Rochester Gas & Electric 10-Q 2005 Q3 Quarterly report

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

FORM 10-Q

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Registrant
Energy East Corporation	Yes	No     X
Rochester Gas and Electric Corporation	Yes	No     X

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

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

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	147,701,362
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 either 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	iv
	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 16 18
	Rochester Gas and Electric Corporation   Condensed Statements of IncomeCondensed Balance SheetsCondensed 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	23 24 26 27 27 28 29
	Notes to Condensed Financial Statements	32
3	Quantitative and Qualitative Disclosures About Market Risk	44
4	Controls and Procedures	45
	PART II - OTHER INFORMATION
2	Unregistered Sales of Equity Securities and Use of Proceeds	46
6	Exhibits	46
Signatures		47
Exhibit Index		48

GLOSSARY OF TERMS

Abbreviations or acronyms frequently used in this report:

Energy East Companies
Berkshire Gas	The Berkshire Gas Company
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
RGS Energy	RGS Energy Group, Inc.
SCG	The Southern Connecticut Gas Company
Third Parties
CGG	Constellation Generation Group, LLC
Connecticut Yankee	Connecticut Yankee Atomic Power Company
ISO	Independent system operator
ISO New England	ISO New England, Inc.
NYISO	New York Independent System Operator
NYTO	New York Transmission Owner
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
Electric Joint Proposal	2002 NYSEG and 2004 RG&E Joint Proposals
APB 25	Accounting Principles Board Opinion No. 25,   Accounting for Stock Issued to Employees
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
ESR	Electric supply reconciliation mechanism
ESCO	energy service company
FASB	Financial Accounting Standards Board

GLOSSARY OF TERMS (Cont'd)
Other, continued
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 generating station, a nuclear power   plant formerly owned by RG&E (sold in June 2004)
IRP	Incentive Rate Plan
LICAP	Locational Installed Capacity Markets
Natural Gas Rate Agreement	the natural gas portion of the RG&E 2004 Electric and   Natural Gas Rate Agreements
NMP2	Nine Mile Point 2 nuclear generating station
NUG	nonutility generator
OCC	Connecticut Office of Consumer Counsel
Policy Statement	NYPSC Statement of Policy on Further Steps Toward   Competition in Retail Energy Markets
ROE	return on equity
SAR	stock appreciation right
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
Voice Your Choice	NYSEG's electric commodity option program

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 and increased state and FERC regulation of, among other things, intercompany cost allocations; 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 comp any'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; extreme weather-related events such as hurricanes, ice storms or snow storms; 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 th e 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		Nine Months
Periods ended September 30,	2005	2004	2005	2004
(Thousands, except per share amounts)
Operating Revenues
Utility	$966,313	$879,018	$3,425,908	$3,172,676
Nonutility	129,618	88,788	389,247	315,424
Total Operating Revenues	1,095,931	967,806	3,815,155	3,488,100
Operating Expenses
Electricity purchased and fuel used in generation
Utility	398,874	366,937	1,112,400	976,894
Nonutility	97,965	57,455	258,409	182,405
Natural gas purchased
Utility	104,323	79,215	746,609	657,458
Nonutility	12,068	4,665	69,904	54,249
Other operating expenses	213,152	204,962	581,288	602,223
Maintenance	51,155	40,110	145,216	121,276
Depreciation and amortization	67,451	68,623	203,493	222,130
Other taxes	56,584	56,016	184,358	188,434
Gain on sale of generation assets	-	(21,252)	-	(340,739)
Deferral of asset sale gain	-	16,414	-	230,783
Total Operating Expenses	1,001,572	873,145	3,301,677	2,895,113
Operating Income	94,359	94,661	513,478	592,987
Other (Income)	(6,041)	(9,874)	(25,104)	(27,294)
Other Deductions	(4,637)	2,568	6,566	7,005
Interest Charges, Net	72,718	69,676	214,736	208,488
Preferred Stock Dividends of Subsidiaries	283	437	1,191	3,215
Income from Continuing Operations   before Income Taxes	32,036	31,854	316,089	401,573
Income Taxes	10,712	14,354	123,034	220,319
Income from Continuing Operations	21,324	17,500	193,055	181,254
Discontinued Operations
Loss from discontinued operations	-	(670)	-	(5,623)
Income taxes	-	857	-	1,040
Loss from Discontinued Operations	-	(1,527)	-	(6,663)
Net Income	$21,324	$15,973	$193,055	$174,591
Earnings per Share from Continuing   Operations, basic and diluted	$.14	$.12	$1.31	$1.24
Loss per Share from Discontinued   Operations, basic and diluted	- -	$(.01)	- -	$(.05)
Earnings per Share, basic and diluted	$.14	$.11	$1.31	$1.19
Dividends Paid per Share	$.275	$.26	$.825	$.78
Average Common Shares Outstanding, basic	147,008	146,385	146,895	146,207
Average Common Shares Outstanding, diluted	147,588	146,807	147,383	146,611

Thenotes on pages 32 through 43 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	Sept. 30,   2005	Dec. 31,   2004
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$414,120	$247,120
Accounts receivable, net	690,290	821,556
Fuel and natural gas in storage, at average cost	275,496	198,640
Materials and supplies, at average cost	28,409	26,592
Accumulated deferred income tax benefits, net	21,384	33,969
Derivative assets	364,385	9,323
Prepayments and other current assets	128,918	86,306
Total Current Assets	1,923,002	1,423,506
Utility Plant, at Original Cost
Electric	5,354,888	5,282,828
Natural gas	2,539,429	2,493,455
Common	439,753	420,372
	8,334,070	8,196,655
Less accumulated depreciation	2,721,362	2,602,013
Net Utility Plant in Service	5,612,708	5,594,642
Construction work in progress	104,860	67,526
Total Utility Plant	5,717,568	5,662,168
Other Property and Investments, Net	208,464	190,148
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	312,903	356,072
Deferred income taxes	25,867	-
Unfunded future income taxes	115,673	115,446
Unamortized loss on debt reacquisitions	63,040	58,345
Environmental remediation costs	122,797	122,052
Nonutility generator termination agreements	89,721	96,158
Other	310,040	419,214
Total regulatory assets	1,040,041	1,167,287
Other assets
Goodwill, net	1,525,353	1,525,353
Prepaid pension benefits	734,339	657,402
Derivative assets	178,749	27,569
Other	124,754	142,680
Total other assets	2,563,195	2,353,004
Total Regulatory and Other Assets	3,603,236	3,520,291
Total Assets	$11,452,270	$10,796,113

Thenotes on pages 32 through 43 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	Sept. 30,   2005	Dec. 31,   2004
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$57,151	$59,231
Notes payable	130,004	206,472
Accounts payable and accrued liabilities	491,459	454,876
Interest accrued	59,004	43,469
Taxes accrued	33,501	8,568
Other	236,772	184,227
Total Current Liabilities	1,007,891	956,843
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	803,177	762,520
Deferred income taxes	-	21,487
Gain on sale of generation assets	180,601	233,378
Pension benefits	24,458	25,354
Other	110,195	107,932
Total regulatory liabilities	1,118,431	1,150,671
Other liabilities
Deferred income taxes	1,225,792	973,599
Nuclear plant obligations	230,635	251,753
Other postretirement benefits	427,293	419,885
Environmental remediation costs	146,456	150,263
Other	445,546	417,485
Total other liabilities	2,475,722	2,212,985
Total Regulatory and Other Liabilities	3,594,153	3,363,656
Debt owed to subsidiary holding solely parent debentures	355,670	355,670
Other long-term debt	3,459,021	3,442,015
Total long-term debt	3,814,691	3,797,685
Total Liabilities	8,416,735	8,118,184
Commitments and Contingencies	-	-
Preferred Stock of Subsidiaries  Redeemable solely at the option of subsidiaries	24,632	46,671
Common Stock Equity  Common stock	1,477	1,471
Capital in excess of par value	1,493,377	1,477,518
Retained earnings	1,273,469	1,201,533
Accumulated other comprehensive income (loss)	252,091	(43,561)
Deferred compensation	(8,133)	(5,020)
Treasury stock, at cost	(1,378)	(683)
Total Common Stock Equity	3,010,903	2,631,258
Total Liabilities and Stockholders' Equity	$11,452,270	$10,796,113

Thenotes on pages 32 through 43 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Nine months ended September 30,	2005	2004
(Thousands)
Operating Activities
Net Income	$193,055	$174,591
Adjustments to reconcile net income to net cash provided    by operating activities
Depreciation and amortization	285,313	287,578
Income taxes and investment tax credits deferred, net	40,150	50,488
Income taxes related to gain on sale of generation assets	-	109,956
Gain on sale of generation assets	-	(340,739)
Deferral of asset sale gain	-	230,783
Pension income	(22,510)	(30,507)
Changes in current operating assets and liabilities
Accounts receivable	136,133	191,469
Inventory	(78,672)	(66,925)
Prepayments and other current assets	(43,259)	2,077
Accounts payable and accrued liabilities	53,487	(64,186)
Interest accrued	15,535	9,235
Taxes accrued	5,607	(33,422)
Customer refund	(25,329)	(58,066)
Other current liabilities	52,755	18,319
Pension contribution	(54,000)	(19,160)
Other assets	23,416	(96,819)
Other liabilities	(23,439)	(37,768)
Net Cash Provided by Operating Activities	558,242	326,904
Investing Activities
Proceeds from sale of generation assets	-	453,678
Refund of excess decommissioning fund	-	76,593
Utility plant additions	(224,426)	(211,107)
Other property and investments additions	(1,758)	(5,453)
Other property and investments sold	16,359	2,255
Other	51	3,854
Net Cash (Used in) Provided by Investing Activities	(209,774)	319,820
Financing Activities
Issuance of common stock	2,425	1,908
Repurchase of common stock	(7,524)	(6,306)
Book overdraft	17,838	41,910
Repayments of first mortgage bonds and preferred stock of   subsidiaries, including net premiums	(22,260)	(261,506)
Long-term note issuances	315,000	276,500
Long-term note repayments	(302,774)	(231,888)
Notes payable three months or less, net	(76,468)	(191,101)
Notes payable issuances	-	3,000
Notes payable repayments	-	(16,000)
Dividends on common stock	(107,705)	(100,493)
Net Cash Used in Financing Activities	(181,468)	(483,976)
Net Increase in Cash and Cash Equivalents	167,000	162,748
Cash and Cash Equivalents, Beginning of Period	247,120	147,869
Cash and Cash Equivalents, End of Period	$414,120	$310,617

Thenotes on pages 32 through 43 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Nine months ended September 30,	2005	2004
(Thousands)
Balance, Beginning of Period	$1,201,533	$1,126,457
Add net income	193,055	174,591
	1,394,588	1,301,048
Deduct Dividends on Capital Stock
Common	121,119	113,976
Balance, End of Period	$1,273,469	$1,187,072

Thenotes on pages 32 through 43 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30,	2005	2004	2005	2004
(Thousands)
Net income	$21,324	$15,973	$193,055	$174,591
Other comprehensive income, net of tax
Net unrealized gains on investments,    net of income tax (expense) for the    three months of $(38) in 2005 and $(688) in    2004 and for the nine months of $(38) in    2005 and $(114) in 2004	77	1,176	73	249
Minimum pension liability adjustment, net of    income tax (expense) for the three months of $-    in 2005 and $(47) in 2004 and for the nine months    of $7 in 2005 and $(47) in 2004	-	71	(11)	71
Unrealized gains on derivatives qualified as hedges,    net of income tax (expense) for the three months of    $(175,750) in 2005 and $(14,679) in 2004    and for the nine months of $(182,033) in 2005    and $(31,908) in 2004	265,966	20,826	281,957	46,637
Reclassification adjustment for derivative    (gains) included in net income, net of    income tax expense for the three    months of $11,744 in 2005 and $195 in    2004 and for the nine months of $(9,026)    in 2005 and $11,205 in 2004	(17,770)	(293)	13,633	(16,894)
Net unrealized gains on derivatives qualified    as hedges	248,196	20,533	295,590	29,743
Total other comprehensive income	248,273	21,780	295,652	30,063
Comprehensive Income	$269,597	$37,753	$488,707	$204,654

Thenotes on pages 32 through 43 are 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 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 stranded costs, and provide stable rates for customers and revenue predictability for those four operating companies. NYSEG's current long-term electric rate plan is set to expire at the end of 2006. In September 2005 NYSEG filed with the NYPSC for an electric rate plan extension that would be effective through 2012. The Southern Connecticut Gas Company's current IRP expired on September 30, 2005. On September 30, 2005, SCG and the OCC filed an amended two-year settlement agreement with the DPUC after the DPUC rejected an August 2005 settlement agreement. CNG is operating with the rates established in its previous long-term plan that expired at the end of September 2005.

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 their outcomes 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 continued evolution of the electric utility industry is evidenced by the recent enactment of the Domenici-Barton Energy Policy Act of 2005, which repealed the Public Utility Holding Company Act of 1935 (PUHCA). With the repeal of PUHCA, the FERC and state utility commissions are given new authority to regulate and monitor, among other things, intercompany cost allocations of holding companies such as Energy East.

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

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

Energy East Corporation

The accompanying Management's Discussion and Analysis of Financial Condition and Results of Operations for each registrant should be read in conjunction with its Management's Discussion and Analysis of Financial Condition and Results of Operations, financial statements and notes contained in its report on Form 10-K filed 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 and services strategy over the past several years, focusing on the transmission and distribution of electricity and natural gas rather than on 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 a majority of its 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. Utility Shared Services Corporation, a subsidiary of Energy East, has improved efficiencies and achieved savings through the integration of the companies' information systems, purchasing, human resources, 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.

NYSEG Electric Rate Plan Extension: On September 30, 2005, NYSEG filed with the NYPSC an Electric Rate Plan Extension, proposing a net overall electricity delivery rate decrease of approximately 9.5% and the continuation of its Voice Your Choice Program for an additional six years (2007 through 2012). NYSEG proposes to decrease customers' bills by approximately 9.5% effective September 1, 2006 by implementing a bill credit to customers for the four-month period ending December 31, 2006. To accomplish this NYSEG will return to its electric customers a portion of its ASGA, initially created as a result of the sale of its generating stations. The ASGA has been enhanced during NYSEG's current rate plan with its customers' share of an earnings sharing mechanism. After the end of the current rate plan and beginning January 1, 2007, NYSEG would reduce its nonbypassable wires charge and increase delivery rates, maintaining the annualized overall delivery rate reduction of approximately 9.5% to be implemented on September 1, 2006. The decrease in the nonbypassable wires charge would be accomplished by accelerating benefits from the expiration of certain NUG contracts and capping the amount of above-market NUG costs over the term of the rate plan extension. NYSEG also proposes to increase its equity to capital ratio from 45% to 50%. In addition, NYSEG's proposal will allow customers to continue to benefit from merger synergies and savings.

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

Energy East Corporation

On October 28, 2005, NYSEG filed a motion with the NYPSC asking that the chairman of the NYPSC recuse himself from any consideration of NYSEG's Electric Rate Plan Extension filing and of NYSEG's proposed Retail Access Plan filed in April 2005. The motion maintains that the chairman's recusal is necessary because his public statements demonstrate that he is biased against NYSEG and its "Voice Your Choice" program, which would violate NYSEG's due process rights for a fair and impartial adjudication. The company is unable to predict when the chairman will decide on NYSEG's motion.

CMP Nuclear Costs: (See Energy East's report on Form 10-K for fiscal year ended December 31, 2004, Item 7, CMP Nuclear Costs.) In June 2004 the DPUC and OCC filed a petition with the FERC asking it to determine if any of Connecticut Yankee's decommissioning costs were not prudently incurred. The DPUC believes that the owners of Connecticut Yankee must bear all imprudently incurred costs. Connecticut Yankee and its owners, including CMP (CMP has a 6% ownership share), filed protests to contest that petition. In August 2004 the FERC rejected the DPUC's petition; approved a rate increase for Connecticut Yankee effective February 1, 2005, subject to refund; and set for hearing certain remaining issues. The DPUC requested rehearing of the FERC's August 2004 Order and on October 20, 2005, the FERC issued an order denying the request for rehearing. The DPUC has alleged that Connecticut Yankee imprudently managed and wrongfully terminated Bechtel Power Corporation (Bechtel), the turnkey decommission ing contractor, and as a result, concludes that approximately $225 to $235 million of Connecticut Yankee's rate increase should be denied. The FERC Staff and Bechtel also allege that the cost increase was imprudently incurred. Connecticut Yankee has filed testimony and briefs supporting its revised schedule of decommissioning costs. An initial decision from a FERC administrative law judge is expected in December 2005. The company is unable to predict the outcome of these proceedings.

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. RG&E's Electric Rate Agreement provides for that unbundling and for the commodity options. Effective January 2005 RG&E customers are annually being provided an opportunity to choose to purchase their commodity service 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 initially 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. Ab out 25% of RG&E's overall load is now served under that fixed price option. On October 4, 2005, RG&E customers began a new enrollment period to choose their commodity service for 2006. RG&E is unable to predict the outcome of the new enrollment period at this time.

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

Energy East Corporation

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 of 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 penalti es 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, in early February 2005, jointly filed with two other New York State utilities, a petition for rehearing that focuses on several areas including the impracticability of the timetable established in that 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 that it would provide some relief in the testing schedule. On July 21, 2005, the NYPSC issued an order detailing the revised requirements for stray voltage testing and reduced penalties during the first year to 37.5 basis points. N YSEG and RG&E have incurred costs of less than $2 million to date, including less than $1 million incurred by RG&E. RG&E estimates that it will incur costs of approximately $2 million by the end of 2005 and NYSEG estimates it will incur approximately another $4 million by the end of 2005 to comply with the order.

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.

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

Energy East Corporation

In August 2004 the NYPSC issued a Policy Statement 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 were required to prepare plans to foster the development of retail energy markets. The plans 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 proposed 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 allowing NYSEG to bill and collect from ESCO customers directly. This proposal is consistent with the commodity options included in NYSEG's recently filed Electric Rate Plan Extension.

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 and RG&E 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.

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 question whether the "PowerSwitch" 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 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.

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

Energy East Corporation

In a related matter, on July 26, 2005, the NYPSC issued a notice soliciting comments on an NYPSC Staff proposal on statewide guidelines for ESCO Referral Programs. As a result of experience gained since the Policy Statement was issued in August 2004, the NYPSC Staff has identified a need for statewide simplicity, consistency and uniformity, to the extent practicable in ESCO Referral Programs. In September and October 2005 NYSEG and RG&E filed comments urging rejection of the proposal and objecting to the proposal to the extent that it will require all utilities to adopt a "PowerSwitch" type program.

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.

RG&E Transmission Project: In September 2003 RG&E applied to the NYPSC for approval to upgrade its electric transmission system. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, NY area. The project's goal is to assure adequate service to customers after the planned closing of RG&E's 257 megawatt coal-fired Russell Station in 2007. In August 2005 RG&E selected the team of EPRO Engineering, E.S. Boulos and O'Connell Electric Company for the project. All approvals have been received and construction on the project is expected to begin in the first quarter of 2006 The estimated total cost of the project is $100 million.

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 CMP's formula rates for 2004 costs as well as its share of ISO New England reliability charges. That increase enables CMP to recover the 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. In a companion docket the FERC approved both a 50 basis point and a 100 basis point ROE incentive adder, but limited application of both adders to regional facilities, subject to suspension, hearing and application of the FERC's Pricing Policy Statement, when it is issued. The New England transmission owners have appealed the limited application of the adders to the Circuit Court of Appeals for the District of Columbia. Other parties have appealed the FERC's decision to grant the adders to regional facilities. The appeals are pending before the Court and no decision is expected until mid 2006. The FERC 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. Those rates became effective, subje ct to refund, February 1, 2005. The FERC conducted evidentiary hearings on the final base level ROE and the incentive for new transmission investment in January and February 2005, and issued an initial decision in May 2005 recommending a base level ROE of 10.72%, plus the 50 basis point adder for regional facilities. The New England transmission owners have filed exceptions to the initial decision both with respect to the base level ROE and also seeking application of the 100 basis point adder for new investments applicable to both the local and

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

Energy East Corporation

regional transmission rates. A final decision from the FERC on those issues is not expected until the end of 2005 or early 2006. 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 market participants on a retroactive basis when it determines that billing adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission or supply revenue or expense, as appropriate, when revised amounts can be estimated. The companies have developed an accrual process that incorporates reasonable estimates of retroactive NYISO billing adjustments as provided to all market participants. However, on an ongoing basis, the companies cannot fully predict either the magnitude or the direction of any final billing adjustments.

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 those requests for rehearing, on July 8, 2005 and October 7, 2005, the NYISO issued back billings that reflected the FERC order concerning the May 2000 issues. NYSEG's updated back billing relating to May 8 and 9, 2000, was approximately $2 million and RG&E's was approximately $1 million. In the third quarter of 2005 NYSEG and RG&E deferred, as regulatory mandates, the amounts associated with the back billings pursuant to their Electric Joint Proposals approved by the NYPSC.

Locational Installed Capacity Markets (LICAP): (See Energy East's report on Form 10-K for fiscal year ended December 31, 2004, Item 7, Locational Installed Capacity Markets.) The FERC administrative law judge in this proceeding issued a recommended decision in June 2005 essentially adopting the ISO New England LICAP market proposal with minor modifications. CMP and other parties that oppose the ISO New England LICAP market proposal filed exceptions to the recommended decision in July 2005. The Domenici-Barton Energy Policy Act of 2005 included a "sense of Congress" provision to the effect that the FERC should carefully consider the objections of the New England states to the LICAP proposal in the recommended decision. In addition, the MPUC, CMP, the DPUC representing the state of Connecticut and the OCC, joined with several Massachusetts parties and filed briefs with the FERC asking that the parties conduct settlement discussions to consider alternatives and that the FERC consider other alternatives to the LICAP market proposal. In response to these protests, the FERC has delayed any possible implementation of LICAP until October 1, 2006, at the earliest and granted oral arguments to consider opposition to LICAP and possible alternatives. During oral arguments with the FERC in September 2005, ISO New England reaffirmed its LICAP proposal. Following oral arguments, the FERC granted the request to conduct settlement discussions to consider alternatives. The discussions will begin in November 2005 and continue until a settlement is reached or January 31, 2006 ,whichever is earlier. CMP cannot predict the outcome of these settlement discussions, how the FERC will rule or what modifications the FERC might make to the filing.

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

Energy East Corporation

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 Regulatory Proceeding: SCG's IRP expired on September 30, 2005. As a result of the DPUC's decision to deny recovery of exogenous costs (see below), SCG filed a one-year rate case on April 29, 2005, requesting approximately $35 million of additional revenues, or an increase of approximately 11% compared with revenues based on current rates. Among other items, the rate filing requested greater recovery of deferred costs similar to SCG's request for recovery of exogenous costs.

On September 30, 2005, SCG filed an Amended Settlement Agreement in response to the DPUC's rejection on August 30, 2005, of SCG's Initial Settlement Agreement. The amended settlement agreement was filed jointly with the OCC and Prosecutorial Staff. The Amended Settlement Agreement includes a 10% ROE based on SCG's average rate base of approximately $397 million and calls for an annualized increase in revenue requirements for firm rates of approximately $24 million, beginning November 1, 2005. The rate increase includes approximately $5 million annually for six years for recovery of amounts previously deferred under SCG's Customer Hardship Arrearage Forgiveness Program and its Three-Way Payment Plan. The increase also includes approximately $12 million for uncollectible expense for all customers. Under the Amended Settlement Agreement, on-system interruptible margins in excess of an annual target will continue to be allocated through a margin sharing mechanism between SCG and its f irm customers. A portion of margins that SCG would have returned to customers will be redirected to fund SCG's hardship assistance programs. SCG expects that the DPUC will make a final decision on the Amended Settlement Agreement before the end of the year.

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. 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 decision. 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 above. SCG has agreed to withdraw its appeal pending before the Connecticut Superior Court within ten business days after the DPUC approves the Amended Settlement Agreement. SCG is not required to withdraw the appeal if the DPUC rejects the Amended Settlement Agreement.

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

Energy East Corporation

Hurricanes' Effects on Natural Gas:While none of Energy East's operating companies were directly affected by Hurricane Katrina or Hurricane Rita, the hurricanes' effects on natural gas supply and subsequent prices has affected the companies' customers. Natural gas prices have risen dramatically since the hurricanes struck the Gulf Coast in late August and September 2005.

In response to the increases in natural gas prices, NYSEG and RG&E filed a petition with the NYPSC on September 27, 2005, to create an emergency Financial Aid Fund for their low-income natural gas customers. NYSEG proposed to contribute $15.6 million to the fund and RG&E proposed to contribute $7 million for the benefit of thousands of customers. NYSEG and RG&E would make funds available from the systems benefit charge already being collected from all electric delivery customers. In addition, RG&E proposes to accelerate to early 2006 a $10 million refund from its ASGA, created as a result of the sale of Ginna, that is currently scheduled for 2007. On October 27, 2005, the NYPSC denied this petition for an emergency Financial Aid Fund.

The hurricanes' effect on natural gas prices has also increased the value of the company's derivative positions that it maintains to hedge natural gas prices for the benefit of customers. That increase in value is reflected on the company's and RG&E's balance sheets in the derivative assets and accumulated other comprehensive income (loss) line items. NYSEG, RG&E and Berkshire Gas 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 and passed on to customers when the related sales commitments are fulfilled.

The company is unable to predict what effect the sharp increase in natural gas prices may have on customer's energy consumption.

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 f inancial position, results of operations and cash flows, but does not expect that the effects will be material. (SeeNote 7 to the Condensed Financial Statements.)

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

Energy East Corporation

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 7 to the Condensed Financial Statements.)

Critical Accounting Estimates

(See Energy East's and RG&E's report on Form 10-K for the fiscal year ended December 31, 2004, Item 7, Critical Accounting Estimates.) During the third quarter of 2005, Energy East and RG&E revised their estimates of unbilled revenues and allowances for doubtful accounts. (See Note 9 to the Condensed Financial Statements.)

Unbilled Revenue: Unbilled revenues represent estimates of receivables for energy provided but not yet billed. The estimates are determined based on various assumptions, such as current month energy load requirements, billing rates by customer classification and delivery loss factors. Changes in those assumptions could significantly affect the estimates of unbilled revenues. During the third quarter of 2005, Energy East re-examined the set of estimates used for all the operating companies and determined that some operating companies required changes to the assumptions used in determining their unbilled revenue estimates.

Allowance for Doubtful Accounts: The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in existing accounts receivable, determined based on experience for each service region and operating segment and other economic data. Each month the operating companies review their allowance for doubtful accounts and past due accounts over 90 days and/or above a specified amount, and review all other balances on a pooled basis by age and type of receivable. When an operating company believes that a receivable will not be recovered, it charges off the account balance against the allowance. Energy East and its operating companies believe that estimates used in the calculation of the allowance for doubtful accounts represent "critical accounting estimates" because management is required to make assumptions about input factors such as economic conditions and customer receivables, which are inherently uncertain and susceptible to change from period to period, th e effect of which could be material.

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

Energy East Corporation

(a) Liquidity and Capital Resources

Operating Activities:Significant operating activities that affected liquidity and cash flows during the first nine months of 2005 include 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 to customers of $15 million in 2006 and $10 million in 2007.
• Contributions of $54 million to certain of the company's pension plans to bring those 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 increased by $79 million reflecting higher gas prices and additions to natural gas storage in preparation for the heating season.
• Accounts receivable declined by $136 million reflecting collections of higher winter bills.

Investing Activities: Capital spending for the nine months ended September 30, 2005, was $224 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 the years 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 nine months ended September 30, 2005, the company issued 598,138 shares of common stock, at an average price of $26.48 per share, through its Investor Services Program. The shares issued were original issue shares. Beginning in the fourth quarter of 2005 shares needed for the Investor Services Program will be purchased in the open market.

During the nine months ended September 30, 2005, the company awarded 265,406 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 $7 million based on the average market price of $26.42 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, each terminating its status as a registrant 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.

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

Energy East Corporation

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, $100 par value 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. In October 2005 CMP issued $15 million of Series F medium-term notes at 5.70% due in 2025 and $15 million of Series F medium-term notes at 5.875% due in 2035 to reduce short-term debt.

In June 2005 the company and its operating utilities replaced their existing revolving credit agreements with two new revolving credit facilities. The company 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 that provided maximum borrowings of up to $425 million in aggregate. In October 2005 the operating utilities' joint facility was increased to $475 million. 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. In October 2005 the maximum sublimits applicable to RG&E, CMP, CNG and SCG were increased. Both facilities have expiration dates in 2010 and require fees on undrawn borrowing capacity. 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 c ovenants 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 secured indebtedness that each borrower may maintain. No borrower is in default, or expected to be in default, under the applicable facility.

In September 2005 CNG issued $20 million of Series C medium-term notes at 5.63% due in 2035. The proceeds were used to reduce short-term debt. In October 2005 CNG issued $25 million of Series C medium-term notes at 5.84% due in 2035. The proceeds were used to fund working capital needs.

In September 2005 SCG redeemed at maturity $25 million of Series II medium-term notes with proceeds from the issuance of short-term debt. In October 2005 SCG issued $25 million of Series III medium-term notes at 5.78% due in 2025. The proceeds were used to fund working capital needs.

Energy East is anticipating the redemption, in the third quarter of 2006, of its $345 million 8.25% junior subordinated debt securities (junior debt) which are held by Energy East Capital Trust I. Energy East Capital Trust I will use the proceeds it receives on the redemption of the 8.25% junior debt to redeem its $345 million of 8.25% Capital Securities (mandatorily redeemable trust preferred securities). Energy East has entered into several hedge positions to fix the interest rate on securities to be issued to finance the redemption of the junior debt.

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

Energy East Corporation

(b)Results of Operations

Earnings per Share

Three months ended September 30,	2005	2004
(Thousands, except per share amounts)
Operating Revenues	$1,095,931	$967,806
Operating Income	$94,359	$94,661
Income from Continuing Operations	$21,324	$17,500
Net Income	$21,324	$15,973
Average Common Shares Outstanding, basic	147,008	146,385
Average Common Shares Outstanding, diluted	147,588	146,807
Earnings per Share from Continuing Operations, basic and diluted	$.14	$.12
Earnings per Share, basic and diluted	$.14	$.11
Dividends Paid per Share	$.275	$.26

Earnings per share from continuing operations for the quarter ended September 30, 2005, increased 2 cents compared to the quarter ended September 30, 2004, primarily because of:

• An increase of 10 cents per share due to higher margins on electricity sales resulting in part from electric commodity programs for New York customers. The higher margins include 3 cents per share due to a change in the estimate of unbilled revenues, net of customer earnings sharing, and
• An increase of 4 cents per share due to lower stock option expense.

Those increases were substantially offset by:

• A decrease of 12 cents per share due to higher operating and maintenance expenses, including approximately 6 cents per share for an increase to the allowance for doubtful accounts.

Nine months ended September 30,	2005	2004
(Thousands, except per share amounts)
Operating Revenues	$3,815,155	$3,488,100
Operating Income	$513,478	$592,987
Income from Continuing Operations	$193,055	$181,254
Net Income	$193,055	$174,591
Average Common Shares Outstanding, basic	146,895	146,207
Average Common Shares Outstanding, diluted	147,383	146,611
Earnings per Share from Continuing Operations, basic and diluted	$1.31	$1.24
Earnings per Share, basic and diluted	$1.31	$1.19
Dividends Paid per Share	$.825	$.78

Earnings per share from continuing operations for the nine months ended September 30, 2005, increased 7 cents compared to the nine months ended September 30, 2004, primarily because of:

• An increase of 22 cents per share due to higher margins on electric sales resulting in part from electric commodity programs for New York customers, and
• An increase of 6 cents per share due to lower stock option expense.

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

Energy East Corporation

Those increases were significantly offset by:

• One-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements that increased earnings 7 cents per share in 2004. The one-time effects include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory treatment, and
• A decrease of 15 cents per share resulting primarily from higher operating and maintenance expenses, including approximately 3 cents per share for storm-related repairs and maintenance, 3 cents per share for increases in the allowance for doubtful accounts, 3 cents per share for higher regional network services transmission costs, and 2 cents per share for increase in pension and other post-retirement benefits cost.

Operating Results for the Electric Delivery Business

Three months ended September 30,	2005	2004
(Thousands)
Retail Deliveries - Megawatt-hours	8,750	7,896
Operating Revenues	$778,982	$722,802
Operating Expenses	$663,546	$615,431
Operating Income	$115,436	$107,371

Operating Revenues:The $56 million increase in operating revenues for the third quarter of 2005 was primarily the result of:

• An increase of $55 million due to retail electric energy supplied by NYSEG and RG&E under various commodity options, primarily resulting from higher market prices for electricity. Higher prices became effective January 1, 2005, for customers who purchase commodity service from NYSEG or RG&E,
• An increase of $69 million in wholesale revenues. That increase includes $11 million resulting from higher prices on the sale of CMP's NUG entitlements that went into effect on March 1, 2005. The remainder resulted primarily from NYSEG's power supply activities, and sales of excess energy for RG&E, and
• An increase of $29 million resulting from higher retail deliveries due to warmer summer weather.

Those increases were partially offset by:

• A decrease of $54 million as a result of lower other electric revenues, including $31 million from accruals under NYSEG's and RG&E's earnings sharing provisions, $18 million from lower accruals by RG&E to reflect actual generation costs and $11 million from accruals in 2004 to offset temporary rate reductions, and
• A decrease of $44 million as a result of lower transition charges. The transition charge reflects the difference between the market price of electricity and the price allowed in NYSEG's and RG&E's long-term electricity supply contracts.

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

Energy East Corporation

Operating Expenses: The $48 million increase in operating expenses for the third quarter of 2005 was primarily the result of:

• An increase of $29 million in power purchases largely resulting from increased wholesale sales and higher prices for electric supply purchased for NYSEG's electric commodity customers,
• Increases in various other operating and maintenance expenses that totaled $15 million. Contributing to that increase were an increase in the allowances for doubtful accounts of approximately $8 million, higher pension expense of approximately $3 million and higher transmission-related expenses of $2 million. The increase in transmission expenses primarily resulted from regional cost increases that were allocated to all New England transmission owners; and
• An increase of $5 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 $21 million pretax gain partially offset by the after tax deferral of the gain of $16 million.

Nine months ended September 30,	2005	2004
(Thousands)
Retail Deliveries - Megawatt-hours	24,167	23,243
Operating Revenues	$2,234,930	$2,094,454
Operating Expenses	$1,846,042	$1,631,578
Operating Income	$388,888	$462,876

Operating Revenues:The $140 million increase in operating revenues for the nine months ended September 30, 2005, was primarily the result of:

• An increase of $62 million due to higher market prices for retail electric energy supplied by NYSEG and RG&E under various commodity options,
• An increase of $112 million in wholesale revenues which includes $26 million as a result of higher prices on the sale of CMP's NUG entitlements, effective March 1, 2005. The remainder resulted primarily from NYSEG's power supply activities, and sales of excess power by RG&E, and
• An increase of $33 million for increased retail deliveries.

Those increases were partially offset by:

• A decrease of $48 million resulting from lower transition charges. The transition charge reflects the difference between the market price of electricity and the price allowed in NYSEG's and RG&E's long-term electricity supply contracts, and
• A decrease of $18 million as a result of lower other electric revenues. A $43 million reduction resulted from accruals under NYSEG's and RG&E's earnings sharing provisions. This was partially offset by a $6 million accrual by CMP for a NUG restructuring incentive, and approximately $18 million in accruals by RG&E to reflect actual generation costs.

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

Energy East Corporation

Operating Expenses: The $214 million increase in operating expenses for the nine months ended September 30, 2005, was primarily the result of:

• An increase of $110 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 $341 million pretax gain partially offset by the after tax deferral of the gain of $231 million,
• A net increase of $1 million in operating expenses as a result of the sale of Ginna, reflecting an increase in purchased power costs of $63 million, substantially offset by decreases of $37 million in other operating and maintenance expenses, $21 million in depreciation and $4 million in other taxes,
• An increase of $72 million in power purchases largely resulting from increased wholesale sales and higher market prices for electric supply purchased for the New York electric commodity customers,
• An increase of $9 million from the second quarter 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 $23 million. Higher storm costs accounted for approximately $7 million of that increase, higher transmission-related expenses accounted for an additional $6 million, and higher pension and post-retirement benefits expense added another $4 million.

Operating Results for the Natural Gas Delivery Business

Three months ended September 30,	2005	2004
(Thousands)
Retail Deliveries - Dekatherms	26,445	25,555
Operating Revenues	$187,331	$156,216
Operating Expenses	$209,094	$175,413
Operating Loss	$(21,763)	$(19,197)

Operating Revenues:The $31 million increase in operating revenues for the third 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, and
• An increase of $5 million in other natural gas revenues.

Operating Expenses: The $34 million increase in operating expenses for the third quarter of 2005 was primarily the result of:

• An increase of $26 million due to higher prices for purchased natural gas costs, and
• An increase of $8 million in the allowance for doubtful accounts.

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

Energy East Corporation

Nine months ended September 30,	2005	2004
(Thousands)
Retail Deliveries - Dekatherms	149,888	149,104
Operating Revenues	$1,190,978	$1,078,222
Operating Expenses	$1,068,058	$964,604
Operating Income	$122,920	$113,618

Operating Revenues:The $113 million increase in operating revenues for the nine months ended September 30, 2005, was primarily the result of:

• An increase of $103 million as a result of higher prices of purchased natural gas that were passed on to customers, and
• An increase of $8 million in other natural gas revenues.

Operating Expenses: The $103 million increase in operating expenses for the nine months ended September 30, 2005 was primarily the result of:

• An increase of $93 million due to higher prices of purchased natural gas, and
• An increase of $9 million in other operating and maintenance costs, including $8 million related to an increase in the allowance for doubtful accounts.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation Condensed Statements of Income- (Unaudited)
	Three Months		Nine Months
Periods ended September 30,	2005	2004	2005	2004
(Thousands)
Operating Revenues
Electric	$207,984	$187,419	$527,041	$511,811
Natural gas	51,455	46,681	273,934	259,364
Total Operating Revenues	259,439	234,100	800,975	771,175
Operating Expenses
Electricity purchased and fuel used in generation	96,580	92,851	232,076	162,643
Natural gas purchased	26,191	24,956	168,918	159,130
Other operating expenses	55,046	44,838	130,669	155,927
Maintenance	12,653	11,709	35,424	39,390
Depreciation and amortization	17,373	19,510	52,856	71,152
Other taxes	17,293	17,205	49,117	56,173
Gain on sale of generation assets	-	(21,252)	-	(340,739)
Deferral of asset sale gain	-	16,414	-	230,783
Total Operating Expenses	225,136	206,231	669,060	534,459
Operating Income	34,303	27,869	131,915	236,716
Other (Income)	(1,136)	(610)	(3,150)	(8,710)
Other Deductions	1,775	(784)	2,043	(2,078)
Interest Charges, Net	13,473	13,992	42,217	41,791
Income before Income Taxes	20,191	15,271	90,805	205,713
Income Taxes	4,679	9,855	33,388	145,429
Net Income	15,512	5,416	57,417	60,284
Preferred Stock Dividends	-	(39)	-	1,789
Earnings Available for Common Stock	$15,512	$5,455	$57,417	$58,495

Thenotes on pages 32 through 43 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	Sept. 30,   2005	Dec. 31,   2004
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$74,761	$71,259
Accounts receivable, net	160,673	149,602
Fuel and natural gas in storage at average cost	56,296	38,955
Materials and supplies, at average cost	9,770	7,850
Accumulated deferred income tax benefits, net	7,278	15,344
Derivative assets	52,318	4,167
Prepayments and other current assets	28,230	19,552
Total Current Assets	389,326	306,729
Utility Plant, at Original Cost
Electric	1,252,755	1,231,128
Natural gas	568,337	557,472
Common	190,071	185,901
	2,011,163	1,974,501
Less accumulated depreciation	576,399	534,465
Net Utility Plant in Service	1,434,764	1,440,036
Construction work in progress	30,236	28,623
Total Utility Plant	1,465,000	1,468,659
Other Property and Investments, Net	12,254	12,649
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	189,564	209,345
Deferred income taxes	7,765	1,673
Unamortized loss on debt reacquisitions	15,177	10,979
Environmental remediation costs	4,981	11,814
Nonutility generator termination agreement	84,549	91,465
Other	135,844	143,638
Total regulatory assets	437,880	468,914
Other assets
Prepaid pension benefits	44,766	37,896
Other	18,669	25,275
Total other assets	63,435	63,171
Total Regulatory and Other Assets	501,315	532,085
Total Assets	$2,367,895	$2,320,122

Thenotes on pages 32 through 43 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	Sept. 30,   2005	Dec. 31,   2004
(Thousands)
Liabilities
Current Liabilities
Accounts payable and accrued liabilities	$81,467	$86,765
Interest accrued	8,169	9,294
Taxes accrued	16,264	12,448
Other	68,947	52,014
Total Current Liabilities	174,847	160,521
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	178,829	172,505
Unfunded future income taxes	97,593	101,873
Gain on sale of generation assets	114,517	139,229
Other	45,726	32,425
Total regulatory liabilities	436,665	446,032
Other liabilities
Deferred income taxes	198,786	180,696
Nuclear waste disposal	107,600	105,391
Other postretirement benefits	77,709	76,396
Environmental remediation costs	16,121	26,357
Other	61,053	48,786
Total other liabilities	461,269	437,626
Total Regulatory and Other Liabilities	897,934	883,658
Other long-term debt	697,932	697,465
Total Liabilities	1,770,713	1,741,644
Commitments and Contingencies	-	-
Common Stock Equity
Common stock	194,429	194,429
Capital in excess of par value	482,009	481,753
Retained earnings	6,977	19,560
Treasury stock, at cost	(117,238)	(117,238)
Accumulated other comprehensive income (loss)	31,005	(26)
Total Common Stock Equity	597,182	578,478
Total Liabilities and Stockholder's Equity	$2,367,895	$2,320,122

Thenotes on pages 32 through 43 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Cash Flows - (Unaudited)
Nine months ended September 30,	2005	2004
(Thousands)
Operating Activities
Net Income	$57,417	$60,284
Adjustments to reconcile net income to net cash provided by    operating activities
Depreciation and amortization	103,216	131,479
Income taxes and investment tax credits deferred, net	3,333	39,866
Income taxes related to gain on sale of generation assets	-	109,956
Gain on sale of generation assets	-	(340,739)
Deferral of asset sale gain	-	230,783
Pension income	(10,806)	(14,721)
Changes in current operating assets and liabilities
Accounts receivable	(5,109)	48,565
Inventory	(19,262)	(20,681)
Prepayments and other current assets	(3,888)	(19,780)
Accounts payable and accrued liabilities	19,099	(19,301)
Interest accrued	(1,126)	(3,675)
Taxes accrued	862	(58,323)
Customer refund	(25,329)	(58,219)
Other current liabilities	8,994	12,112
Other assets	(11,327)	(29,595)
Other liabilities	939	(43,573)
Net Cash Provided by Operating Activities	117,013	24,438
Investing Activities
Proceeds from sale of generation assets	-	453,678
Refund of excess decommissioning fund	-	76,593
Utility plant additions	(43,894)	(60,038)
Nuclear generating plant decommissioning fund	-	(8,560)
Other	(593)	586
Net Cash (Used in) Provided by Investing Activities	(44,487)	462,259
Financing Activities
Repayments of first mortgage bonds and preferred stock	-	(261,500)
Long-term note issuances	-	60,500
Book overdraft	976	18,027
Dividends on common and preferred stock	(70,000)	(171,789)
Net Cash Used in Financing Activities	(69,024)	(354,762)
Net Increase in Cash and Cash Equivalents	3,502	131,935
Cash and Cash Equivalents, Beginning of Period	71,259	17,302
Cash and Cash Equivalents, End of Period	$74,761	$149,237

Thenotes on pages 32 through 43 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Retained Earnings - (Unaudited)
Nine months ended September 30,	2005	2004
(Thousands)
Balance, Beginning of Period	$19,560	$121,032
Add net income	57,417	60,284
	76,977	181,316
Deduct Dividends on Capital Stock
Preferred	-	1,789
Common	70,000	170,000
	70,000	171,789
Balance, End of Period	$6,977	$9,527

Thenotes on pages 32 through 43 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Comprehensive Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30,	2005	2004	2005	2004
(Thousands)
Net income	$15,512	$5,416	$57,417	$60,284
Other comprehensive income, net of tax
Net unrealized gains on derivatives qualified    as hedges, net of income tax (expense) for the    three months of $(24,746) in 2005 and $- in    2004 and for the nine months of $(22,123) in    2005 and $- in 2004	37,313	- -	33,384	- -
Reclassification adjustment for derivative    (gains) included in net income, net of income    tax expense for the three months of $1,191 in    2005 and $- in 2004, and for the nine months    of $1,560 in 2005 and $- in 2004.	(1,796)	- -	(2,353)	- -
Total other comprehensive income (loss)	35,517	-	31,031	-
Comprehensive Income	$51,029	$5,416	$88,448	$60,284

Thenotes on pages 32 through 43 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.

RG&E Transmission Project: 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.

Hurricanes' Effects on Natural Gas: See Energy East's Part I, Item 2, Natural Gas Delivery Business, for this discussion.

(a)Liquidity and Capital Resources

Operating Activities: Cash flows from operating activities for the first nine 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 to customers of $15 million in 2006 and $10 million in 2007.

Investing Activities: Capital spending for the first nine months of 2005 was $44 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.

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

Rochester Gas and Electric Corporation

Financing Activities: During the nine months ended September 30, 2005, RG&E paid common dividends of $70 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 Gas are joint borrowers with RG&E. RG&E does not have any liability for any other joint borrower. In October 2005 the revolving credit facility was increased to $475 million and RG&E's maximum borrowing limit under the facility was increased from $90 million to $100 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 September 30,	2005	2004
(Thousands)
Operating Revenues	$259,439	$234,100
Operating Income	$34,303	$27,869
Earnings Available for Common Stock	$15,512	$5,455

RG&E's earnings for the quarter ended September 30, 2005, increased $10 million compared to the quarter ended September 30, 2004, primarily because of increased margins on electric deliveries of $10 million after tax. The increase includes $5 million resulting from a change in the estimate of unbilled revenues net of accruals for customer earnings sharing.

Nine months ended September 30,	2005	2004
(Thousands)
Operating Revenues	$800,975	$771,175
Operating Income	$131,915	$236,716
Earnings Available for Common Stock	$57,417	$58,495

RG&E's earnings for the nine months ended September 30, 2005, decreased less than $1 million compared to the nine months ended September 30, 2004. Improved results for the electric operating segment due to higher margins on electric deliveries of $10 million discussed above were offset by the effects of one-time benefits of $10 million experienced in 2004 as a result of the sale of Ginna and the approval of the Electric and Natural Gas Rate Agreements.

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

Rochester Gas and Electric Corporation

Operating Results for the Electric Delivery Business

Three months ended September 30,	2005	2004
(Thousands)
Retail Deliveries - Megawatt-hours	2,311	1,840
Operating Revenues	$207,984	$187,419
Operating Expenses	$172,642	$157,279
Operating Income	$35,342	$30,140

Operating Revenues:The $21 million increase in operating revenues for the third quarter of 2005 was primarily the result of:

• An increase of $37 million due to higher wholesale revenues,
• An increase of $41 million due to higher market prices for retail electric energy supplied under various commodity options, and
• An increase of $14 million resulting from higher retail deliveries due to warmer summer weather.

Those increases were partially offset by:

• A decrease of $41 million resulting from lower average prices on deliveries. Higher market prices for electric entitlements are passed through to customers through lower transition charges and
• A decrease of $30 million in other revenues, including $15 million from accruals for customer earnings sharing.

Operating Expenses: The $15 million increase in operating expenses for the third quarter of 2005 was primarily the result of:

• An increase of $5 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 $21 million pretax gain partially offset by the after tax deferral of the gain of $16 million,
• An increase of $4 million for higher purchased power costs, and
• An increase of $6 million for an increase in the bad debt expense related to last year as a result of a reduction to the allowance for doubtful accounts in 2004.

Nine months ended September 30,	2005	2004
(Thousands)
Retail Deliveries - Megawatt-hours	5,799	5,278
Operating Revenues	$527,041	$511,811
Operating Expenses	$426,331	$304,862
Operating Income	$100,710	$206,949

Operating Revenues:The $15 million increase in operating revenues for the nine months ended September 30, 2005, was primarily the result of:

• An increase of $26 million in wholesale sales,
• An increase of $25 million due to higher market prices for retail electric energy under various commodity options, and
• An increase of $13 million for higher delivery volume.

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

Rochester Gas and Electric Corporation

Those increases were partially offset by:

• A decrease of $34 million resulting from lower transition charges, and
• A decrease of $14 million in other revenues, reflecting higher accruals for customer earnings sharing.

Operating Expenses: The $121 million increase in operating expenses for the nine months ended September 30, 2005, was primarily the result of:

• An increase of $110 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 $341 million pretax gain partially offset by the after tax deferral of the gain of $231 million,
• A net increase of $1 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, substantially offset by reductions of $37 million in other operating and maintenance expenses, $21 million in depreciation and $4 million in 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.

Operating Results for the Natural Gas Delivery Business

Three months ended September 30,	2005	2004
(Thousands)
Retail Deliveries - Dekatherms	5,219	5,150
Operating Revenues	$51,455	$46,681
Operating Expenses	$52,494	$48,952
Operating Loss	$(1,039)	$(2,271)

Operating Revenues:The $5 million increase in operating revenues for the third quarter of 2005 was primarily the result of higher natural gas purchase costs that were passed on to customers.

Operating Expenses: The $4 million increase in operating expenses for the third quarter of 2005 was primarily the result of:

• Higher natural gas purchase costs, and
• An increase in the bad debt expense related to last year as a result of a reduction to the allowance for doubtful accounts in 2004.

Nine months ended September 30,	2005	2004
(Thousands)
Retail Deliveries - Dekatherms	37,407	37,828
Operating Revenues	$273,934	$259,364
Operating Expenses	$242,729	$229,597
Operating Income	$31,205	$29,767

Operating Revenues:The $15 million increase in operating revenues for the nine months ended September 30, 2005, was primarily the result of:

• An increase of $19 million due to higher natural gas purchase costs that were passed on to customers.

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

Rochester Gas and Electric Corporation

Those increases were partially offset by:

• A decrease of $4 million due to lower sales primarily due to lower usage per customer.

Operating Expenses: The $13 million increase in operating expenses for the nine months ended September 30, 2005, was primarily the result of:

• An increase of $10 million due to $19 million for higher natural gas purchase costs partially offset by lower volumes, and
• An increase of $2 million for other taxes.

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, 14
RG&E	1, 2, 3, 5, 7, 9, 10, 11, 12, 13, 14

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		Nine Months
Periods ended September 30,	2005	2004	2005	2004
(Thousands)
Energy East
Interest and dividend income	$(5,265)	$(5,356)	$(10,160)	$(7,568)
Allowance for funds used during construction	(392)	(161)	(1,070)	(423)
Gains on hedge activity	2,697	(1,902)	(5,875)	(1,756)
Gains from the sale of nonutility property	-	(543)	-	(1,166)
2004 RG&E Electric and Natural Gas    Rate Agreement	- -	- -	- -	(6,117)
Earnings from equity investments	(1,270)	(880)	(3,207)	(3,482)
Miscellaneous	(1,811)	(1,032)	(4,792)	(6,782)
Total other (income)	$(6,041)	$(9,874)	$(25,104)	$(27,294)
Losses from disposition of nonutility property	-	$(1,105)	$36	$1,178
Losses from hedge activity	$(7,753)	347	(574)	(71)
Donations, civic and political	616	503	2,284	863
Miscellaneous	2,500	2,823	4,820	5,035
Total other deductions	$(4,637)	$2,568	$6,566	$7,005
RG&E
Interest and dividend income	$(1,318)	$(637)	$(2,627)	$(1,475)
Allowance for funds used during construction	(45)	(44)	(144)	(85)
2004 RG&E Electric and Natural Gas    Rate Agreement	- -	- -	- -	(6,117)
Gains on hedge activity	247	-	(502)	-
Miscellaneous	(20)	71	123	(1,033)
Total other (income)	$(1,136)	$(610)	$(3,150)	$(8,710)
Losses from hedge activity	$137	$(336)	$353	$(416)
Miscellaneous	1,638	(448)	1,690	(1,662)
Total other deductions	$1,775	$(784)	$2,043	$(2,078)

Note 3. Income Taxes

The company's effective tax rate of 33% for the quarter ended September 30, 2005, differed from the expected annual effective tax rate of 40% for 2005 primarily as a result of an approximately $3 million benefit from a change in estimate of prior year income taxes to reflect actual 2004 taxes as filed and a settlement of the 2000-2001 IRS audit. The company has provided for taxes for the nine months ended September 30, 2005, at the expected annual effective tax rate.

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

RG&E's effective tax rate of 23% for the quarter ended September 30, 2005, differed from the expected annual effective tax rate of 38% for 2005 primarily as a result of a $1 million change in estimate of prior year income taxes to reflect actual 2004 taxes as filed and an approximately $2 million revision to the estimated taxes to reflect a revised effective tax rate for 2005. RG&E has provided for taxes for the nine months ended September 30, 2005, at the expected annual effective tax rate.

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

Note 4. 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		Nine Months
Periods ended September 30,	2005	2004	2005	2004
(Thousands)
Basic average common shares outstanding	147,008	146,385	146,895	146,207
Restricted stock awards	580	422	488	404
Potentially dilutive common shares	333	355	301	312
Options issued with SARs	(333)	(355)	(301)	(312)
Dilutive average common shares outstanding	147,588	146,807	147,383	146,611

Options to purchase shares of common stock are excluded from the determination of EPS when the exercise price of an option is greater than the average market price of a common share during the period. Shares excluded from the EPS calculation for the three months ended September 30 were: less than $0.1 million in 2005 and 1.2 million in 2004, and for the nine months ended September 30 were: 0.4 million in 2005 and 1.2 million in 2004.

During the nine months ended September 30, 2005, the company awarded 265,406 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 $7 million based on the average market price of $26.42 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 5. 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 Energy East's and RG&E's statements of income for the six months ended June 30, 2004. On September 9, 2004, RG&E received an additional $25 million from CGG for post closing adjustments. As a result, Energy East's and RG&E's statements of income reflect a gain on the sale of Ginna of $21 million for the three months ended September 30, 2004, and $341 million for the nine months ended September 30, 2004. The total deferral of the asset sale gain, after related taxes of $110 million, is $231 million for the nine months ended September 30, 2004.

RG&E's Electric Rate Agreement resolved all regulatory and ratemaking aspects related to the sale of Ginna, including providing for an ASGA of $378 million after the post closing adjustments, and addressing the disposition of the asset sale gain. Upon closing of the sale of Ginna, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. RG&E retained $77 million in excess decommissioning funds, which were credited to customers as part of the ASGA.

Note 6. 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 nine months ended September 30, 2005.

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

Periods ended September 30, 2004,	Three Months	Nine Months
(Thousands)
Component of Energy East Solutions, Inc.
Revenues	$7,643	$48,988
Loss from operations of component held for sale	$(113)	$(539)
Income taxes (benefits)	(43)	(206)
Loss from discontinued operations	$(70)	$(333)
Certain Divisions of Union Water Power Co.
Revenues	$(19)	$13,156
Loss from operations of discontinued business   (including loss on disposal of $5,500 for the nine months)	$(557)	$(5,084)
Income taxes	276	622
Loss from discontinued operations	$(833)	$(5,706)
Griffith Oil Co., Inc.
Revenues	-	-
Loss from operations of discontinued business	-	-
Income taxes	$624	$624
Loss from discontinued operations	$(624)	$(624)
Totals from discontinued operations
Total Revenues	$7,624	$62,144
Total loss from operations of discontinued businesses	$(670)	$(5,623)
Total income taxes	857	1,040
Total loss from discontinued operations	$(1,527)	$(6,663)

Note 7. 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 duringwhich 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 September 30 was: three months: $1.4 million for 2005 and $1.1 million for 2004; and nine months: $4.2 million for 2005 and $2.8 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 September 30 was: three months: $1.3 million for 2005 and $0.8 million for 2004; and nine months: $5.8 million for 2005 and $4.8 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 will have a material effect on its financial position, results of operations or cash flows.

Note 8. 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 $283 million for the nine months ended September 30, 2005, and approximately $274 million for the nine months ended September 30, 2004.

Note 9. Accounts Receivable

Energy East's accounts receivable include consolidated unbilled revenues of $143 million at September 30, 2005, and $227 million at December 31, 2004, and are shown net of an allowance for doubtful accounts of $41 million at September 30, 2005, and $45 million at December 31, 2004.

RG&E's accounts receivable include unbilled revenues of $32 million at September 30, 2005, and $40 million at December 31, 2004, and are shown net of an allowance for doubtful accounts of $13 million at September 30, 2005, and $21 million at December 31, 2004.

Unbilled revenues represent estimates of receivables for energy provided but not yet billed. The estimates are determined based on various assumptions, such as current month energy load requirements, billing rates by customer classification and loss factors. Changes in those assumptions could significantly affect the estimates of unbilled revenues. During the third quarter of 2005, Energy East re-examined the set of estimates used for all the operating companies and determined that some operating companies required changes to the assumptions used in determining their unbilled revenue estimates. Those changes increased the estimated unbilled revenues for September 30, 2005, by approximately $16 million for Energy East and approximately $17 million for RG&E.

The allowance for doubtful accounts is the best estimate of the amount of probable creditlosses in existing accounts receivable, determined based on experience for each region and operating segment and other economic data. Each month the operating companies review their allowance for doubtful accounts and past due accounts over 90 days and/or above a specified amount, and review all other balances on a pooled basis by age and type of receivable. When an operating company believes that a receivable will not be recovered, it charges off the account balance against the allowance. Changes in assumptions about input factors such as economic conditions and customer receivables, which are inherently uncertain and susceptible to change from period to period, could significantly affect the allowance for doubtful accounts estimates. Due to increases in natural gas prices, revised collection data, and other economic factors, Energy East and its operating co mpanies reviewed their estimates and some companies revised their allowance for doubtful accounts for September 30, 2005. Energy East increased its consolidated allowance by $10 million for September 30, 2005.

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. RG&E did not adjust its allowance in the third quarter of 2005.

Note 10. Retirement Benefits

Components of net periodic benefit cost

	Pension Benefits		Postretirement Benefits
Three months ended September 30,	2005	2004	2005	2004
(Thousands)
Energy East
Service cost	$8,487	$8,028	$1,444	$1,462
Interest cost	31,839	32,746	7,681	8,221
Expected return on plan assets	(53,406)	(51,530)	(563)	(573)
Amortization of transition (asset) obligation	-	(308)	1,700	2,000
Amortization of prior service cost	1,212	1,163	(1,894)	(1,711)
Recognized net actuarial (gain) loss	3,984	(268)	2,156	574
Net periodic benefit cost	$(7,884)	$(10,169)	$10,524	$9,973
RG&E
Service cost	$572	$1,234	$(11)	$258
Interest cost	7,330	7,435	1,133	1,513
Expected return on plan assets	(9,820)	(12,136)	-	-
Unrecognized transition obligation	-	-	443	529
Amortization of prior service cost	553	306	144	285
Recognized net actuarial (gain)	(416)	(1,788)	(267)	(66)
Net periodic benefit cost	$(1,781)	$(4,949)	$1,442	$2,519

	Pension Benefits		Postretirement Benefits
Nine months ended September 30,	2005	2004	2005	2004
(Thousands)
Energy East
Service cost	$26,534	$24,083	$4,331	$4,712
Interest cost	95,838	98,238	23,040	26,590
Expected return on plan assets	(160,509)	(154,590)	(1,686)	(1,909)
Amortization of transition (asset) obligation	-	(923)	5,100	6,001
Amortization of prior service cost	3,711	3,488	(5,683)	(5,135)
Recognized net actuarial (gain)	11,916	(803)	6,472	4,369
Net periodic benefit cost	$(22,510)	$(30,507)	$31,574	$34,628
RG&E
Service cost	$3,250	$3,974	$533	$773
Interest cost	20,936	22,337	4,021	4,540
Expected return on plan assets	(33,861)	(36,728)	-	-
Unrecognized transition obligation	-	-	1,371	1,588
Amortization of prior service cost	1,112	937	644	856
Recognized net actuarial (gain) loss	(2,243)	(5,241)	(2)	(198)
Net periodic benefit cost	$(10,806)	$(14,721)	$6,567	$7,559

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

Note 11. 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 and determined that there was no impairment of goodwill and/or unamortized intangible assets at September 30, 2005.

The carrying amounts of goodwill, by operating segment, were the same at September 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 September 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 September 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 September 30, 2005, and $15 million at December 31, 2004. Estimated amortization expense for intangible assets for the next five years is approximately $3 million for 2005 and approximately $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 September 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 12. Commitments and Contingencies

NYISO billing adjustment: The NYISO frequently bills market participants on a retroactive basis when it determines that billing adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission or supply revenue or expense as appropriate when revised amounts can be estimated. The companies have developed an accrual process that incorporates reasonable estimates of retroactive NYISO billing adjustments as provided to all market participants. However, on an ongoing basis, the companies cannot fully predict either the magnitude or the direction of any final billing adjustments.

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 those requests for rehearing, on July 8, 2005 and October 7, 2005, the NYISO issued back billings that reflected the FERC order concerning the May 2000 issues. NYSEG's updated back billing relating to May 8 and 9, 2000 was approximately $2 million and RG&E's was approximately $1 million. In the third quarter of 2005 NYSEG and RG&E deferred, as regulatory mandates, these amounts associated with the back billings pursuant to their Electric Joint Proposals approved by the NYPSC.

Note 13. RG&E Related-Party Transactions

Utility Shared Services Corporation and Energy East Management Corporation provide various administrative and management services to Energy East's operating companies, including RG&E, pursuant to service agreements. The cost of those services is allocated in accordance with cost allocation methodologies set forth in the service agreements. The cost allocation methodologies vary depending on the type of service provided. These intercompany transactions are eliminated in consolidation and no profit results from the transactions. The cost for services provided by Utility Shared Services Corporation and Energy East Management Corporation that were directly charged or allocated to RG&E for the periods ended September 30 were: for the three months approximately $4 million in 2005 and $5 million in 2004, and for the nine months approximately $15 million in 2005 and $18 million in 2004.

Note 14. 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" 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
September 30, 2005
Operating Revenues    Energy East    RG&E	$778,982  $207,984	$187,331  $51,455	$129,618  - -	$1,095,931  $259,439
Net Income (Loss)    Energy East    RG&E	$40,932  $16,292	$(25,868) $(780)	$6,260  - -	$21,324  $15,512
September 30, 2004
Operating Revenues    Energy East    RG&E	$722,802  $187,419	$156,216  $46,681	$88,788  - -	$967,806  $234,100
Net Income (Loss)    Energy East    RG&E	$35,473  $7,063	$(24,771) $(1,647)	$5,271  - -	$15,973  $5,416
Nine months ended
September 30, 2005
Operating Revenues    Energy East    RG&E	$2,234,930  $527,041	$1,190,978  $273,934	$389,247  - -	$3,815,155  $800,975
Net Income    Energy East    RG&E	$147,411  $42,767	$39,287  $14,650	$6,357  - -	$193,055  $57,417
September 30, 2004
Operating Revenues    Energy East    RG&E	$2,094,454  $511,811	$1,078,222  $259,364	$315,424  - -	$3,488,100  $771,175
Net Income    Energy East    RG&E	$140,488  $48,206	$26,220  $12,078	$7,883  - -	$174,591  $60,284
Total Assets
September 30, 2005    Energy East    RG&E	$7,164,113  $1,704,884	$3,969,345  $663,011	$318,812  - -	$11,452,270  $2,367,895
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 October 31, 2005, NYSEG's load was fully hedged for on-peak periods and 91% hedged for off-peak periods for November through December 2005. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings less than $75 thousand for November through December 2005. As of October 31, 2005, NYSEG's load was fully hedged for on and off-peak periods for 2006. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings approximately $250 thousand for 2006. The percentage of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

RG&E's 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 October 31, 2005, RG&E's load was fully hedged for November through December 2005. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings less than $50 thousand for November through Decem ber 2005. As of October 31, 2005, RG&E's load was hedged 84% for on-peak periods and 96% hedged for off-peak periods for 2006. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings approximately $150 thousand for 2006. 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 and actively hedge the load required to serve customers that have chosen them as an option. As of October 31, 2005, the energy marketing subsidiaries fixed price load was 99.7% hedged for 2005 and 97.6% hedged for 2006. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings less than $2 thousand for 2005 and less than $30 thousand for 2006. The percentage of hedged loads for the energy marketing subsidiaries 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.

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 and 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 and actively hedge the load required to serve customers that have chosen them as an option. As of October 31, 2005, the energy marketing subsidiaries fixed price load was 100% hedged for 2005 and 2006. The percentage of hedged load for the energy marketing subsidiaries 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.

The company's Other Comprehensive Income for the nine months ended September 30, 2005, was $296 million. That amount primarily represents the increase in value of the company's derivative positions for future commodity purchases and is the result of price changes for electricity and natural gas in the wholesale market. The increase during the third quarter of 2005 is primarily attributable to the rise in energy prices due to the effects of hurricanes that struck the Gulf Coast of the United States in August and September 2005. Since the company's derivative positions are used only for hedging the price of its load requirements for customers that have chosen a fixed price rate option and the cost of natural gas that is ultimately passed on to customers, Other Comprehensive Income for the three months and nine months will have no effect on future net income.

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 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 either 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   (July 1, 2005 to    July 31, 2005)	1,506		(1)	$28.85		- -		- -
Month #2   (August 1, 2005 to    August 31, 2005)	6,718		(2)	$27.40		- -		- -
Month #3   (September 1, 2005 to    September 30,   2005)	8,191		(1)	$26.57		- -		- -
Total	16,415			$27.23		-		-

(1) Represents shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan.

(2) Includes 2,987 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 3,731 shares of the company's common stock (Par Value $.01) that were withheld to satisfy tax withholding obligations upon vesting of shares of restricted stock awarded through the company's Restricted Stock Plan.

RG&E had no issuer purchases of equity securities during the nine months ended September 30, 2005.

Item 6.  Exhibits

SeeExhibit Index.

Signatures

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

Date: November 3, 2005	ENERGY EAST CORPORATION                   (Registrant) By  /s/ Robert D. Kump                                                     Robert D. Kump            Vice President, Controller & Chief Accounting Officer            (Principal Accounting Officer)
Date: November 3, 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	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	10-28	Power Purchase Agreement between Constellation Power Source, Inc. and Rochester Gas and Electric Corporation dated as of November 24, 2003.
	31-1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	*32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

_________________________________

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