Energy East (EAS) 10-Q 2006 Q1 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  March 31, 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 (585) 546-2700	16-0612110

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes    X      No        

Indicate by check mark whether the registrant is 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 April 28, 2006, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	147,678,358
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 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 12 14
	Rochester Gas and Electric Corporation   Condensed Balance SheetsCondensed Statements of IncomeCondensed Statements of Cash FlowsCondensed Statements of Retained EarningsCondensed Statements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	16 18 19 20 20 21 22
	Notes to Condensed Financial Statements	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	30
	PART II - OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 6.	Exhibits	31
Signatures		32
Exhibit Index		33

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. CMPCentral Maine Power Company is a regulated utility primarily engaged in transmitting and distributing electricity generated by others to retail customers in Maine. CNGConnecticut Natural Gas Corporation is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut. 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. 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. SCGThe Southern Connecticut Gas Company is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut.
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 EPSearnings per share ESCOenergy service company	ESCOenergy service company FASBFinancial Accounting Standards Board FERCFederal Energy Regulatory Commission 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. LICAPlocational installed capacity (pricing mechanism in the New England market as currently proposed) MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations MPUCMaine Public Utilities Commission MW, MWh megawatt, megawatt hour

Glossary (continued)

NEPOOL New England Power Pool

NUGnonutility generator

NYISONew York Independent
System Operator

NYPANew York Power Authority

NYPSCNew York State Public
Service Commission

OCCThe Office of Consumer Counsel
in the State of Connecticut

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


RTORegional Transmission Organization

SARsstock appreciation rights

SECUnited States Securities and
Exchange Commission

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

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,
• the effects of the NYPSC End State model experiment adopted in its Collaborative on End State of Energy Competition,
• enactment and 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 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 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 ended March 31,	2006	2005
(Thousands, except per share amounts)
Operating Revenues
Utility	$1,542,205	$1,489,519
Nonutility	154,349	147,759
Total Operating Revenues	1,696,554	1,637,278
Operating Expenses
Electricity purchased and fuel used in generation
Utility	377,342	356,262
Nonutility	89,389	80,929
Natural gas purchased
Utility	509,769	475,951
Nonutility	43,774	43,179
Other operating expenses	186,106	181,673
Maintenance	52,464	42,515
Depreciation and amortization	69,404	67,921
Other taxes	73,865	68,031
Total Operating Expenses	1,402,113	1,316,461
Operating Income	294,441	320,817
Other (Income)	(10,400)	(7,824)
Other Deductions	4,017	1,975
Interest Charges, Net	78,720	69,736
Preferred Stock Dividends of Subsidiaries	282	476
Income Before Income Taxes	221,822	256,454
Income Taxes	88,581	102,088
Net Income	$133,241	$154,366
Earnings per Share, basic	$.91	$1.05
Earnings per Share, diluted	$.90	$1.05
Dividends Paid per Share	$.29	$.275
Average Common Shares Outstanding, basic	147,034	146,875
Average Common Shares Outstanding, diluted	147,679	147,196

Thenotes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	March 31, 2006	Dec. 31, 2005
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$178,989	$120,009
Investments available for sale	11,575	192,925
Accounts receivable and unbilled revenues, net	1,040,382	933,680
Fuel and natural gas in storage, at average cost	125,972	278,590
Materials and supplies, at average cost	34,397	33,886
Deferred income taxes	18,711	-
Derivative assets	94,125	278,855
Prepayments and other current assets	126,094	92,613
Total Current Assets	1,630,245	1,930,558
Utility Plant, at Original Cost
Electric	5,430,210	5,403,134
Natural gas	2,585,112	2,574,574
Common	535,321	450,641
	8,550,643	8,428,349
Less accumulated depreciation	2,841,517	2,764,399
Net Utility Plant in Service	5,709,126	5,663,950
Construction work in progress	47,935	119,504
Total Utility Plant	5,757,061	5,783,454
Other Property and Investments	199,300	203,159
Regulatory and Other Assets
Regulatory assets
Deferred income taxes	-	13,482
Nuclear plant obligations	294,777	309,888
Unfunded future income taxes	177,984	117,241
Environmental remediation costs	136,533	135,376
Unamortized loss on debt reacquisitions	58,831	60,933
Nonutility generator termination agreements	87,310	86,890
Other	329,436	384,173
Total regulatory assets	1,084,871	1,107,983
Other assets
Goodwill, net	1,525,353	1,525,353
Prepaid pension benefits	748,169	741,831
Derivative assets	59,773	67,907
Other	122,164	127,463
Total other assets	2,455,459	2,462,554
Total Regulatory and Other Assets	3,540,330	3,570,537
Total Assets	$11,126,936	$11,487,708

Thenotes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	March 31, 2006	Dec. 31, 2005
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$286,568	$326,527
Notes payable	19,000	121,347
Accounts payable and accrued liabilities	435,525	629,158
Interest accrued	59,831	46,522
Taxes accrued	108,084	-
Deferred income taxes	-	80,984
Derivative liabilities	41,129	2,019
Other	126,102	186,452
Total Current Liabilities	1,076,239	1,393,009
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	784,361	797,544
Deferred income taxes	19,571	-
Gain on sale of generation assets	181,204	173,216
Pension benefits	21,137	22,798
Natural gas hedges	-	49,205
Other	104,047	124,251
Total regulatory liabilities	1,110,320	1,167,014
Other liabilities
Deferred income taxes	1,057,485	1,033,287
Nuclear plant obligations	227,872	234,907
Other postretirement benefits	430,231	428,691
Environmental remediation costs	168,374	166,462
Other	454,248	499,968
Total other liabilities	2,338,210	2,363,315
Total Regulatory and Other Liabilities	3,448,530	3,530,329
Debt owed to subsidiary holding solely parent debentures	355,670	355,670
Other long-term debt	3,350,609	3,311,395
Total long-term debt	3,706,279	3,667,065
Total Liabilities	8,231,048	8,590,403
Commitments and Contingencies	-	-
Preferred Stock of Subsidiaries  Redeemable solely at the option of subsidiaries	24,631	24,631
Common Stock Equity  Common stock	1,478	1,478
Capital in excess of par value	1,487,355	1,489,256
Retained earnings	1,385,147	1,294,580
Accumulated other comprehensive (loss) income	(472)	89,085
Treasury stock, at cost	(2,251)	(1,725)
Total Common Stock Equity	2,871,257	2,872,674
Total Liabilities and Stockholders' Equity	$11,126,936	$11,487,708

Thenotes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Three months ended March 31,	2006	2005
(Thousands)
Operating Activities
Net income	$133,241	$154,366
Adjustments to reconcile net income to net cash provided  by operating activities
Depreciation and amortization	98,908	89,615
Income taxes and investment tax credits deferred, net	(9,477)	(1,527)
Pension income	(7,466)	(6,393)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	(105,457)	(77,927)
Inventory	152,107	146,590
Prepayments and other current assets	5,730	(17,605)
Accounts payable and accrued liabilities	(167,313)	(26,583)
Interest accrued	13,309	16,098
Taxes accrued	71,002	80,852
Customer refund	(13,998)	(23,639)
Other current liabilities	(80,323)	(71,969)
Pension contributions	-	(54,000)
Other assets	56,519	77,027
Other liabilities	(50,988)	(33,632)
Net Cash Provided by Operating Activities	95,794	251,273
Investing Activities
Utility plant additions	(58,461)	(61,822)
Other property and investments additions	(1,207)	(34,859)
Other property and investments sold	691	13,867
Maturities of current investments available for sale	380,315	418,530
Purchases of current investments available for sale	(198,965)	(407,950)
Other	-	105
Net Cash Provided by (Used in) Investing Activities	122,373	(72,129)
Financing Activities
Issuance of common stock	-	991
Repurchase of common stock	(6,106)	(929)
Book overdraft	(7,166)	(2,847)
Long-term note issuances	40,000	-
Long-term note repayments	(40,894)	(28,358)
Notes payable three months or less, net	(95,489)	(85,490)
Notes payable issuances	38,275	7,000
Notes payable repayments	(45,133)	(3,000)
Dividends on common stock	(42,674)	(35,830)
Net Cash Used in Financing Activities	(159,187)	(148,463)
Net Increase in Cash and Cash Equivalents	58,980	30,681
Cash and Cash Equivalents, Beginning of Period	120,009	111,465
Cash and Cash Equivalents, End of Period	$178,989	$142,146

Thenotes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation CondensedConsolidated Statements of Retained Earnings - (Unaudited)
Three months ended March 31,	2006	2005
(Thousands)
Balance, Beginning of Period	$1,294,580	$1,201,533
Add net income	133,241	154,366
	1,427,821	1,355,899
Deduct dividends on common stock	42,674	40,364
Balance, End of Period	$1,385,147	$1,315,535

Thenotes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
Three months ended March 31,	2006	2005
(Thousands)
Net income	$133,241	$154,366
Other comprehensive income, net of tax
Net unrealized (losses) on investments, net of income tax     benefit of $167 for 2006 and $ - for 2005	(252)	(23)
Net unrealized (losses) gains on derivatives qualified as hedges, net of     income tax benefit (expense) of $76,497 for 2006 and $(28,868)     for 2005	(120,202)	48,356
Reclassification adjustment for derivative losses included in     net income, net of income tax (benefit) of $(20,416) for 2006 and     $(21,371) for 2005	30,897	32,343
Net unrealized (losses) gains on derivatives qualified as hedges	(89,305)	80,699
Total other comprehensive (loss) income	(89,557)	80,676
Comprehensive Income	$43,684	$235,042

Thenotes on pages 24 through 29 are an integral part of the condensed consolidated financial statements.

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

Energy East Corporation

Overview

Energy East's primary operations, 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, 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. SCG received approval for new rates that became effective January 1, 2006 and CNG's rates will be reviewed by the DPUC later this year.

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 expects to implement a new customer care system in the fourth quarter of 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, 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 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 during the next five years, including approximately $900 million dedicated to electric reliability. We focus our financing activities on maintaining adequate liquidity and credit quality and minimizing our cost of capital.

Our Management's Discussion and Analysis of Financial Condition and Results of Operations for the quarter ended March 31, 2006, should be read in conjunction with our Management's Discussion and Analysis of Financial Condition and Results of Operations, 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 a 12-month 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 continue to be 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 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.

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 Plan Extension: 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. As part of its filing, NYSEG proposed to decrease customers' bills prior to the commencement of the rate plan extension by implementing a customer bill credit effective for the four-month period from September 1, 2006, through December 31, 2006. In particular, NYSEG proposed to return to its electric customers $24 million from its ASGA, initially created as a result of the sale of NYSEG's generating stations. The ASGA has been enhanced during NYSEG's current rate plan with its customers' share of excess earnings. NYSEG also proposed, beginning on January 1, 2007, to reduce its nonbypassable wires charge by $163 million and increase delivery rates by $92 million, thereby maintaining an annualized overall electricity delivery rate decrease of approximately $71 million, or 9.5%. NYSEG pr oposed to accomplish the reduction in its nonbypassable wires charge, which would more than offset the increase in delivery rates, 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.

On January 9, 2006, NYSEG filed with the NYPSC revisions and updates to its September 2005 filing, while maintaining the overall framework of its proposed rate plan extension. In its January 2006 filing, NYSEG proposed to reduce its nonbypassable wires charge by an

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

Energy East Corporation

additional $5 million, for a revised reduction of $168 million, and proposed to increase its delivery rates by an additional $12 million for a revised increase of $104 million. As a result of those revisions and updates, NYSEG reduced its proposed annualized overall electricity delivery rate decrease to $64 million, or 8.6%.

In a ruling issued on February 10, 2006, the ALJ in this proceeding denied a motion submitted by two ESCOs in January 2006 to dismiss the portion of the rate filing that requests NYPSC approval of NYSEG's Voice Your Choice program. The Consumer Protection Board, the Public Utility Law Project, and NYSEG opposed the ESCOs' motion. NYSEG stated in its filing that the motion was not supported by law, would deny NYSEG due process, including an evidentiary hearing, and distorted the evidence presented by NYSEG regarding its Voice Your Choice program. In the ruling, the ALJ concluded that the NYPSC's August 2004 Policy Statement was not intended as a binding order and, as a matter of law, does not preclude NYSEG from proposing to extend its Voice Your Choice program. The ALJ also determined that NYSEG's rate plan extension proceeding is the proper forum for consideration of issues presented in its proposal to extend its Voice Your Choice program.

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%, which would equate to an overall delivery rate decrease of approximately $226 million, or about 36.5%, including NYSEG's proposed nonbypassable wires charge reduction for the 2007 rate year. Staff neither rebutted nor addressed NYSEG's revised and updated rate plan extension proposal, including its NUG levelization proposal. Staff also opposed NYSEG's proposal to extend its Voice Your Choice program. Staff has also raised several retroactive accounting issues which, if accepted by the NYPSC, could have a material effect on 2006 earnings. NYSEG believes Staff's positions have no merit and is vigorously contesting these issues.

NYSEG filed its rebuttal case on February 21, 2006, responding to Staff's one-year rate case proposal by proposing to increase delivery rates by approximately $58 million, beginning on January 1, 2007. NYSEG also proposed to amortize an equivalent portion of the ASGA liability through a customer bill credit in the nonbypassable wires charge to offset the delivery increase, resulting in no delivery rate change for 2007. Although NYSEG's rebuttal testimony responds to Staff's one-year rate case proposal, NYSEG continues to support the adoption of a six-year rate plan extension, including its NUG levelization proposal to moderate the delivery rate increase, and its proposal to extend its Voice Your Choice program.

Hearings in this proceeding concluded on April 21, 2006, and various parties filed briefs on April 26, 2006. NYSEG cannot predict the outcome of this proceeding.

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 the companies are allocated an aggregate of over 360 MWs of Niagara Power Project power based on their

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

Energy East Corporation

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 should 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. On January 3, 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. On January 10, 2006, NYSEG and RG&E filed a response to NYPA's answer. NYSEG and RG&E are unable to predict the outcome of this proceeding.

CMP Alternative Rate Plan:On December 7, 2005, CMP and the Office of the Public Advocate filed with the MPUC a stipulation for an extension of CMP's ARP 2000. This stipulation is also supported by low-income customer advocates and a coalition of industrial energy customers has signed the stipulation agreement. The stipulation maintains the provisions of CMP's ARP 2000 and proposes a three-year extension with four additional items. The stipulation provides for a 0.5% increase in the scheduled productivity offset of 2.75% for July 2006 and provides for productivity offsets averaging 2% for 2008, 2009 and 2010. The stipulation adds $2.2 million in assistance for low-income customers annually starting in 2006. Under the stipulation, CMP agrees to educate its customers on the regional benefits of adjusting usage during peak hours and demand periods and also agrees to limit the promotion of increased usage during specified higher demand periods. Finally, CM P agrees to commit to investing an additional $25 million through 2010 for enhancements to the reliability, safety and security of its distribution system.

On February 1, 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. CMP will respond to the recommendations in its brief to be filed on May 19, 2006. The MPUC's decision is expected in the second quarter of 2006. CMP cannot predict the outcome of this proceeding.

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

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

Energy East Corporation

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 retail access initiatives that are based on 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 urging rejection of the proposal and objecting to the proposal to the extent that it will require all utilities to adopt a"PowerSwitch" type program. In an order dated December 22, 2005, 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 also approved, with modifications, Central Hudson's proposed ESCO Referral Program . 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. The NYPSC permitted NYSEG to address the ESCO Referral Program within the context of its current rate case described above. Based on these latest developments, it is unclear whether or not NYSEG will be able to extend its Voice Your Choice program as a part of its ongoing electric rate proceeding.

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 LICAP market proposal based on an administratively set demand curve. In June 2005 the FERC ALJ issued an initial decision, essentially adopting the ISO-NE LICAP market proposal with minor modifications.

CMP and other parties that oppose the ISO-NE LICAP 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 LICAP proposal in the recommended decision. In addition, the MPUC, CMP, the DPUC (representing the state of Connecticut) and the OCC, joined with several Massachusetts parties and filed briefs with the FERC asking that the parties conduct settlement discussions to consider alternatives, and that the FERC consider other alternatives to the LICAP market proposal. In response to these protests, the FERC has delayed any possible implementation of LICAP until October 1, 2006, at the earliest and granted oral arguments to consider opposition to LICAP and possible alternatives. Following oral arguments, the FERC granted the request to conduct settlement discussions to consider alternatives. Settlement discussions began in November 2005 and on January 31, 2006, the settlement ALJ

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

Energy East Corporation

reported to the FERC that most of the parties had reached an agreement in principle on an alternative to LICAP. The LICAP alternative will provide fixed transitional capacity payments from 2006 until 2010 and then provide capacity payments based on a Forward Capacity Market Auction thereafter. CMP opposed the LICAP alternative at a NEPOOL participants meeting. That alternative has been filed with the FERC and various parties have submitted comments in support of or in opposition to the alternative. The ISO-NE has requested that the FERC rule on the LICAP settlement by July 2006 to allow implementation in December 2006.

Presently, CMP and the MPUC, among other parties, are opposed to the LICAP proposal and the alternative, because either proposal could have an adverse effect on Maine's economy by increasing its standard offer rates an estimated 5% to 10%. Maine lawmakers held hearings in March to study the possibility of Maine withdrawing from ISO-NE and will conduct further inquiry regarding regional energy markets and generation deregulation. CMP cannot predict the outcome of these settlement discussions, how the FERC will rule or what modifications the FERC might make to the filing.

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.

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. CNG expects to submit a general rate filing by the end of September 2006.

Proposed New Accounting Standard

Pension Exposure Draft:On March 31, 2006, the FASB issued an Exposure Draft,Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106 and 132(R). The Exposure Draft was issued as Phase I of a two-phase project to comprehensively reconsider existing guidance on accounting for pension and postretirement benefits. Phase II of the project is a multi-year phase that will address remaining issues and be conducted in collaboration with the International Accounting Standards Board. The Exposure Draft proposes to require an entity to: recognize a plan's over- or under-

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

Energy East Corporation

funded status on its balance sheet; recognize actuarial gains and losses and prior service costs as a component of other comprehensive income, and adjust accumulated other comprehensive income as amounts are recognized as components of net periodic benefit cost; adjust retained earnings for any remaining transition asset or obligation, net of tax; revise certain related disclosures; and measure plan assets and benefit obligations as of the date of the balance sheet.

Comments on the Exposure Draft are due at the end of May 2006. One or more public roundtable meetings will be held in late June 2006 and a final Statement is expected to be issued in September 2006. For public companies the recognition of a plan's funded status and related disclosure provisions are proposed to be effective for fiscal years ending after December 15, 2006, with earlier application encouraged and retrospective application (revision of prior periods) required. The provisions related to measuring plan assets and benefit obligations as of the date of the balance sheet would be applied for public companies for fiscal years beginning after December 15, 2006, and are not to be applied retrospectively, but earlier application would be encouraged. Energy East and RG&E each already measure plan assets and benefit obligations as of the balance sheet date. Adoption of a final standard consistent with the Exposure Draft effective for the fiscal year ended December 31, 2006, could have a material eff ect on Energy East's and RG&E's financial position by reducing prepaid benefits and common stock equity, but is not expected to have a material effect on their results of operations or cash flows.

(a) Liquidity and Capital Resources

Operating Activities:Significant operating activities that affected cash flows during the first three months of 2006 included the following:

• A reduction in accounts payable of $167 million that reduced cash primarily resulting from payments for natural gas purchases,
• Increased receivables that reduced cash by $105 million, and
• A reduction in natural gas inventory that increased cash by $152 million.

While the foregoing are normal activities in the first quarter, their magnitudes are larger than normal due to higher energy prices.

Investing Activities: Capital spending for the three months ended March 31, 2006, was $58 million. We project capital spending of $442 million for 2006 and expect to pay for it principally with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, and compliance with environmental requirements and governmental mandates, and includes RG&E's transmission project and new customer care system.

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

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

Energy East Corporation

We repurchased 250,000 shares of our common stock in February 2006, primarily for grants of restricted stock. In February 2006 we awarded 248,320 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 $24.83 per share of common stock awarded.

Beginning in the fourth quarter of 2005 shares needed for our Investor Services Program are purchased in the open market. Cash outflows for the first quarter of 2006 for dividends on our common stock equal the amount of common stock dividends payable because shares required for dividends reinvested in our common stock are now purchased in the open market.

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.

Energy East is planning to call in the third quarter of 2006, at par, its $345 million, 8 1/4% Capital Securities (mandatorily redeemable trust preferred securities). We expect to write off approximately $11 million of unamortized debt expense when the 8 1/4% Capital Securities are called. In November 2006 Energy East's $232 million 5.75% note matures. Energy East has entered into several arrangements to hedge interest rates in connection with the refinancing of these securities.

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%.

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

Energy East Corporation

(b)Results of Operations

Three months ended March 31,	2006	2005
(Thousands, except per share amounts)
Operating Revenues	$1,696,554	$1,637,278
Operating Income	$294,441	$320,817
Net Income	$133,241	$154,366
Average Common Shares Outstanding, basic	147,034	146,875
Earnings per Share, basic	$.91	$1.05
Earnings per Share, diluted	$.90	$1.05
Dividends Paid per Share	$.29	$.275

Earnings per Share

Earnings per share, basic for the quarter ended March 31, 2006, decreased 14 cents compared to the quarter ended March 31, 2005, primarily because of:

• A decrease of 6 cents for higher operating and maintenance expense including 4 cents for storm restoration,
• A decrease of 4 cents for higher interest expense resulting from higher rates on short-term and variable rate debt and higher carrying costs on regulatory liabilities, and
• A decrease of 3 cents resulting from lower electricity sales due to mild winter weather.

Natural gas margins were essentially unchanged from 2005 as the effect of lower delivery volumes was largely offset by weather normalization accruals.

Operating Results for the Electric Delivery Business

Three months ended March 31,	2006	2005
(Thousands)
Retail Deliveries (MWh)	7,764	8,076
Retail Commodity Sales (MWh) (1)	1,224	1,326
Wholesale Sales (MWh)	2,503	1,984
Operating Revenues	$785,306	$768,322
Operating Expenses	$632,355	$584,436
Operating Income	$152,951	$183,886

(1) Also included in Retail Deliveries.

Operating Revenues:The $17 million increase in operating revenues for the first quarter of 2006 was primarily the result of:

• An increase of $41 million in wholesale sales resulting from higher volumes for NYSEG and RG&E,
• An increase of $12 million due to higher prices for retail electric energy supplied by NYSEG and RG&E under various commodity options where they provide supply, and
• An increase of $28 million in other revenues including $19 million in lower accruals for earnings sharing. This $19 million increase included $14 million for the finalization of the actual amount for 2005 per the annual compliance filings by NYSEG and RG&E.

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

Energy East Corporation

Those increases were partially offset by:

• A decrease of $23 million resulting from reduced electricity sales under the companies' commodity programs due largely to warmer winter weather,
• A decrease of $10 million resulting from lower retail deliveries due largely to warmer winter weather, and
• A decrease of $31 million resulting from lower transition charges. The transition charge reflects the difference between the market price of electricity and the prices set by our long-term electricity supply contracts. This charge decreases as market prices increase. Changes in the transition charge have no effect on earnings.

Operating Expenses: The $48 million increase in operating expenses for the first quarter of 2006 was primarily the result of:

• An increase of $22 million in purchased power costs resulting from $36 million for higher wholesale market prices for electricity, reduced by $14 million due to the expiration of a major NUG contract,
• An increase of $20 million in operating and maintenance costs including $10 million for storm restoration, $4 million for uncollectible expense, $2 million for stock option expense and $4 million for a variety of other items, and
• An increase of $5 million in other taxes.

Operating Results for the Natural Gas Delivery Business

Three months ended March 31,	2006	2005
(Thousands)
Retail Deliveries (Dth)	75,645	86,257
Wholesale Sales (Dth)	47	350
Operating Revenues	$756,899	$721,197
Operating Expenses	$619,961	$587,065
Operating Income	$136,938	$134,132

Operating Revenues: The $36 million increase in operating revenues for the first quarter of 2006 was primarily the result of:

• An increase of $110 million primarily as a result of higher market prices of natural gas that were passed on to customers,
• An increase of $9 million as a result of higher base rates approved for SCG effective January 1, 2006,
• An increase of $8 million due to higher billings resulting from weather normalization adjustments, and
• An increase of $6 million in other revenues.

Those increases were partially offset by a decrease of $97 million as a result of lower delivery volumes due largely to warmer winter weather.

Operating Expenses: The $33 million increase in operating expenses for the first quarter of 2006 was primarily the result of:

• An increase of $105 million due to higher market prices for purchased natural gas.

That increase was partially offset by:

• A reduction of $72 million due to lower volumes of natural gas purchases.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	March 31, 2006	Dec. 31, 2005
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$37,705	$28,752
Investments available for sale	-	53,325
Accounts receivable and unbilled revenues, net	212,242	193,807
Fuel and natural gas in storage, at average cost	15,951	57,434
Materials and supplies, at average cost	14,223	13,204
Deferred income taxes	8,869	-
Derivative assets	53	21,597
Prepayments and other current assets	50,404	27,047
Total Current Assets	339,447	395,166
Utility Plant, at Original Cost
Electric	1,264,234	1,258,330
Natural gas	575,252	572,943
Common	197,601	199,015
	2,037,087	2,030,288
Less accumulated depreciation	599,278	583,557
Net Utility Plant in Service	1,437,809	1,446,731
Construction work in progress	24,215	18,748
Total Utility Plant	1,462,024	1,465,479
Other Property and Investments	11,755	11,634
Regulatory and Other Assets
Regulatory assets
Deferred income taxes	-	12,007
Nuclear plant obligations	176,087	183,039
Environmental remediation costs	24,965	25,013
Unamortized loss on debt reacquisitions	13,494	14,336
Nonutility generator termination agreement	79,938	82,243
Other	128,229	127,867
Total regulatory assets	422,713	444,505
Other assets
Prepaid pension benefits	51,881	48,368
Other	18,381	17,121
Total other assets	70,262	65,489
Total Regulatory and Other Assets	492,975	509,994
Total Assets	$2,306,201	$2,382,273

Thenotes on pages 24 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	March 31, 2006	Dec. 31, 2005
(Thousands)
Liabilities
Current Liabilities
Accounts payable and accrued liabilities	$82,392	$123,145
Interest accrued	7,894	9,830
Taxes accrued	30,623	16,438
Deferred income taxes	-	698
Other	39,565	37,958
Total Current Liabilities	160,474	188,069
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	182,553	182,346
Deferred income taxes	16,349	-
Unfunded future income taxes	34,612	89,104
Gain on sale of generation assets	127,570	111,262
Natural gas hedges	-	21,969
Other	50,069	51,015
Total regulatory liabilities	411,153	455,696
Other liabilities
Deferred income taxes	168,463	167,785
Nuclear waste disposal	109,702	108,570
Other postretirement benefits	80,312	80,045
Environmental remediation costs	36,554	36,506
Other	51,792	65,146
Total other liabilities	446,823	458,052
Total Regulatory and Other Liabilities	857,976	913,748
Long-term debt	697,969	697,951
Total Liabilities	1,716,419	1,799,768
Commitments and Contingencies	-	-
Common Stock Equity
Common stock	194,429	194,429
Capital in excess of par value	483,418	483,252
Retained earnings	33,834	28,549
Accumulated other comprehensive (loss)	(4,661)	(6,487)
Treasury stock, at cost	(117,238)	(117,238)
Total Common Stock Equity	589,782	582,505
Total Liabilities and Stockholder's Equity	$2,306,201	$2,382,273

Thenotes on pages 24 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Income - (Unaudited)
Three months ended March 31,	2006	2005
(Thousands)
Operating Revenues
Electric	$185,638	$160,156
Natural gas	160,873	155,564
Total Operating Revenues	346,511	315,720
Operating Expenses
Electricity purchased and fuel used in generation	75,905	64,039
Natural gas purchased	108,833	104,148
Other operating expenses	38,765	39,309
Maintenance	10,908	10,398
Depreciation and amortization	17,818	17,771
Other taxes	17,114	15,177
Total Operating Expenses	269,343	250,842
Operating Income	77,168	64,878
Other (Income)	(1,064)	(1,554)
Other Deductions	182	128
Interest Charges, Net	14,283	13,982
Income Before Income Taxes	63,767	52,322
Income Taxes	23,482	21,394
Net Income	$40,285	$30,928

Thenotes on pages 24 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Cash Flows - (Unaudited)
Three months ended March 31,	2006	2005
(Thousands)
Operating Activities
Net income	$40,285	$30,928
Adjustments to reconcile net income to net cash provided  by operating activities
Depreciation and amortization	33,952	34,167
Income taxes and investment tax credits deferred, net	9,293	10,858
Pension income	(3,514)	(4,513)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	(18,435)	(21,163)
Inventory	40,464	30,447
Prepayments and other current assets	(23,322)	(14,659)
Accounts payable and accrued liabilities	(23,828)	47,160
Interest accrued	(1,936)	(1,236)
Taxes accrued	14,144	8,736
Customer refund	(13,998)	(23,639)
Other current liabilities	(23,400)	(13,494)
Other assets	6,688	(3,979)
Other liabilities	(30,205)	2,606
Net Cash Provided by Operating Activities	6,188	82,219
Investing Activities
Utility plant additions	(13,508)	(9,868)
Maturity of current investments available for sale	137,950	102,825
Purchases of current investments available for sale	(84,625)	(147,850)
Other	(381)	108
Net Cash Provided by (Used in) Investing Activities	39,436	(54,785)
Financing Activities
Book overdraft	(1,671)	(1,658)
Dividends on common stock	(35,000)	(35,000)
Net Cash Used in Financing Activities	(36,671)	(36,658)
Net Increase (Decrease) in Cash and Cash Equivalents	8,953	(9,224)
Cash and Cash Equivalents, Beginning of Period	28,752	11,834
Cash and Cash Equivalents, End of Period	$37,705	$2,610

Thenotes on pages 24 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Retained Earnings - (Unaudited)
Three months ended March 31,	2006	2005
(Thousands)
Balance, Beginning of Period	$28,549	$19,560
Add net income	40,285	30,928
	68,834	50,488
Deduct dividends on common stock	35,000	35,000
Balance, End of Period	$33,834	$15,488

Thenotes on pages 24 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Comprehensive Income- (Unaudited)
Three months ended March 31,	2006	2005
(Thousands)
Net income	$40,285	$30,928
Other comprehensive income, net of tax
Net unrealized gains on investments, net of income tax     (expense) of $(26) for 2006 and $ - for 2005	39	- -
Net unrealized (losses) gains on derivatives qualified as hedges, net of     income tax benefit (expense) of $826 for 2006 and $(1,586) for 2005	(1,246)	2,417
Reclassification adjustment for derivative losses (gains) included in net      income, net of income tax (benefit) expense of $(2,011) for 2006      and $391 for 2005	3,033	(590)
Net unrealized gains on derivatives qualified as hedges	1,787	1,827
Total other comprehensive income	1,826	1,827
Comprehensive Income	$42,111	$32,755

Thenotes on pages 24 through 29 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 Management's Discussion and Analysis of Financial Condition and Results of Operations for the quarter ended March 31, 2006, should be read in conjunction with its Management's Discussion and Analysis of Financial Condition and Results of Operations, financial statements and notes contained in its report on Form 10-K 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 a 12-month 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.

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

Proposed New Accounting Standard

Pension Exposure Draft: See Energy East's Part I, Item 2 - MD&A - Proposed New Accounting Standard, for this discussion.

(a)Liquidity and Capital Resources

Operating Activities: Cash flows from operating activities 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.

Investing Activities: Capital spending for the first three months of 2006 was $14 million. RG&E projects capital spending of $182 million for 2006 and expects to pay for it principally with cash on hand and internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, and compliance with environmental requirements and governmental mandates, and includes a transmission project and a new customer care system.

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

Rochester Gas and Electric Corporation

Financing Activities: During the three months ended March 31, 2006, RG&E paid a common dividend of $35 million.

(b)Results of Operations

Three months ended March 31,	2006	2005
(Thousands)
Operating Revenues	$346,511	$315,720
Operating Income	$77,168	$64,878
Net Income	$40,285	$30,928

Earnings

RG&E's net income for the quarter ended March 31, 2006, increased $9 million compared to the quarter ended March 31, 2005, primarily because of higher net margins on electricity sales.

Operating Results for the Electric Delivery Business

Three months ended March 31,	2006	2005
(Thousands)
Retail Deliveries (MWh)	1,748	1,755
Retail Commodity Sales (MWh) (1)	897	1,021
Wholesale sales (MWh)	1,008	557
Operating Revenues	$185,638	$160,156
Operating Expenses	$137,521	$122,449
Operating Income	$48,117	$37,707

(1) Also included in Retail Deliveries.

Operating Revenues: The $25 million increase in operating revenues for the first quarter of 2006 was primarily the result of:

• An increase of $25 million due to higher wholesale revenues,
• An increase of $22 million due to higher market prices for retail deliveries supplied under various commodity options where RG&E provides supply, and
• An increase of $15 million in other revenues including a reduction of $9 million in the accrual for earnings sharing reflecting the finalization of the actual amount for 2005 per the annual compliance filing.

Those increases were partially offset by:

• A decrease of $37 million resulting from lower average prices on deliveries. Higher market prices for electric entitlements are passed through to customers through a lower transition charge. The transition charge reflects the difference between the market price of electricity and the prices set by RG&E's long-term electricity supply contracts. This charge decreases as market prices increase. Changes in the transition charge have no effect on earnings.

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

Rochester Gas and Electric Corporation

Operating Expenses: The $15 million increase in operating expenses for the first quarter of 2006 was primarily the result of:

• An increase of $12 million for purchased power costs, and
• An increase of $2 million for other taxes.

Operating Results for the Natural Gas Delivery Business

Three months ended March 31,	2006	2005
(Thousands)
Retail Deliveries (Dth)	20,397	23,700
Operating Revenues	$160,873	$155,564
Operating Expenses	$131,822	$128,393
Operating Income	$29,051	$27,171

Operating Revenues: The $5 million increase in operating revenues for the first quarter of 2006 was primarily the result of:

• Higher natural gas prices that were passed on to customers.

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

• Higher prices for purchased natural gas.

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, 5, 6, 7, 8, 9, 10, 11
RG&E	1, 2, 4, 6, 8, 9, 10, 11

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 presented 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 $12 million at March 31, 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 March 31, 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 ended March 31,	2006	2005
(Thousands)
Energy East
Interest and dividend income	$(3,776)	$(2,350)
Allowance for funds used during construction	(489)	(306)
Gains from hedge activity	(2,438)	(1,920)
Earnings from equity investments	(1,059)	(1,149)
Miscellaneous	(2,638)	(2,099)
Total other (income)	$(10,400)	$(7,824)
Losses from hedge activity	$2,324	-
Donations, civic and political	848	$638
Miscellaneous	845	1,337
Total other deductions	$4,017	$1,975
RG&E
Interest and dividend income	$(707)	$(518)
Allowance for funds used during construction	(332)	(54)
Gains from hedge activity	-	(842)
Miscellaneous	(25)	(140)
Total other (income)	$(1,064)	$(1,554)
Miscellaneous	$182	$128
Total other deductions	$182	$128

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 ended March 31,	2006	2005
(Thousands)
Basic average common shares outstanding	147,034	146,875
Restricted stock awards	645	321
Potentially dilutive common shares	144	416
Options issued with SARs	(144)	(416)
Dilutive average common shares	147,679	147,196

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 March 31 were: 1.5 million in 2006 and 0.9 million in 2005.

Note 4. Income Taxes

RG&E's effective tax rate for the first quarter of 2006 is lower than the statutory rate, primarily due to the flow-through effect of equity AFUDC in the determination of the projected 2006 annual effective rate. The projected tax adjustment for equity AFUDC is approximately $7 million and is larger than in recent years because of RG&E's transmission project.

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 independent, ongoing, 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. We are not able to determine if we have variable interests with respect to power purchase contracts with seven of the NUGs because we are unable to obtain the information necessary to (1) determine if any of the seven 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 those NUGs. We routinely r equest necessary information from the seven NUGs, and will continue to do so, but no NUG has yet provided the requested information. We did not consolidate any NUGs as of March 31, 2006, or December 31, 2005.

We purchase electricity from the seven 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. The combined purchases from the seven NUGs totaled approximately $91 million for the three months ended March 31, 2006, and $94 million for the three months ended March 31, 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.

Note 7. 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, was $0.1 million for the quarter ended March 31, 2005, and that amount was 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 earnings per share as reported for the quarter ended March 31, 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 quarter ended March 31, 2006, was $3.9 million.

Note 8. Accounts Receivable

Energy East's accounts receivable include unbilled revenues of $233 million at March 31, 2006, and $315 million at December 31, 2005. Our accounts receivable are shown net of an allowance for doubtful accounts of $58 million at March 31, 2006, and $53 million at December 31, 2005.

RG&E's accounts receivable include unbilled revenues of $46 million at March 31, 2006, and $54 million at December 31, 2005. RG&E's accounts receivable are shown net of an allowance for doubtful accounts of $14 million at March 31, 2006, and $13 million at December 31, 2005.

Note 9. Retirement Benefits

Components of net periodic benefit (income) cost

	Pension Benefits		Postretirement Benefits
Three months ended March 31,	2006	2005	2006	2005
(Thousands)
Energy East
Service cost	$9,198	$9,285	$1,567	$1,549
Interest cost	32,433	32,031	7,879	7,980
Expected return on plan assets	(54,878)	(52,910)	(483)	(556)
Amortization of prior service cost	1,176	1,249	(1,895)	(1,895)
Recognized net actuarial loss	4,605	3,952	2,076	2,635
Amortization of transition obligation	-	-	1,700	1,700
Net periodic benefit (income) cost	$(7,466)	$(6,393)	$10,844	$11,413
RG&E
Service cost	$1,171	$1,339	$166	$272
Interest cost	6,825	6,803	1,107	1,444
Expected return on plan assets	(11,490)	(12,021)	-	-
Amortization of prior service cost	370	280	215	250
Recognized net actuarial (gain) loss	(390)	(914)	(343)	133
Amortization of transition obligation	-	-	457	464
Net periodic benefit (income) cost	$(3,514)	$(4,513)	$1,602	$2,563

Note 10. 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. We completed our annual impairment testing and determined that we had no impairment of goodwill or unamortized intangible assets at September 30, 2005. Energy East and RG&E amortize intangible assets with finite lives (amortized intangible assets) and review them for impairment.

The carrying amount of our goodwill was the same at March 31, 2006, and December 31, 2005. The amounts of goodwill by operating segment (in thousands) are:

Electric Delivery	Natural Gas Delivery	Other	Total
$844,491	$676,588	$4,274	$1,525,353

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

Note 11. 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 March 31,	2006	2005	2006	2005
(Thousands)
Energy East
Electric Delivery	$785,306	$768,322	$58,749	$83,101
Natural Gas Delivery	756,899	721,197	72,728	70,303
Other	154,349	147,759	1,764	962
Total	$1,696,554	$1,637,278	$133,241	$154,366
RG&E
Electric Delivery	$185,638	$160,156	$24,695	$16,172
Natural Gas Delivery	160,873	155,564	15,590	14,756
Total	$346,511	$315,720	$40,285	$30,928

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. 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.

As of April 2006 the portion of load for fixed rate option customers not supplied by owned generation or long-term contracts is 100% hedged for NYSEG, and 100% hedged for RG&E, for on-peak and off-peak periods for May through December 2006. A fluctuation of $1.00 per megawatt-hour in the average price of electricity would change NYSEG's earnings less than $150 thousand, and would change RG&E's earnings less than $150 thousand, for May 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 March 31, 2006, was $56 million, reflecting a decrease of $97 million since December 31, 2005. The decrease is primarily a result of wholesale market price changes for electricity. 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.

Two of our 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 April 2006 the energy marketing subsidiaries' fixed price load is 99% hedged for electricity and 100% hedged for natural gas for May through December 2006. The percentage of hedged load for the energy marketing subsidiaries is based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in load compared to the load forecast.

Item 4.  Controls and Procedures

The principal executive officers and principal financial officers of Energy East and RG&E evaluated the effectiveness of their respective company's disclosure controls and procedures as of the end of the period covered by this report. "Disclosure controls and procedures" are controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, within the time periods specified in the SEC rules and forms, is recorded, processed, summarized and reported, and is accumulated and communicated to the company's management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on their evaluation, the principal executive officers and principal financial officers of Energy East and RG&E concluded that their respective company's disclosure controls and procedures are  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. On February 1, 2006, NYSEG modified certain internal controls over financial reporting to accommodate the implementation of its new customer care system. The customer care system is used for customer bill production and integrates NYSEG's revenue, accounts receivable and cash management transactions with Energy East's centralized accounting system. There was no other change in either company's internal control over financial reporting that occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, that company's internal control over financial reporting.

PART II - OTHER INFORMATION

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

(c)Issuer Purchases of Equity Securities

Energy East Corporation
Period	(a)       Total number of shares purchased	(b)        Average price paid per share	(c)        Total number of shares purchased as part of publicly announced plans or programs	(d)         Maximum number of shares that may yet be purchased under the plans or programs
Month #1   (January 1, 2006 to   January 31, 2006)	30,960(1)	$23.09	- -	- -
Month #2   (February 1, 2006 to   February 28, 2006)	252,405(2)	$24.39	- -	- -
Month #3   (March 1, 2006 to   March 31, 2006)	4,887(3)	$24.23	- -	- -
Total	288,252	$24.25	-	-

(1) Includes 9,136 shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan; and 21,824 shares of the company's common stock (Par Value $.01) that were withheld to satisfy tax withholding obligations upon vesting of shares of restricted stock awarded through the company's Restricted Stock Plan.
⁽²⁾Includes 2,405 shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan; and 250,000 shares of the company's common stock (Par Value $.01) purchased for Treasury for issuance under the company's Restricted Stock Plan and Stock Option Plan.
⁽³⁾ 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 March 31, 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:  May 5, 2006	ENERGY EAST CORPORATION                   (Registrant) By   /s/Robert D. Kump                                                   Robert D. Kump            Vice President, Controller            & Chief Accounting Officer            (Principal Accounting Officer)
Date:  May 5, 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	3-5	By-Laws of the Company as amended April 6, 2006.
	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).