Energy East (EAS) 10-Q 2007 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, 2007

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 April 30, 2007, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	158,031,822
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.

Rochester Gas and Electric Corporation meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

	Table of Contents	Page
	Glossary	ii
	Forward-looking Statements	iv
	PART I - FINANCIAL INFORMATION
Item 1. and 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 10 11
	Rochester Gas and Electric Corporation   Condensed Balance SheetsCondensed Statements of IncomeCondensed Statements of Cash FlowsCondensed Statements of Retained EarningsCondensed Statements of Comprehensive IncomeManagement's Narrative Analysis of Results of Operations	16 18 19 20 20 21
Item 1.	Notes to Condensed Financial Statements	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	31
	PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 6.	Exhibits	32
Signatures		33
Exhibit Index		34

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. Energetix Energetix, Inc. markets electric and natural gas services in upstate New York. Energy East, the company, we, ouror us Energy 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, Inc. and Energy East Enterprises, Inc.

MNGMaine Natural Gas Corporation is a small natural gas delivery company in the state of Maine. 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:

ALJAdministrative Law Judge AMIadvanced metering infrastructure ARP 2000Alternative Rate Plan 2000 ASGAAsset Sale Gain Account DIG Issue G26 Derivatives Implementation Group (DIG) Issue No. G26, "Cash Flow Hedges: Hedging Interest Cash Flows on Variable-Rate Assets and Liabilities That Are Not Based on a Benchmark Interest Rate" DPUCConnecticut Department of Public Utility Control Dth dekatherm EPA Environmental Protection Agency EPSearnings per share ESCOenergy service company FASBFinancial Accounting Standards Board FERCFederal Energy Regulatory Commission FIN 46(R)FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51 FIN 48FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ISO-NEISO New England Inc. MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations MPUCMaine Public Utilities Commission

MW, MWh megawatt, megawatt-hour NBCnonbypassable wires charge NUGnonutility generator NYISONew York Independent System Operator NYPSCNew York State Public Service Commission NYSDECNew York State Department of Environmental Conservation OPEBother post-employment benefits PCBpolychlorinated biphenyl ROEreturn on equity RTORegional Transmission Organization RussellStation A coal-fired electric generation facility in Greece, New York SARstock appreciation right SEC United States Securities and Exchange Commission Statement 109 Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes Statement 157 Statement of Financial Accounting Standards No. 157,Fair Value Measurements Statement 159 Statement of Financial Accounting Standards No. 159,The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment of FASB Statement No. 115

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, 2006, 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 competitive electric and/or natural gas utility markets,
• regulatory uncertainty and volatile energy supply prices,
• implementation of NYSEG's electric rate order issued by the NYPSC that has been in effect since January 1, 2007,
• 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 and retroactive NYISO billing adjustments,
• the operation of ISO-NE as an RTO and CMP's continued participation in ISO-NE,
• 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 commodity costs on customer usage and uncollectible expense,
• our ability to 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,
• the ability of third parties to continue to supply electricity and natural gas,
• our ability to obtain adequate and timely rate relief and/or the extension of current rate plans,
• the possible discontinuation or further modification 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 or contraction 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 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,	2007	2006
(Thousands, except per share amounts)
Operating Revenues
Utility	$1,564,064	$1,542,205
Other	149,674	154,349
Total Operating Revenues	1,713,738	1,696,554
Operating Expenses
Electricity purchased and fuel used in generation
Utility	385,273	377,342
Other	88,853	89,389
Natural gas purchased
Utility	538,506	509,769
Other	42,375	43,774
Other operating expenses	193,723	186,106
Maintenance	40,818	52,464
Depreciation and amortization	68,799	69,404
Other taxes	75,713	73,865
Total Operating Expenses	1,434,060	1,402,113
Operating Income	279,678	294,441
Other (Income)	(8,955)	(10,400)
Other Deductions	3,231	4,017
Interest Charges, Net	68,401	78,720
Preferred Stock Dividends of Subsidiaries	282	282
Income Before Income Taxes	216,719	221,822
Income Taxes	83,425	88,581
Net Income	$133,294	$133,241
Earnings per Share, basic	$.90	$.91
Earnings per Share, diluted	$.90	$.90
Dividends Declared per Share	$.30	$.29
Average Common Shares Outstanding, basic	147,517	147,034
Average Common Shares Outstanding, diluted	148,406	147,679
Thenotes on pages 23 through 29 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	March 31, 2007	Dec. 31, 2006
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$233,717	$93,373
Investments available for sale	185,970	20,000
Accounts receivable and unbilled revenues, net	1,031,195	914,657
Fuel and natural gas in storage, at average cost	92,444	277,766
Materials and supplies, at average cost	34,656	33,273
Deferred income taxes	42,875	93,187
Derivative assets	18,602	1,327
Prepayments and other current assets	144,137	193,226
Total Current Assets	1,783,596	1,626,809
Utility Plant, at Original Cost
Electric	5,596,268	5,557,858
Natural gas	2,664,454	2,654,426
Common	562,030	550,440
	8,822,752	8,762,724
Less accumulated depreciation	2,981,832	2,935,798
Net Utility Plant in Service	5,840,920	5,826,926
Construction work in progress	132,243	121,097
Total Utility Plant	5,973,163	5,948,023
Other Property and Investments	180,383	183,315
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	232,308	263,659
Unfunded future income taxes	269,022	256,683
Environmental remediation costs	144,155	128,925
Unamortized loss on debt reacquisitions	50,714	52,724
Nonutility generator termination agreements	76,555	79,241
Natural gas hedges	4,899	47,372
Pension and other postretirement benefits	344,531	351,011
Other	320,682	356,299
Total regulatory assets	1,442,866	1,535,914
Other assets
Goodwill	1,526,048	1,526,048
Prepaid pension benefits	594,073	577,356
Derivative assets	47,238	46,375
Other	107,933	118,561
Total other assets	2,275,292	2,268,340
Total Regulatory and Other Assets	3,718,158	3,804,254
Total Assets	$11,655,300	$11,562,401
Thenotes on pages 23 through 29 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	March 31, 2007	Dec. 31, 2006
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$260,811	$260,768
Notes payable	11,500	109,363
Accounts payable and accrued liabilities	456,530	470,325
Interest accrued	59,257	57,243
Taxes accrued	129,335	44,009
Unfunded future income taxes	84	19,664
Derivative liabilities	10,298	71,678
Customer refunds	130	70,770
Other	167,636	209,839
Total Current Liabilities	1,095,581	1,313,659
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	824,899	843,273
Deferred income taxes	113,543	105,528
Gain on sale of generation assets	120,515	127,674
Pension benefits	123,520	127,330
Other	151,926	93,268
Total regulatory liabilities	1,334,403	1,297,073
Other liabilities
Deferred income taxes	1,066,290	1,105,117
Nuclear plant obligations	198,015	202,963
Pension and other postretirement benefits	526,133	530,838
Environmental remediation costs	161,949	168,949
Derivative liabilities	17,386	21,871
Other	310,666	306,283
Total other liabilities	2,280,439	2,336,021
Total Regulatory and Other Liabilities	3,614,842	3,633,094
Long-term debt	3,726,152	3,726,709
Total Liabilities	8,436,575	8,673,462
Commitments and Contingencies
Preferred Stock of Subsidiaries
Redeemable solely at the option of subsidiaries	24,592	24,592
Common Stock Equity
Common stock	1,571	1,480
Capital in excess of par value	1,720,876	1,505,795
Retained earnings	1,472,896	1,382,461
Accumulated other comprehensive income (loss)	2,360	(23,779)
Treasury stock, at cost	(3,570)	(1,610)
Total Common Stock Equity	3,194,133	2,864,347
Total Liabilities and Stockholders' Equity	$11,655,300	$11,562,401
Thenotes on pages 23 through 29 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Three months ended March 31,	2007	2006
(Thousands)
Operating Activities
Net income	$133,294	$133,241
Adjustments to reconcile net income to net cash  provided by operating activities
Depreciation and amortization	94,061	98,908
Income taxes and investment tax credits deferred, net	9,394	(9,477)
Pension income	(10,849)	(7,466)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	(190,499)	(105,457)
Inventory	184,300	152,107
Prepayments and other current assets	45,271	5,730
Accounts payable and accrued liabilities	(29,591)	(174,479)
Interest accrued	2,014	13,309
Taxes accrued	78,518	71,002
Customer refunds	(10,115)	(13,998)
Other current liabilities	(54,771)	(80,323)
Other assets	58,317	56,519
Other liabilities	(17,925)	(50,988)
Net Cash Provided by Operating Activities	291,419	88,628
Investing Activities
Utility plant additions	(78,443)	(58,461)
Other property additions	(128)	(1,207)
Other property sold	-	691
Maturities of current investments available for sale	73,815	380,315
Purchases of current investments available for sale	(239,785)	(198,965)
Investments	2,950	-
Net Cash (Used in) Provided by Investing Activities	(241,591)	122,373
Financing Activities
Issuance of common stock	212,098	-
Repurchase of common stock	(8,339)	(6,106)
Long-term note issuances	-	40,000
Long-term note repayments	(764)	(40,894)
Notes payable three months or less, net	(97,791)	(95,489)
Notes payable issuances	373	38,275
Notes payable repayments	(445)	(45,133)
Bank overdraft	24,980	-
Dividends on common stock	(39,596)	(42,674)
Net Cash Provided by (Used in) Financing Activities	90,516	(152,021)
Net Increase in Cash and Cash Equivalents	140,344	58,980
Cash and Cash Equivalents, Beginning of Period	93,373	120,009
Cash and Cash Equivalents, End of Period	$233,717	$178,989
Thenotes on pages 23 through 29 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Three months ended March 31,	2007	2006
(Thousands)
Balance, Beginning of Period	$1,382,461	$1,294,580
Adjustment for the cumulative effect of applying the provisions   of FIN 48 as of January 1, 2007	1,291	- -
Add net income	133,294	133,241
	1,517,046	1,427,821
Deduct dividends on common stock	44,150	42,674
Balance, End of Period	$1,472,896	$1,385,147
Thenotes on pages 23 through 29 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
Three months ended March 31,	2007	2006
(Thousands)
Net income	$133,294	$133,241
Other comprehensive income, net of tax
Net unrealized gains (losses) on investments, net of income tax     (expense) benefit of $(58) for 2007 and $167 for 2006	87	(252)
Amortization of pension costs for nonqualified plans,     net of income tax (expense) of $(138) for 2007	209	- -
Net unrealized (losses) on derivatives qualified as hedges,     net of income tax benefit of $8,760 for 2007 and $76,497     for 2006	(13,255)	(120,202)
Reclassification adjustment for derivative losses included in     net income, net of income tax (benefit) of $(25,930) for     2007 and $(20,416) for 2006	39,098	30,897
Net unrealized gains (losses) on derivatives qualified as hedges	25,843	(89,305)
Total other comprehensive income (loss)	26,139	(89,557)
Comprehensive Income	$159,433	$43,684
Thenotes on pages 23 through 29 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 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 five-year electric rate plan expired December 31, 2006, and new rates went into effect on January 1, 2007. SCG received approval for new rates that became effective January 1, 2006, and CNG recently received approval for new rates that became effective April 1, 2007.

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 the rates that our customers pay for energy. Those proceedings, which are discussed below, could affect the nature of the electric and natural gas utility industries in New York and New England.

We expect to make significant capital investments to enhance the safety and reliability of our distribution systems and to meet the growing energy needs of our customers in an environmentally friendly manner. Capital spending is expected to exceed $3 billion through 2011, including $496 million in 2007. Major spending programs include the installation of advanced metering infrastructure (AMI) in New York and Maine requiring an investment of approximately $500 million; $500 million of transmission investments, predominantly in Maine; a high efficiency transformer replacement program; and a "green" fleet initiative. The majority of our planned transmission investments will be pursuant to a regional reliability planning process and should qualify for the FERC's transmission investment ROE incentive adders for New England transmission owners. We have also proposed to the NYISO that Russell Station be repowered, using either clean coal technology or natural gas, to meet projected load requirements in the Roche ster, New York area. The cost would be approximately $500 million. We estimate that over one-half of our capital spending program will be funded with internally generated funds and the remainder through the issuance of a combination of debt and equity securities.

This MD&A for the quarter ended March 31, 2007, 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, 2006. 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. Our operating companies have become increasingly efficient through realization of merger-enabled synergies. Our current strategic focus is on addressing many of the precepts of the Energy Policy Act of 2005 including: (1) investing in transmission to increase reliability, meet new load growth and connect new, renewable generation to the grid; (2) investing in AMI to promote customer conservation and peak load management; (3) investing in our distribution infrastructure to make it more efficient by reducing losses; and (4) investing in new regulated generation that is environmentally friendly and, where possible, sustainable.

Our individual company 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 our subsidiaries to earn a fair return while minimizing price increases and sharing achieved savings with customers.

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's Supply Service Filing: On April 5, 2007, NYSEG submitted to the NYPSC its proposal for revisions to its supply service. Details of the proposal include:

Simplified Supply Program

• NYSEG will offer customers a single fixed price supply service.
• Residential and small commercial customers who do not choose an ESCO will receive fixed price supply service from NYSEG. The rate would be fixed throughout the year.
• Large commercial and industrial customers who do not choose an ESCO will receive supply service from NYSEG pursuant to NYSEG's current hourly pricing tariff.
• The fixed price will be reset each calendar year.
• The supply component of the fixed price will be based on recent, competitive wholesale solicitations and a market price index.

Preservation and Enhancement of Customer Choice

• NYSEG will eliminate the enrollment period in which customers choose between utility and ESCO suppliers.
• Customers may switch from NYSEG service to an ESCO or back at any time without penalty. NYSEG will assume all switching risk.
• All customers in a service classification will be charged the same fixed nonbypassable wires charge (NBC), thereby making it easier for customers to compare NYSEG's supply rate to ESCO offers. The NBC would be fixed and trued-up annually for all customers. The NBC would be reset each calendar year.

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

Energy East Corporation

Customer Guarantee and Sharing

• NYSEG's customers will be guaranteed an aggregate $20 million (pretax) credit to the NBC, which would be retained by the customers even if NYSEG's pretax margin from offering fixed price supply service is below that level.
• Margins, if any, in excess of the $20 million (pretax) will be shared equally between customers and NYSEG.
• The customers' share will be reflected as a credit in the subsequent year's NBC.

NYSEG is requesting NYPSC approval of its proposal by September 1, 2007, in order to implement supply service by January 1, 2008. NYSEG cannot predict the outcome of this proceeding.

NYPSC Proceeding on NYSEG's Accounting for OPEB: In August 2006 the NYPSC issued its decision in the NYSEG electric rate case. Among other things, the NYPSC instructed the ALJ to open a separate proceeding regarding the NYPSC staff's position that NYSEG should have retained $57 million of interest in its OPEB reserve and used it to reduce rate base. A proceeding has been opened and hearings on the issues raised by the NYPSC staff are currently expected to be held in late 2007. NYPSC acceptance of its staff's position would 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. While NYSEG is vigorously opposing staff on these issues, contending that the NYPSC staff is engaged in retroactive ratemaking, it cannot predict how this matter will be resolved.

Advanced Metering Infrastructure: In February 2007, in response to an August 2006 NYPSC order, NYSEG and RG&E filed a plan to install AMI (smart meters) for all of their electric and natural gas customers. Smart meters would provide customers with detailed consumption data, enabling them to better control their energy usage. Smart meters would also eliminate the need for routine manual meter readings and estimated bills, improve the companies' response to service interruptions, improve the gas balancing and settlement process, reduce greenhouse gas emissions, and create opportunity for a wide range of time-differentiated rates, load management, and load aggregation programs that are expected to reduce peak loads and thereby defer the need for additional electric generation sources. The plan calls for a total capital investment of approximately $370 million between 2007 and 2012.

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 its 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.

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

Energy East Corporation

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 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. 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 involving Russell Station unless a settlement can be reached.

If the Attorney General and the NYSDEC were to commence a Clean Air Act lawsuit against RG&E, they would need to demonstrate that, among other things, the challenged modifications to Russell Station caused an "increase" in emissions from the station. The issue of what constitutes the appropriate test for an emissions increase was before the United States Supreme Court in Environmental Defense v. Duke Energy Corporation, Docket No. 05-848. InApril 2007 the US Supreme Court ruled that the lower courts, in an attempt to reconcile perceived inconsistencies in the EPA's regulation of stationary sources of air pollution, impermissibly invalidated certain of those regulations. The court did not reach a decision concerning whether Duke had in fact violated those regulations. The case was remanded so that that issue, as well as other defenses asserted by Duke, can be adjudicated. The effect of this decision on discussions between RG&E, the Attorney General and NYSDEC is unknown. RG&E, the NYSDE C and the Attorney General continue to discuss this matter and no suit has been filed to date. RG&E is not able to predict the outcome of this matter.

CMP Alternative Rate Plan: CMP submitted to the MPUC its annual price change filing pursuant to the terms of its current ARP 2000 on March 15, 2007. In its filing and subsequent update on April 11, 2007, CMP proposes a distribution rate increase of 2.1% comprised, in part, of the basic price change of inflation minus a productivity offset, the elimination of prior year one-time adjustments, and recovery for additional electric lifeline program costs. Once approved by the MPUC, revised rates will become effective July 1, 2007. ARP 2000 expires December 31, 2007.

On May 1, 2007, CMP submitted a filing to the MPUC proposing a new alternative rate plan for a seven-year term beginning January 1, 2008 (ARP 2008). CMP's proposal retains the basic structure of ARP 2000, including annual price changes based on a specified inflation index less a predetermined productivity offset, service quality indicators and associated penalties for failure to achieve the indicator performance targets, and explicit provisions for the recovery of certain exogenous or mandated costs. The filing proposes to maintain the existing rates at the termination of ARP 2000 as the initial rates for ARP 2008. The first price change under the new rate plan would occur on July 1, 2008. The proposal includes fixed productivity offset values of 0.25% for the initial two years of the rate plan and 0.50% for the remaining five years. It utilizes reserve accounting mechanisms to address recovery of costs associated with major storm restoration and environmental clean-up costs for manufactured gas sites and PCB-contaminated facilities. CMP's ARP 2008 proposal also incorporates incremental investment and operating expenses for new initiatives including: (1) an AMI project to deploy advanced meters and communications to all of CMP's customers; (2) proposed enhancements in vegetation management, inspection practices and distribution betterment projects designed to improve distribution reliability; and (3) accelerated deployment of more efficient distribution transformers. CMP cannot predict the outcome of these proceedings.

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

Energy East Corporation

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.

Natural Gas Supply Agreements: Our natural gas companies - NYSEG, RG&E, SCG, CNG, Berkshire Gas and MNG - each had a three-year strategic alliance with BP Energy Company that ended on March 31, 2007. NYSEG, RG&E, SCG, CNG and Berkshire Gas - have each entered into a new three-year strategic alliance with Coral Energy Resources, beginning on April 1, 2007, that optimizes transportation and storage services.

CNG Regulatory Proceeding:In September 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.

In December 2006 CNG and The Office of Consumer Counsel in the State of Connecticut filed with the DPUC a proposed settlement agreement. On March 14, 2007, the DPUC approved the settlement with minor modifications. The approval included a rate increase of $14.4 million, based on an allowed ROE of 10.1% and a non-firm margin of $12.6 million. The agreement allows CNG to proceed with its proposed automated meter reading project and defer the net costs until its next rate case. CNG also agreed to freeze its base distribution rates for 24 months. The new rates became effective April 1, 2007.

Advanced Metering Infrastructure: See Electric Delivery Business Developments.

New Accounting Standards

The FASB issued Statement 157 in September 2006 and Statement 159 in February 2007. The FASB cleared DIG Issue G26 in December 2006 and it was posted to the FASB website in January 2007. See Item 1, Note 7 to our consolidated financial statements for explanations about these new accounting standards.

(a) Liquidity and Capital Resources

Operating Activities:Significant operating activities that affected cash flows during the three months ended March 31, 2007, included the following:

• A decrease in accounts payable that reduced cash $45 million, primarily due to payments for natural gas and electricity purchases,
• An increase in receivables that reduced cash $113 million,
• A $77 million refund credited to customer account pursuant to NYSEG's 2006 electric rate proceeding,
• A reduction in fuel inventories that increased cash $184 million, and
• Payments of refunds by RG&E of $10 million, which represented the last scheduled refund pursuant to its 2004 electric rate agreement.

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

Energy East Corporation

Investing Activities: Utility capital spending for the three months ended March 31, 2007, was $78 million. Utility capital spending is projected to be $496 million in 2007, the majority of which is expected to be paid for with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates, and the RG&E transmission project.

Current investments available for sale, which consist of auction rate securities, increased $166 million during the quarter as a result of funds available from our March 2007 issuance of common stock.

Financing Activities: The financing activities discussed below include those activities necessary for the company and its principal subsidiaries to maintain adequate liquidity and credit quality and ensure access to capital markets.

On March 27, 2007, we sold nine million shares of common stock at $24.25 per share. As provided for in an underwriting agreement, we sold an additional one million shares of common stock at $24.25 per share on April 2, 2007, pursuant to an over-allotment provision. After deducting underwriting fees and other costs, the aggregate net proceeds were $235 million. The proceeds will be used to fund the repurchase of debt and for general corporate purposes, including our construction program. The sale increased our common equity ratio to 44%.

During the first quarter of 2007 we issued 196,133 shares of our common stock at an average price of $25.23 through our Investor Services Program.

We repurchased 350,000 shares of our common stock in January 2007, primarily for grants of restricted stock. We awarded 296,145 shares of our common stock, issued out of treasury stock, to certain employees through our Restricted Stock Plan, at a grant date fair value of $24.76 per share of common stock.

(b)Results of Operations

Earnings per Share

Three months ended March 31,	2007	2006
(Thousands, except per share amounts)
Net Income	$133,294	$133,241
Earnings per Share, basic	$.90	$.91
Earnings per Share, diluted	$.90	$.90
Dividends Declared per Share	$.30	$.29
Average Common Shares Outstanding, basic	147,517	147,034
Average Common Shares Outstanding, diluted	148,406	147,679

Earnings per basic share for the first quarter 2007 were $0.90 compared to $0.91 per share earned in the first quarter 2006.

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

Energy East Corporation

While earnings were relatively consistent on a year-over-year basis, several key factors affected results:

• Favorable year-over-year weather drove increased retail sales in both the electricity and gas delivery businesses. Heating degree days during the first quarter of 2007 were near normal levels but were approximately 13% higher than the first quarter of 2006, which experienced a relatively mild winter. Weather helped drive a 3% increase in retail electric sales and a 10% increase in retail gas sales. This resulted in $0.04 per share benefit from electric margins and an additional $0.05 per share in natural gas margins.
• Absent sales increases, electric margins reduced earnings per share $0.15 for the quarter due largely to the August 2006 NYSEG rate order.
• Interest costs declined by $0.04 per share on a year-over-year basis driven by lower carrying costs on regulatory liabilities and savings from debt refinancings completed in 2006.
• Year-over-year operation & maintenance expenses were down $0.01 per share. This was driven by lower storm costs which were partially offset by small increases in other O&M items.

Energy Deliveries

Energy deliveries and electricity commodity sales for the first quarter of 2007 compared to the same period in 2006 are shown below.

	Electricity Deliveries (MWh)			Natural Gas Deliveries (Dth)
Three months ended March 31,	2007	2006	Change	2007	2006	Change
(Thousands)
Residential	3,427	3,300	4%	38,687	33,834	14%
Commercial	2,461	2,239	10%	12,416	11,138	11%
Industrial	1,595	1,781	(10%)	1,536	1,497	3%
Other	598	532	12%	4,397	3,509	25%
Transportation of customer-    owned natural gas	NA	NA	NA	26,484	25,609	3%
Total Retail	8,081	7,852	3%	83,520	75,587	10%
Wholesale	1,935	2,503	(23%)	351	46	663%
Total Deliveries	10,016	10,355	(3%)	83,871	75,633	11%
Electricity commodity sales(1)	3,451	3,585	(4%)	NA	NA	NA
(1) Included in total deliveries

Several factors influenced the volume of energy deliveries, with the primary factor being weather. Temperatures in the first quarter of 2007 were significantly colder than in 2006. The effects of warmer or colder winter weather are especially significant to the demand for natural gas. We estimate that for the first quarter of 2007, approximately one-third of the 3% increase in retail electricity deliveries and one-half of the 10% increase in retail natural gas deliveries was the result of colder winter weather. Comparative weather data is shown in the following table.

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

Energy East Corporation

Weather Conditions

Three months ended March 31,	2007	2006	Normal
New York
Heating degree days	3,347	2,989	3,411
Colder than prior year	12%
(Warmer) than normal	(2%)
New England
Heating degree days	3,180	2,814	3,175
Colder than prior year	13%
Colder than normal	-

While significantly colder than last year, weather for the first quarter of 2007, on a heating degree day basis, approximated normal weather.

Operating Results for the Electric Delivery Business

Three months ended March 31,	2007	2006
(Thousands)
Operating revenues
Retail	$592,726	$526,580
Wholesale	127,485	153,066
Other	46,471	105,660
Total Operating Revenues	$766,682	$785,306
Operating Expenses
Electricity purchased and fuel used in generation	$385,273	$377,342
Other operating and maintenance expenses	167,271	169,882
Depreciation and amortization	44,523	46,050
Other taxes	38,431	39,081
Total Operating Expenses	$635,498	$632,355
Operating Income	$131,184	$152,951

Operating Revenues:The $19 million decrease in operating revenues for the first quarter of 2007 was primarily the result of:

• A decrease of $23 million resulting from higher accruals for earnings sharing, which is included in other revenues. $14 million of this decrease related to adjustments recorded in 2006 resulting from the finalization of NYSEG's and RG&E's annual compliance filings.
• A decrease of $10 million resulting from NYSEG's delivery rate decrease pursuant to the order in its 2006 rate proceeding,
• A decrease of $26 million in wholesale revenues, reflecting a 23% decline in wholesale volume,
• A decrease of $36 million resulting from lower accruals for the NBC, which will be passed on to customers through lower transition charges, and
• A decrease of $8 million resulting from a 4% decline in electricity sales under supply service programs in New York.

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

Energy East Corporation

Those decreases were partially offset by:

• An increase of $64 million in average delivery prices, primarily resulting from higher transition charges. Transition charges allow the companies to recover actual generation and purchased power costs and have no net effect on earnings. The increase in transition charges was partially offset by the NBC accrual discussed above.
• An increase of $9 million resulting from increased prices for electricity sales under supply service programs in New York, and
• An increase of $11 million resulting from a 3% increase in retail deliveries. Approximately one-third of the increase was due to colder temperatures in 2007.

Operating Expenses: The $3 million increase in operating expenses for the first quarter of 2007 was primarily the result of:

• An increase of $8 million for higher purchased power costs.

That increase was partially offset by:

• A decrease of $3 million in operating and maintenance expenses attributable largely to storm-related costs.

Operating Results for the Natural Gas Delivery Business

Three months ended March 31,	2007	2006
(Thousands)
Operating Revenues
Retail	$799,134	$757,624
Wholesale	3,497	16
Other	(5,249)	(741)
Total Operating Revenues	$797,382	$756,899
Operating Expenses
Natural gas purchased	$538,506	$509,769
Other operating and maintenance expenses	55,876	56,127
Depreciation and amortization	22,095	21,343
Other taxes	35,487	32,722
Total Operating Expenses	$651,964	$619,961
Operating Income	$145,418	$136,938

Operating Revenues: The $40 million increase in operating revenues for the first quarter of 2007 was primarily the result of:

• An increase of $89 million resulting from a 10% increase in retail deliveries. Approximately one-half of the increase was due to colder temperatures in 2007.

Those increases were partially offset by:

• A decrease of $44 million resulting from lower market prices for natural gas that were passed on to customers, and
• A decrease of $6 million resulting from lower weather normalization accruals.

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

Energy East Corporation

Operating Expenses: The $32 million increase in operating expenses for the first quarter of 2007 was primarily the result of:

• An increase of $66 million in natural gas purchases due to increased delivery volumes, and
• An increase of $3 million in gross receipts taxes resulting from higher revenues.

Those increases were partially offset by:

• A decrease of $37 million in natural gas purchases resulting from lower market prices.

Operating Results for the Energy Marketing Business

The primary business included in our Other segment is our energy marketing business comprised of Energetix, Inc. and NYSEG Solutions, Inc., which market electricity and natural gas to customers throughout the state of New York. They currently have 162,000 electricity customers and 52,000 natural gas customers in the service territories of RG&E, NYSEG and several other New York state utilities.

Three months ended March 31,	2007	2006
(Thousands)
Electricity sales (MWh)	1,048	1,199
Natural gas sales (Dth)	3,957	3,491
Operating Revenues
Electric	$94,057	$93,314
Natural gas	41,872	45,367
Total Operating Revenues	$135,929	$138,681
Operating Expenses
Electricity purchased	$89,044	$89,361
Natural gas purchased	40,399	40,923
Other operating expenses	3,123	2,971
Total Operating Expenses	$132,566	$133,255
Operating Income	$3,363	$5,426

Operating Revenues: The $3 million decrease in operating revenues for the first quarter of 2007 was primarily the result of:

• A decrease of $12 million due to lower electricity sales due to the loss of some large customers to other suppliers, and
• A decrease of $10 million due to lower natural gas prices.

Those decreases were partially offset by:

• An increase of $13 million due to higher electricity prices, and
• An increase of $6 million due to higher natural gas volumes.

Operating Expenses: The $1 million decrease in operating expense for the first quarter of 2007 was primarily the result of:

• A decrease of $11 million in purchased electricity due to lower sales volume, and
• A decrease of $6 million in purchased natural gas due to lower market prices.

Those decreases were partially offset by:

• An increase of $11 million in purchased electricity due to higher prices, and
• An increase of $5 million in natural gas purchases due to higher sales.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	March 31, 2007	Dec. 31, 2006
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$4,313	$5,902
Accounts receivable and unbilled revenues, net	248,724	213,142
Fuel and natural gas in storage, at average cost	10,060	50,021
Materials and supplies, at average cost	14,011	13,533
Deferred income taxes	2,450	14,663
Broker margin accounts	12,413	31,359
Prepayments and other current assets	31,133	36,781
Total Current Assets	323,104	365,401
Utility Plant, at Original Cost
Electric	1,308,441	1,298,609
Natural gas	587,324	584,857
Common	207,761	202,276
	2,103,526	2,085,742
Less accumulated depreciation	632,296	619,262
Net Utility Plant in Service	1,471,230	1,466,480
Construction work in progress	88,282	80,291
Total Utility Plant	1,559,512	1,546,771
Other Property and Investments	11,705	11,271
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	149,495	174,307
Deferred income taxes	12,078	-
Unfunded future income taxes	20,905	13,154
Environmental remediation costs	25,755	25,988
Unamortized loss on debt reacquisitions	10,276	11,071
Nonutility generator termination agreement	70,716	73,021
Natural gas hedges	1,632	22,724
Other	114,953	123,720
Total regulatory assets	405,810	443,985
Other assets
Prepaid pension benefits	100,991	97,180
Other	16,994	15,782
Total other assets	117,985	112,962
Total Regulatory and Other Assets	523,795	556,947
Total Assets	$2,418,116	$2,480,390
Thenotes on pages 23 through 29 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	March 31, 2007	Dec. 31, 2006
(Thousands)
Liabilities
Current Liabilities
Notes payable	$6,000	$20,890
Accounts payable and accrued liabilities	96,939	135,863
Interest accrued	8,006	9,589
Taxes accrued	19,239	12,711
Unfunded future income taxes	-	3,987
Derivative liabilities	2,067	22,542
Other	22,865	44,947
Total Current Liabilities	155,116	250,529
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	188,752	189,035
Deferred income taxes	-	6,541
Gain on sale of generation assets	109,798	118,031
Pension benefit	32,881	33,519
Other	45,406	39,096
Total regulatory liabilities	376,837	386,222
Other liabilities
Deferred income taxes	252,296	237,440
Nuclear waste disposal	115,203	113,763
Other postretirement benefits	74,531	74,583
Asset retirement obligation	21,483	21,251
Environmental remediation costs	37,523	37,523
Other	45,946	58,464
Total other liabilities	546,982	543,024
Total Regulatory and Other Liabilities	923,819	929,246
Long-term debt	698,044	698,025
Total Liabilities	1,776,979	1,877,800
Commitments and Contingencies
Common Stock Equity
Common stock	194,429	194,429
Capital in excess of par value	483,826	483,662
Retained earnings	86,403	50,844
Accumulated other comprehensive (loss)	(6,283)	(9,107)
Treasury stock, at cost	(117,238)	(117,238)
Total Common Stock Equity	641,137	602,590
Total Liabilities and Stockholder's Equity	$2,418,116	$2,480,390
Thenotes on pages 23 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,	2007	2006
(Thousands)
Operating Revenues
Electric	$194,098	$185,638
Natural gas	183,903	160,873
Total Operating Revenues	378,001	346,511
Operating Expenses
Electricity purchased and fuel used in generation	86,692	75,905
Natural gas purchased	129,723	108,833
Other operating expenses	43,380	38,765
Maintenance	11,614	10,908
Depreciation and amortization	18,108	17,818
Other taxes	19,281	17,114
Total Operating Expenses	308,798	269,343
Operating Income	69,203	77,168
Other (Income)	(1,220)	(1,064)
Other Deductions	294	182
Interest Charges, Net	13,681	14,283
Income Before Income Taxes	56,448	63,767
Income Taxes	20,889	23,482
Net Income	$35,559	$40,285
Thenotes on pages 23 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,	2007	2006
(Thousands)
Operating Activities
Net income	$35,559	$40,285
Adjustments to reconcile net income to net cash  provided by operating activities
Depreciation and amortization	34,334	33,952
Income taxes and investment tax credits deferred, net	15,866	9,293
Pension income	(4,449)	(3,514)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	(35,582)	(18,435)
Inventory	39,845	40,464
Prepayments and other current assets	24,652	(23,322)
Accounts payable and accrued liabilities	(3,868)	(25,499)
Interest accrued	(1,583)	(1,936)
Taxes accrued	5,577	14,144
Customer refund	(10,056)	(13,998)
Other current liabilities	(22,152)	(23,400)
Other assets	5,971	6,688
Other liabilities	(14,693)	(30,205)
Net Cash Provided by Operating Activities	69,421	4,517
Investing Activities
Utility plant additions	(30,884)	(13,508)
Maturities of current investments available for sale	20,200	137,950
Purchases of current investments available for sale	(20,200)	(84,625)
Investments	(236)	(381)
Net Cash (Used in) Provided by Investing Activities	(31,120)	39,436
Financing Activities
Notes payable three months or less, net	(14,890)	-
Dividends on common stock	(25,000)	(35,000)
Net Cash Used in Financing Activities	(39,890)	(35,000)
Net (Decrease) Increase in Cash and Cash Equivalents	(1,589)	8,953
Cash and Cash Equivalents, Beginning of Period	5,902	28,752
Cash and Cash Equivalents, End of Period	$4,313	$37,705
Thenotes on pages 23 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,	2007	2006
(Thousands)
Balance, Beginning of Period	$50,844	$28,549
Add net income	35,559	40,285
	86,403	68,834
Deduct dividends declared on common stock	-	35,000
Balance, End of Period	$86,403	$33,834
Thenotes on pages 23 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,	2007	2006
(Thousands)
Net income	$35,559	$40,285
Other comprehensive income, net of tax
Net unrealized (losses) gains on investments, net of income tax    benefit (expense) of $19 for 2007 and $(26) for 2006	(28)	39
Unrealized gains (losses) on derivatives qualified as    hedges, net of income tax (expense) benefit of $(4,831)    for 2007 and $826 for 2006	7,285	(1,246)
Reclassification adjustment for derivative (gains) losses    included in net income, net of income tax expense (benefit)    of $2,940 for 2007 and $(2,011) for 2006	(4,433)	3,033
Net unrealized gains on derivatives qualified as hedges	2,852	1,787
Total other comprehensive income	2,824	1,826
Comprehensive Income	$38,383	$42,111
Thenotes on pages 23 through 29 are an integral part of the condensed financial statements.

Item 2.  Management's Narrative Analysis of Results of Operations

Rochester Gas and Electric Corporation

RG&E meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q for a reduced disclosure format and is therefore presenting a management's narrative analysis of the results of operations as specified in General Instruction H(2)(a) of Form 10-Q.

Earnings

RG&E's net income for the first quarter of 2007 decreased $5 million compared to the first quarter of 2006 primarily as a result of $3 million in increased operating and maintenance expenses, including $2 million for increased reserves for uncollectibles; $1 million due to lower margins on electric deliveries; and $1 million for higher gross receipts taxes.

Operating Results for the Electric Delivery Business

Three months ended March 31,	2007	2006
(Thousands)
Operating Revenues
Retail	$116,695	$67,335
Wholesale	63,936	56,931
Other	13,467	61,372
Total Operating Revenues	$194,098	$185,638
Operating Expenses
Electricity purchased and fuel used in generation	$86,692	$75,905
Other operating and maintenance expenses	43,352	37,785
Depreciation and amortization	13,335	13,235
Other taxes	12,174	10,596
Total Operating Expenses	$155,553	$137,521
Operating Income	$38,545	$48,117

Operating Revenues: Operating revenues increased $8 million for the first quarter of 2007 as a result of:

• An increase of $7 million resulting from a 10% increase in wholesale delivery volumes, and
• An increase of $61 million resulting primarily from higher transition charges. Transition charges allow RG&E to recover actual generation and purchased power costs and have no net effect on earnings. The increase in transition charges was partially offset by the NBC accrual discussed below.

Those increases were partially offset by:

• A decrease of $9 million due to lower market prices for electricity sales, under commodity options where RG&E provides supply,
• A decrease of $39 million for lower NBC accruals, which will be passed on to customers through lower transition charges,
• A decrease of $2 million for lower sales under RG&E's commodity programs, and
• A decrease of $9 million resulting from higher earnings sharing accruals. In 2006 earnings sharing was reduced by $9 million because of an adjustment to the actual 2005 amount, pursuant to RG&E's annual compliance filing.

Management's Narrative Analysis of Results of Operations

Rochester Gas and Electric Corporation

Operating Expenses: The $18 million increase in operating expenses for the first quarter of 2007 was the result of:

• An increase of $11 million for purchased power costs, and
• An increase of $6 million in operating and maintenance costs.

Operating Results for the Natural Gas Delivery Business

Three months ended March 31,	2007	2006
(Thousands)
Operating Revenues
Retail	$189,347	$167,991
Other	(5,444)	(7,118)
Total Operating Revenues	$183,903	$160,873
Operating Expenses
Natural gas purchased	$129,723	$108,833
Other operating and maintenance expenses	11,642	11,888
Depreciation and amortization	4,773	4,583
Other taxes	7,107	6,518
Total Operating Expenses	$153,245	$131,822
Operating Income	$30,658	$29,051

Operating Revenues:The $23 million increase in operating revenues for the first quarter of 2007 was primarily the result of:

• A increase of $21 million due to higher delivery volumes, and
• An increase of $2 million in other revenue.

Operating Expenses:The $21 million increase in operating expenses for the first quarter of 2007 was primarily due to higher natural gas purchases to meet increased delivery volumes.

New Accounting Standards

The FASB issued Statement 157 in September 2006 and Statement 159 in February 2007. See Item 1, Note 7 to RG&E's financial statements for explanations about these new accounting standards.

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

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, 2006. 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 2007 presentation. Effective January 1, 2007, the companies recognized book overdrafts where no credit was required to be extended by a bank as an operating activity rather than as a financing activity. As a result, Energy East's net cash provided by operating activities and net cash used in financing activities decreased $7.2 million for the three months ended March 31, 2006. RG&E's net cash provided by operating activities and net cash used in financing activities decreased $1.7 million for the same period.

Note 2. Other (Income) and Other Deductions

Three months ended March 31,	2007	2006
(Thousands)
Energy East
Interest and dividend income	$(2,811)	$(3,776)
Allowance for funds used during construction	(1,249)	(489)
Earnings from equity investments	(931)	(1,059)
Gains from energy risk contracts	(1,085)	(2,438)
Miscellaneous	(2,879)	(2,638)
Total other (income)	$(8,955)	$(10,400)
Losses on energy risk contracts	$2,292	$2,324
Donations, civic and political	470	848
Miscellaneous	469	845
Total other deductions	$3,231	$4,017
RG&E
Interest and dividend income	$(237)	$(707)
Allowance for funds used during construction	(966)	(332)
Miscellaneous	(17)	(25)
Total other (income)	$(1,220)	$(1,064)
Miscellaneous	$294	$182
Total other deductions	$294	$182

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,	2007	2006
(Thousands)
Basic average common shares outstanding	147,517	147,034
Restricted stock awards	889	645
Potentially dilutive common shares	157	144
Options issued with SARs	(157)	(144)
Dilutive average common shares outstanding	148,406	147,679

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: 2.1 million in 2007 and 1.5 million in 2006.

Note 4. Income Taxes

Our effective tax rate was 38.4% for the quarter ended March 31, 2007. Income taxes were $3.2 million less than they would have been at the statutory rate of 39.9%, primarily due to the flow-through effects of removal costs and the permanent difference related to the subsidy available under the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The effective tax rate was 39.9% for the quarter ended March 31, 2006, and was essentially the same as the statutory rate.

RG&E's effective tax rate was 37.0% for the quarter ended March 31, 2007, and 36.8% for the quarter ended March 31, 2006. Income taxes were less than they would have been at the statutory rate of 39.9%, $1.6 million less for 2007 and $1.9 million less for 2006, primarily due to the flow-through effects of removal costs and the allowance for funds used during construction.

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 also provides guidance for the representation of reserves in the balance sheet and the proper measurement of deferred tax assets and liabilities using the FIN 48 standard. That guidance requires classifying as current reserves that are expected to be addressed in the next 12-month period. It also requires that the tax basis of assets and liabilities reflect the presumed FIN 48 outcome vs. the actual filing position in determining the proper level of accumulated deferred income taxes in accordance with Statement 109.

We adopted FIN 48 effective January 1, 2007. The total amount of gross unrecognized tax benefits at the date of adoption was $26.6 million. This amount includes income taxes of $21.2 million, interest of $5.2 million and a penalty of $0.2 million. Including interest and penalty, $14 million of the gross unrecognized tax benefits would affect the effective tax rate, if recognized. There was no material change to those amounts during the quarter ended March 31, 2007. The adoption did not have a material effect on our results of operation, financial position or cash flows. Upon our adoption of FIN 48, the cumulative effect was an increase to retained earnings of $1.3 million. In addition, we reclassified $2.3 million of accumulated deferred income tax liabilities.

We have been audited through 2000 for New York State income taxes, through 2001 for federal income taxes and through 2002 for Maine income taxes. The statute of limitations in Connecticut has expired for all years through 2002. Our New York State returns for 2001 through 2004, federal returns for 2002 through 2005 and Maine returns for 2003 and 2004 are currently under review. We anticipate that the reviews will be completed within the next 12 months. Approximately $13.8 million of the gross income tax reserves relate to the years currently under audit, with the majority relating to combined state reporting issues. We cannot estimate the ultimate outcome of the reviews.

RG&E adopted FIN 48 effective January 1, 2007. The total amount of gross unrecognized tax benefits at the date of adoption was $3.6 million. This amount includes income taxes of $3.1 million and interest of $0.5 million. Including interest and penalty, $0.3 million of the gross unrecognized tax benefit would affect the effective tax rate, if recognized. There was no material change to those amounts during the quarter ended March 31, 2007. RG&E's adoption did not have a material effect on its results of operation, financial position or cash flows. Upon RG&E's adoption of FIN 48, there was no cumulative effect on retained earnings. However, RG&E reclassified $2.3 million of accumulated deferred income tax liabilities.

RG&E has been audited through 2000 for New York State income taxes and 2001 for federal income taxes. RG&E's New York State returns for 2000 through 2004 and federal returns for 2002 through 2005 are currently under review. RG&E anticipates that the reviews will be completed within the next 12 months. Approximately $1.7 million of the gross income tax reserve relates to those years, with the majority relating to the application of transition rules applicable to utilities in New York State. RG&E cannot estimate the ultimate outcome of the reviews.

The company and RG&E continue to classify all interest and penalties related to uncertain tax positions as income tax expense.

New York State Income Tax Legislation:On April 9, 2007, New York State enacted its 2007 - 2008 budget, which included amendments to the state income tax. Those amendments include a reduction in the corporate net income tax rate to 7.1% from 7.5%, and the adoption of a single sales factor for apportioning taxable income to New York State. Both amendments are effective January 1, 2007.

The company and RG&E are evaluating the effects of the amendments, but believe that the amendments will not have a material effect on their financial position, cash flows or results of operation.

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. FIN 46(R) requires a business enterprise 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 various 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 with respect to FIN 46(R) and determined that most of the 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 six remaining NUGs because we are unable to obtain the information necessary to: (1) determine if any of those 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 routine ly 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 March 31, 2007, or December 31, 2006.

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 six NUGs is approximately 462 MWs. The combined purchases from the six NUGs totaled approximately $106 million for the three months ended March 31, 2007, and $91 million for the three months ended March 31, 2006.

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.

NYPSC Proceeding on NYSEG's Accounting for OPEB: In August 2006 the NYPSC issued its decision in the NYSEG electric rate case. Among other things, the NYPSC instructed the ALJ to open a separate proceeding regarding the NYPSC staff's position that NYSEG should have retained $57 million of interest in its OPEB reserve and used it to reduce rate base. A proceeding has been opened and hearings on the issues raised by the NYPSC staff are currently expected to be held in late 2007. NYPSC acceptance of its staff's position would 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. While NYSEG is vigorously opposing staff on these issues, contending that the NYPSC staff is engaged in retroactive ratemaking, it cannot predict how this matter will be resolved.

Note 7. New Accounting Standards

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, but does not require any new fair value measurements. 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 plan to adopt Statement 15 7 effective January 1, 2008, and are currently assessing the effects Statement 157 would have on their results of operation, financial position and/or cash flows.

Statement 159: In February 2007 the FASB issued Statement 159, which will allow an entity to measure eligible financial instruments and certain other items at fair value as of specified election dates on an instrument-by-instrument basis (the fair value option). The fair value option is irrevocable unless a new election date occurs. The fair value option will significantly expand an entity's ability to select the measurement attribute for certain key assets and liabilities, and allow it to mitigate potential mismatches that arise under the current mixed measurement attribute model. Statement 159 will be effective as of the beginning of an entity's first fiscal year that begins after November 15, 2007, with early adoption permitted when specified conditions are met. Retrospective application to fiscal years preceding the effective date is not permitted unless the entity chooses early adoption. Application to eligible items existing at the effective date (or early adoption date) is permitted. Energy East and RG&E plan to adopt Statement 159 as of January 1, 2008, and are currently assessing the effects Statement 159 would have on their results of operation, financial position and/or cash flows.

DIG Issue G26: In December 2006 the FASB cleared DIG Issue G26, which provides guidance concerning a cash flow hedge of a variable-rate financial asset or liability for which the interest rate risk is not based solely on an index, such as an interest rate that is reset through an auction process. According to DIG Issue G26, an entity may designate the risk being hedged as the risk of overall changes in the hedged cash flows related to a variable-rate financial asset or liability. However, it may not designate the risk being hedged as the interest rate risk (the risk of changes in cash flows attributable to changes in the designated benchmark interest rate) unless the cash flows of the hedged transaction are explicitly based on that same benchmark interest rate. The implementation guidance of DIG Issue G26 is effective April 1, 2007. As a result of applying DIG Issue G26, we dedesignated the hedging relationships as of April 1, 2007, for two of NYSEG's cash flow hedges. A $3.3 million pre tax loss on those derivatives for the period prior to April 1, 2007, will remain in accumulated other comprehensive income and be reclassified into earnings in the same periods that the hedged forecasted transactions affect earnings. RG&E's cash flow hedges were not affected by DIG Issue G26.

Note 8. Accounts Receivable

Energy East's accounts receivable includes unbilled revenues of $245 million at March 31, 2007, and $221 million at December 31, 2006, and are shown net of an allowance for doubtful accounts of $60 million at both March 31, 2007, and December 31, 2006.

RG&E's accounts receivable include unbilled revenues of $55 million at March 31, 2007, and $50 million at December 31, 2006, and are shown net of an allowance for doubtful accounts of $14 million at March 31, 2007, and $11 million at December 31, 2006.

Note 9. Retirement Benefits

Energy East and RG&E have funded noncontributory defined benefit pension plans that cover substantially all of their employees. The plans provide defined benefits based on years of service and final average salary. Energy East and RG&E also have other postretirement health care benefit plans covering substantially all of their employees. The health care plans are contributory with participants' contributions adjusted annually.

Components of net periodic benefit (income) cost

	Pension Benefits		Postretirement Benefits
Three months ended March 31,	2007	2006	2007	2006
(Thousands)
Energy East
Service cost	$9,348	$9,198	$1,453	$1,567
Interest cost	32,690	32,433	7,429	7,879
Expected return on plan assets	(58,234)	(54,878)	(647)	(483)
Amortization of prior service cost	1,141	1,176	(1,858)	(1,895)
Recognized net loss	4,206	4,605	1,373	2,076
Amortization of transition obligation	-	-	1,700	1,700
Net periodic benefit (income) cost	$(10,849)	$(7,466)	$9,450	$10,844
RG&E
Service cost	$1,189	$1,171	$157	$166
Interest cost	6,733	6,825	1,123	1,107
Expected return on plan assets	(11,733)	(11,490)	-	-
Amortization of prior service cost	370	370	215	215
Recognized net gain	(1,008)	(390)	(407)	(343)
Amortization of transition obligation	-	-	457	457
Net periodic benefit (income) cost	$(4,449)	$(3,514)	$1,545	$1,602

Note 10. 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 includes:

	Operating Revenues		Net Income
Three months ended March 31,	2007	2006	2007	2006
(Thousands)
Energy East
Electric Delivery	$766,682	$785,306	$55,154	$58,749
Natural Gas Delivery	797,382	756,899	76,395	72,728
Other	149,674	154,349	1,745	1,764
Total	$1,713,738	$1,696,554	$133,294	$133,241
RG&E
Electric Delivery	$194,098	$185,638	$18,915	$24,695
Natural Gas Delivery	183,903	160,873	16,644	15,590
Total	$378,001	$346,511	$35,559	$40,285

Item 3.  Quantitative and Qualitative Disclosures About Market Risk
(See report on Form 10-K for Energy East for the fiscal year ended December 31, 2006, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

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 effectively combines delivery and supply service at a fixed price. NYSEG uses 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 2007 the expected load for NYSEG's fixed rate option customers is fully hedged for May through December 2007. A fluctuation of $1.00 per MWh in the average price of electricity would change NYSEG's earnings less than $250 thousand for May through December 2007. RG&E expects to meet its fixed price load obligations for 2007 with owned generation or long-term supply contracts. The percentage of NYSEG's and RG&E's hedged load is based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecasts.

All of our natural gas utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices in order to provide price stability to customers. The cost or benefit of natural gas futures and forwards is included in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts as regulatory assets or regulatory liabilities.

Energetix and NYSEG Solutions, Inc. 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 2007 the energy marketing subsidiaries' expected fixed price loads were fully hedged for May through December 2007. A fluctuation of $1.00 per MWh in the average price of electricity would change their earnings less than $10,000 for May through December 2007. The percentage of hedged load for the energy marketing subsidiaries is based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecasts.

NYSEG, RG&E, Energetix and NYSEG Solutions face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are dependent on a counterparty's or the counterparty guarantor's applicable credit rating (normally Moody's or S&P). When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.

We use interest rate swap agreements to manage the risk of increases in variable interest rates (such as NYSEG's auction rate notes) and to maintain desired fixed-to-floating rate ratios. We record amounts paid and received under those agreements as adjustments to the interest expense of the specific debt issues. As required by DIG Issue G26 (see PartI, Item 1, Note 7. New Accounting Standards) we dedesignated the hedging relationships as of April 1, 2007, for NYSEG's two cash flow hedges related to its auction rate notes. We are investigating our options concerning the future management of interest rate risk for those instruments.

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 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   (January 1, 2007 to   January 31, 2007)	385,114(1)		$24.01		- -		- -
Month #2   (February 1, 2007 to   February 28, 2007)	4,724(2)		$25.14		- -		- -
Month #3   (March 1, 2007 to   March 31, 2007)	4,839(2)		$24.15		- -		- -
Total	394,677		$24.02		-		-
(1) Includes 4,850 shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employee's Stock Purchase Plan; 30,264 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; and 350,000 shares of the company's common stock (Par Value $.01) purchased for Treasury for issuance under the company's Restricted Stock Plan and Stock Option Plan. (2)  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, 2007.

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 3, 2007	ENERGY EAST CORPORATION                   (Registrant) By   /s/Robert D. Kump                                          Robert D. Kump            Senior Vice President and Chief Financial Officer            (Principal Accounting Officer)
Date:  May 3, 2007	ROCHESTER GAS AND ELECTRIC CORPORATION                   (Registrant) By   /s/Joseph J. Syta                                            Joseph J. Syta            Vice President - Controller and Treasurer            (Principal Financial Officer)

EXHIBIT INDEX

The following exhibits are delivered with this report:

Registrant	Exhibit No.	Description of Exhibit
Energy East Corporation	31-1	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	*32	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Rochester Gas and  Electric Corporation	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).