Energy East (EAS) 10-Q 2006 Q2 Quarterly report

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

FORM 10-Q

(Mark One)
[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934
      For the quarterly period ended  June 30, 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 July 31, 2006, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	147,701,521
Rochester Gas and Electric Corporation	Par value $5 per share	34,506,513(1)
(1) All shares are owned by RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation.

This combined Form 10-Q is separately filed byEnergy East CorporationandRochester Gas and Electric Corporation. Information contained herein relating to either registrant is filed by such registrant on its own behalf. Neither registrant makes any representation as to information relating to the other registrant.

		Table of Contents	Page
		Glossary	ii
		Forward-looking Statements	iv
		PART I - FINANCIAL INFORMATION
Item 1. Item 2.		Financial Statements (Unaudited) Management's Discussion and Analysis of Financial Condition     and Results of Operations
		Energy East Corporation   Condensed Consolidated Statements of IncomeCondensed Consolidated Balance SheetsCondensed Consolidated Statements of Cash FlowsCondensed Consolidated Statements of Retained EarningsCondensed Consolidated Statements of Comprehensive IncomeManagement's Discussion and Analysis of Financial Conditionand Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	1 2 4 5 5 6 15 17
		Rochester Gas and Electric Corporation   Condensed Balance SheetsCondensed Statements of IncomeCondensed Statements of Cash FlowsCondensed Statements of Retained EarningsCondensed Statements of Comprehensive Income   Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a)Liquidity and Capital Resources   (b)Results of Operations	22 24 25 26 26 27 27 28
		Notes to Condensed Financial Statements	32
Item 3.		Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.		Controls and Procedures	40
		PART II - OTHER INFORMATION
Item 1A.		Risk Factors	41
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 4.	Submission of Matters to a Vote of Security Holders		42
Item 6.		Exhibits	42
Signatures			43
Exhibit Index			44

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 FASBFinancial Accounting Standards Board FERCFederal Energy Regulatory Commission FIN 48 FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 GinnaRobert E. Ginna Nuclear Power Plant, a nuclear power plant sold by RG&E in June 2004 IRPIncentive Rate Plan ISO-NEISO New England Inc. MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations MPUCMaine Public Utilities Commission MW, MWh megawatt, megawatt hour

Glossary (continued)

NEPOOL New England Power Pool

NMP2 Nine Mile Point 2 nuclear
generating station

NUGnonutility generator

NYISONew York Independent
System Operator

NYPANew York Power Authority

NYPSCNew York State Public
Service Commission

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

RDRecommended Decision


ROEreturn on equity

RTORegional Transmission Organization

SARstock appreciation right

SECUnited States Securities and
Exchange Commission

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

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

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

TCCtransmission congestion contract

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

Forward-looking Statements

The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. This Form 10-Q contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. Whenever used in this report, the words "estimate," "expect," "believe," "anticipate," or similar expressions are intended to identify such forward-looking statements.

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties that could cause actual results to differ materially from those contemplated in any forward-looking statements are discussed in our Form 10-K for the fiscal year ended December 31, 2005, Item 1A - Risk Factors and Item 7 - MD&A - Market Risk, and also include, among others:

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

We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Energy East Corporation Condensed Consolidated Statements of Income- (Unaudited)
	Three Months		Six Months
Periods ended June 30,	2006	2005	2006	2005
(Thousands, except per share amounts)
Operating Revenues
Utility	$1,000,898	$970,076	$2,543,103	$2,459,595
Nonutility	111,927	111,068	265,333	257,637
Total Operating Revenues	1,112,825	1,081,144	2,808,436	2,717,232
Operating Expenses
Electricity purchased and fuel used in generation
Utility	354,208	357,264	731,549	713,526
Nonutility	84,237	79,515	173,627	160,444
Natural gas purchased
Utility	172,663	166,335	682,432	642,286
Nonutility	9,560	14,658	53,334	57,837
Other operating expenses	202,174	185,662	387,338	366,144
Maintenance	43,750	51,545	96,214	94,061
Depreciation and amortization	70,061	68,121	139,464	136,042
Other taxes	58,265	59,743	132,130	127,774
Total Operating Expenses	994,918	982,843	2,396,088	2,298,114
Operating Income	117,907	98,301	412,348	419,118
Other (Income)	(6,910)	(4,993)	(17,310)	(12,817)
Other Deductions	4,131	2,980	8,148	4,956
Interest Charges, Net	75,142	72,282	153,863	142,018
Preferred Stock Dividends of Subsidiaries	283	433	564	908
Income Before Income Taxes	45,261	27,599	267,083	284,053
Income Taxes	16,976	10,234	105,558	112,322
Net Income	$28,285	$17,365	$161,525	$171,731
Earnings per Share, basic	$.19	$.12	$1.10	$1.17
Earnings per Share, diluted	$.19	$.12	$1.09	$1.17
Dividends Declared and Paid per Share	$.29	$.275	$.58	$.55
Average Common Shares Outstanding, basic	146,903	146,831	146,968	146,853
Average Common Shares Outstanding, diluted	147,678	147,390	147,679	147,294
Thenotes on pages 32 through 39 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2006	Dec. 31, 2005
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$255,289	$120,009
Investments available for sale	17,250	192,925
Accounts receivable and unbilled revenues, net	759,899	933,680
Fuel and natural gas in storage, at average cost	196,359	278,590
Materials and supplies, at average cost	36,872	33,886
Deferred income taxes	28,197	-
Derivative assets	77,048	278,855
Prepayments and other current assets	138,458	92,613
Total Current Assets	1,509,372	1,930,558
Utility Plant, at Original Cost
Electric	5,449,901	5,403,134
Natural gas	2,600,793	2,574,574
Common	539,320	450,641
	8,590,014	8,428,349
Less accumulated depreciation	2,875,833	2,764,399
Net Utility Plant in Service	5,714,181	5,663,950
Construction work in progress	77,673	119,504
Total Utility Plant	5,791,854	5,783,454
Other Property and Investments	193,186	203,159
Regulatory and Other Assets
Regulatory assets
Deferred income taxes	-	13,482
Nuclear plant obligations	280,486	309,888
Unfunded future income taxes	176,046	117,241
Environmental remediation costs	138,191	135,376
Unamortized loss on debt reacquisitions	56,807	60,933
Nonutility generator termination agreements	84,618	86,890
Natural gas hedges	25,449	-
Other	315,484	384,173
Total regulatory assets	1,077,081	1,107,983
Other assets
Goodwill	1,525,353	1,525,353
Prepaid pension benefits	757,087	741,831
Derivative assets	89,431	67,907
Other	119,703	127,463
Total other assets	2,491,574	2,462,554
Total Regulatory and Other Assets	3,568,655	3,570,537
Total Assets	$11,063,067	$11,487,708
Thenotes on pages 32 through 39 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2006	Dec. 31, 2005
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$299,070	$326,527
Current portion of debt owed to subsidiary holding   solely parent debentures	105,670	- -
Notes payable	12,000	121,347
Accounts payable and accrued liabilities	380,001	629,158
Interest accrued	44,782	46,522
Taxes accrued	92,856	-
Deferred income taxes	-	80,984
Derivative liabilities	54,210	2,019
Other	122,865	186,452
Total Current Liabilities	1,111,454	1,393,009
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	795,549	797,544
Deferred income taxes	6,693	-
Gain on sale of generation assets	181,596	173,216
Pension benefits	19,856	22,798
Natural gas hedges	-	49,205
Other	124,530	124,251
Total regulatory liabilities	1,128,224	1,167,014
Other liabilities
Deferred income taxes	1,062,897	1,033,287
Nuclear plant obligations	220,981	234,907
Other postretirement benefits	431,579	428,691
Environmental remediation costs	169,287	166,462
Other	470,482	499,968
Total other liabilities	2,355,226	2,363,315
Total Regulatory and Other Liabilities	3,483,450	3,530,329
Debt owed to subsidiary holding solely parent debentures	250,000	355,670
Other long-term debt	3,335,473	3,311,395
Total long-term debt	3,585,473	3,667,065
Total Liabilities	8,180,377	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	1,488,621	1,489,256
Retained earnings	1,370,829	1,294,580
Accumulated other comprehensive (loss) income	(652)	89,085
Treasury stock, at cost	(2,217)	(1,725)
Total Common Stock Equity	2,858,059	2,872,674
Total Liabilities and Stockholders' Equity	$11,063,067	$11,487,708
Thenotes on pages 32 through 39 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Cash Flows - (Unaudited)
Six months ended June 30,	2006	2005
(Thousands)
Operating Activities
Net income	$161,525	$171,731
Adjustments to reconcile net income to net cash  provided by operating activities
Depreciation and amortization	199,933	185,021
Income taxes and investment tax credits deferred, net	(19,465)	5,612
Pension income	(15,036)	(14,626)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	173,264	129,243
Inventory	79,245	51,813
Prepayments and other current assets	(790)	4,263
Accounts payable and accrued liabilities	(225,471)	(22,942)
Interest accrued	(1,740)	(25,330)
Taxes accrued	52,695	(1,099)
Customer refund	(15,017)	32,488
Other current liabilities	(83,657)	(58,165)
Pension contributions	-	(54,000)
Other assets	52,310	44,348
Other liabilities	(43,785)	(44,106)
Net Cash Provided by Operating Activities	314,011	404,251
Investing Activities
Utility plant additions	(153,032)	(147,658)
Other property additions	(1,394)	(1,747)
Other property sold	-	145
Maturities of current investments available for sale	710,775	786,605
Purchases of current investments available for sale	(535,100)	(815,610)
Investments	10,533	16,249
Net Cash Provided by (Used in) Investing Activities	31,782	(162,016)
Financing Activities
Issuance of common stock	-	2,194
Repurchase of common stock	(6,107)	(7,420)
Book overdraft	(6,106)	(173)
Redemption of preferred stock   of subsidiary, including premium	- -	(22,220)
Long-term note issuances	77,172	270,000
Long-term note repayments	(80,849)	(256,892)
Notes payable three months or less, net	(106,108)	(130,568)
Notes payable issuances	53,410	10,500
Notes payable repayments	(56,649)	(9,000)
Dividends on common stock	(85,276)	(71,714)
Net Cash Used in Financing Activities	(210,513)	(215,293)
Net Increase in Cash and Cash Equivalents	135,280	26,942
Cash and Cash Equivalents, Beginning of Period	120,009	111,465
Cash and Cash Equivalents, End of Period	$255,289	$138,407
Thenotes on pages 32 through 39 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Retained Earnings - (Unaudited)
Six months ended June 30,	2006	2005
(Thousands)
Balance, Beginning of Period	$1,294,580	$1,201,533
Add net income	161,525	171,731
	1,456,105	1,373,264
Deduct dividends on common stock	85,276	80,715
Balance, End of Period	$1,370,829	$1,292,549
Thenotes on pages 32 through 39 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Statements of Comprehensive Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30,	2006	2005	2006	2005
(Thousands)
Net income	$28,285	$17,365	$161,525	$171,731
Other comprehensive income, net of tax
Net unrealized gains (losses) on investments, net of    income tax (expense) benefit in the three months of    $(142) in 2006 and $- in 2005 and for the six months    of $24 in 2006 and $- in 2005	215	19	(37)	(4)
Minimum pension liability adjustment net of income    tax benefit for the three months and six months of    $661 in 2006 and $7 in 2005	(997)	(11)	(997)	(11)
Unrealized gains (losses) on derivatives qualified as    hedges, net of income tax benefit (expense) for the     three months of $(4,686) in 2006 and $22,586 in    2005 and for the six months of $71,811 in 2006    and $(6,283) in 2005	6,726	(32,365)	(113,476)	15,991
Reclassification adjustment for (gains) losses    included in net income, net of income tax expense    (benefit) for the three months of $4,063 in 2006 and    $601 in 2005 and for the six months of $(16,353) in    2006 and $(20,769) in 2005	(6,124)	(940)	24,773	31,403
Net unrealized (losses) gains on derivatives qualified    as hedges	602	(33,305)	(88,703)	47,394
Total other comprehensive (loss) income	(180)	(33,297)	(89,737)	47,379
Comprehensive Income (Loss)	$28,105	$(15,932)	$71,788	$219,110
Thenotes on pages 32 through 39 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, 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. NYSEG has filed for an extension of its electric rate plan; its current plan expires December 31, 2006. 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 State and New England.

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

We engage in various investing and financing activities to meet our strategic objectives. Our primary goal for investing activities is to maintain a reliable energy delivery infrastructure. We fund our investing activities primarily with internally generated funds. We plan to invest nearly $2 billion in our energy delivery infrastructure over the next five years, including approximately $900 million dedicated to electric reliability. We focus our financing activities on maintaining adequate liquidity and credit quality and minimizing our cost of capital.

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

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

Energy East Corporation

Strategy

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

Our long-term rate plans 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. (See NYSEG Electric Rate Plan Extension and Other Proceedings in the NYPSC Collaborative on End State of Energy Competition.)

Electric Delivery Business Developments

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

NYSEG Electric Rate 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 earnings resulting from the earnings sharing mechanism. NYSEG's Electric Rate Plan Extension, as subsequently amended, also proposed, beginning on January 1, 2007, to reduce the nonbypassable wires charge by $168 million and increase delivery rates by $104 million, thereby maintaining an annu alized overall electricity delivery rate decrease of approximately $64 million, or 8.6%. NYSEG proposed 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.

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

Energy East Corporation

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 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.

Hearings in this proceeding concluded on April 21, 2006, and various parties filed briefs on April 26, 2006, and May 10, 2006.

On June 9, 2006, the ALJs assigned to NYSEG's electric rate plan extension proceeding issued their RD. The RD, among other things, recommends:

• A decrease in delivery rates of $37 million. NYSEG's most recent update in the proceeding requested a $58 million increase in delivery rates.

• A 9.3% ROE. NYSEG had requested an 11% ROE.

• A significant modification to NYSEG's commodity options program, including:

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

-  A reduction in the allowance, from 35% to 22%, used to set the supply rate to cover the costs of providing fixed price electricity at retail.

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

NYSEG believes that the commodity options program, as recommended, is unworkable and inconsistent with the development of a competitive retail market for supply. In particular, the lower allowance used to set the supply rate does not cover the cost and risk of providing fixed price electricity at retail and would stifle participation by retail energy service providers. If the commodity portion of the RD were adopted as proposed, NYSEG could not offer fixed price electricity to its customers on those terms.

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

Energy East Corporation

If the RD were adopted in its entirety by the NYPSC, the RD would have a significant adverse effect on NYSEG's financial condition and results of operations. In addition to the items noted above, the RD ignores over $25 million of forecasted expenses, which, if the RD were adopted, would force NYSEG to cut operating, maintenance and capital spending, resulting in significant workforce reductions and degradation in current levels of customer service. It is also likely that NYSEG would be forced to file a new electric rate case.

NYSEG filed briefs objecting to certain aspects of the RD on June 29, 2006, and opposing objections of other parties on July 14, 2006. Further, 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. A final NYPSC decision is expected in August 2006. NYSEG cannot predict the outcome of this proceeding.

Flood Damage in NYSEG's Service Territory: A major flood affected certain regions of NYSEG's service territory beginning on June 27, 2006, resulting in extensive damage. Pursuant to the terms of its current electric and natural gas rate plans, NYSEG will defer for future cost recovery virtually all incremental operating and maintenance costs, net of insurance proceeds, resulting from the flooding. NYSEG is still assessing the full magnitude of those costs, which it expects to be in excess of $5 million.

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

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

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

Energy East Corporation

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 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. In January 2006 the NYPA answered those comments, arguing that the FERC should ignore certain issues that NYSEG and RG&E raised and that allocation issues are not an appropriate question in the relicensing proceeding. NYSEG and RG&E filed a response to NYPA's answer in January 2006, and continue to be active participants in the proceeding. NYSEG and RG&E are unable to predict the outcome of this proceeding.

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

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

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

Energy East Corporation

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

Pursuant to a FERC approved settlement, in July 2004 Connecticut Yankee filed for FERC approval of a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of decommissioning costs. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars and result in annual collections of $93 million from Connecticut Yankee's owners, including CMP. The revised estimate reflects increases in the projected costs for spent fuel storage, security, liability and property insurance and the fact that Connecticut Yankee had to take over all work to complete the decommissioning of the plant due to its termination of its contract with Bechtel, the turnkey decommissioning contractor, in July 2003. Bechtel filed a lawsuit in Connecticut state court challenging that termination and Connecticut Yankee filed a counterclaim to recover damages caused by Bechtel's breac h of contract and termination. In April 2006 Connecticut Yankee and Bechtel settled this matter. Any amount Connecticut Yankee recovers from Bechtel will be credited to its decommissioning costs and any remaining decommissioning funds would be returned to electric customers when decommissioning is complete.

Other Proceedings in the NYPSC Collaborative on End State of Energy Competition: NYSEG and RG&E have supplied comments in NYPSC proceedings regarding other investor-owned utility programs that are designed to encourage customers to migrate from utilities to ESCOs. NYSEG and RG&E believe that the "PowerSwitch" program implemented by Orange and Rockland Utilities, Inc. is flawed, since it results in customers being switched to ESCOs without complete information on the program. In their filing, NYSEG and RG&E question whether the "PowerSwitch" program is consistent with the NYPSC's Uniform Business Practices. NYSEG and RG&E believe the program results are suspect and should not be used as a basis to expand the program to other utilities. In June 2005 the NYPSC approved Central Hudson Gas & Electric Corporation's retail access plan and rejected NYSEG's and RG&E's comments requesting the NYPSC to not take action on Central Hudson's plan and to suspen d 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 a December 2005 order the NYPSC established procedures for utilities to follow in implementing ESCO Referral Programs based on the Orange & Rockland model, as modified and enhanced with additional consumer protection measures. The NYPSC has approved ESCO Referral Programs for Orange & Rockland, Central Hudson, Niagara

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

Energy East Corporation

Mohawk Power Corporation, Consolidated Edison Company of New York, Inc., and National Fuel Gas Distribution Corporation. Pursuant to an NYPSC order, RG&E has initiated a collaborative with interested parties for the purpose of RG&E implementing an ESCO Referral Program. They are discussing the effects such a program would have on RG&E's Voice Your Choice program. The NYPSC permitted NYSEG to address the ESCO Referral Program within the context of its electric rate plan extension described above. (See NYSEG Electric Rate Plan Extension.)

New England RTO: In March 2004 the FERC issued an order that accepted a six-state New England RTO as proposed by ISO-NE and the New England transmission owners. As an RTO, ISO-NE is responsible for the independent operation of the regional transmission system and regional wholesale energy market. The transmission owners retain ownership of their transmission facilities and control over their revenue requirements. The FERC also approved both a 50 basis point ROE incentive adder for regional transmission facilities subject to RTO control and a 100 basis point ROE incentive adder for new regional transmission facilities developed by an RTO. The New England transmission owners appealed the application of the adders to local facilities to the Circuit Court of Appeals for the District of Columbia. Other parties appealed the FERC's decision to grant the adders to regional facilities. On June 30, 2006, the Court denied the appeals and upheld the FERC's decisions. (See report on Form 10-K for Energy East for the fiscal year ended December 31, 2005, Item 7 - MD&A, Electric Delivery Business Developments.)

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

CMP and other parties that oppose the ISO-NE market proposal filed exceptions to the recommended decision in July 2005. The Energy Policy Act of 2005 included a "sense of Congress" provision to the effect that the FERC should carefully consider the objections of the New England states to the proposal in the recommended decision. 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 market proposal. In response to those protests, the FERC has delayed any possible implementation until October 1, 2006, at the earliest, and granted oral arguments to consider opposition to the market proposal 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 in January 2006 the settlement ALJ reported to the FERC that most of the parties had reached an agreement in principle on an alternative. The alternative would provide fixed transitional capacity payments from 2006 until 2010 and provide capacity payments based on a Forward Capacity Market Auction thereafter. CMP opposed this settlement agreement because of the unjustified cost of the transition payments to electric customers in

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

Energy East Corporation

Maine. The ISO-NE and a majority of NEPOOL participants supported the settlement agreement. That alternative has been filed with the FERC as a component of a comprehensive settlement agreement.

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

MPUC Inquiries into Maine Initative for Long-Term Utility Capacity Contracts and
New England RTO: Maine lawmakers enacted legislation in 2006 that requires the MPUC to conduct an inquiry concerning whether or not CMP and other Maine electric utilities should continue to participate in the New England RTO, as operated by the ISO-NE. That legislation also requires the MPUC to conduct further inquiry regarding regional energy markets and generation deregulation. Among the actions initiated by such legislation is an MPUC inquiry into the development of a Maine electric resource adequacy plan and the use of long-term generating capacity contracts between utilities and capacity suppliers as a mechanism to support such a plan. The MPUC's inquiry is expected to lead to further proceedings, including the development of implementing rules and a series of reports to the Maine Legislature. The long-term contracting rules and the first report on resource adequacy will be submitted to the legislature for further action in early 2007. In a related inquiry, the MPUC will consider whether it beli eves that Maine's transmission and distribution utilities should continue to participate in the New England RTO. This inquiry will consider the legal authority, the costs and benefits of and alternatives to an RTO, and will result in a report to the Maine Legislature. CMP will participate in these MPUC proceedings and cannot predict the outcome of these inquiries.

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.

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. On August 1, 2006, CNG notified the DPUC of its intent to submit a general rate filing by the end of September 2006, requesting a net rate increase of $28 million, or 7.9%, in base delivery revenues effective April 1, 2007.

New and Proposed Accounting Standards

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

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 the first phase of a two-phase project to comprehensively reconsider existing guidance on accounting for pension and postretirement benefits. The second phase 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- funded status on its balance sheet; recognize actuarial gains and losses

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

Energy East Corporation

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 year-end balance sheet.

Two public roundtable meetings were held on June 27, 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. The provisions related to measuring plan assets and benefit obligations as of the date of the year-end balance sheet would be applied for public companies for fiscal years beginning after December 15, 2006, and earlier application would be encouraged. Energy East and RG&E each already measure plan assets and benefit obligations as of the year-end balance sheet date. Adoption of a final standard, consistent with proposed modifications to the Exposure Draft, effective for the fiscal year ended December 31, 2006, could have a material effect on Energy East's and RG&E's financial position by reducing prepaid benefits and common stock equity, but would not affe ct their results of operations or cash flows.

(a) Liquidity and Capital Resources

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

• A reduction in accounts payable of $225 million that reduced cash primarily due to payments for natural gas purchases and purchased power,
• Decreased receivables that increased cash by $173 million, and
• A reduction in natural gas inventory that increased cash by $79 million.

While the foregoing represent normal activity for the period, the amounts are greater than normal due to higher energy prices.

Investing Activities: Capital spending for the six months ended June 30, 2006, was $153 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.

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.

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

Energy East Corporation

In the fourth quarter of 2005, instead of issuing new shares, we began purchasing shares of our common stock in the open market for dividends reinvested through our Investor Services Program. Therefore, our 2006 cash outflows for dividends equal the amount of our dividends as shown on our retained earnings statement.

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

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

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

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

In November 2006 Energy East's $232 million 5.75% note matures. Energy East has entered into an arrangement to hedge the interest rate in connection with the refinancing of that security.

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

Energy East Corporation

(b)Results of Operations

Earnings per Share

Three months ended June 30,	2006	2005
(Thousands, except per share amounts)
Operating Revenues	$1,112,825	$1,081,144
Operating Income	$117,907	$98,301
Net Income	$28,285	$17,365
Average Common Shares Outstanding, basic	146,903	146,831
Average Common Shares Outstanding, diluted	147,678	147,390
Earnings per Share, basic and diluted	$.19	$.12
Dividends Paid per Share	$.29	$.275

Earnings per share for the quarter ended June 30, 2006, increased 7 cents compared to the quarter ended June 30, 2005, primarily because of:

• An increase of 14 cents per share due to higher margins on electricity sales, including 4 cents per share for recovery of undercollected transition charges and 2 cents per share for adjustments to the nonbypassable wires charge. The transition charge reflects the difference between the market price of electricity and the prices set by our long-term electricity supply contracts.

That increase was offset by:

• A decrease of 2 cents per share for lower net margin on natural gas sales, and

• A decrease of 4 cents per share due to higher operating and maintenance expenses, including increases of approximately 9 cents per share for higher uncollectible reserves (reflecting both an increase in 2006 and the effect of a decrease in 2005), partially offset by a decrease of 3 cents per share for lower stock option expense.

Six months ended June 30,	2006	2005
(Thousands, except per share amounts)
Operating Revenues	$2,808,436	$2,717,232
Operating Income	$412,348	$419,118
Net Income	$161,525	$171,731
Average Common Shares Outstanding, basic	146,968	146,853
Average Common Shares Outstanding, diluted	147,679	147,294
Earnings per Share, basic	$1.10	$1.17
Earnings per Share, diluted	$1.09	$1.17
Dividends Paid per Share	$.58	$.55

Earnings per share, basic for the six months ended June 30, 2006, decreased 7 cents compared to the six months ended June 30, 2005, primarily because of:

• A decrease of 9 cents per share resulting from increased operating and maintenance costs including 10 cents per share for higher uncollectible reserves (reflecting both an increase in 2006 and the effect of a decrease in 2005) and 3 cents per share for storm-related repairs partially offset by a decrease of 2 cents per share for lower stock option expense,
• A decrease of 5 cents per share for higher interest expense resulting from higher rates on short-term and variable rate debt and higher carrying costs on regulatory liabilities,
• A decrease of 2 cents per share for lower net margin on natural gas sales, and

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

Energy East Corporation

• A decrease of 3 cents per share resulting from increased depreciation expense and other taxes. The depreciation increase was primarily due to the implementation of NYSEG's customer care system.

Those decreases were partially offset by:

• An increase of 12 cents per share due to higher margins on electricity sales, including 8 cents per share for lower earnings sharing accruals and 2 cents per share for adjustments to the nonbypassable wires charge.

Operating Results for the Electric Delivery Business

Three months ended June 30,	2006	2005
(Thousands)
Retail Deliveries (MWh)	7,316	7,341
Retail Commodity Sales (MWh)(1)	3,022	3,181
Wholesale Sales (MWh)	2,485	2,460
Operating Revenues	$717,692	$687,626
Operating Expenses	$605,720	$598,060
Operating Income	$111,972	$89,566
(1) Also included in Retail Deliveries.

Operating Revenues:The $30 million increase in operating revenues for the second quarter of 2006 was primarily the result of:

• An increase of $16 million in wholesale revenue primarily resulting from higher volumes at NYSEG and RG&E,
• An increase of $15 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 $8 million in other revenues, including $6 million for nonbypassable wires charge accruals.

Those increases were partially offset by:

• A decrease of $8 million resulting from reduced electricity sales under the companies' commodity programs, and
• A decrease of $3 million resulting from lower retail deliveries.

Operating Expenses: The $8 million increase in operating expenses for the second quarter of 2006 was primarily the result of:

• An increase of $10 million for higher uncollectible reserves, partially offset by a decrease of $2 million for various other items.

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

Energy East Corporation

Six months ended June 30,	2006	2005
(Thousands)
Retail Deliveries (MWh)	15,163	15,417
Retail Commodity Sales (MWh)(1)	6,587	6,960
Wholesale Sales (MWh)	4,986	4,445
Operating Revenues	$1,502,998	$1,455,949
Operating Expenses	$1,238,076	$1,182,497
Operating Income	$264,922	$273,452
(1) Also included in Retail Deliveries.

Operating Revenues:The $47 million increase in operating revenues for the six months ended June 30, 2006, was primarily the result of:

• An increase of $58 million in wholesale revenue primarily resulting from higher volumes at NYSEG and RG&E,
• An increase of $28 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 $34 million in other revenues including $20 million in lower accruals for earnings sharing and $6 million for the nonbypassable wires charge. The $20 million increase includes $14 million from the first quarter of 2006 for the finalization of the actual amount of earnings sharing for 2005 per the annual compliance filings by NYSEG and RG&E.

Those increases were partially offset by:

• A decrease of $26 million resulting from reduced sales under the companies' commodity programs,
• A decrease of $16 million resulting from lower retail deliveries due largely to warmer winter weather, and
• A decrease of $30 million in average delivery prices resulting from lower transition charges. This charge decreases as market prices increase.

Operating Expenses: The $56 million increase in operating expenses for the six months ended June 30, 2006, was primarily the result of:

• An increase of $18 million in purchased power costs resulting from $46 million for higher wholesale electricity market prices, reduced by $28 million due to the expiration of a major NUG contract in 2006,
• An increase of $28 million in operating and maintenance costs including $9 million for storm restoration, $13 million for higher uncollectible reserves and $4 million related to NYSEG's rate case,
• An increase of $4 million in depreciation resulting largely from the implementation of NYSEG's new customer care system, and
• An increase of $5 million in other taxes primarily due to a refund received in 2005.

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

Energy East Corporation

Operating Results for the Natural Gas Delivery Business

Three months ended June 30,	2006	2005
(Thousands)
Retail Deliveries (Dth)	35,638	37,187
Wholesale Sales (Dth)	45	348
Operating Revenues	$283,206	$282,450
Operating Expenses	$281,934	$271,899
Operating Income	$1,272	$10,551

Operating Revenues: The $1 million increase in operating revenues for the second quarter of 2006 was primarily the result of:

• An increase of $6 million as a result of higher market prices of natural gas, and
• An increase of $3 million as a result of higher base rates for SCG effective January 1, 2006.

Those increases were partially offset by:

• A decrease of $5 million in delivery volumes due to warmer weather and customer conservation, and
• A decrease of $3 million in other revenue.

Operating Expenses: The $10 million increase in operating expenses for the second quarter of 2006 was primarily the result of:

• An increase of $5 million due to higher market prices for purchased natural gas, and
• An increase of $7 million in operating and maintenance costs including $12 million for higher uncollectible reserves, partially offset by reductions for various other items.

Those increases were partially offset by:

• A decrease of $2 million in other taxes.

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

Energy East Corporation

Six months ended June 30,	2006	2005
(Thousands)
Retail Deliveries (Dth)	111,283	123,444
Wholesale Sales (Dth)	91	698
Operating Revenues	$1,040,105	$1,003,646
Operating Expenses	$901,895	$858,964
Operating Income	$138,210	$144,682

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

• An increase of $127 million primarily as a result of higher natural gas market prices that were passed on to customers, and
• An increase of $13 million due to higher base rates for SCG effective January 1, 2006.

Those increases were partially offset by:

• A decrease of $103 million as a result of lower delivery volumes due largely to warmer winter weather and customer conservation.

Operating Expenses: The $43 million increase in operating expenses for the six months ended June 30, 2006, was primarily the result of:

• An increase of $105 million due to higher market prices for purchased natural gas, and
• An increase of $6 million in operating and maintenance costs including $11 million for higher uncollectible reserves, partially offset by a decrease of $5 million for various other items.

Those increases were partially offset by:

• A reduction of $69 million due to lower volumes of natural gas purchases.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	June 30, 2006	Dec. 31, 2005
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$74,100	$28,752
Investments available for sale	-	53,325
Accounts receivable and unbilled revenues, net	167,077	193,807
Fuel and natural gas in storage, at average cost	32,939	57,434
Materials and supplies, at average cost	17,167	13,204
Deferred income taxes	12,002	-
Derivative assets	93	21,597
Prepayments and other current assets	42,616	27,047
Total Current Assets	345,994	395,166
Utility Plant, at Original Cost
Electric	1,269,647	1,258,330
Natural gas	579,252	572,943
Common	198,439	199,015
	2,047,338	2,030,288
Less accumulated depreciation	610,525	583,557
Net Utility Plant in Service	1,436,813	1,446,731
Construction work in progress	39,773	18,748
Total Utility Plant	1,476,586	1,465,479
Other Property and Investments	11,375	11,634
Regulatory and Other Assets
Regulatory assets
Deferred income taxes	-	12,007
Nuclear plant obligations	169,954	183,039
Environmental remediation costs	26,315	25,013
Unamortized loss on debt reacquisitions	12,653	14,336
Nonutility generator termination agreement	77,632	82,243
Natural gas hedges	13,243	-
Other	115,604	127,867
Total regulatory assets	415,401	444,505
Other assets
Prepaid pension benefits	56,018	48,368
Derivative assets	6,873	372
Other	14,916	16,749
Total other assets	77,807	65,489
Total Regulatory and Other Assets	493,208	509,994
Total Assets	$2,327,163	$2,382,273
Thenotes on pages 32 through 39 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Balance Sheets - (Unaudited)
	June 30, 2006	Dec. 31, 2005
(Thousands)
Liabilities
Current Liabilities
Accounts payable and accrued liabilities	$74,138	$123,145
Interest accrued	9,525	9,830
Taxes accrued	36,135	16,438
Deferred income taxes	-	698
Derivative liabilities	16,314	1,562
Other	30,807	36,396
Total Current Liabilities	166,919	188,069
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	185,139	182,346
Deferred income taxes	14,080	-
Unfunded future income taxes	36,121	89,104
Gain on sale of generation assets	129,934	111,262
Natural gas hedges	-	21,969
Other	44,734	51,015
Total regulatory liabilities	410,008	455,696
Other liabilities
Deferred income taxes	166,531	167,785
Nuclear waste disposal	110,977	108,570
Other postretirement benefits	80,721	80,045
Environmental remediation costs	37,523	36,506
Other	52,417	65,146
Total other liabilities	448,169	458,052
Total Regulatory and Other Liabilities	858,177	913,748
Long-term debt	697,988	697,951
Total Liabilities	1,723,084	1,799,768
Commitments and Contingencies
Common Stock Equity
Common stock	194,429	194,429
Capital in excess of par value	483,500	483,252
Retained earnings	45,785	28,549
Accumulated other comprehensive (loss) income	(2,397)	(6,487)
Treasury stock, at cost	(117,238)	(117,238)
Total Common Stock Equity	604,079	582,505
Total Liabilities and Stockholder's Equity	$2,327,163	$2,382,273
Thenotes on pages 32 through 39 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30,	2006	2005	2006	2005
(Thousands)
Operating Revenues
Electric	$172,962	$158,902	$358,599	$319,057
Natural gas	63,146	66,915	224,020	222,479
Total Operating Revenues	236,108	225,817	582,619	541,536
Operating Expenses
Electricity purchased and fuel used in generation	79,260	71,457	155,165	135,496
Natural gas purchased	34,878	38,579	143,711	142,727
Other operating expenses	41,764	36,313	80,529	75,623
Maintenance	11,838	12,373	22,746	22,770
Depreciation and amortization	17,804	17,712	35,622	35,483
Other taxes	17,425	16,648	34,539	31,825
Total Operating Expenses	202,969	193,082	472,312	443,924
Operating Income	33,139	32,735	110,307	97,612
Other (Income)	(873)	(459)	(1,937)	(2,013)
Other Deductions	223	139	405	267
Interest Charges, Net	14,026	14,763	28,310	28,744
Income Before Income Taxes	19,763	18,292	83,529	70,614
Income Taxes	7,811	7,316	31,293	28,710
Net Income	$11,952	$10,976	$52,236	$41,904
Thenotes on pages 32 through 39 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Cash Flows - (Unaudited)
Six months ended June 30,	2006	2005
(Thousands)
Operating Activities
Net income	$52,236	$41,904
Adjustments to reconcile net income to net cash  provided by operating activities
Depreciation and amortization	67,910	68,315
Income taxes and investment tax credits deferred, net	6,054	7,392
Pension income	(7,647)	(9,025)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	26,730	11,646
Inventory	20,532	4,590
Prepayments and other current assets	(15,569)	(1,399)
Accounts payable and accrued liabilities	(29,701)	17,684
Interest accrued	(305)	84
Taxes accrued	19,617	3,126
Customer refund	(15,426)	(25,330)
Other current liabilities	(23,560)	(18,614)
Other assets	2,490	(8,478)
Other liabilities	(30,153)	11,302
Net Cash Provided by Operating Activities	73,208	103,197
Investing Activities
Utility plant additions	(42,890)	(29,666)
Maturities of current investments available for sale	261,325	275,200
Purchases of current investments available for sale	(208,000)	(300,360)
Other	(671)	108
Net Cash Provided by (Used in) Investing Activities	9,764	(54,718)
Financing Activities
Book overdraft	(2,624)	(641)
Dividends on common stock	(35,000)	(35,000)
Net Cash Used in Financing Activities	(37,624)	(35,641)
Net Increase in Cash and Cash Equivalents	45,348	12,838
Cash and Cash Equivalents, Beginning of Period	28,752	11,834
Cash and Cash Equivalents, End of Period	$74,100	$24,672
Thenotes on pages 32 through 39 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Retained Earnings - (Unaudited)
Six months ended June 30,	2006	2005
(Thousands)
Balance, Beginning of Period	$28,549	$19,560
Add net income	52,236	41,904
	80,785	61,464
Deduct dividends on common stock	35,000	35,000
Balance, End of Period	$45,785	$26,464
Thenotes on pages 32 through 39 are an integral part of the condensed financial statements.

Rochester Gas and Electric Corporation Condensed Statements of Comprehensive Income - (Unaudited)
	Three Months			Six Months
Periods ended June 30,	2006	2005	2006		2005
(Thousands)
Net income	$11,952	$10,976	$52,236		$41,904
Other comprehensive income, net of tax
Net unrealized (losses) on investments, net of    income tax benefits in 2006 of $117 for the    three months and $92 for the six months	(177)	- -	(138)		- -
Minimum pension liability adjustment net of    income tax benefit for the three months and    six months in 2006 of $261	(394)	- -	(394)		- -
Unrealized gains (losses) on derivatives qualified    as hedges, net of income tax (expense)    benefit for the three months of $(1,108) in    2006 and $4,209 in 2005 and for the six    months of $(282) in 2006 and $2,623 in 2005	1,672	(6,346)	426		(3,929)
Reclassification adjustment for derivative losses    (gains) included in net income, net of income    tax (benefit) expense for the three months of    $(771) in 2006 and $(22) in 2005 and for the    six months of $(2,783) in 2006 and $369    in 2005	1,163	33	4,196		(557)
Net unrealized gains (losses) on derivatives    qualified as hedges	2,835	(6,313)	4,622		(4,486)
Total other comprehensive income (loss)	2,264	(6,313)	4,090		(4,486)
Comprehensive Income	$14,216	$4,663	$56,326		$37,418
Thenotes on pages 32 through 39 are an integral part of the condensed financial statements.

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

Rochester Gas and Electric Corporation

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

Electric Delivery Business Developments

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

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

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

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

Natural Gas Delivery Business Developments

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

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

New and Proposed Accounting Standards

FIN 48: See Energy East's Part I, Item 2 - MD&A - New and Proposed Accounting Standards, for this discussion.

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

(a) Liquidity and Capital Resources

Operating Activities: Cash flows from operating activities for the six months ended June 30 included refunds to RG&E customers of $15 million in 2006 and $25 million in 2005, from proceeds from the sale of Ginna, pursuant to the Electric Rate Agreement. The Electric Rate Agreement requires an additional refund to customers of $10 million in 2007.

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

Rochester Gas and Electric Corporation

Investing Activities: Capital spending for the six months ended June 30, 2006, was $43 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.

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

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

(b)Results of Operations

Earnings

Three months ended June 30,	2006	2005
(Thousands)
Operating Revenues	$236,108	$225,817
Operating Income	$33,139	$32,735
Net Income	$11,952	$10,976

RG&E's net income for the second quarter of 2006 increased $1 million compared to the second quarter of 2005. Earnings for the quarter in 2006 for both the electric and natural gas segments were consistent with the prior year quarter.

Six months ended June 30,	2006	2005
(Thousands)
Operating Revenues	$582,619	$541,536
Operating Income	$110,307	$97,612
Net Income	$52,236	$41,904

RG&E's net income for the six months ended June 30, 2006, increased $10 million compared to the six months ended June 30, 2005, primarily because of higher net margins on electricity sales in the first quarter of 2006.

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

Rochester Gas and Electric Corporation

Operating Results for the Electric Delivery Business

Three months ended June 30,	2006	2005
(Thousands)
Retail Deliveries (MWh)	1,747	1,733
Retail Commodity Sales (MWh)(1)	836	881
Wholesale Sales (MWh)	1,016	791
Operating Revenues	$172,962	$158,902
Operating Expenses	$145,360	$131,239
Operating Income	$27,602	$27,663
(1) Also included in Retail Deliveries.

Operating Revenues: The $14 million increase in operating revenues for the second quarter of 2006 was primarily the result of:

• An increase of $11 million due to higher wholesale revenues,
• An increase of $2 million due to higher market prices for retail deliveries under various commodity options where RG&E provides supply, and
• An increase of $7 million resulting from higher other revenues. The $7 million is net of a $4 million accrual for higher earnings sharing.

Those increases were partially offset by:

• A decrease of $6 million resulting from lower average delivery prices.

Operating Expenses: The $14 million increase in operating expenses for the second quarter of 2006 was primarily the result of:

• An increase of $8 million for purchased power costs, and
• An increase of $5 million in operating and maintenance expenses primarily due to the effect of a decrease in the uncollectible reserve in 2005.

Six months ended June 30,	2006	2005
(Thousands)
Retail Deliveries (MWh)	3,495	3,488
Retail Commodity Sales (MWh)(1)	1,714	1,841
Wholesale Sales (MWh)	2,023	1,349
Operating Revenues	$358,599	$319,057
Operating Expenses	$282,880	$253,688
Operating Income	$75,719	$65,369
(1) Also included in Retail Deliveries.

Operating Revenues: The $40 million increase in operating revenues for the first half of 2006 was primarily the result of:

• An increase of $36 million due to higher wholesale revenues,
• An increase of $33 million due to higher market prices for retail deliveries under various commodity options where RG&E provides supply, and

• An increase of $22 million in other revenues including a reduction of $4 million in the accrual for earnings sharing. The remainder is primarily due to increased credits from the ASGA.

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

Rochester Gas and Electric Corporation

Those increases were partially offset by:

• A decrease of $43 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.
• And a decrease of $9 million resulting from lower electricity sales under RG&E's commodity programs.

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

• An increase of $20 million for purchased power costs,
• An increase of $6 million for operating and maintenance expenses, primarily due to the effect of a decrease in the uncollectible reserve in 2005, and
• An increase of $3 million for other taxes.

Operating Results for the Natural Gas Delivery Business

Three months ended June 30,	2006	2005
(Thousands)
Retail Deliveries (Dth)	7,427	8,488
Operating Revenues	$63,146	$66,915
Operating Expenses	$57,609	$61,843
Operating Income	$5,537	$5,072

Operating Revenues:The $4 million decrease in operating revenues for the second quarter of 2006 was primarily the result of lower delivery volumes largely due to warmer weather and customer conservation.

Operating Expenses: The $4 million decrease in operating expenses for the second quarter of 2006 was primarily the result of lower natural gas purchases due to lower customer usage because of warmer weather and customer conservation.

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

Rochester Gas and Electric Corporation

Six months ended June 30,	2006	2005
(Thousands)
Retail Deliveries (Dth)	27,824	32,188
Operating Revenues	$224,020	$222,479
Operating Expenses	$189,432	$190,236
Operating Income	$34,588	$32,243

Operating Revenues: The $2 million increase in operating revenues for the six months ended June 30, 2006, was primarily the result of $30 million for higher natural gas prices offset by $29 million for lower customer usage because of warmer weather and customer conservation.

Operating Expenses: The $1 million decrease in operating expenses for the six months ended June 30, 2006, was primarily the result of lower operating and maintenance costs. Purchased natural gas costs increased less than $1 million as lower demand resulting from warmer weather and customer conservation offset the effect of higher prices.

Item 1.  Financial Statements

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

Notes to Condensed Financial Statements of Registrants:

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

Note 1. Unaudited Condensed Financial Statements

In the opinion of each registrant's management, the accompanying unaudited condensed financial statements reflect all adjustments necessary for a fair statement of the interim periods presented. All such adjustments are of a normal, recurring nature. The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Energy East's financial statements consolidate its majority-owned subsidiaries after eliminating all intercompany transactions.

The accompanying unaudited financial statements for each registrant should be read in conjunction with the financial statements and notes contained in the report on Form 10-K filed by each registrant for the fiscal year ended December 31, 2005. Due to the seasonal nature of the registrants' operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Reclassifications: Certain amounts have been reclassified in the companies' unaudited financial statements to conform to the 2006 presentation.

Effective December 31, 2005, Energy East and RG&E revised the presentation of their investments in auction rate securities, classifying them as current investments available for sale rather than as cash and cash equivalents. Energy East held current investments of $17 million at June 30, 2006, and $193 million at December 31, 2005, which consisted of auction rate securities classified as available for sale. RG&E held no current investments at June 30, 2006, and $53 million at December 31, 2005. Investments in these securities are recorded at cost, which approximates fair market value due to their variable interest rates. Energy East and RG&E have no cumulative unrealized or realized gains or losses from their current investments. All income generated from these current investments is recorded as interest income.

Note 2. Other (Income) and Other Deductions

	Three Months		Six Months
Periods ended June 30,	2006	2005	2006	2005
(Thousands)
Energy East
Interest and dividend income	$(4,115)	$(2,545)	$(7,892)	$(4,895)
AFUDC	(384)	(372)	(873)	(678)
Earnings from equity investments	(442)	(788)	(1,501)	(1,938)
Gains from hedge activity	-	(285)	(2,438)	(2,325)
Miscellaneous	(1,969)	(1,003)	(4,606)	(2,981)
Total other (income)	$(6,910)	$(4,993)	$(17,310)	$(12,817)
Losses from hedge activity	$2,318	$768	$4,643	$933
Donations, civic and political	861	1,029	1,708	1,667
Miscellaneous	952	1,183	1,797	2,356
Total other deductions	$4,131	$2,980	$8,148	$4,956
RG&E
Interest and dividend income	$(768)	$(790)	$(1,475)	$(1,309)
AFUDC	(209)	(46)	(541)	(99)
Gains from hedge activity	-	213	-	(749)
Miscellaneous	104	164	79	144
Total other (income)	$(873)	$(459)	$(1,937)	$(2,013)
Losses from hedge activity	-	$52	-	$216
Miscellaneous	$223	87	$405	51
Total other deductions	$223	$139	$405	$267

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		Six Months
Periods ended June 30,	2006	2005	2006	2005
(Thousands)
Basic average common shares outstanding	146,903	146,831	146,968	146,853
Restricted stock awards	775	559	711	441
Potentially dilutive common shares	144	280	144	245
Options issued with SARs	(144)	(280)	(144)	(245)
Dilutive average common shares outstanding	147,678	147,390	147,679	147,294

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 June 30 were: 1.5 million in 2006 and 0.5 million in 2005 and for the six months ended June 30 were: 1.5 million in 2006 and 0.5 million in 2005.

Note 4. Income Taxes

Our effective tax rate for the quarter ended June 30, 2006, is lower than the statutory rate primarily due to revisions of the annual forecasted effective tax rate made during the second quarter of 2006, in accordance with Accounting Principles Board Opinion No. 28, Interim Financial Reporting.

RG&E's effective tax rate for the six months ended June 30, 2006, is lower than the statutory rate, primarily due to the flow-through effect of AFUDC in the determination of the projected 2006 annual effective rate. The projected annual tax adjustment for equity AFUDC is approximately $3 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. One of the NUG contracts expired in April 2006 and will not be renewed. We are not able to determine if we have variable interests with respect to power purchase contracts with six remaining NUGs because we are unable to obtain the information necessary to (1) determine if any of the six NUGs is a variable interest entity, (2) determine if an operating utility is a NUG's primary beneficiary or (3) perform t he accounting required to consolidate any of those NUGs. We routinely request necessary information from the six NUGs, and will continue to do so, but no NUG has yet provided the requested information. We did not consolidate any NUGs as of June 30, 2006, or December 31, 2005.

We continue to purchase electricity from the six NUGs at above-market prices. We are not exposed to any loss as a result of our involvement with the NUGs because we are allowed to recover through rates the cost of our purchases. Also, we are under no obligation to a NUG if it decides not to operate for any reason. The combined contractual capacity for the seven NUGs is approximately 517 MWs, including 55 MWs for the contract that expired in April 2006. The combined purchases from the seven NUGs totaled approximately $174 million for the six months ended June 30, 2006, and $187 million for the six months ended June 30, 2005.

Note 6. Commitments and Contingencies

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

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

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

Note 7. Long-term Debt

Debt owed to subsidiary holding solely parent debentures: The debt owed to a subsidiary holding solely parent debentures consists of Energy East's 8 1/4% junior subordinated debt securities maturing on July 1, 2031, that are held by Energy East Capital Trust I (the Trust). We redeemed all of the junior subordinated debt securities at par on July 24, 2006, financed by the issuance of $250 million of unsecured long-term debt at 6.75%, due in 2036, and by the issuance of short-term debt. We expensed approximately $11 million of unamortized debt expense in July 2006 in connection with the redemption. In accordance with the provisions of FASB Statement of Financial Accounting Standards No. 6,Classification of Short-Term Obligations Expected to be Refinanced, we excluded from current liabilities the $250 million of debt that was refinanced on a long-term basis. Also in July 2006 the Trust redeemed, at par, its $345 million, 8 1/4% Capital Securities.

Note 8. New Accounting Standards

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

Share-Based Compensation: We early adopted Statement 123(R) effective October 1, 2005, using the modified version of prospective application. Statement 123(R) is a revision of Statement 123 and requires a public entity to measure the cost of employee services that it receives in exchange for an award of equity instruments based on the grant-date fair value of the award and recognize that cost over the period during which the employee is required to provide service in exchange for the award. Statement 123(R) also requires a public entity to initially measure the cost of employee services received in exchange for an award of liability instruments (e.g., instruments that are settled in cash) based on the award's current fair value, subsequently remeasure the fair value of the award at each reporting date through the settlement date and recognize changes in fair value during the required service period as compensation cost over that period.

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

Share-based compensation, net of related tax effects, for both the quarter and six months ended June 30, 2005, was approximately $6 million and those amounts were the same as if the fair value based method in accordance with Statement 123 had been applied to all awards. Net income and basic and diluted EPS as reported for the quarter and six months ended June 30, 2005, are no different than as if the fair value based method had been applied. Share-based compensation, net of related tax effects, for the periods ended June 30, 2006, was less than $1 million for the quarter and was approximately $4 million for the six months.

Note 9. Accounts Receivable

Energy East's accounts receivable include unbilled revenues of $138 million at June 30, 2006, and $315 million at December 31, 2005. Our accounts receivable are shown net of an allowance for doubtful accounts of $69 million at June 30, 2006, and $53 million at December 31, 2005.

RG&E's accounts receivable include unbilled revenues of $32 million at June 30, 2006, and $54 million at December 31, 2005. RG&E's accounts receivable are shown net of an allowance for doubtful accounts of $15 million at June 30, 2006, and $13 million at December 31, 2005.

Note 10. Retirement Benefits

Components of net periodic benefit (income) cost

	Pension Benefits		Postretirement Benefits
Three months ended June 30,	2006	2005	2006	2005
(Thousands)
Energy East
Service cost	$9,524	$8,762	$1,359	$1,338
Interest cost	31,165	31,968	6,781	7,379
Expected return on plan assets	(55,969)	(54,193)	(364)	(567)
Amortization of prior service cost	1,192	1,250	(1,857)	(1,894)
Recognized net actuarial loss	6,518	3,980	1,316	1,681
Amortization of transition obligation	-	-	1,700	1,700
Net periodic benefit (income) cost	$(7,570)	$(8,233)	$8,935	$9,637
RG&E
Service cost	$1,179	$1,339	$152	$272
Interest cost	6,596	6,803	1,119	1,444
Expected return on plan assets	(11,481)	(12,020)	-	-
Amortization of prior service cost	371	279	215	250
Recognized net actuarial loss	(798)	(913)	(318)	132
Amortization of transition obligation	-	-	457	464
Net periodic benefit (income) cost	$(4,133)	$(4,512)	$1,625	$2,562

	Pension Benefits		Postretirement Benefits
Six months ended June 30,	2006	2005	2006	2005
(Thousands)
Energy East
Service cost	$18,722	$18,047	$2,926	$2,887
Interest cost	63,598	63,999	14,660	15,359
Expected return on plan assets	(110,847)	(107,103)	(847)	(1,123)
Amortization of prior service cost	2,368	2,499	(3,752)	(3,789)
Recognized net actuarial loss	11,123	7,932	3,392	4,316
Amortization of transition obligation	-	-	3,400	3,400
Net periodic benefit (income) cost	$(15,036)	$(14,626)	$19,779	$21,050
RG&E
Service cost	$2,350	$2,678	$318	$544
Interest cost	13,421	13,606	2,226	2,888
Expected return on plan assets	(22,971)	(24,041)	-	-
Amortization of prior service cost	741	559	430	500
Recognized net actuarial (gain) loss	(1,188)	(1,827)	(661)	265
Amortization of transition obligation	-	-	914	928
Net periodic benefit (income) cost	$(7,647)	$(9,025)	$3,227	$5,125

Note 11. Goodwill and Intangible Assets

We do not amortize goodwill or intangible assets with indefinite lives (unamortized intangible assets). We test goodwill and unamortized intangible assets for impairment at least annually. 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 June 30, 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 June 30, 2006, and December 31, 2005, primarily consisted of pension assets. Our amortized intangible assets had a gross carrying amount of $27 million at June 30, 2006, and $31 million at December 31, 2005, and primarily consisted of investments in pipelines and water rights. Accumulated amortization was $14 million at June 30, 2006, and $18 million at December 31, 2005.

RG&E has no goodwill or unamortized intangible assets. RG&E's amortized intangible assets consisted of water rights and had a gross carrying amount of $3 million and accumulated amortization of $2 million at June 30, 2006, and December 31, 2005.

Note 12. Segment Information

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

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

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

	Operating Revenues		Net Income
Three months ended June 30,	2006	2005	2006	2005
(Thousands)
Energy East
Electric Delivery	$717,692	$687,626	$35,714	$23,378
Natural Gas Delivery	283,206	282,450	(10,905)	(5,148)
Other	111,927	111,068	3,476	(865)
Total	$1,112,825	$1,081,144	$28,285	$17,365
RG&E
Electric Delivery	$172,962	$158,902	$10,602	$10,301
Natural Gas Delivery	63,146	66,915	1,350	675
Total	$236,108	$225,817	$11,952	$10,976

	Operating Revenues		Net Income
Six months ended June 30,	2006	2005	2006	2005
(Thousands)
Energy East
Electric Delivery	$1,502,998	$1,455,949	$94,463	$106,479
Natural Gas Delivery	1,040,105	1,003,646	61,822	65,156
Other	265,333	257,637	5,240	96
Total	$2,808,436	$2,717,232	$161,525	$171,731
RG&E
Electric Delivery	$358,599	$319,057	$35,297	$26,474
Natural Gas Delivery	224,020	222,479	16,939	15,430
Total	$582,619	$541,536	$52,236	$41,904

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 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&am p;E's exposure, to market fluctuations for procurement of their fixed rate option electricity supply.

As of July 2006 the portion of forecasted load for fixed rate option customers that is not supplied by owned generation or long-term contracts is, overall, fully hedged for NYSEG and for RG&E for August through December 2006. A fluctuation of $1.00 per MWh in the average price of electricity would change NYSEG's earnings less than $100 thousand, and would change RG&E's earnings less than $50 thousand, for August 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 June 30, 2006, was $41 million, reflecting a decrease of $128 million since December 31, 2005. The decrease is primarily a result of wholesale market price changes for electricity. Treasury hedges included in accumulated other comprehensive income as of June 30, 2006 were $26 million, reflecting a $41 million increase since December 31, 2005, due to increases in interest rates that have been hedged for anticipated financings. Other comprehensive income for the remainder of 2006 will have no effect on future net income because we only use financial electricity contracts to hedge the price of our electric load requirements for customers who have chosen a fixed rate option.

Two of our nonutility energy marketing subsidiaries offer retail electric and natural gas service to customers in New York State and actively hedge the load required to serve customers that have chosen them as their commodity supplier. As of July 2006 those subsidiaries' fixed price loads are fully hedged for electricity and for natural gas for August through December 2006. The percentage of hedged load for the two subsidiaries is based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in load compared to the load forecast.

Item 4.  Controls and Procedures

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

Energy East and RG&E each maintain a system of internal control over financial reporting designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Each company's system of internal control over financial reporting contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. There was no change in Energy East's or RG&E's internal control over financial reporting that occurred during the most recent fiscal quarter that materially affected, or is reasonably likely to materially affect, the respective company's internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1A.  Risk Factors

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

Changes in the Northeast Electric Commodity Supply Business: The RD issued in the NYSEG Electric Rate Plan Extension includes recommendations as to NYSEG's fixed price commodity program that NYSEG believes are unworkable, and NYSEG believes that it could not offer fixed price electricity to its customers on the terms proposed in the RD. In addition, pursuant to an NYPSC order, RG&E has initiated a collaborative with interested parties for the purpose of RG&E implementing an ESCO Referral Program and they are discussing the effects of such a program on RG&E's Voice Your Choice Program. (See Energy East's Part I, Item 2, MD&A, Electric Delivery Business Developments - NYSEG Electric Rate Plan Extension and Other Proceedings in the NYPSC Collaborative on End State of Energy Competition.)

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

(c)Issuer Purchases of Equity Securities

Energy East Corporation
Period		(a)        Total number of shares purchased		(b)        Average price paid per share		(c)        Total number of shares purchased as part of publicly announced plans or programs		(d)        Maximum number of shares that may yet be purchased under the plans or programs
Month #1   (April 1, 2006 to   April 30, 2006)	5,351(1)		$25.15		- -		- -
Month #2   (May 1, 2006 to   May 31, 2006)	4,851(1)		$24.29		- -		- -
Month #3   (June 1, 2006 to   June 30, 2006)	4,876(1)		$23.84		- -		- -
Total	15,078		$24.45		-		-
(1)  Represents shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan.

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

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

Energy East Corporation

Energy East's Annual Meeting of Stockholders was held on June 8, 2006. The following matters were voted on:

a) The election of 11 directors for a term expiring at the 2007 Annual Meeting:

Nominees	Votes For	Votes Withheld
James H. Brandi	119,678,731	1,657,012
John T. Cardis	116,925,103	4,410,640
Joseph J. Castiglia	119,218,043	2,117,700
Lois B. DeFleur	119,298,561	2,037,182
G. Jean Howard	119,776,588	1,559,155
David M. Jagger	119,842,085	1,493,658
Seth A. Kaplan	119,776,423	1,559,320
Ben E. Lynch	119,301,843	2,033,900
Peter J. Moynihan	119,844,470	1,491,273
Walter G. Rich	119,755,768	1,579,975
Wesley W. von Schack	119,696,995	1,638,748

(b) Approval of amendments to the company's Certificate of Incorporation to eliminate shareholder super majority voting provisions:

Shares For:	116,281,490
Shares Against:	3,558,362
Shares Abstain:	1,495,891

(c) Ratification of the appointment of PricewaterhouseCoopers LLP as the company's independent registered public accounting firm for 2006:

Shares For:	120,008,107
Shares Against:	626,561
Shares Abstain:	701,075

Item 6.  Exhibits

SeeExhibit Index.

Signatures

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

Date:  August 3, 2006	ENERGY EAST CORPORATION                   (Registrant) By   /s/Robert D. Kump                                          Robert D. Kump            Vice President, Controller            & Chief Accounting Officer            (Principal Accounting Officer)
Date:  August 3, 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	3-6	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the state of New York on June 12, 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).

Energy East agrees to furnish, upon request, a copy of the Five-Year Revolving Credit Agreement among Energy East, certain lenders, Citibank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, and HSBC Bank USA, National Association, UBS Securities LLC and Wachovia Bank, N.A., as Co-Documentation Agents, as amended and restated as of June 2, 2006. The total amount of securities authorized under such agreement does not exceed 10% of the total assets of Energy East.

RG&E agrees to furnish, upon request, a copy of the Five-Year Revolving Credit Agreement among RG&E, New York State Electric & Gas Corporation, Central Maine Power Company, The Southern Connecticut Gas Company, Connecticut Natural Gas Corporation and The Berkshire Gas Company, certain lenders, Wachovia Bank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, and The Bank of New York, Citibank, N.A. and Sovereign Bank, as Co-Documentation Agents, as amended and restated as of June 2, 2006. The total amount of securities authorized under such agreement does not exceed 10% of the total assets of RG&E.