(22) in 2005 and $- in 2004, and for the six    months of $369 in 2005 and $- in 2004.	33	- -	(557)	- -
Total other comprehensive loss	(6,313)	-	(4,486)	-
Comprehensive Income	$4,663	$28,929	$37,418	$54,869

Thenotes on pages 26 through 34 are an integral part of the condensed financial statements.

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

Rochester Gas and Electric Corporation

Electric Delivery Business

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

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

Errant Voltage: See Energy East's Part I, Item 2, Electric Delivery Business, for this discussion.

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

Transmission Planning and Expansion and Generation Interconnection: See Energy East's Part I, Item 2, Electric Delivery Business, for this discussion.

NYISO Billing Adjustment: See Energy East's Part I, Item 2, 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 in western New York.

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

(a)Liquidity and Capital Resources

Operating Activities: Cash flow from operating activities for the first six months of 2005 included a $25 million refund to RG&E customers from proceeds of the sale of Ginna, pursuant to the Electric Rate Agreement. The Electric Rate Agreement requires additional refunds of $15 million in 2006 and $10 million in 2007.

Investing Activities: Capital spending for the first six months of 2005 was $30 million. Capital spending is projected to be $91 million for 2005 and is expected to be paid for principally with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements and governmental mandates.

Financing Activities: During the first six months of 2005, RG&E paid common dividends of $35 million to Energy East.

In June 2005 RG&E replaced its $230 million revolving credit facility, in which NYSEG was a joint borrower with a five-year $425 million revolving credit facility in which NYSEG, CNG, SCG, CMP and Berkshire are joint borrowers. RG&E does not have any liability for any other joint borrower. RG&E's initial sublimit is $65 million and its maximum borrowing limit under the facility is

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

Rochester Gas and Electric Corporation

$90 million. The facility contains various covenants and conditions on borrowings, including a limit on RG&E's indebtedness to total capitalization of 0.65 to 1.0 and a restriction on RG&E's secured indebtedness. RG&E is not in default, and is not expected to be in default, under the facility.

(b)Results of Operations

Earnings

Three months ended June 30	2005	2004
(Thousands)
Operating Revenues	$225,817	$223,729
Operating Income	$32,735	$148,995
Earnings Available for Common Stock	$10,976	$27,614

RG&E's earnings for the quarter ended June 30, 2005, decreased $17 million compared to the quarter ended June 30, 2004, primarily because of the one-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements, that increased earnings $10 million in the second quarter of 2004. The one-time effects included the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory treatment. In addition certain ongoing effects of the Electric and Natural Gas Rate Agreements were recorded in 2004 in different periods than in 2005, accounting for an additional $3 million decrease in net income for the quarter ended June 30, 2005, as compared to June 30, 2004.

Six months ended June 30	2005	2004
(Thousands)
Operating Revenues	$541,536	$537,075
Operating Income	$97,612	$208,847
Earnings Available for Common Stock	$41,904	$53,041

RG&E's earnings for the six months ended June 30, 2005, decreased $11 million compared to the six months ended June 30, 2004, primarily because of the one-time benefits experienced in 2004 as a result of the sale of Ginna and the approval of the Electric and Natural Gas Rate Agreements, which were partially offset by improved results for the electric operating segment due to provisions of the Electric Rate Agreement.

Operating Results for the Electric Delivery Business

Three months ended June 30	2005	2004
(Thousands)
Retail Deliveries - Megawatt-hours	1,733	1,699
Operating Revenues	$158,902	$160,209
Operating Expenses	$131,239	$17,841
Operating Income	$27,663	$142,368

Operating Revenues:The $1 million decrease in operating revenues for the second quarter of 2005 was primarily the result of:

• A decrease of $5 million resulting from lower average prices on deliveries, and
• A decrease of $1 million in other revenues.

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

Rochester Gas and Electric Corporation

Those decreases were partially offset by:

• An increase of $2 million due to higher wholesale revenues, and
• An increase of $3 million due to increased retail deliveries.

Operating Expenses: The $113 million increase in operating expenses for the second quarter of 2005 was primarily the result of:

• An increase of $105 million as a result of the regulatory treatment in 2004 of RG&E's gain on the sale of Ginna, which included RG&E's recognition of a $319 million pretax gain partially offset by the after tax deferral of the gain of $214 million,

• A net increase of $5 million in operating costs as a result of the sale of Ginna, including a $30 million increase for purchases of power to replace power previously generated by Ginna partially offset by reductions of $15 million for other operating and maintenance expenses, $8 million for depreciation and $2 million for other taxes, and
• An increase of $9 million due to certain credits to other operating expenses that resulted from the Electric Rate Agreement and reduced expenses in the second quarter of 2004. These items were primarily the elimination of reserves established pending regulatory treatment.

Those increases were partially offset by:

• A decrease of $7 million in bad debt expense.

Six months ended June 30	2005	2004
(Thousands)
Retail Deliveries - Megawatt-hours	3,488	3,439
Operating Revenues	$319,057	$324,393
Operating Expenses	$253,688	$147,583
Operating Income	$65,369	$176,810

Operating Revenues:The $5 million decrease in operating revenues for the six months ended June 30, 2005, was primarily the result of:

• A decrease of $11 million in wholesale sales, and
• A decrease of $14 million resulting from lower average prices on deliveries.

Those decreases were partially offset by:

• An increase of $16 million in other revenues, including $8 million due to the amortization of the ASGA to offset incremental supply costs resulting from the sale of Ginna, and
• An increase of $4 million due to increased retail deliveries.

Operating Expenses: The $106 million increase in operating expenses for the six months ended June 30, 2005, was primarily the result of:

• An increase of $105 million as a result of the regulatory treatment in 2004 of RG&E's gain on the sale of Ginna, which included RG&E's recognition of a $319 million pretax gain partially offset by the after tax deferral of the gain of $214 million,
• A net increase of $2 million in operating costs as a result of the sale of Ginna, including a $63 million increase for purchases of power to replace power previously generated by Ginna, partially offset by reductions of $36 million for other operating and maintenance expenses, $21 million for depreciation and $4 million for other taxes, and
• An increase of $9 million due to certain credits to other operating expenses that resulted from the Electric Rate Agreement and reduced expenses in the second quarter of 2004.

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

Rochester Gas and Electric Corporation

Those increases in operating expenses were offset by:

• A decrease of $10 million in other operating and maintenance expenses, including a $8 million reduction in bad debt expense.

Operating Results for the Natural Gas Delivery Business

Three months ended June 30	2005	2004
(Thousands)
Retail Deliveries - Dekatherms	8,488	8,529
Operating Revenues	$66,915	$63,520
Operating Expenses	$61,843	$56,893
Operating Income	$5,072	$6,627

Operating Revenues:The $3 million increase in operating revenues for the second quarter of 2005 was primarily the result of:

• An increase of $5 million due to higher natural gas purchase costs that were passed on to customers.

Those increases were partially offset by:

• A decrease of $1 million due to lower sales primarily due to lower volume usage per customer.

Operating Expenses: The $5 million increase in operating expenses for the second quarter of 2005 was primarily the result of:

• An increase of $5 million due to higher natural gas purchase costs.

Six months ended June 30	2005	2004
(Thousands)
Retail Deliveries - Dekatherms	32,188	32,677
Operating Revenues	$222,479	$212,682
Operating Expenses	$190,235	$180,645
Operating Income	$32,244	$32,037

Operating Revenues:The $10 million increase in operating revenues for the first six months of 2005 was primarily the result of:

• An increase of $13 million due to higher natural gas purchase costs that were passed on to customers, and
• An increase of $3 million due to the Natural Gas Rate Agreement.

Those increases were partially offset by:

• A decrease of $5 million due to lower sales primarily due to lower usage per customer.

Operating Expenses: The $10 million increase in operating expenses for the first six months of 2005 was primarily the result of:

• An increase of $12 million due to higher natural gas purchase costs.

Those increases were partially offset by:

• A decrease of $3 million due to lower sales primarily due to lower usage per customer.

Item 1.  Financial Statements

Notes to Condensed Financial Statements
for
Energy East Corporation
Rochester Gas and Electric Corporation

Notes to Condensed Financial Statements of Registrants:

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

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 statement of the interim results for the periods presented. 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 consolidate its 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, 2004. 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 companies' unaudited financial statements to conform to the 2005 presentation and to reflect 2004 discontinued operations for Energy East.

Note 2. Other (Income) and Other Deductions

	Three Months		Six Months
Periods ended June 30	2005	2004	2005	2004
(Thousands)
Energy East
Interest income	$(2,520)	$(959)	$(4,847)	$(1,365)
Allowance for funds used during construction	(372)	(160)	(678)	(262)
Gains from the sale of nonutility property	(26)	(1,159)	(99)	(1,236)
Earnings from equity investments	(788)	(935)	(1,938)	(2,602)
2004 RG&E Electric and Natural Gas    Rate Agreement	- -	(6,117)	- -	(6,117)
Gains on hedge activity	(4,289)	(238)	(8,572)	146
Miscellaneous	(1,001)	(2,112)	(2,929)	(5,984)
Total other (income)	$(8,996)	$(11,680)	$(19,063)	$(17,420)
Losses from disposition of property	$    (1)	$339	$36	$810
Losses on hedge activity	4,772	150	7,179	(418)
Miscellaneous	2,213	670	3,987	4,045
Total other deductions	$6,984	$1,159	$11,202	$4,437
RG&E
Interest income	$(790)	$(1,028)	$(1,309)	$(838)
Allowance for funds used during construction	(46)	(31)	(99)	(41)
2004 RG&E Electric and Natural Gas    Rate Agreement	- -	(6,117)	- -	(6,117)
Gains on hedge activity	213	-	(749)	-
Miscellaneous	164	(261)	144	(1,104)
Total other (income)	$(459)	$(7,437)	$(2,013)	$(8,100)
Losses from disposition of property	$  -	$(80)	$  -	$(80)
Losses on hedge activity	52	(80)	216	(80)
Miscellaneous	87	(1,508)	51	(1,135)
Total other deductions	$139	$(1,668)	$267	$(1,295)

Note 3. Basic and Diluted Earnings per Share

Basic 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 SARs. Historically, all stock options have been 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		Six Months
Periods ended June 30	2005	2004	2005	2004
(Thousands)
Basic average common shares outstanding	146,831	146,148	146,853	146,116
Restricted stock awards	559	448	441	396
Potentially dilutive common shares	280	302	245	266
Options issued with SARs	(280)	(302)	(245)	(266)
Dilutive average common shares outstanding	147,390	146,596	147,294	146,512

Options to purchase shares of common stock are excluded from the determination of EPS when the exercise price of an option is greater than the average market price of a common share during the period. Shares excluded from the EPS calculation for the three months ended June 30 were: 0.5 million in 2005 and 0.7 million in 2004, and for the six months ended June 30 were: 0.5 million in 2005 and 1.3 million in 2004.

During the second quarter of 2005 the company awarded 241,493 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of approximately $6 million based on the average market price of $26.16 per share of common stock on the dates of the awards. The shares vest based on the conditions outlined in the restricted stock award grants, including the achievement of targeted shareholder returns, but no later than January 1, 2011.

Note 4. 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 equals the $214 million deferral of asset sale gain, as reflected on RG&E's statement of income.

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

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. Therefore, RG&E recorded pretax income of $105 million and income tax expense of $105 million, increasing the effective tax rate from an expected rate of 39% for the company and 41% for RG&E, to an effective rate of 56% for the company and 71% for RG&E.

RG&E's Electric Rate Agreement established a customer refunds of $60 million that were issued near the end of the second quarter of 2004 and resulted in a book overdraft of $57 million since most of the refunds were still outstanding at June 30, 2004.

Note 5. Discontinued Operations

In keeping with the company's focus on its regulated electric and natural gas delivery businesses, during recent years the company has been systematically exiting certain noncore businesses. All businesses sold were previously reported in the company's Other business segment. In July 2004 Union Water Power Company, a subsidiary of CMP Group, sold the assets associated with its utility locating and construction divisions. In October 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. There were no discontinued operations during the first six months of 2005.

The results of discontinued operations of the businesses sold in 2004 were:

	Three Months	Six Months
Periods ended June 30	2004	2004
(Thousands)
Certain Divisions of Union Water Power Co.
Revenues	$8,157	$13,175
Loss from businesses held for sale    (including estimated loss on disposal in    2004 of $5,500)	$(4,249)	$(4,527)
Income taxes	467	345
Loss from discontinued operations	$(4,716)	$(4,872)
Component of Energy East Solutions, Inc.
Revenues	$11,628	$41,345
Loss from businesses sold	$(67)	$(425)
Income taxes (benefits)	(26)	(162)
Loss from discontinued operations	$(41)	$(263)
Totals from discontinued operations
Total Revenues	$19,785	$54,520
Total loss from businesses sold	$(4,316)	$(4,952)
Total income taxes	441	183
Total loss from discontinued operations	$(4,757)	$(5,135)

Note 6. New Accounting Pronouncements

Statement 123(R): In December 2004 the FASB issued Statement 123(R), which is a revision of Statement 123. Statement 123(R) requires a public entity to measure the cost of employee services that it receives in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is to be recognized over the period during which the employee is required to provide service in exchange for the award. Statement 123(R) also requires a public entity to initially measure the cost of employee services received in exchange for an award of liability instruments based on the award's current fair value. The fair value of the liability award will subsequently be remeasured at each reporting date through the settlement date and changes in fair value during the required service period will be recognized as compensation cost over that period. Statement 123(R) was to be effective for public entities as of the beginning of the first interim or annual reporting period that begins a fter June 15, 2005. In April 2005 the SEC approved a new rule that for public companies delays the effective date of Statement 123(R). Under the new rule, a public company will be required to prepare financial statements in accordance with Statement 123(R) beginning with the first interim or annual reporting period of its first fiscal year beginning on or after June 15, 2005.

The company plans to adopt Statement 123(R) effective January 1, 2006, and follow the modified version of prospective application. The weighted-average fair value per share of stock options awarded in 2004, 2003 and 2002 ranged between $2.93 and $3.91, and is not expected to change significantly for future awards of stock options. As required by Statement 123(R), the company will no longer defer compensation cost for awards of restricted stock. Instead it will recognize additional paid-in capital and compensation cost for the restricted stock over the estimated vesting period, which is the period during which the employee is required to provide service in exchange for the award as adjusted based on the expected achievement of performance conditions.

In the second quarter of 2005 the SEC staff provided its views concerning vesting of stock-based awards based on retirement eligibility criteria. The company currently applies APB 25 and follows the nominal vesting period approach for its restricted stock awards, which have a retirement eligibility provision. Following the nominal vesting period approach, the company records compensation expense over the estimated vesting period for the restricted stock award, beginning on the grant date. If an employee were to retire before the end of the estimated vesting period, any remaining unrecognized compensation cost related to that employee's restricted stock would be recognized at the date of retirement. After it adopts Statement 123(R) the company will be required to follow the nonsubstantive vesting period approach for any new awards of its restricted stock. According to that approach, an award is considered to be vested, for expense recognition purposes when the employee's retention of the award is no longer contingent on providing subsequent service. Therefore, the compensation cost would be recognized immediately for restricted stock granted to an employee who is eligible for retirement on the date of the grant. The company will continue to follow the nominal vesting period approach for any restricted stock awards granted prior to adoption of Statement 123(R) including the remaining portion of nonvested outstanding awards. Actual compensation cost for restricted stock following the nominal vesting period approach for the periods ended June 30 was: three months: $1.2 million for 2005 and $1.1 million for 2004; and six months: $2.8 million for 2005 and $1.7 million for 2004. Pro forma compensation expense for restricted stock awards, which reflects an estimate of compensation cost following the nonsubstantive vesting period approach, for the periods ended June 30 was: three months: $4.2 million for 2005 and $0.3 million for 2004; and six months: $4.5 million for 2005 and $4.0 million for 2004.

The company is evaluating the expected effects of the adoption of Statement 123(R) on its financial position, results of operations and cash flows, but does not expect that the effects will be material.

FIN 47: In March 2005 the FASB issued FIN 47. FIN 47 clarifies that the term "conditional asset retirement obligation" as used in Statement 143 refers to an entity's "legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity." FIN 47 requires that if an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional asset retirement obligation, it must recognize that liability at the time the liability is incurred. For calendar-year enterprises such as Energy East and its subsidiaries, FIN 47 is effective no later than December 31, 2005. The company plans to apply FIN 47 as of December 31, 2005. The company is currently in the process of evaluating whether it has conditional asset retirement obligations in addition to its current asset retirement obligations. The company does not expect that its application of FIN 47 w ill have a material effect on its financial position, results of operations or cash flows.

Note 7. FIN 46(R)

In December 2003 the FASB issued FIN 46(R), which 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 46(R) 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 46(R) to all entities subject to the interpretation as of March 31, 2004.

CMP and NYSEG have independent, ongoing, power purchase contracts with NUGs. CMP and NYSEG were not involved in the formation of and do not have ownership interests in any NUGs. CMP and NYSEG evaluated each of their power purchase contracts with NUGs with respect to FIN 46(R). Most of the purchase contracts were determined not to be variable interests for one of the following four 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 46(R) 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 and NYSEG requested information from the seven 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 seven NUGs is approximately 517 megawatts. Purchases from the seven NUGs totaled approximately $177 million for the six months ended June 30, 2005 and approximately $184 million for the six months ended June 30, 2004.

Note 8. Accounts Receivable

Energy East's accounts receivable include consolidated unbilled revenues of $130 million at June 30, 2005, and $227 million at December 31, 2004, and are shown net of an allowance for doubtful accounts of $42 million at June 30, 2005, and $45 million at December 31, 2004.

RG&E's accounts receivable include unbilled revenues of $13 million at June 30, 2005, and $40 million at December 31, 2004, and are shown net of an allowance for doubtful accounts of $13 million at June 30, 2005, and $21 million at December 31, 2004.

RG&E reduced its allowance for doubtful accounts during the second quarter of 2005 by approximately $8 million. That change in estimate was due to revised assumptions of the likelihood of noncollection of accounts receivable based on RG&E's historical collection experience.

Note 9. Retirement Benefits

Components of net periodic benefit cost

	Pension Benefits		Postretirement Benefits
Three months ended June 30	2005	2004	2005	2004
(Thousands)
Energy East
Service cost	$8,762	$7,807	$1,338	$1,407
Interest cost	31,968	32,931	7,379	8,987
Expected return on plan assets	(54,193)	(51,742)	(567)	(672)
Amortization of transition (asset) obligation	-	(307)	1,700	1,984
Amortization of prior service cost	1,250	1,161	(1,894)	(1,713)
Recognized net actuarial (gain) loss	3,980	(210)	1,681	1,583
Net periodic benefit cost	$(8,233)	$(10,360)	$9,637	$11,576
RG&E
Service cost	$1,339	$1,234	$272	$243
Interest cost	6,803	7,435	1,444	1,502
Expected return on plan assets	(12,020)	(12,136)	-	-
Unrecognized transition obligation	-	-	464	514
Amortization of prior service cost	279	306	250	277
Recognized net actuarial (gain) loss	(913)	(1,788)	132	(110)
Net periodic benefit cost	$(4,512)	$(4,949)	$2,562	$2,426

	Pension Benefits		Postretirement Benefits
Six months ended June 30	2005	2004	2005	2004
(Thousands)
Energy East
Service cost	$18,047	$16,055	$2,887	$3,250
Interest cost	63,999	65,492	15,359	18,369
Expected return on plan assets	(107,103)	(103,060)	(1,123)	(1,336)
Amortization of transition (asset) obligation	-	(615)	3,400	4,001
Amortization of prior service cost	2,499	2,325	(3,789)	(3,424)
Recognized net actuarial (gain) loss	7,932	(535)	4,316	3,795
Net periodic benefit cost	$(14,626)	$(20,338)	$21,050	$24,655
RG&E
Service cost	$2,678	$2,740	$544	$515
Interest cost	13,606	14,902	2,888	3,027
Expected return on plan assets	(24,041)	(24,592)	-	-
Unrecognized transition obligation	-	-	928	1,059
Amortization of prior service cost	559	631	500	571
Recognized net actuarial (gain) loss	(1,827)	(3,453)	265	(132)
Net periodic benefit cost	$(9,025)	$(9,772)	$5,125	$5,040

In March 2005 Energy East's subsidiaries contributed $54 million to their pension plans. They do not anticipate any further contributions in 2005.

Note 10. Goodwill and Intangible Assets

The company does not amortize goodwill and/or intangible assets with indefinite lives (unamortized intangible assets). The company tests goodwill and/or unamortized intangible assets for impairment at least annually. The company and RG&E amortize intangible assets with finite lives (amortized intangible assets) and review them for impairment. The company completed its annual impairment testing in the third quarter of 2004 and determined that there was no impairment of goodwill and/or unamortized intangible assets.

The carrying amounts of goodwill, by operating segment, were the same at June 30, 2005, and December 31, 2004, and are shown in the table below.

	Electric Delivery	Natural Gas Delivery	Other	Total
(Thousands)
Energy East	$844,491	$676,588	$4,274	$1,525,353

The company's unamortized intangible assets had a carrying amount of $9 million at June 30, 2005, and $10 million at December 31, 2004, and primarily consisted of pension assets. The company's amortized intangible assets had a gross carrying amount of $32 million at June 30, 2005, and $31 million at December 31, 2004, and primarily consisted of investments in pipelines and customer lists. Accumulated amortization was $17 million at June 30, 2005, and $15 million at December 31, 2004. Estimated amortization expense for intangible assets for the next five years is approximately $2 million for 2005 and $1 million for each year, 2006 through 2009.

RG&E has no goodwill or unamortized intangible assets. RG&E's amortized intangible assets consisted of water rights and had a gross carrying amount of $3 million and accumulated amortization of $2 million at June 30, 2005, and December 31, 2004. Estimated amortization expense for intangible assets is $78 thousand for each of the next five years, 2006 through 2010.

Note 11. Commitments and Contingencies

NYISO billing adjustment: The NYISO frequently bills transmission owners on a retroactive basis when adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission revenue or expense as appropriate when revised amounts can be estimated. On January 25, 2005, the NYISO notified the NYTOs, including NYSEG and RG&E, of errors related to transmission congestion contract billings for periods including May 2000 through October 2002. NYSEG's retroactive billing was approximately $0.7 million and RG&E's was less than $0.1 million for the periods in question. Both amounts were expensed during the first two quarters of 2005.

In a separate issue in March 2005 the FERC issued an order directing the NYISO to modify certain energy prices for May 8 and 9, 2000, and to back bill NYISO market participants, including NYSEG and RG&E. The NYISO and many market participants filed requests for rehearing with the FERC concerning that order. While the FERC has not ruled on these requests for rehearing, on July 8, 2005, the NYISO issued back billings that addressed a number of the May 8 and 9, 2000, issues. NYSEG's back billing was $2.3 million and RGE's was $1.4 million. Both amounts were expensed during the second quarter of 2005.

Note 12. Segment Information

The company's electric delivery segment consists of its regulated transmission, distribution and generation operations in New York and Maine and its natural gas delivery segment consists of its regulated transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts. The company measures segment profitability based on net income. "Other" segment includes: the company's corporate assets, interest income, interest expense and operating expenses, nonutility businesses and intersegment eliminations.

RG&E's electric delivery segment consists of its regulated transmission, distribution and generation operations. Its natural gas delivery segment consists of its regulated transportation, storage and distribution operations. RG&E measures segment profitability based on net income. RG&E operates in the State of New York.

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

	Electric      Delivery	Natural Gas     Delivery	Other	Total
(Thousands)
Three months ended
June 30, 2005
Operating Revenues    Energy East    RG&E	$687,627  $158,902	$282,450  $66,915	$111,868  - -	$1,081,945  $225,817
Net Income (Loss)    Energy East    RG&E	$23,378  $10,301	$(5,148) $675	$(865) - -	$17,365  $10,976
June 30, 2004
Operating Revenues    Energy East    RG&E	$641,057 $160,209	$240,282  $63,520	$87,599  - -	$968,938 $223,729
Net Income (Loss)    Energy East    RG&E	$43,819 $27,464	$(12,815) $1,465	$7,062  - -	$38,066 $28,929
Six months ended
June 30, 2005
Operating Revenues    Energy East    RG&E	$1,455,949  $319,057	$1,003,646  $222,479	$259,628  - -	$2,719,223  $541,536
Net Income    Energy East    RG&E	$106,479  $26,474	$65,156  $15,430	$96  - -	$171,731  $41,904
June 30, 2004
Operating Revenues    Energy East    RG&E	$1,371,652  $324,393	$922,006  $212,682	$226,636  - -	$2,520,294  $537,075
Net Income    Energy East    RG&E	$105,014  $41,143	$50,992  $13,726	$2,612  - -	$158,618  $54,869
Total Assets
June 30, 2005    Energy East    RG&E	$6,772,194  $1,670,396	$3,803,812  $649,599	$255,983  - -	$10,831,989  $2,319,995
December 31, 2004    Energy East    RG&E	$6,737,573  $1,670,488	$3,851,063  $649,634	$207,477  - -	$10,796,113  $2,320,122

Item 3.  Quantitative and Qualitative Disclosures About Market Risk
(See report on Form 10-K for Energy East and RG&E for fiscal year ended December 31, 2004, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

Commodity Price Risk: Commodity price risk, due to volatility experienced in the electric wholesale markets, is a significant issue for the company, NYSEG and RG&E. The companies manage this risk through a combination of regulatory mechanisms, such as allowing for the pass-through of the market price of electricity to customers, and through comprehensive risk management processes. These measures mitigate the companies' commodity price exposure, but do not completely eliminate it.

NYSEG, RG&E and Energy East's energy marketing subsidiaries 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 fixed and variable rate options, and an option to purchase electricity supply from an ESCO. Approximately 40% of NYSEG's total electric load is now provided by an ESCO 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. NYSEG actively hedges the load required to serve customers who select the bundled rate option. As of July 30, 2005, NYSEG's load was fully hedged for on-peak periods and 99% hedged for off-peak periods for August through December 2005. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings less than $50,000 for August through December 2005. The percentage of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as hi storical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

RG&E's current electric rate plan offers retail customers choice in their electricity supply including fixed and variable rate options, and an option to purchase electricity supply from an ESCO. Approximately 75% of RG&E's total electric load is now provided by an ESCO or at the market price. RG&E's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the fixed rate option, which combines delivery and supply service at a fixed price. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. RG&E actively hedges the load required to serve customers who select the fixed rate option. As of July 30, 2005, RG&E's load was fully hedged for August through December 2005. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings less than $150 thousand for August through December 20 05. The percentage of RG&E's hedged load is based on RG&E's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

Two of Energy East's energy marketing subsidiaries offer retail electric service to customers in New York State. The energy marketing subsidiaries actively hedge the load required to serve customers that have chosen them as an option. As of July 30, 2005, the energy marketing subsidiaries fixed price load was 98% hedged for 2005. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings less than $50 thousand in 2005. The percentage of energy marketing subsidiaries hedged load is based on 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.

Other Comprehensive Income for the six months of 2005 was $47 million. That amount primarily represents the increase in value of the company's derivative positions for future commodity purchases and results from price changes for electricity in the wholesale market. Since the company's derivative positions are used only for hedging its load requirements for customers on fixed prices, Other Comprehensive Income for the quarter will have no effect on future net income.

All of Energy East's natural gas utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk.

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, which is passed on to customers when the related sales commitments are fulfilled.

Two of Energy East's energy marketing subsidiaries offer retail natural gas service to customers in New York State. The energy marketing subsidiaries actively hedge the load required to serve customers that have chosen them as an option. As of July 30, 2005, the energy marketing subsidiaries fixed price load was 100% hedged in 2005. The percentage of energy marketing subsidiaries hedged load is based on 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.

Item 4.  Controls and Procedures

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

Energy East 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. Each company's system of internal control over financial reporting contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. There were no changes in the companies' internal control over financial reporting that occurred during each company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the respective company's internal control over financial reporting.

PART II - OTHER INFORMATION

Item 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   (April 1, 2005 to   April 30, 2005)	255,959		(1)	$25.94		- -		- -
Month #2   (May 1, 2005 to   May 31, 2005)	4,252		(2)	$27.77		- -		- -
Month #3   (June 1, 2005 to   June 30, 2005)	6,364		(2)	$29.14		- -		- -
Total	266,575			$26.04		-		-

(1) Includes 5,959 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 250,000 shares of the company's common stock (Par Value $.01) purchased for Treasury for issuance under the company's Restricted Stock Plan and Stock Option Plan.
⁽²⁾ Includes 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.

RG&E had no issuer purchase of equity securities during the six months ended June 30, 2005.

Item 4.  Submission of Matters to a Vote of Security Holders

Energy East Corporation

Energy East's Annual Meeting of Stockholders was held on June 9, 2005. The following matters were voted on:

(a)  The election of ten directors:

Nominees	Votes For	Votes Withheld
John T. Cardis	121,208,689	2,104,657
Joseph J. Castiglia	120,938,473	2,374,873
Lois B. DeFleur	119,321,164	3,992,182
G. Jean Howard	121,187,721	2,125,625
David M. Jagger	121,237,236	2,076,110
Seth A. Kaplan	121,189,563	2,123,783
Ben E. Lynch	120,685,385	2,627,961
Peter J. Moynihan	121,181,049	2,132,297
Walter G. Rich	121,248,456	2,064,890
Wesley W. von Schack	120,344,459	2,968,887

(b)  Ratification of the appointment of PricewaterhouseCoopers LLP as the company's independent registered public accounting firm:

Shares For:	121,334,467
Shares Against:	1,124,994
Shares Abstain:	853,885

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:  August 4, 2005	ENERGY EAST CORPORATION                   (Registrant) By  /s/ Robert D. Kump                                                                         Robert D. Kump            Vice President, Controller & Chief Accounting Officer            (Principal Accounting Officer)
Date:  August 4, 2005	ROCHESTER GAS AND ELECTRIC CORPORATION                   (Registrant) By  /s/ Joseph J. Syta                                                                            Joseph J. Syta            Vice President - Controller and Treasurer            (Principal Financial Officer)

EXHIBIT INDEX

The following exhibits are delivered with this report:

Registrant	Exhibit No.	Description of Exhibit
Energy East Corporation	(A)10-24	Amended and Restated Employment Agreement dated as   of June 14, 1999, by and among the Company, CMP Group, Inc.   and F. Michael McClain, Jr.
	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.

_________________________________

(A) Management contract or compensatory plan or arrangement.

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

Energy East agrees to furnish, upon request, a copy of the Five-Year Revolving Credit Agreement among Energy East, certain lenders, Citibank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, and HSBC Bank USA, National Association, UBS Securities LLC and Wachovia Bank, N.A., as Co-Documentation Agents, dated as of June 16, 2005. The total amount of securities authorized under such agreement does not exceed 10% of the total assets of Energy East.

RG&E agrees to furnish, upon request, a copy of the Five-Year Revolving Credit Agreement among RG&E, New York State Electric & Gas Corporation, Central Maine Power Company, The Southern Connecticut Gas Company, Connecticut Natural Gas Corporation and The Berkshire Gas Company, certain lenders, Wachovia Bank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, and The Bank of New York, Citibank, N.A. and Sovereign Bank, as Co-Documentation Agents, dated as of June 16, 2005. The total amount of securities authorized under such agreement does not exceed 10% of the total assets of RG&E.