Rochester Gas & Electric 10-Q 2006 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, 2006

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 (800) 743-2110	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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Registrant	Large accelerated        filer	Accelerated         filer	Non-accelerated        filer
Energy East Corporation	X
Rochester Gas and Electric Corporation			X

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

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

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

As of October 31, 2006, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	147,707,223
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 representation as to information relating to the other registrant.

	Table of Contents	Page
	Glossary	ii
	Forward-looking Statements	iv
	PART I - FINANCIAL INFORMATION
Item 1. Item 2.	Financial Statements (Unaudited) 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 IncomeManagement's Discussion and Analysis of Financial Conditionand Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	1 2 4 5 5 6 15 17
	Rochester Gas and Electric Corporation   Condensed Balance SheetsCondensed Statements of IncomeCondensed Statements of Cash FlowsCondensed Statements of Retained EarningsCondensed Statements of Comprehensive IncomeManagement's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	22 24 25 26 26 27 28 29
Item 1.	Notes to Condensed Financial Statements	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	43
	PART II - OTHER INFORMATION
Item 1	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 6.	Exhibits	44
Signatures		45
Exhibit Index		46

Glossary

Abbreviations for the Energy East companies mentioned in this report:
Berkshire GasThe Berkshire Gas Company is a regulated utility primarily engaged in the distribution of natural gas in western Massachusetts. Berkshire Gas is a wholly-owned subsidiary of Berkshire Energy Resources. CMPCentral Maine Power Company is a regulated utility primarily engaged in transmitting and distributing electricity generated by others to retail customers in Maine. CMP is a wholly-owned subsidiary of CMP Group, Inc. CNGConnecticut Natural Gas Corporation is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut. CNG is a wholly-owned subsidiary of CTG Resources, Inc. Energy East, the company, we, ouror usEnergy East Corporation is the parent company of RGS Energy Group, Inc., Connecticut Energy Corporation, CMP Group, Inc., CTG Resources, Inc., Berkshire Energy Resources, The Energy Network and Energy East Enterprises.	NYSEGNew York State Electric & Gas Corporation is a regulated utility primarily engaged in purchasing and delivering electricity and natural gas in the central, eastern and western parts of the state of New York. NYSEG is a wholly-owned subsidiary of RGS Energy Group, Inc. RG&ERochester Gas and Electric Corporation is a regulated utility primarily engaged in generating, purchasing and delivering electricity and purchasing and delivering natural gas in an area centered around the city of Rochester, New York. RG&E is a wholly-owned subsidiary of RGS Energy Group, Inc. SCGThe Southern Connecticut Gas Company is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut. SCG is a wholly-owned subsidiary of Connecticut Energy Corporation.
Abbreviations or acronyms frequently used in this report:
AFUDCallowance for funds used during construction ALJAdministrative Law Judge APB 25Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ARP 2000Alternative Rate Plan 2000 ASGAAsset Sale Gain Account Dth dekatherm DPUCConnecticut Department of Public Utility Control Electric Rate AgreementElectric portion of RG&E's 2004 Electric and Natural Gas Rate Agreements	ESCOenergy service company FASBFinancial Accounting Standards Board FERCFederal Energy Regulatory Commission FIN 48 FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 GinnaRobert E. Ginna Nuclear Power Plant, a nuclear power plant sold by RG&E in June 2004 IRPIncentive Rate Plan ISO-NEISO New England Inc. MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations

Glossary (continued)

MPUCMaine Public Utilities Commission

MW, MWh megawatt, megawatt hour

NEPOOL New England Power Pool

NMP2 Nine Mile Point 2 nuclear
generating station

NUGnonutility generator

NYISONew York Independent
System Operator

NYPANew York Power Authority

NYPSCNew York State Public
Service Commission

NYSDECNew York State Department of Environmental Conservation

OrderTheNYPSC order in NYSEG's
Electric Rate Plan Extension proceeding

Policy Statement NYPSC Statement of
Policy on Further Steps Toward Competition
in Retail Energy Markets

ROEreturn on equity

RTORegional Transmission Organization

SARstock appreciation right

SECUnited States Securities and
Exchange Commission

Statement 87 Statement of Financial Accounting Standards No. 87,Employers' Accounting
for Pensions


Statement 88 Statement of Financial Accounting Standards No. 88,Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits

Statement 106 Statement of Financial Accounting Standards No. 106,Employers' Accounting for Postretirement Benefits Other Than Pensions

Statement 109 Statement of Financial Accounting Standards No. 109,Accounting for Income Taxes

Statement 123Statement of Financial
Accounting Standards No. 123,Accounting
for Stock-Based Compensation

Statement 123(R)Statement of Financial
Accounting Standards No. 123 (revised 2004),Shared-Based Payment

Statement 132(R) Statement of Financial Accounting Standards No. 132 (revised 2003),Employers' Disclosures about Pensions and Other Postretirement Benefits - an amendment of FASB Statements No. 87, 88, and 106

Statement 157 Statement of Financial Accounting Standards No. 157,Fair Value Measurements

Statement 158 Statement of Financial Accounting Standards No. 158,Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)

TCCtransmission congestion contract

Voice Your ChoiceRG&E's and NYSEG's electric commodity option programs

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 that could cause actual results to differ materially from those contemplated in any forward-looking statements are discussed in our Form 10-K for the fiscal year ended December 31, 2005, Item 1A - Risk Factors and Item 7 - MD&A - Market Risk, and also include, among others:

• the deregulation and continued regulatory unbundling of a formerly vertically integrated utility industry,
• our ability to compete in the rapidly changing and increasingly competitive electric and/or natural gas utility markets,
• regulatory uncertainty in a politically-charged environment of escalating and volatile energy prices,
• implementation of the NYPSC's Order in NYSEG's Electric Rate Plan Extension proceeding,
• the effects of the NYPSC End State model experiment adopted in its Collaborative on End State of Energy Competition,
• implementation of the Energy Policy Act of 2005,
• increased state and FERC regulation of, among other things, intercompany cost allocations,
• the operation of the NYISO,
• the operation of ISO-NE as an RTO,
• our continued ability to recover NUG and other costs,
• changes in fuel supply or cost and the success of strategies to satisfy power requirements,
• our ability to expand our products and services including our energy infrastructure in the Northeast,
• the effect of rapidly increasing commodity costs on customer usage and uncollectible expense,
• our ability to achieve and maintain enterprise-wide integration synergies,
• market risk from changes in value of financial or commodity instruments, derivative or nonderivative, caused by fluctuations in interest rates or commodity prices,
• our ability to obtain adequate and timely rate relief and/or the extension of current rate plans,
• the possible discontinuation of fixed-price supply programs in the state of New York,
• nuclear decommissioning or environmental incidents,
• legal or administrative proceedings,
• changes in the cost or availability of capital,
• economic growth in the areas in which we do business,
• extreme weather-related events such as floods, hurricanes, ice storms or snow storms,
• weather variations affecting customer energy usage,
• authoritative accounting guidance,
• acts of terrorism,
• the effect of the volatility in the equity and fixed income markets on the cost of pension and other postretirement benefits,
• the inability of our 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 our publicly disseminated documents and filings.

We 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,	2006	2005	2006	2005
(Thousands, except per share amounts)
Operating Revenues
Utility	$969,093	$966,313	$3,512,196	$3,425,908
Other	121,261	128,870	386,594	386,508
Total Operating Revenues	1,090,354	1,095,183	3,898,790	3,812,416
Operating Expenses
Electricity purchased and fuel used in generation
Utility	401,603	398,874	1,133,153	1,112,400
Other	95,060	97,965	268,686	258,409
Natural gas purchased
Utility	97,469	104,323	779,902	746,609
Other	7,709	12,068	61,043	69,904
Other operating expenses	202,677	212,404	590,015	578,781
Maintenance	57,509	51,155	153,723	145,216
Depreciation and amortization	69,921	67,451	209,385	203,493
Other taxes	58,495	56,584	190,625	184,126
Total Operating Expenses	990,443	1,000,824	3,386,532	3,298,938
Operating Income	99,911	94,359	512,258	513,478
Other (Income)	(9,873)	(13,931)	(27,183)	(26,747)
Other Deductions	12,332	3,253	20,480	8,209
Interest Charges, Net	76,818	72,718	230,681	214,736
Preferred Stock Dividends of Subsidiaries	283	283	847	1,191
Income Before Income Taxes	20,351	32,036	287,433	316,089
Income Taxes	(661)	10,712	104,896	123,034
Net Income	$21,012	$21,324	$182,537	$193,055
Earnings per Share, basic and diluted	$.14	$.14	$1.24	$1.31
Dividends Declared and Paid per Share	$.29	$.275	$.87	$.825
Average Common Shares Outstanding, basic	146,903	147,008	146,946	146,895
Average Common Shares Outstanding, diluted	147,702	147,588	147,686	147,383
Thenotes on pages 32 through 41 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	Sept. 30, 2006	Dec. 31, 2005
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$107,090	$120,009
Investments available for sale	42,900	192,925
Accounts receivable and unbilled revenues, net	691,327	933,680
Fuel and natural gas in storage, at average cost	295,972	278,590
Materials and supplies, at average cost	34,950	33,886
Deferred income taxes	47,611	-
Derivative assets	12,526	278,855
Prepayments and other current assets	243,709	92,613
Total Current Assets	1,476,085	1,930,558
Utility Plant, at Original Cost
Electric	5,501,997	5,403,134
Natural gas	2,635,772	2,574,574
Common	532,790	450,641
	8,670,559	8,428,349
Less accumulated depreciation	2,878,087	2,764,399
Net Utility Plant in Service	5,792,472	5,663,950
Construction work in progress	91,968	119,504
Total Utility Plant	5,884,440	5,783,454
Other Property and Investments	183,050	203,159
Regulatory and Other Assets
Regulatory assets
Deferred income taxes	-	13,482
Nuclear plant obligations	278,843	309,888
Unfunded future income taxes	201,519	117,241
Environmental remediation costs	139,627	135,376
Unamortized loss on debt reacquisitions	54,674	60,933
Nonutility generator termination agreements	81,928	86,890
Natural gas hedges	56,712	-
Other	311,620	384,173
Total regulatory assets	1,124,923	1,107,983
Other assets
Goodwill	1,526,048	1,525,353
Prepaid pension benefits	764,744	741,831
Derivative assets	50,135	67,907
Other	116,533	127,463
Total other assets	2,457,460	2,462,554
Total Regulatory and Other Assets	3,582,383	3,570,537
Total Assets	$11,125,958	$11,487,708
Thenotes on pages 32 through 41 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	Sept. 30, 2006	Dec. 31, 2005
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$116,741	$326,527
Notes payable	177,330	121,347
Accounts payable and accrued liabilities	373,335	629,158
Interest accrued	56,668	46,522
Taxes accrued	25,056	-
Deferred income taxes	-	80,984
Derivative liabilities	77,357	2,019
Customer refund	70,715	14,698
Other	165,862	171,754
Total Current Liabilities	1,063,064	1,393,009
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	834,945	797,544
Deferred income taxes	39,386	-
Gain on sale of generation assets	130,881	173,216
Pension benefits	18,385	22,798
Natural gas hedges	-	49,205
Other	88,396	124,251
Total regulatory liabilities	1,111,993	1,167,014
Other liabilities
Deferred income taxes	1,051,880	1,033,287
Nuclear plant obligations	209,774	234,907
Other postretirement benefits	432,181	428,691
Environmental remediation costs	172,276	166,462
Other	477,410	499,968
Total other liabilities	2,343,521	2,363,315
Total Regulatory and Other Liabilities	3,455,514	3,530,329
Debt owed to subsidiary holding solely parent debentures	-	355,670
Other long-term debt	3,799,095	3,311,395
Total long-term debt	3,799,095	3,667,065
Total Liabilities	8,317,673	8,590,403
Commitments and Contingencies
Preferred Stock of Subsidiaries  Redeemable solely at the option of subsidiaries	24,592	24,631
Common Stock Equity  Common stock	1,478	1,478
Capital in excess of par value	1,499,479	1,489,256
Retained earnings	1,349,239	1,294,580
Accumulated other comprehensive (loss) income	(64,881)	89,085
Treasury stock, at cost	(1,622)	(1,725)
Total Common Stock Equity	2,783,693	2,872,674
Total Liabilities and Stockholders' Equity	$11,125,958	$11,487,708
Thenotes on pages 32 through 41 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Nine months ended September 30,	2006	2005
(Thousands)
Operating Activities
Net income	$182,537	$193,055
Adjustments to reconcile net income to net cash  provided by operating activities
Depreciation and amortization	309,663	285,313
Income taxes and investment tax credits deferred, net	20,881	40,150
Pension income	(22,553)	(22,510)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	241,423	136,133
Inventory	(18,446)	(78,672)
Prepayments and other current assets	(106,813)	(43,259)
Accounts payable and accrued liabilities	(257,963)	53,487
Interest accrued	10,146	15,535
Taxes accrued	(16,662)	5,607
Customer refund	(15,486)	(25,329)
Other current liabilities	(34,592)	52,755
Pension contributions	(400)	(54,000)
Other assets	(13,395)	23,416
Other liabilities	(37,569)	(23,439)
Net Cash Provided by Operating Activities	240,771	558,242
Investing Activities
Utility plant additions	(266,678)	(224,426)
Other property additions	(1,468)	(805)
Other property sold	-	548
Maturities of current investments available for sale	1,005,365	1,236,105
Purchases of current investments available for sale	(855,340)	(1,368,150)
Investments	20,203	14,909
Net Cash Provided by (Used in) Investing Activities	(97,918)	(341,819)
Financing Activities
Issuance of common stock	-	2,425
Repurchase of common stock	(6,107)	(7,524)
Book overdraft	19,769	17,838
Redemption of preferred stock   of subsidiary, including premium	(39)	(22,260)
Long-term note issuances	552,148	315,000
Long-term note repayments	(649,648)	(302,774)
Notes payable three months or less, net	48,683	(80,968)
Notes payable issuances	78,560	19,500
Notes payable repayments	(71,260)	(15,000)
Dividends on common stock	(127,878)	(107,705)
Net Cash Used in Financing Activities	(155,772)	(181,468)
Net (Decrease) Increase in Cash and Cash Equivalents	(12,919)	34,955
Cash and Cash Equivalents, Beginning of Period	120,009	111,465
Cash and Cash Equivalents, End of Period	$107,090	$146,420
Thenotes on pages 32 through 41 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Nine months ended September 30,	2006	2005
(Thousands)
Balance, Beginning of Period	$1,294,580	$1,201,533
Add net income	182,537	193,055
	1,477,117	1,394,588
Deduct dividends on common stock	127,878	121,119
Balance, End of Period	$1,349,239	$1,273,469
Thenotes on pages 32 through 41 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Net income	$21,012	$21,324	$182,537	$193,055
Other comprehensive income, net of tax
Net unrealized gains on investments, net of    income tax (expense) for the three months of    $(653) in 2006 and $(38) in 2005 and for the nine    months of $(629) in 2006 and $(38) in 2005	986	77	949	73
Minimum pension liability adjustment net of income    tax benefit for the three months of $552 in 2006, and    $- in 2005 and for the nine months of $1,214 in 2006    and $7 in 2005	(841)	- -	(1,838)	(11)
Unrealized (losses) gains on derivatives qualified as    hedges, net of income tax benefit (expense) for the    three months of $34,077 expense in 2006 and    $(175,750) in 2005 and for the nine months of    $105,888 in 2006 and $(182,033) in 2005	(50,718)	265,966	(164,194)	281,957
Reclassification adjustment for (gains) losses    included in net income, net of income tax expense    (benefit) for the three months of $9,057 in 2006 and    $11,744 in 2005 and for the nine months of $(7,296)    in 2006 and $(9,026) in 2005	(13,656)	(17,770)	11,117	13,633
Net unrealized (losses) gains on derivatives qualified    as hedges	(64,374)	248,196	(153,077)	295,590
Total other comprehensive (loss) income	(64,229)	248,273	(153,966)	295,652
Comprehensive (Loss) Income	$(43,217)	$269,597	$28,571	$488,707
Thenotes on pages 32 through 41 are an integral part of our 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, our electric and natural gas utility operations, are subject to rate regulation established predominately by state utility commissions. The approved regulatory treatment on various matters significantly affects our financial position, results of operations and cash flows. We have long-term rate plans for NYSEG's natural gas segment, RG&E, CMP and Berkshire Gas that currently 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. Where long-term rate plans are not in effect, we monitor the adequacy of rate levels and file for new rates when necessary. NYSEG's current electric rate plan expires December 31, 2006, and new rates will go into effect in 2007. SCG received approval for new rates that became effective January 1, 2006, and CNG recently filed for new rates.

We continue to focus our strategic efforts in the areas that have the greatest effect on customer satisfaction and shareholder value. NYSEG implemented a new customer care system in the first quarter of 2006 and RG&E implemented a similar system in October 2006.

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 our operations and rates that our customers pay for energy, although their outcomes are difficult to predict. Those proceedings, some of which are discussed below, could affect the nature of the electric and natural gas utility industries in New York State and New England.

The continued evolution of the electric utility industry is evidenced by the enactment of the 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 have new authority to regulate and monitor, among other things, intercompany cost allocations of holding companies such as Energy East.

We engage in various investing and financing activities to meet our strategic objectives. Our primary goal for investing activities is to maintain a reliable energy delivery infrastructure. We fund our investing activities primarily with internally generated funds. We plan to invest nearly $2 billion in our energy delivery infrastructure over the next five years, including approximately $900 million dedicated to electric reliability. The $900 million includes $260 million for CMP's five-year construction plan to enhance transmission reliability and service. We expect those investments will be FERC-regulated and we expect them to qualify for FERC's ROE incentive adders. (See New England RTO.) We focus our financing activities on maintaining adequate liquidity and credit quality and minimizing our cost of capital.

Our MD&A for the quarter and nine months ended September 30, 2006, should be read in conjunction with our MD&A, financial statements and notes contained in our report on Form 10-K for the fiscal year ended December 31, 2005. Due to the seasonal nature of our operations, financial results for interim periods are not necessarily indicative of trends for the annual period.

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

Energy East Corporation

Strategy

We have maintained a consistent energy delivery and services strategy over the past several years, focusing on the safe, secure and reliable transmission and distribution of electricity and natural gas. We have sold a majority of our noncore businesses and our regulated generation assets and we continue to invest in infrastructure that supports our electric and natural gas delivery systems. Achieving operating excellence and efficiencies throughout the company is central to our strategy.

Our long-term rate plans are a critical component of our success. While specific provisions may vary among our public utility subsidiaries, our overall strategy includes creating stable rate environments that allow those subsidiaries to earn a fair return while minimizing price increases and sharing achieved savings with customers. We presently offer the most comprehensive commodity programs in New York State, providing a full menu of electricity supply choices, including a fixed price option for customers who do not want to be subject to volatile wholesale electricity prices. However, the NYPSC recently denied our proposal to extend the long-term rate plan for NYSEG's electric segment, and approved a one-year rate plan that will reduce NYSEG's earnings in 2007 and limit NYSEG's ability to offer customer options for supply in 2007 and beyond. (See NYSEG Electric Rate Order and Other Proceedings in the NYPSC Collaborative on End State of Energy Competition.)

Electric Delivery Business Developments

Our electric delivery business consists primarily of our regulated electricity transmission, distribution and generation operations in upstate New York and Maine.

NYSEG Electric Rate Order: In September 2005 NYSEG filed a six-year Electric Rate Plan Extension with the NYPSC, to commence on January 1, 2007, which is the day after the end of its current rate plan. NYSEG's Electric Rate Plan Extension, as subsequently amended, proposed, beginning on January 1, 2007, to reduce the nonbypassable wires charge by $168 million and increase delivery rates by $104 million, thereby resulting in an annualized overall electricity delivery rate decrease of $64 million, or 8.6%. NYSEG proposed to accomplish the reduction in its nonbypassable wires charge by accelerating benefits from certain expiring above-market NUG contracts and capping the amount of above-market NUG costs over the term of the rate plan extension (referred to as NYSEG's NUG levelization proposal). NYSEG also proposed to increase its equity ratio from 45% to 50%. In addition, NYSEG's proposal would allow customers to continue to benefit from merger synergies and savings.

In early February 2006 Staff of the NYPSC (Staff) and six other parties submitted their direct cases. Staff presented only a one-year rate case. In its presentation, Staff proposed a delivery rate decrease of approximately $83 million, or about 13.4%. Staff neither rebutted nor addressed NYSEG's revised and updated rate plan extension proposal, including its NUG levelization proposal and opposed NYSEG's proposal to extend its Voice Your Choice program. Staff also raised several retroactive accounting issues that will be addressed in a future proceeding and, if accepted by the NYPSC, would have a material effect on earnings.

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

Energy East Corporation

On August 23, 2006, the NYPSC issued the Order, which included the following provisions:

• A decrease in delivery rates of $36 million. NYSEG's most recent update in the proceeding requested a $58 million increase in delivery rates.

• A 9.55% ROE. NYSEG had requested an 11% ROE.

• An equity ratio of 41.6% based on Energy East's consolidated capital structure. NYSEG had requested a 50% equity ratio based on its stand-alone capital structure.

• A refund of $77 million to be paid from NYSEG's ASGA and will not affect earnings. The ASGA was initially created as a result of the sale of NYSEG's generating stations and has been enhanced during NYSEG's current electric rate plan with the customers' share of earnings from the earnings sharing mechanism. Payment of the refund is expected to be made through a credit to customers' bills in the first quarter of 2007.

• One issue raised by Staff concerns $57 million of interest associated with NYSEG's internal other post employment benefits (OPEB) reserve, which NYSEG has offset against other OPEB costs in its income statement over the past decade. The NYPSC determined that $3.6 million in annual revenues that NYSEG receives will remain temporary pending further examination of the NYSEG's accounting for OPEB costs. A proceeding related to this issue will begin in the fourth quarter of 2006 and could result in NYSEG treating all or a portion of the $57 million as an addition to its internal OPEB reserve, with a corresponding charge to income.

• Significant modifications to NYSEG's commodity options program, including:

-  Use of the variable rate supply option as the default for all customers not making a supply election, as opposed to the current fixed price default option.

-  A reduction in the allowance, from 35% to 24% of the calendar year 2007 market price, used to set the supply rate to cover the costs of providing fixed price electricity at retail.

-  The use of an earnings collar for supply of plus or minus $5 million with 80%/20% (customers/shareholders) sharing outside the collar. NYSEG currently can earn 300 basis points ROE on supply (approximately $21 million) after which earnings are shared 50%/50%.

NYSEG believes that the commodity options program in the Order is unworkable and inconsistent with the development of a competitive retail market for supply. In particular, NYSEG believes that the lower allowance used to set the supply rate does not cover the cost and risk of providing fixed price electricity at retail and will likely stifle participation by retail energy service providers.

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

Energy East Corporation

The Order will have a significant adverse effect on NYSEG's financial condition and results of operations. NYSEG believes that the Order provides an inadequate ROE and ignored millions of dollars of forecasted expenses, which will force NYSEG to adjust operating, maintenance and capital spending, and is likely to result in workforce reductions and degradation in current levels of customer service. It also excludes from rate base $8.5 million of costs related to system implementation to facilitate integration activities, which treatment, if upheld, would require an impairment of these assets. Any impairment would be partially offset by lower accruals under the earnings sharing mechanism.

On September 7, 2006, NYSEG filed a petition with the NYPSC for rehearing and request for oral argument responding to certain aspects of the Order including the disallowance of system implementation costs. NYSEG is also considering an appeal to a state appellate court and filing a new electric rate case in 2007.

Flood Damage in NYSEG's Service Territory: A major flood affected certain regions of NYSEG's service territory beginning on June 27, 2006, resulting in extensive damage. Pursuant to the terms of its current electric and natural gas rate plans, NYSEG will defer for future cost recovery substantially all incremental operating and maintenance costs, net of insurance proceeds, resulting from the flooding. As of September 2006, NYSEG's costs incurred to recover from the flood were $8 million, of which $6 million was deferred for future recovery.

RG&E Dispute Settlement Related to NMP2 Exit Agreement: In November 2001 RG&E and three other NMP2 joint owners, including Niagara Mohawk Power Corporation (Niagara Mohawk), sold their interests in NMP2 to Constellation Nuclear, LLC. In connection with the sale of NMP2, RG&E informed Niagara Mohawk that RG&E's payment obligations and rights to certain TCCs would cease according to the terms of an exit agreement executed by RG&E and Niagara Mohawk in June 1998. Niagara Mohawk disagreed with RG&E's position, claiming that RG&E must continue to make annual payments that were to decline from about $7 million per year in 2002 to $4 million per year in 2007, and remain at that level until 2043. In August 2001, RG&E filed a complaint asking the New York State Supreme Court, Monroe County, to find that, as a result of the sale of its interest in NMP2, RG&E has no further obligation to make payments under t he exit agreement and that the TCCs to which RG&E was entitled under the exit agreement should be returned to and accepted by Niagara Mohawk.

In the first quarter of 2006, RG&E and Niagara Mohawk stayed the litigation and entered into confidential mediation with the support of the NYPSC. On June 29, 2006, the parties executed a settlement agreement that provides for RG&E's one-time payment of $34 million to Niagara Mohawk and further provides that RG&E retains the rights and obligations related to the TCCs until 2043, including the value accumulated to date of approximately $4 million. The settlement agreement was contingent upon the fulfillment of certain closing conditions, including FERC acceptance of an amendment to and restatement of the exit agreement. All of the necessary closing conditions were fulfilled, including a favorable judgement from the FERC, and RG&E made the required payment. In accordance with the 2001 settlement and order associated with the transfer of RG&E's share of NMP2 to Constellation Nuclear and RG&E's Electric Rate Agreement, RG&E adjusted its regulatory asset established as a res ult of the sale of NMP2 for the amount of the $34 million payment to Niagara Mohawk, which was offset by the accumulated TCC amount of approximately $4 million and will be adjusted by any future TCC amounts. RG&E's results of operations were not affected by the settlement of this dispute.

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

Energy East Corporation

Threatened Litigation for Russell Station: In October 1999 RG&E received a letter from the New York State Attorney General's office alleging that RG&E may have constructed and operated major modifications to the Beebee and Russell generating stations without obtaining the required prevention of significant deterioration or new source review permits. The letter requested that RG&E provide the Attorney General's office with a large number of documents relating to this allegation. In January 2000 RG&E received a subpoena from the NYSDEC ordering production of similar documents. RG&E supplied documents and complied with the subpoena.

The NYSDEC served RG&E with a notice of violation in May 2000 alleging that between 1983 and 1987 RG&E completed five projects at Russell Station, scheduled to be shut down in 2007, and two projects at Beebee Station, which is currently shut down, without obtaining the appropriate permits. RG&E believes it has complied with the applicable rules and there is no basis for the Attorney General's and the NYSDEC's allegations. Beginning in July 2000 the NYSDEC, the Attorney General and RG&E had a number of discussions with respect to the resolution of the notice of violation. RG&E, the NYSDEC and the Attorney General last discussed this matter in August 2005. In October 2006 the Attorney General's office and the NYSDEC notified RG&E of their intention to file a complaint in federal court for violations at Russell Station unless a settlement can be reached. RG&E is not able to predict the outcome of this matter.

Niagara Power Project Relicensing: The NYPA's FERC license with respect to the Niagara Power Project expires on August 31, 2007. In order to continue to operate the Niagara Power Project, the NYPA filed a relicensing application in August 2005. The NYPA's relicensing process is important to NYSEG's and RG&E's customers because an aggregate of over 360 MWs of Niagara Power Project power has been allocated to the companies based on their contracts with the NYPA. (NYSEG and RG&E also receive allocations from the St. Lawrence Project pursuant to those same contracts.) The contracts expire on August 31, 2007, upon termination of the NYPA's FERC license. The annual value of the Niagara allocation to the companies at current electricity market prices is approximately $100 million and the loss of the allocation would increase NYSEG's and RG&E's residential customer rates. However, the NYPA has stated that the allocation of Niagara Power Project power to NYSEG and RG&E shoul d not be addressed in the relicensing proceeding and that the disposition of the power will be in accordance with state and federal requirements.

NYSEG and RG&E filed a motion in November 2005 to intervene in the relicensing proceeding and in December 2005 submitted comments arguing that the FERC should (1) consider power allocation issues (including to NYSEG and RG&E) in its review of the application (2) require the NYPA to update the record with information concerning the benefits of the allocation to NYSEG and RG&E customers and (3) require the NYPA to meet with NYSEG and RG&E to discuss their allocations and the effects on their customers of the withdrawal of the allocations. In January 2006 the NYPA answered those comments, arguing that the FERC should ignore certain issues that NYSEG and RG&E raised and that allocation issues are not an appropriate question in the relicensing proceeding. NYSEG and RG&E filed a response to NYPA's answer in January 2006, and continue to be active participants in the proceeding. NYSEG and RG&E are unable to predict the outcome of this proceeding.

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

Energy East Corporation

CMP Alternative Rate Plan:In December 2005 CMP and the Office of the Public Advocate filed with the MPUC a stipulation for an extension of CMP's ARP 2000. The stipulation was also supported by low-income customer advocates, and a coalition of industrial energy customers signed the stipulation agreement. The stipulation maintained the provisions of CMP's ARP 2000

and proposed a three-year extension with four additional items. The stipulation provided for a 0.5% increase in the scheduled productivity offset of 2.75% for July 2006 and provided for productivity offsets averaging 2% for 2008, 2009 and 2010. The stipulation included an additional $2.2 million in assistance for low-income customers annually starting in 2006. Under the stipulation, CMP agreed to educate its customers on the regional benefits of adjusting usage during peak hours and demand periods and also agreed to limit the promotion of increased usage during specified higher demand periods. Finally, CMP agreed to commit to investing an additional $25 million through 2010 for enhancements to the reliability, safety and security of its distribution system.

In February 2006 the MPUC approved that portion of the stipulation increasing assistance to low-income customers for one year. On April 28, 2006, the Staff of the MPUC filed its analysis and recommendations with the MPUC commissioners, opposing the stipulation other than the portion that was implemented. CMP and the stipulating parties responded to the Staff's recommendations in a brief filed on May 19, 2006. On June 5, 2006, the MPUC determined that the stipulation as proposed was not in the public interest and on June 21, 2006, the MPUC agreed to dismiss the proceeding at the request of the stipulating parties. CMP will continue to operate under the terms of ARP 2000, which expires in December 2007.

CMP Nuclear Costs: CMP owns shares of stock in three companies that own nuclear generating facilities in New England that have been permanently shut down, and are decommissioned or in process of being decommissioned: Maine Yankee Atomic Power Company (38% ownership), Connecticut Yankee Atomic Power Company (6% ownership) and Yankee Atomic Electric Power Company (9.5% ownership). (See report on Form 10-K for Energy East for the fiscal year ended December 31, 2005, Item 7 - MD&A, Electric Delivery Business Developments.)

Pursuant to a FERC approved settlement, in July 2004 Connecticut Yankee filed for FERC approval of a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of decommissioning costs. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars and result in annual collections of $93 million from Connecticut Yankee's owners, including CMP. The revised estimate reflects increases in the projected costs for spent fuel storage, security, liability and property insurance and the fact that Connecticut Yankee had to take over all work to complete the decommissioning of the plant due to its termination of its contract with Bechtel, the turnkey decommissioning contractor, in July 2003. On August 11, 2006, Connecticut Yankee filed a Settlement Agreement supported by all parties, including the FERC trial staff, that resolved all of the issues contested and will allow Connecticut Yankee to collect the increased decommissioning costs. The revised decommissioning charges will be collected in wholesale rates effective January 1, 2007, until December 2015. FERC approval of the Settlement Agreement is pending.

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

Energy East Corporation

On September 30, 2006, the U.S. Court of Federal Claims issued a favorable ruling for the three Yankee companies in their litigation with the federal government over its failure to remove spent nuclear fuel from the three former nuclear power plant sites. In the ruling, Yankee Atomic was awarded $33 million in damages for costs through 2001, Connecticut Yankee was awarded $34 million for costs through 2001, and Maine Yankee was awarded $76 million for costs through 2002. CMP's sponsor-weighted share of the award is approximately $34 million. Since spent nuclear fuel continues to be stored at the sites, the Yankee companies will have the opportunity to recover more damages in future lawsuits. The federal government is expected to appeal the decision, which would delay any damage awards. Any awards ultimately received would be credited to the Yankee companies' respective electric ratepayer-funded, decommissioning or spent fuel trust funds. CMP cannot predict the ultimate outcome of th is matter.

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: NYSEG and RG&E have 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. is flawed, since it results in customers being switched to ESCOs without complete information on the program. 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 are suspect and should not be used as a basis to expand the program to other utilities. In June 2005 the NYPSC approved Central Hudson Gas & Electric Corporation's retail access plan and rejected NYSEG's and RG&E's comments requesting the NYPSC to not take action on Central Hudson's plan and to suspend the development of new reta il access initiatives that are based on what NYSEG and RG&E believe are flawed models.

In a related matter, in July 2005, the NYPSC issued a notice soliciting comments on a 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 objecting to the proposal to the extent that it will require all utilities to adopt a "PowerSwitch" type program. In a December 2005 order the NYPSC established procedures for utilities to follow in implementing ESCO Referral Programs based on the Orange & Rockland model, as modified and enhanced with additional consumer protection measures. The NYPSC has approved ESCO Referral Programs for Orange & Rockland, Central Hudson, Niagara Mohawk Power Corporation, Consolidated Edison Company of New York, Inc., and National Fuel Gas Di stribution Corporation. Pursuant to an NYPSC order, RG&E has initiated a collaborative with interested parties for the purpose of RG&E implementing an ESCO Referral Program. They are discussing the effects such a program would have on RG&E's Voice Your Choice program. On September 1, 2006, RG&E filed its proposal for the ESCO referral plan parameters. The NYPSC required NYSEG to implement an ESCO Referral Program as part of its Order in the electric rate plan extension proceeding described above. NYSEG filed its proposal for the ESCO referral program parameters on October 23, 2006. (See NYSEG Electric Rate Order.)

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

Energy East Corporation

New England RTO: In March 2004 the FERC issued an order that accepted a six-state New England RTO as proposed by ISO-NE and the New England transmission owners. The RTO began operations effective February 1, 2005. As an RTO, ISO-NE is responsible for the independent operation of the regional transmission system and regional wholesale energy market. The transmission owners retain ownership of their transmission facilities and control over their revenue requirements. The FERC also approved both a 50 basis point ROE incentive adder for regional transmission facilities subject to RTO control and a 100 basis point ROE incentive adder for new regional transmission facilities developed by an RTO. The New England transmission owners appealed the application of the adders to local facilities to the Circuit Court of Appeals for the District of Columbia. Other parties appealed the FERC's decision to grant the adders to regional facilities. On June 30, 2006, the Court denied the appeals and upheld t he FERC's decisions. On October 31, 2006, the FERC issued an Opinion and Order on Initial Decision establishing the ROE applicable to the RTO, including CMP's transmission system. The October 31 Order adopts a base-level ROE of 10.2 percent, with three adjustments as follows: a 50 basis point incentive for RTO participation; a 100 basis point incentive for new transmission investment; and, a 74 basis point adjustment reflecting updated bond data, as applicable to the period commencing with the date of the Order. The resulting ROEs for existing transmission are 10.7 percent for the period February 1, 2005 through October 31, 2006 and 11.4 percent for the going-forward period. The ROEs that will apply to new transmission include the 100 basis point adjustment and are 11.7 percent prior to the date of the Order and 12.4 percent for the going-forward period. Parties can seek rehearing within 30 days of the Order and can appeal the final Order. The Company cannot predict the outcome of these proceedings. (See rep ort on Form 10-K for Energy East for the fiscal year ended December 31, 2005, Item 7 - MD&A, Electric Delivery Business Developments.)

Locational Installed Capacity Markets: In 2003 the FERC required ISO-NE to file a proposed mechanism to implement, by January 1, 2006, location or deliverability requirements in the installed capacity or resource adequacy market to ensure that generators that provide capacity within areas of New England are appropriately compensated for reliability. In response, in 2004 ISO-NE developed and filed with the FERC a market proposal based on an administratively set demand curve (previously referred to as locational installed capacity or LICAP). In June 2005 the FERC ALJ issued an initial decision, essentially adopting the ISO-NE market proposal, with minor modifications.

CMP and other parties that oppose the ISO-NE market proposal filed exceptions to the recommended decision in July 2005. The 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 proposal in the recommended decision. Following oral arguments, the FERC granted the request to conduct settlement discussions to consider alternatives. Settlement discussions began in November 2005 and in January 2006 the settlement ALJ reported to the FERC that most of the parties had reached an agreement in principle on an alternative. The alternative would provide fixed transitional capacity payments from 2006 until 2010 and provide capacity payments based on a Forward Capacity Market Auction thereafter. CMP opposed this settlement agreement because of the cost of the transition payments to electric customers in Maine. The ISO-NE and a majority of NEPOOL participants supported the settlement agreement. That altern ative has been filed with the FERC as a component of a comprehensive settlement agreement.

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

Energy East Corporation

Although, CMP objects to certain elements of the settlement agreement, it elected not to file opposing comments with the FERC. The MPUC, among other parties, filed comments opposing the settlement agreement, because the proposal could have an adverse effect on Maine's economy by increasing its generation supply rates, including standard offer rates, by an estimated 5% to 10%. On June 15, 2006, the FERC issued an order accepting the settlement agreement without modification. The MPUC and other parties opposed to the settlement agreement filed a request with the FERC asking it to reconsider its June 15 order. If the opposing parties' efforts to prevent the alternative resource adequacy market are unsuccessful, any resulting increase in costs associated with regional installed capacity will be reflected in Maine consumers' generation supply rates beginning in December 2006. On October 31, 2006, the FERC issued an Order on Rehearing and Clarification denying requests for rehearing and affirming its approval o f the settlement agreement. Parties can appeal the FERC order and CMP cannot predict the outcome of these proceedings.

MPUC Inquiries into Long-Term Utility Contracting and New England RTO: Maine lawmakers enacted legislation in 2006 that requires the MPUC to conduct an inquiry concerning whether or not CMP and other Maine electric utilities should continue to participate in the New England RTO, as operated by the ISO-NE. That legislation also requires the MPUC to conduct further inquiry regarding regional energy markets and generation deregulation. Among the actions initiated by such legislation is an MPUC inquiry into the development of a Maine electric resource adequacy plan and the use of long-term generating capacity contracts between utilities and capacity suppliers as a mechanism to support such a plan. The MPUC's inquiry is expected to lead to further proceedings, including the development of implementing rules and a series of reports to the Maine Legislature. The long-term contracting rules and the first report on resource adequacy will be submitted to the legislature for further action in early 200 7. In a related inquiry, the MPUC will consider whether it believes that Maine's transmission and distribution utilities should continue to participate in the New England RTO. This inquiry will consider the legal authority, the costs and benefits of and alternatives to an RTO, and will result in a report to the Maine Legislature. CMP will participate in these MPUC proceedings and cannot predict the outcome of these inquiries.

Natural Gas Delivery Business Developments

Our natural gas delivery business consists of our regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Massachusetts and Maine.

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: See Electric Delivery Business Developments.

CNG Regulatory Proceeding:In March 2005 CNG responded to a DPUC request pertaining to CNG's IRP that subsequently expired on September 30, 2005, indicating that CNG's existing rates would continue in effect after the expiration of the IRP, but the earnings sharing mechanism, the rate stay-out commitment, the exogenous cost provision and provisions involving merger-enabled gas cost savings would no longer be applicable.

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

Energy East Corporation

On March 21, 2006, the DPUC notified CNG that it had initiated a general rate review of CNG pursuant to Connecticut General Statutes, which state that the DPUC must conduct a financial review or require a rate case every four years. On September 29, 2006, CNG submitted a general rate filing, requesting a net rate increase of $28.2 million, or 7.9%, in base delivery revenues effective April 1, 2007, based on an 11.0% ROE. The requested increase includes $6.7 million for increased bad debt expense, including a hardship program, $5.6 million for sharing of achieved management efficiencies and $4.3 million to offset lower normalized customer usage.

New Accounting Standards

The FASB released FIN 48 in July 2006 and issued Statements 157 and 158 in September 2006. See Item 1, Note 8 to our financial statements for information concerning the new accounting standards.

(a) Liquidity and Capital Resources

Operating Activities:Significant operating activities that affected cash flows during the nine months ended September 30, 2006, included the following:

• A reduction in accounts payable of $258 million that reduced cash primarily due to payments for natural gas and electricity purchases,
• Decreased receivables that increased cash by $241 million,
• Payments of $169 million to counterparties in derivative contracts representing both refunds of amounts held at year end and current collateral obligations, and
• The payment of $34 million by RG&E to resolve a dispute with Niagara Mohawk. (See RG&E Dispute Settlement Related to NMP2 Exit Agreement.)

The Order in NYSEG's electric rate case requires a $77 million refund to customers funded from the ASGA. That refund is currently expected to be paid as bill credits in the first quarter of 2007. Other aspects of the Order will reduce earnings and, therefore cash flow, and may affect NYSEG's credit ratings and increase its costs of borrowing, but should not have other effects on liquidity.

Investing Activities: Capital spending for the nine months ended September 30, 2006, was $267 million. We project capital spending of $442 million in 2006, including $53 million for an RG&E transmission project, and expect to pay for it principally with internally generated funds. (See report on Form 10-K for Energy East for the fiscal year ended December 31, 2005, Item 7- MD&A, Electric Delivery Business Developments, RG&E Transmission Project.) Capital spending is primarily for the extension of energy delivery service, necessary improvements to existing facilities, and compliance with environmental requirements and governmental mandates, and includes the transmission project and a new customer care system.

Cash flows from investing activities include proceeds from the liquidation of auction rate securities which are recorded as current investments available for sale. We use auction rate securities in a manner similar to cash equivalents and the amount invested in such securities will increase as short-term funds are available. Our investments in auction rate securities have decreased during the year as a result of the operational activities discussed above.

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

Energy East Corporation

Financing Activities: The financing activities discussed below include those activities necessary for us and our principal subsidiaries to maintain adequate liquidity and credit quality and ensure access to capital markets. Activities include maintenance of credit facilities and various medium-term and long-term debt arrangements.

We repurchased 250,000 shares of our common stock in February 2006, primarily for grants of restricted stock. In the nine months ended September 30, 2006, we awarded 272,733 shares of our common stock, issued out of our treasury stock, to certain employees through our Restricted Stock Plan, at a weighted-average grant date fair value of $24.75 per share of common stock awarded.

Beginning in the fourth quarter of 2005 and continuing through the third quarter of 2006, instead of issuing new shares, we purchased shares of our common stock in the open market for dividends reinvested and optional cash purchases through our Investor Services Program (ISP). Therefore, during the nine months ended September 30, 2006, cash outflows for dividends equal the amount of our dividends as shown on our retained earnings statement. In the fourth quarter of 2006, we resumed issuing new shares through our ISP.

In January 2006 CMP issued $10 million of Series F medium-term notes at 5.27%, due in 2016, and $30 million of Series F medium-term notes at 5.30%, due in 2016, to refinance maturing debt.

In April 2006 NYSEG issued $12 million of Series 2006A tax-exempt multi-mode bonds, at an initial interest rate of 3.10%, which is presently reset weekly in an auction process, due in 2024, to refinance $12 million of maturing debt that had an interest rate of 6%.

In June 2006 we extended for one year our two revolving credit facilities. Energy East is the sole borrower in a facility providing maximum borrowings of up to $300 million and our operating utilities are joint borrowers in a facility providing maximum borrowings of up to $475 million in aggregate. Sublimits that total to the aggregate limit apply to each joint borrower and can be altered within the constraints imposed by maximum limits that apply to each joint borrower. Both facilities have expiration dates in 2011 and require fees on undrawn borrowing capacity. Energy East pays a facility fee of 10 basis points annually on its $300 million revolver and each joint borrower pays a facility fee on its revolver sublimit, ranging from 6 to 10 basis points annually depending on the rating of its unsecured debt. For purposes of calculating the maximum ratio of consolidated total debt to total capitalization, we have amended both facilities to exclude from consolidated net worth the balance of 'Accumulated other comprehensive income (loss)' as it appears on the consolidated balance sheet. This change anticipates the potential effect Statement 158 would have on total capitalization, which requires that unrecognized postretirement costs be recognized as components of other comprehensive income. No borrower is in default, and no condition exists that is likely to create a default, under either facility.

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

Energy East Corporation

On July 24, 2006, we redeemed all of our 8 1/4% junior subordinated debt securities at par and expensed approximately $11 million of unamortized debt expense in July 2006 in connection with the redemption. The redemption was financed by the issuance of $250 million of unsecured long-term debt at 6.75%, due in 2036, and by the issuance of short-term debt. (See Note 7 to our Condensed Consolidated Financial Statements.) In July 2006 we settled the hedges we had entered into in connection with the refinancing at a gain of approximately $15 million, which we will amortize over the life of the new debt.

In August 2006 we issued an additional $250 million of unsecured long-term debt at 6.75% due in 2036. We used substantially all of the proceeds to redeem $232 million of 5.75% notes that were scheduled to mature in November 2006. In August 2006 we settled the hedges we had entered into in connection with the refinancing at a gain of approximately $8 million, which we will amortize over the life of the new debt.

In October 2006 we raised our common stock dividend 3.4% to a new annual rate of $1.20 per share.

(b)Results of Operations

Earnings per Share

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands, except per share amounts)
Net Income	$21,012	$21,324	$182,537	$193,055
Earnings per Share, basic and diluted	$.14	$.14	$1.24	$1.31
Dividends Declared and Paid per Share	$.29	$.275	$.87	$.825
Average Common Shares Outstanding, basic	146,903	147,008	146,946	146,895
Average Common Shares Outstanding, diluted	147,702	147,588	147,686	147,383

Three Months: Earnings per share for the quarter ended September 30, 2006, were unchanged compared to the quarter ended September 30, 2005. The recognition of unamortized debt expenses related to the redemption of our 8 1/4% junior subordinated debt securities in July 2006 reduced earnings by 5 cents per share. That decrease was offset by lower income tax expense of 5 cents per share reflecting actual 2005 tax expense as filed, revisions to estimated 2006 tax expense and settlement of an audit of our 2002 and 2003 federal income tax returns.

Nine Months: Earnings per share for the nine months ended September 30, 2006, decreased 7 cents compared to the nine months ended September 30, 2005, primarily because of:

• A decrease of 11 cents per share resulting from higher uncollectible reserves (reflecting both an increase in 2006 and the effect of a decrease in 2005),
• A decrease of 6 cents per share for higher interest expense resulting from higher rates on short-term and variable rate debt, higher debt balances and higher carrying costs on regulatory liabilities,
• The recognition of unamortized debt expense of 5 cents per share resulting from the redemption of our 8 1/4% junior subordinated debt securities in July 2006, and

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

Energy East Corporation

• A decrease of 5 cents per share resulting from increased depreciation expense and other taxes. The depreciation increase was primarily due to placing NYSEG's customer care system into service in the first quarter of 2006.

Those decreases were partially offset by:

• An increase of 12 cents per share due to higher margins on electricity sales, primarily reflecting lower accruals under various earnings sharing mechanisms, and
• A decrease in tax expense of 5 cents per share, as discussed above.

Operating Results for the Electric Delivery Business

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Electric Deliveries (MWh)
Retail deliveries	8,146	8,750	23,398	24,167
Retail commodity sales*	3,450	3,769	10,106	10,729
Wholesale sales	2,151	2,326	7,139	6,769
Operating revenues
Retail revenues	$591,768	$610,251	$1,666,341	$1,734,454
Wholesale revenues	133,689	155,087	428,567	388,483
Other revenues	56,980	13,644	190,528	111,993
Total Operating Revenues	$782,437	$778,982	$2,285,436	$2,234,930
Operating Expenses
Electricity purchased and fuel used in generation	$401,603	$398,874	$1,133,153	$1,112,400
Other operating and maintenance expenses	179,760	183,380	517,503	492,959
Depreciation and amortization	46,308	43,746	139,009	132,289
Other taxes	38,976	37,546	115,058	108,394
Total Operating Expenses	$666,647	$663,546	$1,904,723	$1,846,042
Operating Income	$115,790	$115,436	$380,713	$388,888
*Also included in Retail Deliveries

Three Months

Operating Revenues:The $3 million increase in operating revenues for the third quarter of 2006 was primarily the result of:

• An increase of $13 million due to higher prices for retail electric energy sold by NYSEG and RG&E under various commodity options where they provide supply,
• An increase of $29 million resulting from lower accruals for earnings sharing which is included in other revenues, and
• An increase of $51 million in average prices for delivery resulting primarily from lower transition charges. The transition charge reflects the difference between the market price of electricity and the prices of our long-term electricity contracts, and increases as market prices decrease.

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

Energy East Corporation

Those increases were partially offset by:

• A decrease of $45 million resulting from an 8% decline in electricity sales under NYSEG's and RG&E's commodity programs,
• A decrease of $21 million in wholesale sales reflecting both an 8% decline in volume and lower wholesale prices, and
• A decrease of $14 million resulting from a 7% decline in retail deliveries from 2005 levels. Approximately 2% of the 7% decrease was due to cooler temperatures as there were 21% fewer cooling degree days in New York and 11% fewer in Maine compared to the prior year. In addition, about 1% of the decline was attributable to the expiration of a major NUG contract for CMP at the end of 2005. Energy previously sold to CMP is now retained and used by the NUG for its own load requirements. Another 3% of the decline was attributable to an adjustment that increased unbilled revenues in the third quarter of 2005.

Operating Expenses: The $3 million increase in operating expenses for the third quarter of 2006 was primarily the result of:

• An increase of $3 million for higher purchased power costs, which was net of a $14 million reduction due to the expiration of a major NUG contract for CMP, and
• An increase of $3 million in depreciation primarily due to placing NYSEG's customer care system into service in the first quarter of 2006.

Those increases were partially offset by:

• A decrease of $3 million due to various operating and maintenance expense items.

Nine Months

Operating Revenues:The $51 million increase in operating revenues for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $40 million in wholesale revenue resulting from a 5% increase in wholesale volumes and higher wholesale market prices,
• An increase of $43 million due to higher prices for retail electric energy sold by NYSEG and RG&E under various commodity options where they provide supply,
• An increase of $40 million in average delivery prices resulting from higher transition charges, and
• An increase of $50 million resulting from lower accruals for earnings sharing including $14 million in the first quarter of 2006 for the finalization of actual earnings sharing amounts for 2005 per NYSEG's and RG&E's annual compliance filings.

Those increases were partially offset by:

• A decrease of $71 million resulting from a 6% reduction in sales volume under the companies' commodity programs,
• A decrease in other revenue of $18 million including $6 million related to a NUG incentive CMP recorded in 2005. The remainder is primarily for accruals to reconcile to actual purchased power costs, and

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

Energy East Corporation

• A decrease of $32 million resulting from a 3% decline in retail deliveries, about 1% of which is weather related. In addition to the cooler summer temperatures described above, warmer winter weather contributed to the decline in sales volume. Year-to-date heating degree days declined by 11% in New York and 13% in Maine from 2005 levels. In addition, about 1% of the decline was attributable to the expiration of a major NUG contract for CMP. Another 1% of the decline was attributable to an adjustment that increased unbilled revenues in the third quarter of 2005.

Operating Expenses: The $59 million increase in operating expenses for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $21 million in purchased power costs resulting from a $63 million increase for higher wholesale electricity market prices, partially offset by a $42 million decrease due to the expiration of a major NUG contract in 2006,
• An increase of $25 million in operating and maintenance costs, including $9 million for storm restoration, $14 million for higher bad debt expense, including uncollectible reserves, and $4 million related to costs incurred for NYSEG's rate case,
• An increase of $7 million in depreciation resulting largely from NYSEG's new customer care system, and
• An increase of $7 million in other taxes primarily due to a refund received in 2005.

Operating Results for the Natural Gas Delivery Business

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Deliveries (Dth)
Retail deliveries (excluding transportation)	11,034	10,408	79,535	87,355
Transportation deliveries	14,287	16,037	57,074	62,533
Wholesale sales	-	185	91	884
Operating Revenues
Retail revenues	$177,108	$172,260	$1,211,388	$1,172,021
Other revenues	9,548	15,071	15,372	18,957
Total Operating Revenues	$186,656	$187,331	$1,226,760	$1,190,978
Operating Expenses
Natural gas purchased	$97,469	$104,323	$779,902	$746,609
Other operating and maintenance expenses	66,748	64,510	190,830	182,611
Depreciation and amortization	21,511	22,259	64,229	66,426
Other taxes	18,356	18,002	71,018	72,412
Total Operating Expenses	$204,084	$209,094	$1,105,979	$1,068,058
Operating Income	$(17,428)	$(21,763)	$120,781	$122,920

Three Months

Operating Revenues: Operating revenues for the third quarter of 2006 decreased less than $1 million. The decrease was the result of:

• A decrease of $7 million as a result of lower market prices for natural gas that were passed on to customers, and
• A decrease of $5 million in other revenues.

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

Energy East Corporation

That decrease was partially offset by:

• An increase of $9 million resulting from a 6% increase in delivery volumes, and
• An increase of $2 million due to higher base rates at SCG effective January 1, 2006.

Operating Expenses: The $5 million decrease in operating expenses for the third quarter of 2006 was primarily the result of:

• A decrease of $9 million due to lower market prices for purchased natural gas.

That decrease was partially offset by:

• An increase of $3 million related to higher delivery volumes, and
• An increase of $2 million in operating and maintenance expense, including $4 million for increased bad debt expense.

Nine Months

Operating Revenues: The $36 million increase in operating revenues for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $120 million primarily as a result of higher market prices for natural gas that were passed on to customers, and
• An increase of $14 million due to higher base rates for SCG effective January 1, 2006.

Those increases were partially offset by:

• A decrease of $96 million as a result of a 9% decrease in delivery volumes, largely due to warmer winter weather and customer conservation. Through the third quarter of 2006 heating degree days declined 11% compared to the same period in 2005 and caused approximately 7% of the sales decline, and
• A decrease of $3 million in other revenue.

Operating Expenses: The $38 million increase in operating expenses for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $99 million due to higher market prices for purchased natural gas, and
• An increase of $8 million in operating and maintenance costs including $14 million for higher bad debt expense, partially offset by a decrease of $4 million for lower payroll and benefit costs and $2 million for various other items.

Those increases were partially offset by:

• A reduction of $68 million due to lower volumes of natural gas sold.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	Sept. 30, 2006	Dec. 31, 2005
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$5,619	$28,752
Investments available for sale	-	53,325
Accounts receivable and unbilled revenues, net	156,359	193,807
Fuel and natural gas in storage, at average cost	56,646	57,434
Materials and supplies, at average cost	14,934	13,204
Deferred income taxes	17,683	-
Derivative assets	-	21,597
Prepayments and other current assets	96,827	27,047
Total Current Assets	348,068	395,166
Utility Plant, at Original Cost
Electric	1,300,589	1,258,330
Natural gas	591,384	572,943
Common	177,031	199,015
	2,069,004	2,030,288
Less accumulated depreciation	602,021	583,557
Net Utility Plant in Service	1,466,983	1,446,731
Construction work in progress	53,399	18,748
Total Utility Plant	1,520,382	1,465,479
Other Property and Investments	11,373	11,634
Regulatory and Other Assets
Regulatory assets
Deferred income taxes	-	12,007
Nuclear plant obligations	181,457	183,039
Environmental remediation costs	25,231	25,013
Unamortized loss on debt reacquisitions	11,811	14,336
Nonutility generator termination agreement	75,327	82,243
Natural gas hedges	29,897	-
Other	114,180	127,867
Total regulatory assets	437,903	444,505
Other assets
Prepaid pension benefits	59,838	48,368
Derivative assets	-	372
Other	15,145	16,749
Total other assets	74,983	65,489
Total Regulatory and Other Assets	512,886	509,994
Total Assets	$2,392,709	$2,382,273
Thenotes on pages 32 through 41 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	Sept. 30, 2006	Dec. 31, 2005
(Thousands)
Liabilities
Current Liabilities
Notes payable	$32,600	-
Accounts payable and accrued liabilities	106,508	$123,145
Interest accrued	7,954	9,830
Taxes accrued	-	16,438
Deferred income taxes	-	698
Derivative liabilities	31,465	1,562
Other	32,576	36,396
Total Current Liabilities	211,103	188,069
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	187,891	182,346
Deferred income taxes	32,630	-
Unfunded future income taxes	22,275	89,104
Gain on sale of generation assets	118,823	111,262
Natural gas hedges	-	21,969
Other	34,347	51,015
Total regulatory liabilities	395,966	455,696
Other liabilities
Deferred income taxes	176,561	167,785
Nuclear waste disposal	112,389	108,570
Other postretirement benefits	80,945	80,045
Environmental remediation costs	37,523	36,506
Other	72,533	65,146
Total other liabilities	479,951	458,052
Total Regulatory and Other Liabilities	875,917	913,748
Long-term debt	698,006	697,951
Total Liabilities	1,785,026	1,799,768
Commitments and Contingencies
Common Stock Equity
Common stock	194,429	194,429
Capital in excess of par value	483,581	483,252
Retained earnings	58,226	28,549
Accumulated other comprehensive (loss) income	(11,315)	(6,487)
Treasury stock, at cost	(117,238)	(117,238)
Total Common Stock Equity	607,683	582,505
Total Liabilities and Stockholder's Equity	$2,392,709	$2,382,273
Thenotes on pages 32 through 41 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Income - (Unaudited)
	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Operating Revenues
Electric	$210,047	$207,984	$568,647	$527,041
Natural gas	42,440	51,455	266,459	273,934
Total Operating Revenues	252,487	259,439	835,106	800,975
Operating Expenses
Electricity purchased and fuel used in generation	100,553	96,580	255,719	232,076
Natural gas purchased	21,086	26,191	164,797	168,918
Other operating expenses	48,908	55,046	129,437	130,901
Maintenance	12,206	12,653	34,951	35,424
Depreciation and amortization	17,444	17,373	53,066	52,856
Other taxes	17,343	17,293	51,882	48,885
Total Operating Expenses	217,540	225,136	689,852	669,060
Operating Income	34,947	34,303	145,254	131,915
Other (Income)	(1,326)	(1,136)	(3,263)	(3,150)
Other Deductions	208	1,775	614	2,043
Interest Charges, Net	13,972	13,473	42,281	42,217
Income Before Income Taxes	22,093	20,191	105,622	90,805
Income Taxes	9,652	4,679	40,945	33,388
Net Income	$12,441	$15,512	$64,677	$57,417
Thenotes on pages 32 through 41 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,	2006	2005
(Thousands)
Operating Activities
Net income	$64,677	$57,417
Adjustments to reconcile net income to net cash  provided by operating activities
Depreciation and amortization	101,629	103,216
Income taxes and investment tax credits deferred, net	40,379	3,333
Pension income	(11,471)	(10,806)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	37,448	(5,109)
Inventory	(943)	(19,262)
Prepayments and other current assets	(62,971)	(3,888)
Accounts payable and accrued liabilities	(13,893)	19,099
Interest accrued	(1,876)	(1,126)
Taxes accrued	(20,699)	862
Customer refund	(15,426)	(25,329)
Other current liabilities	(21,805)	8,994
Other assets	(42,011)	(11,327)
Other liabilities	(49,406)	1,047
Net Cash Provided by Operating Activities	3,632	117,121
Investing Activities
Utility plant additions	(91,671)	(43,894)
Maturities of current investments available for sale	372,950	444,285
Purchases of current investments available for sale	(319,625)	(439,760)
Investments	42	(701)
Net Cash Provided by (Used in) Investing Activities	(38,304)	(40,070)
Financing Activities
Notes Payable	32,600	-
Book overdraft	13,939	976
Dividends on common stock	(35,000)	(70,000)
Net Cash Used in Financing Activities	11,539	(69,024)
Net (Decrease) Increase in Cash and Cash Equivalents	(23,133)	8,027
Cash and Cash Equivalents, Beginning of Period	28,752	11,834
Cash and Cash Equivalents, End of Period	$5,619	$19,861
Thenotes on pages 32 through 41 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,	2006	2005
(Thousands)
Balance, Beginning of Period	$28,549	$19,560
Add net income	64,677	57,417
	93,226	76,977
Deduct dividends on common stock	35,000	70,000
Balance, End of Period	$58,226	$6,977
Thenotes on pages 32 through 41 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,	2006	2005	2006		2005
(Thousands)
Net income	$12,441	$15,512	$64,677		$57,417
Other comprehensive income, net of tax
Net unrealized gains on investments, net of    income (expense) in 2006 of $(423) for the    three months and $(331) for the nine months	638	- -	500		- -
Minimum pension liability adjustment net of    income tax benefit for the nine months    of $261 in 2006	-	- -	(394)		- -
Unrealized (losses) gains on derivatives    qualified as hedges, net of income tax    benefit (expense) for the three months of    $7,050 in 2006 and $(24,746) in 2005 and    for the nine months of $6,768 in 2006 and    $(22,123) in 2005	(10,632)	37,313	(10,206)		33,384
Reclassification adjustment for derivative losses    (gains) included in net income, net of income    tax (benefit) expense for the three months of    $(713) in 2006 and $1,191 in 2005 and for    the nine months of $(3,496) in 2006 and    $1,560 in 2005	1,075	(1,796)	5,272		(2,353)
Net unrealized (losses) gains on derivatives    qualified as hedges	(9,557)	35,517	(4,934)		31,031
Total other comprehensive (loss) income	(8,919)	35,517	(4,828)		31,031
Comprehensive Income	$3,522	$51,029	$59,849		$88,448
Thenotes on pages 32 through 41 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

RG&E's MD&A for the quarter and nine months ended September 30, 2006, should be read in conjunction with its MD&A, financial statements and notes contained in its report on Form 10-K for the fiscal year ended December 31, 2005. Due to the seasonal nature of RG&E's operations, financial results for interim periods are not necessarily indicative of trends for the annual period.

Electric Delivery Business Developments

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 Dispute Settlement Related to NMP2 Exit Agreement: See Energy East's Part I, Item 2 - MD&A - Electric Delivery Business Developments, for this discussion.

Threatened Litigation for Russell Station: See Energy East's Part I, Item 2 - MD&A - Electric Delivery Business Developments, for this discussion.

Niagara Power Project Relicensing: See Energy East's Part I, Item 2 - MD&A - Electric Delivery Business Developments, for this discussion.

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: See Energy East's Part I, Item 2 - MD&A - Electric Delivery Business Developments, for this discussion.

Natural Gas Delivery Business Developments

RG&E's natural gas delivery business consists of its regulated transportation, storage and distribution operations in western New York.

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: See Energy East's Part I, Item 2 - MD&A - Electric Delivery Business Developments, for this discussion.

New Accounting Standards

The FASB released FIN 48 in July 2006 and issued Statements 157 and 158 in September 2006. See Item 1, Note 8 to RG&E's financial statements for information concerning the new accounting standards.

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

Rochester Gas and Electric Corporation

(a) Liquidity and Capital Resources

Operating Activities: Cash flows from operating activities for the nine months ended September 30 included refunds to RG&E customers of $15 million in 2006 and $25 million in 2005, from proceeds from the sale of Ginna, pursuant to the Electric Rate Agreement. The Electric Rate Agreement requires an additional refund to customers of $10 million in 2007. Cash flows also include RG&E's $34 million payment to resolve a dispute with Niagara Mohawk. (See RG&E Dispute Settlement Related to NMP2 Exit Agreement.)

Investing Activities: Capital spending for the nine months ended September 30, 2006, was $92 million. RG&E projects capital spending of $182 million in 2006, including $53 million for its transmission project, and expects to pay for it principally with cash on hand and internally generated funds. Capital spending is primarily for the extension of energy delivery service, necessary improvements to existing facilities, and compliance with environmental requirements and governmental mandates, and includes the transmission project and a new customer care system.

Financing Activities: During the nine months ended September 30, 2006, RG&E paid a common dividend of $35 million.

In June 2006 RG&E extended for one year its joint revolving credit facility. RG&E is a joint borrower, along with NYSEG, CNG, SCG, CMP and Berkshire Gas, in a facility providing maximum borrowings of up to $475 million in aggregate. Sublimits that total to the aggregate limit apply to each joint borrower and can be altered within the constraints imposed by maximum limits that apply to each joint borrower. The facility expires in 2011 and requires fees on undrawn borrowing capacity. RG&E has no liability for any other joint borrower. RG&E's maximum borrowing limit under the facility is $100 million. RG&E pays a facility fee of 10 basis points annually on its current revolver limit. For purposes of calculating RG&E's maximum ratio of total debt to total capitalization, we have amended the facility to exclude from net worth the balance of 'Accumulated other comprehensive income (loss)' as it appears on the balance sheet. This change anticipates the potential effect Statement 158 would have on total capitalization, which requires that unrecognized postretirement costs be recognized as components of other comprehensive income. RG&E is not in default, and no condition exists that is likely to create a default, under the facility.

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

Rochester Gas and Electric Corporation

(b)Results of Operations

Earnings

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Operating Revenues	$252,487	$259,439	$835,106	$800,975
Operating Income	$34,947	$34,303	$145,254	$131,915
Net Income	$12,441	$15,512	$64,677	$57,417

Three Months: RG&E's net income for the third quarter of 2006 decreased $3 million compared to the third quarter of 2005 primarily as a result of tax adjustments that lowered tax expense in 2005 and factors discussed below in Operating Results for the Electric and Natural Gas Delivery Businesses.

Nine Months: RG&E's net income for the nine months ended September 30, 2006, increased $7 million compared to the nine months ended September 30, 2005, primarily because of a $10 million increase for higher net margins on electricity sales in the first quarter of 2006, partially offset by the $3 million decrease described above for the third quarter.

Operating Results for the Electric Delivery Business

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Electric Deliveries (MWh)
Retail deliveries	2,006	2,311	5,502	5,799
Retail commodity sales*	995	1,096	2,709	2,937
Wholesale sales	941	832	2,964	2,180
Operating Revenues
Retail revenues	$125,569	$145,053	$322,609	$366,463
Wholesale revenues	54,156	67,791	164,632	142,365
Other revenues	30,322	(4,860)	81,406	18,213
Total Operating Revenues	$210,047	$207,984	$568,647	$527,041
Operating Expenses
Electricity purchased and fuel used in   generation	$100,553	$96,580	$255,719	$232,076
Other operating and maintenance expenses	46,219	51,137	124,646	123,617
Depreciation and amortization	12,810	12,609	39,279	38,661
Other taxes	12,425	12,316	35,243	31,977
Total Operating Expenses	$172,007	$172,642	$454,887	$426,331
Operating Income	$38,040	$35,342	$113,760	$100,710
*Also included in Retail deliveries

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

Rochester Gas and Electric Corporation

Three Months

Operating Revenues: Operating revenues increased $2 million for the third quarter of 2006 as a result of:

• An increase of $41 million resulting from higher average delivery prices, reflecting a higher transition charge, and

• An increase of $19 million resulting from lower accruals under the earnings sharing mechanism.

Those increases were partially offset by:

• A decrease of $13 million due to lower wholesale revenues,
• A decrease of $29 million due to lower market prices for electric energy sold under commodity options where RG&E provides supply,
• A decrease of $12 million due to reduced sales volume under RG&E's commodity programs, and
• A decrease of $3 million due to lower delivery volumes.

Operating Expenses: The $1 million decrease in operating expenses for the third quarter of 2006 was the result of a decrease of $4 million in operating and maintenance costs, including pension costs, offset by an increase of $4 million for purchased power costs.

Nine Months

Operating Revenues: The $42 million increase in operating revenues for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $22 million due to higher wholesale revenues,
• An increase of $21 million due to higher market prices for electric energy sold under various commodity options where RG&E provides supply,

• An increase of $24 million resulting from lower accruals under the earnings sharing mechanism including $9 million in the first quarter for the finalization of the actual earnings sharing amount for 2005 per RG&E's annual compliance filing, and
• An increase in other revenues of $17 million, primarily reflecting credits from RG&E's ASGA to recover purchased power costs.

Those increases were partially offset by:

• A decrease of $5 million resulting from lower delivery volumes, and
• A decrease of $37 million resulting from lower electricity sales under RG&E's commodity programs.

Operating Expenses: The $29 million increase in operating expenses for the nine months ended September 30, 2006, was primarily the result of:

• An increase of $24 million for purchased power costs, and
• An increase of $3 million for other taxes resulting from a refund received in 2005.

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

Rochester Gas and Electric Corporation

Operating Results for the Natural Gas Delivery Business

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Deliveries (Dth)
Retail deliveries (excluding transportation)	1,638	1,951	17,200	17,425
Transportation deliveries	2,886	3,268	15,148	19,982
Operating Revenues
Retail revenues	$34,700	$38,992	$260,932	$265,269
Other revenues	7,740	12,463	5,527	8,665
Total Operating Revenues	$42,440	$51,455	$266,459	$273,934
Operating Expenses
Natural gas purchased	$21,086	$26,191	$164,797	$168,918
Other operating and maintenance expenses	14,895	16,562	39,742	42,707
Depreciation and amortization	4,634	4,764	13,787	14,195
Other taxes	4,918	4,977	16,639	16,909
Total Operating Expenses	$45,533	$52,494	$234,965	$242,729
Operating Income	$(3,093)	$(1,039)	$31,494	$31,205

Three Months

Operating Revenues:The $9 million decrease in operating revenues for the third quarter of 2006 was primarily the result of:

• A decrease of $4 million due to lower delivery volumes, and
• A decrease of $5 million in other revenue.

Operating Expenses:The $7 million decrease in operating expenses for the third quarter of 2006 was primarily due to:

• A decrease of $5 million purchased natural gas costs due primarily to lower volume, and
• A decrease of $2 million in other operating and maintenance costs.

Nine Months

Operating Revenues: The $7 million decrease in operating revenues for the nine months ended September 30, 2006, was primarily the result of:

• A decline of $33 million due to lower deliveries resulting from warmer weather, and
• A reduction of $3 million in other revenue.

Those decreases were partially offset by:

• An increase of $28 million due to higher fuel costs passed on to customers.

Operating Expenses: The $8 million decrease in operating expenses for the nine months ended September 30, 2006, was primarily the result of:

• A decrease of $3 million in operating and maintenance costs, and
• A decrease of $4 million in purchased natural gas costs due to lower sales volumes.

Item 1.  Financial Statements

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

Notes to Condensed Financial Statements of Registrants:

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

Note 1. Unaudited Condensed Financial Statements

In the opinion of each registrant's management, the accompanying unaudited condensed financial statements reflect all adjustments necessary for a fair statement of the interim periods presented. All such adjustments are of a normal, recurring nature. The year-end condensed balance sheet data 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 fiscal year ended December 31, 2005. 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 2006 presentation.

Effective December 31, 2005, Energy East and RG&E revised the presentation of their investments in auction rate securities, classifying them as current investments available for sale rather than as cash and cash equivalents. Energy East held current investments of $43 million at September 30, 2006, and $193 million at December 31, 2005, which consisted of auction rate securities classified as available for sale. RG&E held no current investments at September 30, 2006, and $53 million at December 31, 2005. Investments in these securities are recorded at cost, which approximates fair market value due to their variable interest rates. Energy East and RG&E have no cumulative unrealized or realized gains or losses from their current investments. All income generated from these current investments is recorded as interest income.

Note 2. Other (Income) and Other Deductions

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Energy East
Interest and dividend income	$(5,714)	$(5,265)	$(13,606)	$(10,160)
AFUDC	(630)	(392)	(1,503)	(1,070)
Earnings from equity investments	(963)	(1,270)	(2,463)	(3,207)
Gains from hedge activity	(691)	(5,537)	(2,310)	(7,369)
Miscellaneous	(1,875)	(1,467)	(7,301)	(4,941)
Total other (income)	$(9,873)	$(13,931)	$(27,183)	$(26,747)
Losses from hedge activity	$1,254	$137	$6,258	$1,069
Recognition of debt expense	11,248	-	11,248	-
Donations, civic and political	665	616	2,374	2,284
Miscellaneous	(835)	2,500	600	4,856
Total other deductions	$12,332	$3,253	$20,480	$8,209
RG&E
Interest and dividend income	$(909)	$(1,318)	$(2,384)	$(2,627)
AFUDC	(411)	(45)	(952)	(144)
Gains from hedge activity	-	247	-	(502)
Miscellaneous	(6)	(20)	73	123
Total other (income)	$(1,326)	$(1,136)	$(3,263)	$(3,150)
Losses from hedge activity	-	$137	-	$353
Miscellaneous	$208	1,638	$614	1,690
Total other deductions	$208	$1,775	$614	$2,043

Note 3. Basic and Diluted Earnings per Share

We determine basic EPS 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, we have issued stock options in tandem with SARs and substantially all stock option plan participants have exercised the SARs instead of the stock options. The numerator we use in calculating both basic and diluted EPS for each period is our reported net income.

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

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Basic average common shares outstanding	146,903	147,008	146,946	146,895
Restricted stock awards	799	580	740	488
Potentially dilutive common shares	137	333	141	301
Options issued with SARs	(137)	(333)	(141)	(301)
Dilutive average common shares outstanding	147,702	147,588	147,686	147,383

We exclude from the determination of EPS options that have an exercise price that is greater than the average market price of the common shares during the period. Shares excluded from the EPS calculation for the three months ended September 30 were: 1.5 million in 2006 and less than 0.1 million in 2005 and for the nine months ended September 30 were: 1.2 million in 2006 and 0.4 million in 2005.

Note 4. Income Taxes

Our effective tax rate for the quarter ended and nine months ended September 30, 2006, was lower than the statutory rate due to recurring flow-through items and out of period adjustments, including the effects of an audit of our 2002 and 2003 federal income tax returns and the filing of our 2005 federal and New York State (NYS) income tax returns. Our quarterly effective tax rate was also reduced due to the effect of applying the updated estimated annual effective tax rate to January through June operations.

RG&E's effective tax rate for the quarter ended September 30, 2006, is higher than the statutory rate due to out of period adjustments, including the effects of the audit of the 2002 and 2003 federal income tax returns and the filing of the 2005 federal and NYS income tax returns. RG&E's effective tax rate for the nine months ended September 30, 2006 was lower than the statutory rate due to recurring flow-through items, which offset the effects of the out period adjustments mentioned above.

	Three Months		Nine Months
Periods ended September 30,	2006	2005	2006	2005
(Thousands)
Energy East
Tax expense at statutory rate	$8,228	$12,888	$114,952	$126,516
2005 Adjustments to actual	(2,061)	(1,484)	(2,061)	(1,484)
Audit adjustments	980	(548)	4,061	930
2006 Effective tax rate update	(6,932)	1,994	-	-
Current period flow-through items	(876)	(2,138)	(12,056)	(2,928)
Total Income Taxes	$(661)	$10,712	$104,896	$123,034
RG&E
Tax expense at statutory rate	$8,810	$8,051	$42,117	$36,208
2005 Adjustments to actual	2,266	-	2,266	(1,144)
Audit adjustments	1,026	(37)	962	(248)
2006 Effective tax rate update	(1,520)	(1,921)	-	-
Current period flow-through items	(930)	(1,414)	(4,400)	(1,428)
Total Income Taxes	$9,652	$4,679	$40,945	$33,388

Note 5. 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. A business enterprise is required to consolidate a variable interest entity if the enterprise has a variable interest that will absorb a majority of the entity's expected losses.

We have power purchase contracts with NUGs. However, we were not involved in the formation of and do not have ownership interests in any NUGs. We have evaluated all of our power purchase contracts with NUGs and determined that most of the power purchase contracts are not variable interests for one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUG is a governmental organization or an individual. One of the NUG contracts expired in April 2006. We are not able to determine if we have variable interests with respect to power purchase contracts with six remaining NUGs because we are unable to obtain the information necessary to (1) determine if any of the six NUGs is a variable interest entity, (2) determine if an operating utility is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of t hose NUGs.

We routinely request necessary information from the six NUGs, and will continue to do so, but no NUG has yet provided the requested information. We did not consolidate any NUGs as of September 30, 2006, or December 31, 2005.

We continue to purchase electricity from the six NUGs at above-market prices. We are not exposed to any loss as a result of our involvement with the NUGs because we are allowed to recover through rates the cost of our purchases. Also, we 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 MWs, including 55 MWs for the contract that expired in April 2006. The combined purchases from the seven NUGs totaled approximately $266 million for the nine months ended September 30, 2006, and $283 million for the nine months ended September 30, 2005.

Note 6. 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 are available. The two companies have developed an accrual process that incorporates available information about retroactive NYISO billing adjustments as provided to all market participants. However, on an ongoing basis, they cannot fully predict either the magnitude or the direction of any final billing adjustments.

RG&E Dispute Settlement Related to NMP2 Exit Agreement: In November 2001 RG&E and three other NMP2 joint owners, including Niagara Mohawk Power Corporation (Niagara Mohawk), sold their interests in NMP2 to Constellation Nuclear, LLC. In connection with the sale of NMP2, RG&E informed Niagara Mohawk that RG&E's payment obligations and rights to certain TCCs would cease according to the terms of an exit agreement executed by RG&E and Niagara Mohawk in June 1998. Niagara Mohawk disagreed with RG&E's position, claiming that RG&E must continue to make annual payments that were to decline from about $7 million per year in 2002 to $4 million per year in 2007, and remain at that level until 2043. In August 2001, RG&E filed a complaint asking the New York State Supreme Court, Monroe County, to find that, as a result of the sale of its interest in NMP2, RG&E has no further obligation to make payments under the exit agreement and that the TCCs to which RG&E was e ntitled under the exit agreement should be returned to and accepted by Niagara Mohawk.

In the first quarter of 2006, RG&E and Niagara Mohawk stayed the litigation and entered into confidential mediation with the support of the NYPSC. On June 29, 2006, the parties executed a settlement agreement that provides for RG&E's one-time payment of $34 million to Niagara Mohawk and further provides that RG&E retains the rights and obligations related to the TCCs until 2043, including the value accumulated to date of approximately $4 million. The settlement agreement was contingent upon the fulfillment of certain closing conditions, including FERC acceptance of an amendment to and restatement of the exit agreement. All of the necessary closing conditions were fulfilled, including a favorable judgement from the FERC, and RG&E made the required payment. In accordance with the 2001 settlement and order associated with the transfer of RG&E's share of NMP2 to Constellation Nuclear and RG&E's Electric Rate Agreement, RG&E adjusted its regulatory asset established as a result of t he sale of NMP2 for the amount of the $34 million payment to Niagara Mohawk, which was offset by the accumulated TCC amount of approximately $4 million and will be adjusted by any future TCC amounts. RG&E's results of operations were not affected by the settlement of this dispute.

Note 7. Long-term Debt

Debt owed to subsidiary holding solely parent debentures: The debt owed to a subsidiary holding solely parent debentures consisted of Energy East's 8 1/4% junior subordinated debt securities that were to mature on July 1, 2031, and were held by Energy East Capital Trust I (the Trust). We redeemed all of the junior subordinated debt securities at par on July 24, 2006, financed by the issuance of $250 million of unsecured long-term debt at 6.75%, due in 2036, and by the issuance of short-term debt. We expensed approximately $11 million of unamortized debt expense in July 2006 in connection with the redemption. Also in July 2006 the Trust redeemed, at par, its $345 million, 8 1/4% Capital Securities.

Note 8. New Accounting Standards

FIN 48: In July 2006 the FASB released FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with Statement 109 by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or to be taken in a tax return. The evaluation of a tax position is a two-step process. The first step is for an entity to determine if it is more likely than not that a tax position will be sustained upon examination. The second step involves measuring the amount of tax benefit to be recognized in the financial statements based on the largest amount of benefit that meets the prescribed recognition threshold. The difference between the amounts based on that position and the position taken in a tax return is generally recorded as a liability. FIN 48 is effective for fiscal years beginning after December 15, 2006. Upon adoption of FIN 48, the cumulative effect of applying the provisions of FIN 48 must be reported as an adjustment to the opening balance of retained earnings for that fiscal year. Energy East and RG&E will adopt FIN 48 effective January 1, 2007. They are currently assessing the effect FIN 48 would have on their results of operations, financial position and cash flows, but expect that it will not be material.

Statement 157: In September 2006 the FASB issued Statement 157. Changes from current practice that will result from the application of Statement 157 relate to the definition of fair value, the methods used to measure fair value, and expanded disclosures about fair value measurements.FAS 157 applies under other accounting pronouncements that require or permit fair value measurements in which the FASB previously concluded that fair value is the relevant measurement attribute. It does not require any new fair value measurements, but may change current practice for some entities. Statement 157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with earlier application encouraged. The provisions are to be applied prospectively, with certain exceptions. A cumulative-effect adjustment to retained earnings is required for application to certain financial instruments. Energy East and RG&E wil l adopt Statement 157 effective January 1, 2008. We are currently assessing the effect Statement 157 would have on our results of operations, financial position and cash flows.

Statement 158: In September 2006 the FASB issued Statement 158, which amends FASB Statements No. 87, 88, 106 and 132(R), and requires an employer to:

• recognize the overfunded or underfunded status of defined benefit pension and/or other postretirement plans as an asset or liability in its balance sheet,
• recognize changes in the funded status of such plans in the year in which the changes occur through other comprehensive income,

• measure the funded status of a plan as of the date of its year-end balance sheet, and
• disclose in the notes to the annual financial statements certain effects that the delayed recognition of the gains or losses, prior service costs or credits and transition asset or obligation are expected to have on net periodic benefit cost for the next fiscal year.

The funded status of a benefit plan is measured as the difference between plan assets at fair value and the benefit obligation, which is the projected benefit obligation for a pension plan and the accumulated postretirement benefit obligation for any other postretirement benefit plan. As required by Statement 158, gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost pursuant to Statement 87 or Statement 106 are recognized as a component of other comprehensive income, net of tax. Gains or losses, prior service costs or credits and the transition asset or obligation remaining from the initial application of Statements 87 and 106 that are recognized in accumulated other comprehensive income are adjusted as they are subsequently recognized as components of net periodic benefit cost pursuant to the recognition and amortization provisions of those Statements.

Energy East and RG&E will initially apply the recognition and disclosure provisions of Statement 158 as of December 31, 2006, and each expects no material effect on their financial position and no effect on their results of operation or cash flows. Retrospective application of the recognition provisions and measurement provisions is not permitted. They measure their pension and other postretirement plan assets and benefit obligations as of the date of their fiscal year-end balance sheet and therefore have no need to change their measurement date.

The following are estimates of the effects on the balance sheet of adopting Statement 158, based on Energy East's and RG&E's most recent measurement of benefit plan assets and obligations, which was as of December 31, 2005:

(Millions of $)	Energy East		RG&E
Decrease in total assets	$418	4%	$15	1%
Decrease in total liabilities	$118	1%	$4	-
Decrease in total shareholder equity	$300	10%	$11	2%

We are currently assessing the effect that our adoption of Statement 158 would have on our financial position in light of our approved regulatory rate mechanisms for the recovery of defined benefit pension and other postretirement plan costs.

Share-Based Compensation: We early adopted Statement 123(R) effective October 1, 2005, using the modified version of prospective application. Statement 123(R) is a revision of Statement 123 and 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 (e.g., 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.

We incur a liability for our stock option plan awards in accordance with Statement 123(R) because our policy is to grant SARs in tandem with any stock options and employees can request that the awards be settled in cash rather than by issuing equity instruments. Prior to our adoption of Statement 123(R), we applied APB 25, as permitted by Statement 123, to account for our stock-based compensation to employees. We also incurred a liability for our stock options/SARs under ABP 25, but we used the intrinsic value method to determine our liability and the related compensation cost. Statement 123 required the amount of the liability for awards that call for settlement in cash to be measured each period based on the current stock price, which produced the same result as using the intrinsic value method under APB 25 for such awards. Compensation for shares granted under our Restricted Stock Plan is determined using the grant-date fair value of shares awarded, which is based on the market price of Energy&nbs p;East's common stock on the date of the restricted stock award and is not subsequently remeasured.

Share-based compensation, net of related tax effects, for the periods ended September 30, 2005, was a negative $4.1 million for the quarter and a positive $1.6 million for the nine months. Those amounts were the same as if the fair value based method in accordance with Statement 123 had been applied to all awards. Net income and basic and diluted EPS as reported for the quarter and nine months ended September 30, 2005, are no different than as if the fair value based method had been applied. Share-based compensation, net of related tax effects, for the periods ended September 30, 2006, was approximately $0.6 million for the quarter and was approximately $5.0 million for the nine months.

Note 9. Accounts Receivable

Energy East's accounts receivable includes unbilled revenues of $126 million at September 30, 2006, and $315 million at December 31, 2005. Our accounts receivable are shown net of an allowance for doubtful accounts of $70 million at September 30, 2006, and $53 million at December 31, 2005.

RG&E's accounts receivable include unbilled revenues of $36 million at September 30, 2006, and $54 million at December 31, 2005. RG&E's accounts receivable are shown net of an allowance for doubtful accounts of $15 million at September 30, 2006, and $13 million at December 31, 2005.

Note 10. Retirement Benefits

Energy East sponsors defined benefit pension plans and postretirement benefit plans applicable to substantially all employees. We use a December 31 measurement date for our pension and postretirement benefit plans.

On August 17, 2006, the Pension Protection Act of 2006 (Act) was enacted into law, primarily to eliminate funding shortfalls for defined benefit pension plans. The Act requires employers with such plans to make contributions to meet specified funding targets. We are in the process of evaluating the effects, if any, that the provisions of the Act could have on our financial position, results of operations and cash flows. However, based on our current funding levels and the provisions of the Act, we do not anticipate additional contributions beyond normal levels in the near future. On September 15, 2006, Energy East contributed $0.4 million to its pension plans for the 2006 plan year. We do not plan to make any further contributions in 2006.

Components of net periodic benefit (income) cost

	Pension Benefits		Postretirement Benefits
Three months ended September 30,	2006	2005	2006	2005
(Thousands)
Energy East
Service cost	$9,360	$8,487	$1,463	$1,444
Interest cost	31,800	31,839	7,330	7,681
Expected return on plan assets	(55,423)	(53,406)	(423)	(563)
Amortization of prior service cost	1,184	1,212	(1,876)	(1,894)
Recognized net actuarial loss	5,562	3,984	1,696	2,156
Amortization of transition obligation	-	-	1,700	1,700
Net periodic benefit (income) cost	$(7,517)	$(7,884)	$9,890	$10,524
RG&E
Service cost	$1,175	$572	$159	$(11)
Interest cost	6,710	7,330	1,114	1,133
Expected return on plan assets	(11,486)	(9,820)	-	-
Amortization of prior service cost	371	553	214	144
Recognized net actuarial loss	(594)	(416)	(330)	(267)
Amortization of transition obligation	-	-	457	443
Net periodic benefit (income) cost	$(3,824)	$(1,781)	$1,614	$1,442

	Pension Benefits		Postretirement Benefits
Nine months ended September 30,	2006	2005	2006	2005
(Thousands)
Energy East
Service cost	$28,082	$26,534	$4,389	$4,331
Interest cost	95,398	95,838	21,990	23,040
Expected return on plan assets	(166,270)	(160,509)	(1,270)	(1,686)
Amortization of prior service cost	3,552	3,711	(5,628)	(5,683)
Recognized net actuarial loss	16,685	11,916	5,088	6,472
Amortization of transition obligation	-	-	5,100	5,100
Net periodic benefit (income) cost	$(22,553)	$(22,510)	$29,669	$31,574
RG&E
Service cost	$3,525	$3,250	$477	$533
Interest cost	20,131	20,936	3,340	4,021
Expected return on plan assets	(34,457)	(33,861)	-	-
Amortization of prior service cost	1,112	1,112	644	644
Recognized net actuarial (gain) loss	(1,782)	(2,243)	(991)	(2)
Amortization of transition obligation	-	-	1,371	1,371
Net periodic benefit (income) cost	$(11,471)	$(10,806)	$4,841	$6,567

Note 11. Goodwill and Intangible Assets

We do not amortize goodwill or intangible assets with indefinite lives (unamortized intangible assets). We test goodwill and unamortized intangible assets for impairment at least annually. Energy East and RG&E amortize intangible assets with finite lives (amortized intangible assets) and review them for impairment.

Changes in the carrying amounts of goodwill as of September 30, 2006, are for preacquisition income tax adjustments. The amounts of goodwill by operating segment (in thousands) are:

	Sept. 30, 2006	Dec. 31, 2005
Electric Delivery	$845,296	$844,491
Natural Gas Delivery	677,080	676,588
Other	3,672	4,274
Total	$1,526,048	$1,525,353

Our unamortized intangible assets, which had a carrying amount of $17 million at September 30, 2006, and $19 million at December 31, 2005, primarily consisted of pension assets. Our amortized intangible assets had a gross carrying amount of $27 million at September 30, 2006, and $31 million at December 31, 2005, and primarily consisted of investments in pipelines and water rights. Accumulated amortization was $14 million at September 30, 2006, and $18 million at December 31, 2005.

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, 2006, and December 31, 2005.

Note 12. Segment Information

Our electric delivery segment consists of our regulated transmission, distribution and generation operations in New York and Maine, and our natural gas delivery segment consists of our regulated transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts. We measure segment profitability based on net income. Other includes primarily our energy marketing companies, and interest income, intersegment eliminations and our other nonutility businesses.

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

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

	Operating Revenues		Net Income
Three months ended September 30,	2006	2005	2006	2005
(Thousands)
Energy East
Electric Delivery	$782,437	$778,982	$44,649	$40,932
Natural Gas Delivery	186,656	187,331	(18,706)	(25,868)
Other	121,261	128,870	(4,931)	6,260
Total	$1,090,354	$1,095,183	$21,012	$21,324
RG&E
Electric Delivery	$210,047	$207,984	$13,766	$16,292
Natural Gas Delivery	42,440	51,455	(1,325)	(780)
Total	$252,487	$259,439	$12,441	$15,512

	Operating Revenues		Net Income
Nine months ended September 30,	2006	2005	2006	2005
(Thousands)
Energy East
Electric Delivery	$2,285,436	$2,234,930	$139,112	$147,411
Natural Gas Delivery	1,226,760	1,190,978	43,116	39,287
Other	386,594	386,508	309	6,357
Total	$3,898,790	$3,812,416	$182,537	$193,055
RG&E
Electric Delivery	$568,647	$527,041	$49,063	$42,767
Natural Gas Delivery	266,459	273,934	15,614	14,650
Total	$835,106	$800,975	$64,677	$57,417

Item 3.  Quantitative and Qualitative Disclosures About Market Risk
(See report on Form 10-K for Energy East and RG&E for the fiscal year ended December 31, 2005, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

Commodity Price Risk: Commodity price risk, due to volatility experienced in the wholesale energy markets, is a significant issue for the electric and natural gas utility industries. We manage this risk through a combination of regulatory mechanisms, such as allowing for the pass-through of the market price of electricity and natural gas to customers, and through comprehensive risk management processes. These measures mitigate our commodity price exposure, but do not completely eliminate it.

NYSEG's and RG&E's current electric rate plans offer their retail customers choice in their electricity supply including fixed and variable rate options, and an option to purchase electricity supply from an ESCO. Approximately 45% of NYSEG's, and approximately 78% of RG&E's, total electric load is now provided by an ESCO or at the market price. During the fourth quarter of 2006, NYSEG's and RG&E's electric customers will choose their supply options for 2007.

NYSEG's and 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. NYSEG and RG&E use electricity contracts, both

physical and financial, to manage fluctuations in the cost of electricity required to serve customers who select the fixed rate option. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. Owned electric generation and long-term supply contracts reduce NYSEG's exposure, and significantly reduce RG&E's exposure, to market fluctuations for procurement of their fixed rate option electricity supply, and reduce the volatility of rates for those customers that have chosen a variable rate option. Pursuant to NYSEG's Electric Rate Order, beginning January 1, 2007, NYSEG will also hedge a portion of the supply required for customers that have chosen the variable rate option, with all costs and benefits of the hedges being passed on to those customers.

As of October 2006 the portion of forecasted load for fixed rate option customers that is not supplied by owned generation or long-term contracts is, overall, fully hedged for NYSEG and for RG&E for November and December 2006. A fluctuation of $1.00 per MWh in the average price of electricity would change NYSEG's earnings less than $60 thousand, and would change RG&E's earnings less than $50 thousand, for November through December 2006. The percentage of hedged load for NYSEG and RG&E is based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in load compared to the load forecast.

Accumulated other comprehensive income associated with our financial electricity contracts at September 30, 2006, was $18 million, reflecting a decrease of $151 million since December 31, 2005. The decrease is primarily a result of wholesale market price declines for electricity but also reflects the settlement of hedge positions. Treasury hedges included in accumulated other comprehensive income as of September 30, 2006, were $11 million, reflecting a $3 million increase since December 31, 2005, due to changes in interest rates that have been hedged for anticipated financings and to settlements of hedge positions for recent financings. Other comprehensive income for the remainder of 2006 will have no effect on future net income because we only use financial electricity contracts to hedge the price of our electric load requirements for customers who have chosen a fixed rate option.

Our nonutility energy marketing subsidiaries offer retail electric and natural gas service to customers in New York State and actively hedge the load required to serve customers that have chosen them as their commodity supplier. As of October 2006 those subsidiaries' fixed price loads are fully hedged for electricity and for natural gas for November and December 2006. The percentage of hedged load for our 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 load compared to the load forecast.

Item 4.  Controls and Procedures

The principal executive officers and principal financial officers of Energy East and RG&E evaluated the effectiveness of their respective company's disclosure controls and procedures as of the end of the period covered by this report. "Disclosure controls and procedures" are controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, within the time periods specified in the SEC's rules and forms, is recorded, processed, summarized and reported, and is accumulated and communicated to the company's management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on their evaluation, the principal executive officers and principal financial officers of Energy East and RG&E concluded that their respective company's disclosure controls and procedures a re 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 accounting principles generally accepted in the United States of America. 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 was no change in Energy East's or RG&E's internal control over financial reporting that occurred during the most recent fiscal quarter that materially affected, or is reasonably likely to materially affect, the respective company's internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.    Legal Proceedings

(See Energy East's Part I, Item 2, MD&A, Threatened Litigation for Russell Station.)

Item 1A.  Risk Factors

The information presented below updates, and should be read in conjunction with, the risk factor information disclosed in our annual report on Form 10-K. (See report on Form 10-K for Energy East for the fiscal year ended December 31, 2005, Part I, Item 1A. Risk Factors.)

Changes in the Northeast Electric Commodity Supply Business: The NYSEG Electric Rate Order includes requirements as to NYSEG's commodity options program that NYSEG believes are unworkable and inconsistent with the development of a competitive retail market for supply. In addition, pursuant to an NYPSC order, RG&E has initiated a collaborative with interested parties for the purpose of RG&E implementing an ESCO Referral Program and they are discussing the effects of such a program on RG&E's Voice Your Choice Program. (See Energy East's Part I, Item 2, MD&A, Electric Delivery Business Developments - NYSEG Electric Rate Order and Other Proceedings in the NYPSC Collaborative on End State of Energy Competition.)

NYSEG Electric Rate Order: The NYSEG Electric Rate Order significantly reduces rates and limits commodity supply business earnings. As a result, NYSEG will be forced to revise its plans for capital and other spending, which may affect the level of service to its customers.

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(1)		(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, 2006 to   July 31, 2006)	6,616		$23.81		- -		- -
Month #2   (August 1, 2006 to   August 31, 2006)	4,870		$24.60		- -		- -
Month #3   (September 1, 2006 to   September 30, 2006)	5,686		$23.82		- -		- -
Total	17,172		$24.04		-		-
(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.

RG&E had no issuer purchases of equity securities during the quarter ended September 30, 2006.

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 2, 2006	ENERGY EAST CORPORATION                   (Registrant) By   /s/Robert D. Kump                                          Robert D. Kump            Vice President, Controller            & Chief Accounting Officer            (Principal Accounting Officer)
Date:  November 2, 2006	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	4-8	Eighth Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of July 24, 2006, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000.
	31-1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	*32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Rochester Gas and  Electric Corporation	31-1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	*32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

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