10-Q

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, 2007

OR

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934
      For the transition period from             to            

Commission file number	Exact name of Registrant as specified in its charter, State of incorporation, Address and Telephone number	IRS Employer Identification No.
1-14766	Energy East Corporation(Incorporated in New York) 52 Farm View Drive New Gloucester, Maine 04260-5116 (207) 688-6300 www.energyeast.com	14-1798693

Indicate by check mark whether the 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):

Large accelerated filer    X    Accelerated filer         Non-accelerated filer        

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes           No    X   

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

The number of shares of common stock (Par value $.01 per share) outstanding as of July 31, 2007, was 158,278,536.

	Table of Contents	Page
	Glossary	ii
	Forward-looking Statements	iv
	PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)   Condensed Consolidated Statements of IncomeCondensed Consolidated Balance SheetsCondensed Consolidated Statements of Cash FlowsCondensed Consolidated Statements of Retained EarningsCondensed Consolidated Statements of Comprehensive IncomeNotes to Condensed Consolidated Financial Statements	1 2 4 5 5 6
Item 2.	Management's Discussion and Analysis of Financial Condition     and Results of Operations   (a) Liquidity and Capital Resources   (b) Results of Operations	14 20 21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	29
	PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 4.	Submission of Matters to a Vote of Security Holders	31
Item 6.	Exhibits	31
Signature		32
Exhibit Index		33

Glossary

Abbreviations for the Energy East companies mentioned in this report:

Berkshire Gas The Berkshire Gas Company is a regulated utility primarily engaged in the distribution of natural gas in western Massachusetts. Berkshire Gas is a wholly-owned subsidiary of Berkshire Energy Resources. CMP Central Maine Power Company is a regulated utility primarily engaged in transmitting and distributing electricity generated by others to retail customers in Maine. CMP is a wholly-owned subsidiary of CMP Group, Inc. CNG Connecticut Natural Gas Corporation is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut. CNG is a wholly-owned subsidiary of CTG Resources, Inc. Energetix Energetix, Inc. markets electric and natural gas services in upstate New York. Energy East, the company, we, our or us Energy East Corporation is the parent company of RGS Energy Group, Inc., Connecticut Energy Corporation, CMP Group, Inc., CTG Resources, Inc., Berkshire Energy Resources, The Energy Network, Inc. and Energy East Enterprises, Inc.

MNG Maine Natural Gas Corporation is a small natural gas delivery company in the state of Maine. NYSEG New York State Electric & Gas Corporation is a regulated utility primarily engaged in purchasing and delivering electricity and natural gas in the central, eastern and western parts of the state of New York. NYSEG is a wholly-owned subsidiary of RGS Energy Group, Inc. RG&E Rochester Gas and Electric Corporation is a regulated utility primarily engaged in generating, purchasing and delivering electricity and purchasing and delivering natural gas in an area centered around the city of Rochester, New York. RG&E is a wholly-owned subsidiary of RGS Energy Group, Inc. SCG The Southern Connecticut Gas Company is a regulated utility primarily engaged in the retail distribution of natural gas in Connecticut. SCG is a wholly-owned subsidiary of Connecticut Energy Corporation.

Abbreviations or acronyms frequently used in this report:

ALJ Administrative Law Judge AMI advanced metering infrastructure ARP 2000 Alternative Rate Plan 2000 DIG Issue G26 Derivatives Implementation Group (DIG) Issue No. G26, "Cash Flow Hedges: Hedging Interest Cash Flows on Variable-Rate Assets and Liabilities That Are Not Based on a Benchmark Interest Rate" DPUC Connecticut Department of Public Utility Control Dth dekatherm EITF 06-10 Emerging Issues Task Force Issue No. 06-10, "Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements" EPA Environmental Protection Agency EPS earnings per share ESCO energy service company FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FIN 46(R) FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51 FIN 48 FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 FSP FIN 39-1 FASB Staff Position No. FIN 39-1, "Amendment of FASB Interpretation No. 39" ISO-NE ISO New England Inc. MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations Merger The proposed transaction whereby Energy East will merge with Green Acquisition Capital, Inc., a direct, wholly-owned subsidiary of Iberdrola, S.A. and we would become a subsidiary of Iberdrola as provided for in the Merger Agreement

Merger Agreement The Agreement and Plan of Merger dated as of June 25, 2007, among Iberdrola, S.A., Green Acquisition Capital, Inc., a direct, wholly-owned subsidiary of Iberdrola, and Energy East MPUC Maine Public Utilities Commission MW, MWh megawatt, megawatt-hour NBC nonbypassable wires charge NUG nonutility generator NYISO New York Independent System Operator NYPSC New York State Public Service Commission NYSDEC New York State Department of Environmental Conservation OPEB other post-employment benefits PCB polychlorinated biphenyl ROE return on equity RTO Regional Transmission Organization Russell Station A coal-fired electric generation facility in Greece, New York SAR stock appreciation right SEC United States Securities and Exchange Commission Statement 109 Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes Statement 157 Statement of Financial Accounting Standards No. 157, Fair Value Measurements Statement 159 Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment of FASB Statement No. 115 VEBA Voluntary employees' beneficiary association authorized by Internal Revenue Code Section 501(c)(9)

Forward-looking Statements

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

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties that could cause actual results to differ materially from those contemplated in any forward-looking statements are discussed in our Form 10-K for the fiscal year ended December 31, 2006, Item 1A - Risk Factors and Item 7 - MD&A - Market Risk, and also include, among others:

• the occurrence of any event, change or other circumstances that could give rise to the termination of the proposed Merger Agreement,
• the outcome of any legal or regulatory proceedings that have been instituted against us or others following the announcement of the Merger Agreement,
• our ability to obtain stockholder approval of the Merger,
• the failure of the Merger to close for any reason, including the failure to obtain regulatory approvals required for the Merger,
• the regulatory process relating to the Merger, which could delay the Merger or result in the imposition of conditions that could have a material adverse effect on the surviving company,
• our ability to compete in the rapidly changing and competitive electric and/or natural gas utility markets,
• regulatory uncertainty and volatile energy supply prices,
• implementation of the Energy Policy Act of 2005,
• increased state and FERC regulation,
• the operation of the NYISO and retroactive NYISO billing adjustments,
• the operation of ISO-NE as an RTO and CMP's continued participation in ISO-NE,
• our continued ability to recover NUG and other costs,
• changes in fuel supply or cost and the success of strategies to satisfy power requirements,
• our ability to expand our products and services including our energy infrastructure in the Northeast,
• the effect of commodity costs on customer usage and uncollectible expense,
• our ability to maintain enterprise-wide integration synergies,
• market risk from changes in value of financial or commodity instruments, derivative or nonderivative, caused by fluctuations in interest rates or commodity prices,
• the ability of third parties to continue to supply electricity and natural gas,
• our ability to obtain adequate and timely rate relief and/or the extension of current rate plans,
• the possible discontinuation or further modification of fixed-price supply programs in New York,
• nuclear decommissioning or environmental incidents,
• legal or administrative proceedings,
• changes in the cost or availability of capital,
• economic growth or contraction in the areas in which we do business,
• extreme weather-related events such as floods, hurricanes, ice storms or snow storms,
• weather variations affecting customer energy usage,
• changes in authoritative accounting guidance,
• acts of terrorism,
• the effect of volatility in the equity and fixed income markets on the cost of pension and other postretirement benefits,
• the inability of our internal control framework to provide absolute assurance that all incidents of fraud or error will be detected and prevented, and
• other considerations that may be disclosed from time to time in our publicly disseminated documents and filings.

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

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Energy East Corporation Condensed Consolidated Statements of Income - (Unaudited)
	Three Months		Six Months
Periods ended June 30,	2007	2006	2007	2006
(Thousands, except per share amounts)
Operating Revenues
Utility	$977,006	$1,000,898	$2,541,070	$2,543,103
Other	112,020	111,927	261,693	265,333
Total Operating Revenues	1,089,026	1,112,825	2,802,763	2,808,436
Operating Expenses
Electricity purchased and fuel used in generation
Utility	351,412	354,208	736,685	731,549
Other	85,164	84,237	174,018	173,627
Natural gas purchased
Utility	174,232	172,663	712,738	682,432
Other	12,120	9,560	54,494	53,334
Other operating expenses	203,503	202,174	397,226	387,338
Maintenance	48,809	43,750	89,627	96,214
Depreciation and amortization	68,273	70,061	137,072	139,464
Other taxes	58,787	58,265	134,500	132,130
Total Operating Expenses	1,002,300	994,918	2,436,360	2,396,088
Operating Income	86,726	117,907	366,403	412,348
Other (Income)	(10,752)	(6,910)	(19,707)	(17,310)
Other Deductions	1,423	4,131	4,654	8,148
Interest Charges, Net	67,855	75,142	136,255	153,863
Preferred Stock Dividends of Subsidiaries	282	283	564	564
Income Before Income Taxes	27,918	45,261	244,637	267,083
Income Taxes	8,427	16,976	91,852	105,558
Net Income	$19,491	$28,285	$152,785	$161,525
Earnings per Share, basic	$.12	$.19	$1.00	$1.10
Earnings per Share, diluted	$.12	$.19	$1.00	$1.09
Dividends Declared per Share	$.30	$.29	$.60	$.58
Average Common Shares Outstanding, basic	157,112	146,903	152,341	146,968
Average Common Shares Outstanding, diluted	158,122	147,678	153,291	147,679
The notes on pages 6 through 13 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2007	Dec. 31, 2006
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$200,427	$93,373
Investments available for sale	225,590	20,000
Accounts receivable and unbilled revenues, net	799,984	914,657
Fuel and natural gas in storage, at average cost	209,302	277,766
Materials and supplies, at average cost	33,146	33,273
Deferred income taxes	53,017	93,187
Derivative assets	16,564	1,327
Prepayments and other current assets	127,538	193,226
Total Current Assets	1,665,568	1,626,809
Utility Plant, at Original Cost
Electric	5,666,685	5,557,858
Natural gas	2,679,351	2,654,426
Common	565,690	550,440
	8,911,726	8,762,724
Less accumulated depreciation	3,040,719	2,935,798
Net Utility Plant in Service	5,871,007	5,826,926
Construction work in progress	130,304	121,097
Total Utility Plant	6,001,311	5,948,023
Other Property and Investments	180,194	183,315
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	218,258	263,659
Unfunded future income taxes	269,552	256,683
Environmental remediation costs	177,197	128,925
Unamortized loss on debt reacquisitions	48,705	52,724
Nonutility generator termination agreements	73,871	79,241
Natural gas hedges	17,377	47,372
Pension and other postretirement benefits	332,566	351,011
Other	318,551	356,299
Total regulatory assets	1,456,077	1,535,914
Other assets
Goodwill	1,526,048	1,526,048
Prepaid pension benefits	618,275	577,356
Derivative assets	54,952	46,375
Other	108,238	118,561
Total other assets	2,307,513	2,268,340
Total Regulatory and Other Assets	3,763,590	3,804,254
Total Assets	$11,610,663	$11,562,401
The notes on pages 6 through 13 are an integral part of our condensed consolidated financial statements.

Energy East Corporation Condensed Consolidated Balance Sheets - (Unaudited)
	June 30, 2007	Dec. 31, 2006
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$263,834	$260,768
Notes payable	36,998	109,363
Accounts payable and accrued liabilities	379,781	470,325
Interest accrued	54,863	57,243
Taxes accrued	113,684	44,009
Unfunded future income taxes	84	19,664
Derivative liabilities	28,193	71,678
Customer refunds	-	70,770
Other	177,452	209,839
Total Current Liabilities	1,054,889	1,313,659
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	834,561	843,273
Deferred income taxes	98,792	105,528
Gain on sale of generation assets	111,876	127,674
Pension benefits	122,087	127,330
Other	163,092	93,268
Total regulatory liabilities	1,330,408	1,297,073
Other liabilities
Deferred income taxes	1,102,061	1,105,117
Nuclear plant obligations	193,084	202,963
Pension and other postretirement benefits	521,000	530,838
Environmental remediation costs	194,163	168,949
Derivative liabilities	14,477	21,871
Other	294,052	306,283
Total other liabilities	2,318,837	2,336,021
Total Regulatory and Other Liabilities	3,649,245	3,633,094
Long-term debt	3,664,825	3,726,709
Total Liabilities	8,368,959	8,673,462
Commitments and Contingencies
Preferred Stock of Subsidiaries
Redeemable solely at the option of subsidiaries	24,592	24,592
Common Stock Equity
Common stock	1,584	1,480
Capital in excess of par value	1,750,522	1,505,795
Retained earnings	1,445,281	1,382,461
Accumulated other comprehensive income (loss)	23,318	(23,779)
Treasury stock, at cost	(3,593)	(1,610)
Total Common Stock Equity	3,217,112	2,864,347
Total Liabilities and Stockholders' Equity	$11,610,663	$11,562,401
The notes on pages 6 through 13 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,	2007	2006
(Thousands)
Operating Activities	$152,785	$161,525
Net income
Adjustments to reconcile net income to net cash  provided by operating activities
Depreciation and amortization	189,442	199,933
Income taxes and investment tax credits deferred, net	6,695	(19,465)
Pension income	(23,678)	(15,036)
Changes in current operating assets and liabilities
Accounts receivable and unbilled revenues, net	41,833	173,264
Inventory	68,952	79,245
Prepayments and other current assets	65,850	(790)
Accounts payable and accrued liabilities	(56,429)	(231,577)
Interest accrued	(2,380)	(1,740)
Taxes accrued	59,515	52,695
Customer refunds	(10,047)	(15,017)
Other current liabilities	(53,081)	(83,657)
Other assets	47,626	52,310
Other liabilities	(42,058)	(43,785)
Net Cash Provided by Operating Activities	445,025	307,905
Investing Activities
Utility plant additions	(179,814)	(153,032)
Other property additions	(350)	(1,394)
Other property sold	19	-
Maturities of current investments available for sale	462,260	710,775
Purchases of current investments available for sale	(667,850)	(535,100)
Investments	3,519	10,533
Net Cash (Used in) Provided by Investing Activities	(382,216)	31,782
Financing Activities
Issuance of common stock	236,196	-
Repurchase of common stock	(8,339)	(6,107)
Long-term note issuances	-	77,172
Long-term note repayments	(29,061)	(80,849)
Notes payable three months or less, net	(72,244)	(106,108)
Notes payable issuances	726	53,410
Notes payable repayments	(847)	(56,649)
Dividends on common stock	(82,186)	(85,276)
Net Cash Provided by (Used in) Financing Activities	44,245	(204,407)
Net Increase in Cash and Cash Equivalents	107,054	135,280
Cash and Cash Equivalents, Beginning of Period	93,373	120,009
Cash and Cash Equivalents, End of Period	$200,427	$255,289
The notes on pages 6 through 13 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,	2007	2006
(Thousands)
Balance, Beginning of Period	$1,382,461	$1,294,580
Adjustment for the cumulative effect of applying the provisions   of FIN 48 as of January 1, 2007	1,291	- -
Add net income	152,785	161,525
	1,536,537	1,456,105
Deduct dividends on common stock	91,256	85,276
Balance, End of Period	$1,445,281	$1,370,829
The notes on pages 6 through 13 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,	2007	2006	2007	2006
(Thousands)
Net income	$19,491	$28,285	$152,785	$161,525
Other comprehensive income, net of tax
Net unrealized gains (losses) on     investments, net of income tax     (expense) benefit for the three months     of $(114) in 2007 and $(142) in 2006 and     for the six months of $(172) in 2007 and     $24 in 2006	178	215	265	(37)
Minimum pension liability adjustment net of     income tax benefit of $661 for the three     months and six months in 2006	- -	(997)	- -	(997)
Amortization of pension costs for     nonqualified plans, net of income tax     (expense) of $(1,264) for the three     months and $(1,402) for the six months     in 2007	1,859	- -	2,068	- -
Net unrealized gains (losses) on     derivatives qualified as hedges, net of     income tax (expense) benefit for the     three months of $(7,084) in 2007 and     $(4,686) in 2006 and for the six months of     $1,675 in 2007 and $71,811 in 2006	10,636	6,726	(2,620)	(113,476)
Net unrecognized gains on settled cash flow     treasury hedges, net of income tax     expense of $(5,872) for the three months     and six months in 2007	7,734	- -	7,734	- -
Reclassification adjustment for derivative     losses (gains) included in net income,     net of income tax (benefit) expense for     the three months of $(358) in 2007 and     $4,063 in 2006 and for the six months of     $(26,288) in 2007 and $(16,553) in 2006	552	(6,124)	39,650	24,773
Net unrealized gains (losses) on     derivatives qualified as hedges	18,922	602	44,764	(88,703)
Total other comprehensive income (loss)	20,959	(180)	47,097	(89,737)
Comprehensive Income	$40,450	$28,105	$199,882	$71,788
The notes on pages 6 through 13 are an integral part of our condensed consolidated financial statements.

Notes to Condensed Consolidated Financial Statements

Note 1. Unaudited Condensed Consolidated Financial Statements

In the opinion of management, the accompanying unaudited condensed consolidated 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.

Our financial statements consolidate our majority-owned subsidiaries after eliminating all intercompany transactions.

On June 25, 2007, we entered into an Agreement and Plan of Merger with Iberdrola, S.A., and Green Acquisition Capital, Inc. pursuant to which we will become a wholly-owned subsidiary of Iberdrola upon receipt of required regulatory approvals and satisfaction of other closing conditions.

The accompanying unaudited financial statements should be read in conjunction with the financial statements and notes contained in our report on Form 10-K filed for the fiscal year ended December 31, 2006. Due to the seasonal nature of our operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Reclassifications: Certain amounts have been reclassified in the unaudited financial statements to conform to the 2007 presentation. Effective January 1, 2007, we recognize book overdrafts where no credit is required to be extended by a bank as an operating activity rather than as a financing activity. As a result, our net cash provided by operating activities and net cash used in financing activities decreased $6 million for the six months ended June 30, 2006. Effective April 1, 2007, we began recording the unrecognized gains and losses on settled treasury hedges in other comprehensive income rather than as other assets or long-term debt. As a result, our other comprehensive income increased by $10 million for the three and six months ended June 30, 2007.

Note 2. Other (Income) and Other Deductions

	Three Months		Six Months
Periods ended June 30,	2007	2006	2007	2006
(Thousands)
Interest and dividend income	$(6,250)	$(4,115)	$(9,061)	$(7,892)
Allowance for funds used during construction	(1,207)	(384)	(2,456)	(873)
Earnings from equity investments	(813)	(442)	(1,744)	(1,501)
Gains from energy risk contracts	(390)	-	(1,475)	(2,438)
Miscellaneous	(2,092)	(1,969)	(4,971)	(4,606)
Total other (income)	$(10,752)	$(6,910)	$(19,707)	$(17,310)
Losses on energy risk contracts	$1,195	$2,318	$3,487	$4,643
Donations, civic and political	475	861	945	1,708
Miscellaneous	(247)	952	222	1,797
Total other deductions	$1,423	$4,131	$4,654	$8,148

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,	2007	2006	2007	2006
(Thousands)
Basic average common shares outstanding	157,112	146,903	152,341	146,968
Restricted stock awards	1,010	775	950	711
Potentially dilutive common shares	162	144	156	144
Options issued with SARs	(162)	(144)	(156)	(144)
Dilutive average common shares outstanding	158,122	147,678	153,291	147,679

We exclude from the determination of EPS options that have an exercise price that is greater than the average market price of the common shares during the period. Shares excluded from the EPS calculation for the three months and six months ended June 30 were: 2.1 million in 2007 and 1.5 million in 2006.

Note 4. Income Taxes

Our effective tax rate was 29.9% for the quarter ended June 30, 2007. Income taxes were $2.8 million less than they would have been at the statutory rate of 39.9%. The effective tax rate was 37.3% for the quarter ended June 30, 2006. Income taxes were $1.2 million less than they would have been at the statutory rate.

Our effective tax rate was 37.5% for the six months ended June 30, 2007. Income taxes were $5.9 million less than they would have been at the statutory rate. The effective tax rate was 39.4% for the six months ended June 30, 2006. Income taxes were $1.2 million less than they would have been at the statutory rate. Differences between the effective rate and the statutory rate are primarily due to the flow-through effects of removal costs and the permanent difference related to the subsidy available under the Medicare Prescription Drug Improvement and Modernization Act of 2003, partially offset by increases related to the flow-through effects of book vs. tax depreciation.

FIN 48: In July 2006 the FASB released FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with Statement 109 by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or to be taken in a tax return. The evaluation of a tax position is a two-step process. The first step is for an entity to determine if it is more likely than not that a tax position will be sustained upon examination. The second step involves measuring the amount of tax benefit to be recognized in the financial statements based on the largest amount of benefit that meets the prescribed recognition threshold. The difference between the amounts based on that position and the position taken in a tax return is generally recorded as a liability.

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

We adopted FIN 48 effective January 1, 2007. The total amount of gross unrecognized tax benefits at the date of adoption was $26.6 million and included income taxes of $21.2 million, interest of $5.2 million and a penalty of $0.2 million. The total amount of gross unrecognized tax benefits as of June 30, 2007 is $26.7 million and includes income taxes of $21.2 million, interest of $5.3 million and a penalty of $0.2 million. Including interest and penalty, $14 million of the gross unrecognized tax benefits would affect the effective tax rate, if recognized. The adoption did not have a material effect on our results of operation, financial position or cash flows. Upon our adoption of FIN 48, the cumulative effect was an increase to retained earnings of $1.3 million. In addition, we reclassified $2.3 million of accumulated deferred income tax liabilities.

We have been audited through 2000 for New York state income taxes, through 2001 for federal income taxes and through 2002 for Maine income taxes. The statute of limitations in Connecticut has expired for all years through 2002. Our New York state returns for 2001 through 2004, federal returns for 2002 through 2005 and Maine returns for 2003 and 2004 are currently under review. We anticipate that the reviews will be completed within the next 12 months. Approximately $12.7 million of the gross income tax reserves relate to the years currently under audit, with the majority relating to combined state reporting issues. We cannot estimate the ultimate outcome of the reviews.

We continue to classify all interest and penalties related to uncertain tax positions as income tax expense.

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

We have determined that these amendments will not have a material effect on our financial position, cash flows or results of operation.

Also included in the 2007-2008 New York state budget was a provision whereby certain corporations would be required to file unitary income tax returns. This provision is effective January 1, 2007. On June 25, 2007 New York state issued a Technical Service Bulletin providing further guidance as to what meets the unitary income tax filing criteria.

While the company continues to monitor this issue, it has currently determined that it does not meet the unitary income tax filing criteria based on its' review of the legislation, the June 25, 2007 Technical Service Bulletin and other public statements made by New York State Department of Taxation and Finance representatives.

Note 5. Variable Interest Entities

A variable interest entity is an entity that is not controllable through voting interests and/or in which the equity investor does not bear the residual economic risks and rewards. FIN 46(R) requires a business enterprise to consolidate a variable interest entity if the enterprise has a variable interest that will absorb a majority of the entity's expected losses.

We have power purchase contracts with various NUGs. However, we were not involved in the formation of and do not have ownership interests in any NUGs. We have evaluated all of our power purchase contracts with NUGs with respect to FIN 46(R) and determined that most of the purchase contracts are not variable interests for one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUG is a governmental organization or an individual. We are not able to determine if we have variable interests with respect to power purchase contracts with six remaining NUGs because we are unable to obtain the information necessary to: (1) determine if any of those NUGs is a variable interest entity, (2) determine if an operating utility is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of those NUGs. We routine ly request necessary information from the six NUGs, and will continue to do so, but no NUG has yet provided the requested information. We did not consolidate any NUGs as of June 30, 2007, or December 31, 2006.

We continue to purchase electricity from the six NUGs at above-market prices. We are not exposed to any loss as a result of our involvement with the NUGs because we are allowed to recover through rates the cost of our purchases. Also, we are under no obligation to a NUG if it decides not to operate for any reason. The combined contractual capacity for the six NUGs is approximately 462 MWs. The combined purchases from the six NUGs totaled approximately $199 million for the six months ended June 30, 2007, and $174 million for the six months ended June 30, 2006.

Note 6. Long-term Debt

On July 23, 2007, RG&E redeemed at par all of its outstanding $125 million principal amount First Mortgage 6.65% Bonds, due 2032, Series UU, financed by the issuance in July 2007 of $100 million of First Mortgage 6.47% Bonds, due in 2032, Series WW. In accordance with the provisions of FASB Statement of Financial Accounting Standards No. 6, Classification of Short-Term Obligations Expected to be Refinanced, RG&E excluded from current liabilities the $100 million of debt that was refinanced on a long-term basis.

Note 7. Commitments and Contingencies

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

NYPSC Proceeding on NYSEG's Accounting for OPEB: In August 2006 the NYPSC issued its decision in the NYSEG electric rate case. Among other things, the NYPSC instructed the ALJ to open a separate proceeding regarding the NYPSC staff's position that NYSEG should have retained $57 million of interest in its OPEB reserve and used it to reduce rate base rather than to reduce OPEB expenses. NYPSC acceptance of its staff's position would have resulted in NYSEG treating all or a portion of the $57 million as an addition to its internal OPEB reserve, with a corresponding charge to income. In July 2007 NYSEG, the NYPSC staff and various intervenors filed a joint proposal with the NYPSC resolving all outstanding issues in this matter. The joint proposal, if approved, would require NYSEG to refund $17 million to customers and to establish an external VEBA trust fund for already reserved OPEB costs of approximately $112 million, which are currently deducted from rate base. NYSEG would contribute $60 milli on in 2007 and $52 million in 2008. The joint proposal requires pretax charges to earnings for regulatory purposes of $8 million in 2007, $5 million in 2008, and $4 million in 2009. The charges in 2008 and 2009 will be offset by cost reductions resulting from earnings on the VEBA.

Merger-related Lawsuit: In connection with Iberdrola's proposed acquisition of Energy East, Howard Lasker, an alleged shareholder of Energy East, filed a purported class action complaint on or about July 6, 2007, in the Supreme Court of the State of New York for Kings County (Brooklyn), against us and our directors. The complaint alleges that, among other things, the consideration for the proposed acquisition is unfair and inadequate because it does not provide Energy East shareholders with a sufficient premium and the defendants have breached their fiduciary duty. The complaint seeks an injunction on the completion of the Merger as well as monetary damages in an amount not specified. A response to the complaint is currently due September 5, 2007. We and our directors dispute these allegations and intend to vigorously defend this suit.

Note 8. Environmental Liability

In June 2007, based on an updated study, we increased our estimate of the costs related to the investigation and remediation of certain of RG&E's existing sites where gas was manufactured in the past. The liability to investigate and perform remediation, as necessary, for those inactive gas manufacturing sites increased $25 million as of June 30, 2007. There is no effect on net income as a result of the increase in estimate because the costs will be recovered in rates or through insurance settlements.

Note 9. New Accounting Standards

Statement 157: In September 2006 the FASB issued Statement 157. Changes from current practice that will result from the application of Statement 157 relate to the definition of fair value, the methods used to measure fair value, and expanded disclosures about fair value measurements. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements in which the FASB previously concluded that fair value is the relevant measurement attribute, but does not require any new fair value measurements. Statement 157 will be effective for financial statements issued for fiscal years beginning after

November 15, 2007, and interim periods within those fiscal years, with earlier application encouraged. The provisions are to be applied prospectively, with certain exceptions. A cumulative-effect adjustment to retained earnings is required for application to certain financial instruments. We plan to adopt Statement 157 effective January 1, 2008, and are currently assessing the effects that the adoption would have on our results of operation, financial position and/or cash flows.

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

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

EITF 06-10: The FASB ratified the consensus in EITF 06-10 in late March 2007. EITF 06-10 requires an employer to recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement (in which the employee, versus the employer, owns and controls the insurance policy) in accordance with either FASB Statement No. 106, Employers' Accounting for Postretirement Benefits Other than Pensions, (Statement 106) or APB Opinion No. 12, Omnibus Opinion - 1967 (Opinion 12). An entity would recognize a liability in accordance with Statement 106 if, in substance, a postretirement benefit plan exists or, in accordance with Opinion 12, if the arrangement is, in substance, an individual deferred compensation contract. EITF 06-10 also requires an employer to recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement. EITF 06-10 is effective for fiscal years beginning after December 15, 2007, including interim periods within those fiscal years, with earlier application permitted. Entities should recognize the effects of applying the consensus through either (1) a change in accounting principle through a cumulative-effect adjustment to retained earnings as of the beginning of the year of adoption or (2) a change in accounting principle through retrospective application to all prior periods. We plan to apply the consensus in EITF 06-10 as of January 1, 2008, as a change in accounting principle through a cumulative-effect adjustment to retained earnings. We are currently assessing the effects that the application of EITF 06-10 would have on our results of operation, financial position and/or cash flows, but expect that the effects will not be material.

FSP FIN 39-1: The FASB issued FSP FIN 39-1 in late April 2007. FSP FIN 39-1 permits a reporting entity that is party to a master netting arrangement to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with paragraph 10 of FASB Interpretation No. 39, Offsetting of Certain Amounts Related to Certain Contracts (Interpretation 39). FSP FIN 39-1 also amends Interpretation 39 to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects of applying FSP FIN 39-1 are to be recognized as a change in accounting principle through retrospective application for all financial statements presented unless it is impracticable to do so. Upon adoption of FSP FIN 39-1, a reporting entity would be allowed to change its accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. We plan to adopt FSP FIN 39-1 as of January 1, 2008, and are currently assessing the effects that the adoption would have on our results of operation, financial position and/or cash flows.

Note 10. Accounts Receivable

Our accounts receivable include unbilled revenues of $145 million at June 30, 2007, and $221 million at December 31, 2006, and are shown net of an allowance for doubtful accounts of $65 million at June 30, 2007, and $59 million at December 31, 2006.

Note 11. Retirement Benefits

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

Components of net periodic benefit (income) cost

	Pension Benefits		Postretirement Benefits
Three months ended June 30,	2007	2006	2007	2006
(Thousands)
Service cost	$8,208	$9,524	$1,424	$1,359
Interest cost	32,235	31,165	7,416	6,781
Expected return on plan assets	(58,196)	(55,969)	(776)	(364)
Amortization of prior service cost	1,166	1,192	(1,859)	(1,857)
Recognized net loss	3,758	6,518	1,393	1,316
Amortization of transition obligation	-	-	1,700	1,700
Net periodic benefit (income) cost	$(12,829)	$(7,570)	$9,298	$8,935

	Pension Benefits		Postretirement Benefits
Six months ended June 30,	2007	2006	2007	2006
(Thousands)
Service cost	$17,556	$18,722	$2,877	$2,926
Interest cost	64,925	63,598	14,845	14,660
Expected return on plan assets	(116,430)	(110,847)	(1,423)	(847)
Amortization of prior service cost	2,307	2,368	(3,717)	(3,752)
Recognized net actuarial loss	7,964	11,123	2,766	3,392
Amortization of transition obligation	-	-	3,400	3,400
Net periodic benefit (income) cost	$(23,678)	$(15,036)	$18,748	$19,779

Under the terms of the joint proposal entered into by NYSEG to resolve issues related to its OPEB costs, NYSEG has agreed to establish and fund a VEBA. Assuming the joint proposal is approved by the NYPSC, NYSEG expects to contribute $60 million to the VEBA near the end of the third quarter of 2007.

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.

Selected information for our business segments includes:

	Operating Revenues		Net Income
Three months ended June 30,	2007	2006	2007	2006
(Thousands)
Electric Delivery	$682,602	$717,692	$21,001	$35,714
Natural Gas Delivery	294,404	283,206	(1,412)	(10,905)
Other	112,020	111,927	(98)	3,476
Total	$1,089,026	$1,112,825	$19,491	$28,285

	Operating Revenues		Net Income
Six months ended June 30,	2007	2006	2007	2006
(Thousands)
Electric Delivery	$1,449,284	$1,502,998	$76,155	$94,463
Natural Gas Delivery	1,091,786	1,040,105	74,984	61,822
Other	261,693	265,333	1,646	5,240
Total	$2,802,763	$2,808,436	$152,785	$161,525

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

Overview

See Recent Developments for a discussion of our Agreement and Plan of Merger with Iberdrola whereby we will become a wholly-owned subsidiary of Iberdrola upon completion of the Merger.

Energy East's primary operations, our electric and natural gas utility operations, are subject to rate regulation established predominately by state utility commissions. The approved regulatory treatment on various matters significantly affects our financial position, results of operations and cash flows. We have long-term rate plans for NYSEG's natural gas segment, RG&E, CMP and Berkshire Gas that currently allow for recovery of certain costs, including stranded costs, and provide stable rates for customers and revenue predictability. Where long-term rate plans are not in effect, we monitor the adequacy of rate levels and file for new rates when necessary. NYSEG's five-year electric rate plan expired December 31, 2006, and new rates went into effect on January 1, 2007. SCG received approval for new rates that became effective January 1, 2006, and CNG recently received approval for new rates that became effective April 1, 2007.

Continuing uncertainty in the evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings that could significantly affect our operations and the rates that our customers pay for energy. Those proceedings, which are discussed below, could affect the nature of the electric and natural gas utility industries in New York and New England.

We expect to make significant capital investments to enhance the safety and reliability of our distribution systems and to meet the growing energy needs of our customers in an environmentally responsive manner. Capital spending is expected to exceed $3 billion through 2011, including $496 million in 2007. Major spending programs include the installation of advanced metering infrastructure (AMI) in New York and Maine requiring an investment of approximately $360 million; in excess of $500 million of transmission investments, predominantly in Maine; a high efficiency transformer replacement program; and a "green" fleet initiative. The majority of our planned transmission investments will be pursuant to a regional reliability planning process and should qualify for the FERC's transmission investment ROE incentive adders for New England transmission owners. We have also proposed that RG&E build a new 300 MW power plant at the Russell Station that would likely use natural gas. The proposed plant would meet projected load requirements in the Rochester, New York area and would cost approximately $300 million. We estimate that over one-half of our capital spending program will be funded with internally generated funds and the remainder through the issuance of a combination of debt and equity securities.

This MD&A for the quarter and six months ended June 30, 2007, should be read in conjunction with our MD&A, financial statements and notes contained in our report on Form 10-K for the fiscal year ended December 31, 2006. Due to the seasonal nature of our operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Strategy

We have maintained a consistent energy delivery and services strategy over the past several years, focusing on the safe, secure and reliable transmission and distribution of electricity and natural gas. Our operating companies have become increasingly efficient through realization of merger-enabled synergies. Our current strategic focus is on addressing many of the precepts of the Energy Policy Act of 2005 including: (1) investing in transmission to increase reliability, meet new load growth and connect new, renewable generation to the grid; (2) investing in AMI to promote customer conservation and peak load management; (3) investing in our distribution infrastructure to make it more efficient by reducing losses; and (4) investing in new regulated generation that is environmentally friendly and, where possible, sustainable.

Our individual company rate plans are a critical component of our success. While specific provisions may vary among our public utility subsidiaries, our overall strategy includes creating stable rate environments that allow our subsidiaries to earn a fair return while minimizing price increases and sharing achieved savings with customers, subject to conditions contained in the Merger Agreement.

Recent Developments

On June 25, 2007, we announced that we had entered into the Merger Agreement with Iberdrola, S.A. ("Iberdrola"), a corporation organized under the Laws of the Kingdom of Spain, and Green Acquisition Capital, Inc., a New York corporation that is a wholly-owned subsidiary of Iberdrola.

The Merger Agreement provides for a business combination whereby we and our subsidiaries would become wholly-owned subsidiaries of Iberdrola and each outstanding share of common stock of Energy East (other than shares of Energy East common stock owned by us as treasury stock or by one of our subsidiaries or by Iberdrola or a subsidiary of Iberdrola) will be converted into the right to receive $28.50 per share in cash, without interest.

Iberdrola is one of the world's largest energy companies with more than 26,000 employees. Iberdrola is a leading owner and operator of renewable energy facilities, having an installed capacity of over 6,800 MW of wind generation (the largest wind portfolio in the world) and almost 10,000 MW of hydro generation. In the United States, Iberdrola owns and operates the largest wind facility on the East Coast - Maple Ridge, in upstate New York - and has over 20,000 MW of renewable generation under development.

Consummation of the Merger is subject to various customary closing conditions, including the requisite approval by our shareholders, the absence of injunctions or restraints imposed by governmental entities, the receipt of required regulatory approvals and the absence of any material adverse change to us. We and our directors have received a class action complaint on behalf of our shareholders, alleging in substance that the Merger Consideration is unfair and inadequate.

We expect the Merger to be completed in 2008 following receipt of the required approvals including the FERC, the Federal Communications Commission (FCC), and the public utilities commissions in Connecticut, Maine, New Hampshire and New York. Requests for the necessary approvals were made on August 1, 2007, with the four state public utilities commissions, the FERC and the FCC. There can be no assurance as to when or if the proposed Merger will be consummated. Until then, we and our subsidiaries will continue to operate as a separate company.

Electric Delivery Business Developments

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

NYSEG's Supply Service Filing: On April 5, 2007, NYSEG submitted to the NYPSC its proposal for revisions to its commodity supply service. On July 10, 2007, NYSEG, NYPSC staff and other interested parties submitted to the NYPSC for consideration a joint proposal resolving all issues related to NYSEG's filing. Provisions of the Supply Service Plan joint proposal include:

• Continuation of supply service options for customers including taking service from an ESCO, taking service from NYSEG under a Fixed Price Option (FPO) and taking service from NYSEG under various variable price options, depending on the size of the customer.
• Customers would choose their supply service option annually in November and December for the upcoming year.
• The variable rate options will continue to be the default service for customers that do not choose to take service from an ESCO or from NYSEG under the FPO.
• The commodity component of the FPO will be calculated and set annually as under the current commodity program; however, the cost allowance used to set the supply rate will increase. The cost allowance is the margin over projected market prices.
• Customers would be able to switch from the FPO to ESCO service at any time during the year, not just during the enrollment period.
• NYSEG will retain the first $10 million (pretax) of earnings, with sharing above that amount at 85% to ratepayers and 15% to shareholders.
• NYSEG will absorb any losses that are experienced on the FPO.

The provisions of the joint proposal would remain in place for a three-year term beginning on January 1, 2008, unless modified as part of an electric delivery rate case prior to that time.

A hearing on the joint proposal was held on July 31, 2007. We cannot predict whether the NYPSC will accept, modify or reject the joint proposal.

NYPSC Proceeding on NYSEG's Accounting for OPEB: In August 2006 the NYPSC issued its decision in the NYSEG electric rate case. Among other things, the NYPSC instructed the ALJ to open a separate proceeding regarding the NYPSC staff's position that NYSEG should have retained $57 million of interest in its OPEB reserve and used it to reduce rate base rather than to reduce OPEB expenses. NYPSC acceptance of its staff's position would have resulted in NYSEG treating all or a portion of the $57 million as an addition to its internal OPEB reserve, with a corresponding charge to income. In July 2007 NYSEG, the NYPSC staff and various intervenors filed a joint proposal with the NYPSC resolving all outstanding issues in this matter. The joint proposal, if approved, would require NYSEG to refund $17 million to customers and to establish an external VEBA trust fund for already reserved OPEB costs of approximately $112 million, which are currently deducted from rate base. NYSEG would contribute $60 million in 2007 and $52 million in 2008. The joint proposal requires pretax charges to earnings for regulatory purposes of $8 million in 2007, $5 million in 2008, and $4 million in 2009. The charges in 2008 and 2009 will be offset by cost reductions resulting from earnings on the VEBA.

Advanced Metering Infrastructure: In response to an August 2006 NYPSC order, NYSEG and RG&E filed a plan to install AMI (smart meters) for all of their electric and natural gas customers. Smart meters would provide customers with detailed consumption data, enabling them to better control their energy usage. Smart meters would also eliminate the need for routine manual meter readings and estimated bills, improve the companies' response to service interruptions, improve the gas balancing and settlement process, reduce greenhouse gas emissions, and create opportunity for a wide range of time-differentiated rates, load management, and load aggregation programs that are expected to reduce peak loads and thereby defer the need for additional electric generation sources. In May 2007 NYSEG and RG&E filed a supplemental plan that includes updated cost estimates for NYPSC review and approval. The plan calls for a total capital investment of approximately $268 million between 2008 a nd 2010. Approval for rate treatment has been requested to go into effect January 1, 2008; the NYPSC is expected to act on that request later this year.

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. NYSEG and RG&E have been allocated an aggregate of 360 MWs of Niagara Power Project power based on contracts with the NYPA which are scheduled to expire on August 31, 2007. NYSEG and RG&E also receive an allocation of 148 MWs from the St. Lawrence Project pursuant to those same contracts. On March 15, 2007, FERC issued to the NYPA a new license pursuant to an Order on Offer of Settlement and Issuing New License (the "Order"). In the Order FERC rejected our arguments for a continued allocation, stating that its policy is not to direct a specific allocation absent statutory directive, but to leave those matters to private contract or state regulation. The annual value of the allocations to us is approximatel y $67 million for the Niagara Power and $51 million for the St. Lawrence Project, and the loss of the allocations will increase our residential customer rates. At its meeting on July 31, 2007, the Board of Trustees of the NYPA approved a resolution calling for the extension of NYSEG's and RG&E's contracts with the NYPA through June 30, 2008, subject to early termination by the NYPA on at least 30 days' prior written notice. Under the contract extensions, the allocation to the two companies will be slightly reduced, from a total of 508 MWs to a total of 451 MWs, which significantly reduces the effect on the residential customer rates during the time of the contract extensions.

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

The NYSDEC served RG&E with a notice of violation in May 2000 alleging that between 1983 and 1987 RG&E completed five projects at Russell Station and two projects at Beebee Station, which is currently shut down, without obtaining the appropriate permits. RG&E believes it has complied with the applicable rules and there is no basis for the Attorney General's and the NYSDEC's allegations. Beginning in July 2000 the NYSDEC, the Attorney General and RG&E had a number of discussions with respect to the resolution of the notice of violation. In October 2006 the Attorney General's office and the NYSDEC notified RG&E of their intention to file a complaint in federal court for violations involving Russell Station unless a settlement can be reached.

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

CMP July 1, 2007 Price Change: CMP's delivery prices decreased by a total of $7 million effective July 1, 2007, as a result of the annual update to CMP's transmission revenue requirement, a change in its stranded cost reconciliation adjustment and its annual ARP 2000 distribution price change. This decrease results primarily from lower transmission costs and a transmission refund requirement previously reserved by CMP. In July each year CMP updates its transmission revenue requirement and reflects the resulting price change in rates pursuant to its tariff on file with the FERC. CMP's transmission revenue requirement decreased by $7 million, primarily due to lower transmission costs. On June 12, 2007, the MPUC approved a settlement implementing an annual stranded cost reconciliation in which CMP will reduce its stranded cost rates by $4 million. These decreases are partially offset by increases under ARP 2000. CMP submitted to the MPUC its annual price change filing pursuant to the terms of its cur rent ARP 2000 on March 15, 2007, and on June21, 2007, the MPUC approved a settlement which provided for a 1.6% distribution rate increase effective July 1, 2007.

CMP Alternative Rate Plan: On May 1, 2007, CMP submitted a filing to the MPUC proposing a new alternative rate plan for a seven-year term beginning January 1, 2008 (referred to as ARP 2008). CMP's current ARP 2000 ends on December 31, 2007. CMP's proposal retains the basic structure of ARP 2000, including annual price changes based on a specified inflation index less a predetermined productivity offset, service quality indicators and associated penalties for failure to achieve the performance targets, and explicit provisions for the recovery of certain exogenous or mandated costs. The filing proposes to maintain the existing rates at the termination of ARP 2000 as the initial rates for ARP 2008. The first price change under the new rate plan would occur on July 1, 2008. The proposal includes fixed productivity offset values of 0.25% for the initial two years of the rate plan and 0.50% for the remaining five years. It utilizes reserve accounting mechanisms to address recovery of costs associated wi th major storm restoration and environmental clean-up costs for manufactured gas sites and PCB-contaminated facilities. CMP's ARP 2008 proposal also incorporates incremental investment and operating expenses for new initiatives including: (1) an AMI project to deploy advanced meters and communications to all of CMP's customers at an estimated cost of $90 million; (2) proposed enhancements in vegetation management, inspection practices and distribution betterment projects designed to improve distribution reliability; and (3) accelerated deployment of more efficient distribution transformers. CMP cannot predict the outcome of this proceeding.

April 2007 Storms: CMP experienced two significant winter storms in April that resulted in widespread outages for its customers and significant damage to its distribution facilities. CMP incurred approximately $11 million in incremental operations and maintenance expenses to restore electric service to its customers after the storms. CMP estimates that it is entitled to recover approximately $4.9 million of those costs under ARP 2000 and has deferred that amount as a regulatory asset. CMP plans to request recovery of the $4.9 million either in its current ARP 2008 proceeding or in some other rate proceeding before the MPUC.

Natural Gas Delivery Business Developments

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

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

CNG Regulatory Proceeding: In September 2006 CNG submitted a general rate filing, requesting a net rate increase of $28.2 million, or 7.9%, in base delivery revenues effective April 1, 2007, based on an 11.0% ROE. The requested increase includes $6.7 million for increased bad debt expense, including a hardship program, $5.6 million for sharing of achieved management efficiencies and $4.3 million to offset lower normalized customer usage.

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

Advanced Metering Infrastructure: See Electric Delivery Business Developments.

New Accounting Standards

See Item 1, Note 9 to our condensed consolidated financial statements for explanations about the following new accounting standards recently released by the FASB:

• Statement 157 issued in September 2006,
• Statement 159 issued in February 2007,
• DIG Issue G26 cleared in December 2006 and posted to the FASB website in January 2007,
• EITF 06-10 ratified in March 2007, and
• FSP FIN 39-1 posted in April 2007.

(a) Liquidity and Capital Resources

Operating Activities: Significant operating activities that affected cash flows during the six months ended June 30, 2007, included the following:

• A decrease in accounts payable that decreased cash $56 million, primarily due to payments for natural gas and electricity purchases,
• A decrease in prepayments that increased cash by $66 million,
• A decrease in receivables that increased cash $42 million, and
• A decrease in fuel inventories that increased cash $69 million.

In addition, RG&E paid a cash refund to customers of $10 million, which represented the last scheduled refund pursuant to its 2004 electric rate agreement and NYSEG refunded $77 million as a credit to customer bills, which was required as part of its August 2006 rate order.

Investing Activities: Utility capital spending for the six months ended June 30, 2007, was $180 million. We project utility capital spending of $496 million for 2007, the majority of which we expect to pay for with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates, and the RG&E transmission project.

Current investments available for sale, which consist of auction rate securities, increased $206 million during the six months as a result of funds available from our March 2007 issuance of common stock.

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

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

During the six months ended June 30, 2007, we issued 406,073 shares of our common stock at an average price of $24.87 through our Investor Services Program.

We repurchased 350,000 shares of our common stock in January 2007, primarily for grants of restricted stock. We awarded 296,145 shares of our common stock, issued out of treasury stock, to certain employees through our Restricted Stock Plan, at a grant date fair value of $24.76 per share of common stock. On July 1, 2007, we issued 47,826 shares at a grant date fair value of $26.09 per share of common stock.

In July 2007 RG&E issued and sold $100 million of First Mortgage 6.47% Bonds, due 2032, Series WW, to fund a portion of the amount necessary to redeem $125 million of its First Mortgage 6.65% Bonds, due 2032, Series UU, which were redeemed on July 23, 2007.

On July 18, 2007, RG&E filed a Form 15 with the SEC, and on July 24, 2007, the New York Stock Exchange filed a Form 25 with respect to RG&E's redeemed Series UU bonds, which, upon effectiveness, terminates RG&E's status as a registrant under the Securities Exchange

Act of 1934 (Exchange Act). RG&E will no longer file Exchange Act reports including Forms 10-K, 10-Q and 8-K, and proxy statements or information statements. We do not expect that the termination of RG&E's Exchange Act registration will materially affect RG&E's access to or cost of capital.

(b) Results of Operations

Earnings per Share

	Three Months		Six Months
Periods ended June 30,	2007	2006	2007	2006
(Thousands, except per share amounts)
Net Income	$19,491	$28,285	$152,785	$161,525
Earnings per Share, basic	$.12	$.19	$1.00	$1.10
Earnings per Share, diluted	$.12	$.19	$1.00	$1.09
Dividends Declared and Paid per Share	$.30	$.29	$.60	$.58
Average Common Shares Outstanding, basic	157,112	146,903	152,341	146,968
Average Common Shares Outstanding, diluted	158,122	147,678	153,291	147,679

Three Months

Earnings per basic share for the quarter ended June 30, 2007 decreased 7 cents compared to the quarter ended June 30, 2006, primarily because of:

• Lower electric margins which, excluding delivery volume increases, reduced earnings per share 17 cents per share largely due to the August 2006 NYSEG electric rate order, and
• Higher operating and maintenance costs, which reduced earnings by 2 cents per share. Increases in operating and maintenance costs included 3 cents per share for higher storm costs and 3 cents per share for costs related to the Merger, which were partially offset by 3 cents per share for lower bad debt expense.

These decreases were offset by:

• Higher electricity and natural gas delivery volumes which resulted in a 5 cents per share increase in electric margins and an increase of 4 cents per share in natural gas margins, and
• Lower interest expenses which increased earnings by 3 cents per share due to lower carrying costs on regulatory liabilities, savings from debt refinancings completed in 2006 and the issuance of equity in March 2007.

Six Months

Earnings per share, basic for the six months ended June 30, 2007, decreased 10 cents per share compared to the six months ended June 30, 2006, primarily because of:

• Lower electric margins which, excluding delivery volume increases, reduced earnings per share 32 cents, largely due to the August 2006 NYSEG rate order, and
• The effect of a higher number of common shares outstanding, which decreased earnings per share by 4 cents.

These decreases were partially offset by:

• Higher electricity and natural gas delivery volumes, which resulted in a 9 cents per share increase in electric margins and an increase of 8 cents per share in natural gas margins, and
• Lower interest costs, which increased earnings 7 cents per share, for the reasons described above.

Energy Deliveries

Energy deliveries and electricity commodity sales for the three and six months ended June 30, 2007, compared to the comparable periods in 2006 are shown below.

	Electricity Deliveries (MWh)			Natural Gas Deliveries (Dth)
Three months ended June 30,	2007	2006	Change	2007	2006	Change
(Thousands)
Residential	2,784	2,609	7%	11,493	11,139	3%
Commercial	2,470	2,433	2%	4,234	3,848	10%
Industrial	1,945	1,740	12%	539	547	(1%)
Other	545	591	(8%)	2,698	2,982	(10%)
Transportation of customer-    owned natural gas	NA	NA	NA	16,885	17,121	(1%)
Total Retail	7,744	7,373	5%	35,849	35,637	1%
Wholesale	1,783	2,485	(28%)	267	45	493%
Total Deliveries	9,527	9,858	(3%)	36,116	35,682	1%
Electricity commodity sales(1)	3,238	3,085	5%	NA	NA	NA
(1) Included in total deliveries

	Electricity Deliveries (MWh)			Natural Gas Deliveries (Dth)
Six months ended June 30,	2007	2006	Change	2007	2006	Change
(Thousands)
Residential	6,211	5,908	5%	50,182	44,972	12%
Commercial	4,931	4,674	5%	16,648	14,985	11%
Industrial	3,539	3,521	1%	2,078	2,043	2%
Other	1,142	1,122	2%	7,093	6,491	9%
Transportation of customer-    owned natural gas	NA	NA	NA	43,367	42,730	1%
Total Retail	15,823	15,225	4%	119,368	111,221	7%
Wholesale	3,720	4,987	(25%)	618	91	579%
Total Deliveries	19,543	20,212	(3%)	119,986	111,312	8%
Electricity commodity sales(1)	6,690	6,643	1%	NA	NA	NA
(1) Included in total deliveries

Several factors influenced the change in volume of energy deliveries, with the primary factor being weather. Temperatures during the first half of 2007 were significantly colder than in 2006. The effects of warmer or colder weather are especially significant to the demand for natural gas. We estimate that for the first six months of 2007, approximately one-third of the 4% increase in retail electricity deliveries and about one-half of the 7% increase in retail natural gas deliveries was due to colder weather. Comparative weather data is shown in the following table.

Weather Conditions

	Three Months			Six Months
Periods ended June 30,	2007	2006	Normal	2007	2006	Normal
New York
Total heating degree days	910	846	957	4,257	3,835	4,368
Colder than prior year	8%			11%
(Warmer) than normal	(5%)			(3%)
New England
Total heating degree days	824	728	835	4,004	3,542	4,010
Colder than prior year	13%			13%
(Warmer) than normal	(1%)			-

Operating Results for the Electric Delivery Business

	Three Months		Six Months
Periods ended June 30,	2007	2006	2007	2006
(Thousands)
Operating revenues
Retail	$524,567	$547,954	$1,117,235	$1,074,496
Wholesale	104,574	141,812	232,050	294,878
Other	53,461	27,926	99,999	133,624
Total Operating Revenues	$682,602	$717,692	$1,449,284	$1,502,998
Operating Expenses
Electricity purchased and fuel used in generation	$351,412	$354,208	$736,685	$731,550
Other operating and maintenance expenses	175,794	167,861	343,066	337,743
Depreciation and amortization	44,590	46,650	89,113	92,701
Other taxes	36,818	37,001	75,248	76,082
Total Operating Expenses	$608,614	$605,720	$1,244,112	$1,238,076
Operating Income	$73,988	$111,972	$205,172	$264,922

Three Months

Operating Revenues: The $35 million decrease in operating revenues for the second quarter of 2007 was primarily the result of:

• A decrease of $25 million in average delivery prices, primarily resulting from lower transition charges. Transition charges allow our electric utility companies to recover actual generation and purchased power costs and have no net effect on earnings,
• A decrease of $8 million resulting from NYSEG's delivery rate decrease pursuant to its August 2006 rate order.
• A decrease of $37 million in wholesale revenues, reflecting a 28% decline in wholesale volume, and
• A decrease of $12 million resulting from lower prices for electricity sales under supply service programs in New York.

Those decreases were partially offset by:

• An increase of $21 million resulting from higher accruals for the NBC, which will be passed on to customers through higher transition charges,
• An increase of $13 million resulting from a 5% increase in retail deliveries,
• An increase of $10 million resulting from a 5% increase in sales under supply service programs in New York, and
• An increase of $4 million in other revenues.

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

• An increase of $8 million in operating and maintenance expenses primarily attributable to increased storm costs for CMP.

That increase was partially offset by:

• A decrease of $3 million for lower purchased power costs, and
• A decrease of $2 million in depreciation due to lower rates adopted as part of NYSEG's August 2006 rate order.

Six Months

Operating Revenues: The $54 million decrease in operating revenues for the six months ended June 30, 2007 was primarily the result of:

• A decrease of $25 million resulting from higher accruals for earnings sharing, which is included in other revenues. That decrease includes $14 million of adjustments recorded in 2006 resulting from the finalization of NYSEG's and RG&E's annual compliance filings for 2005,
• A decrease of $18 million resulting from NYSEG's delivery rate decrease pursuant to its August 2006 rate order,
• A decrease of $63 million in wholesale revenues, reflecting a 25% decline in wholesale volume,
• A decrease of $7 million resulting from lower accruals for the NBC, which will be passed on to customers through lower transition charges, and
• A decrease of $4 million resulting from lower prices for electricity sales under supply service programs in New York.

Those decreases were partially offset by:

• An increase of $40 million in average delivery prices, primarily resulting from higher transition charges. Transition charges allow our electric utility companies to recover actual generation and purchased power costs and have no net effect on earnings. The increase in transition charges was partially offset by the NBC accrual discussed above, and
• An increase of $23 million resulting from a 4% increase in retail deliveries. Approximately one-third of the increase was due to colder winter temperatures in 2007.

Operating Expenses: The $6 million increase in operating expenses for the six months ended June 30, 2007 was primarily the result of:

• An increase of $5 million for higher purchased power costs, and
• An increase of $5 million in operating and maintenance costs resulting from small increases in several categories and reductions in regulatory credits applied in 2006 that ceased in 2007.

Those increases were partially offset by:

• A decrease of $4 million in depreciation expense due to lower rates adopted in NYSEG's August 2006 rate order.

Operating Results for the Natural Gas Delivery Business

	Three Months		Six Months
Periods ended June 30,	2007	2006	2007	2006
(Thousands)
Operating Revenues
Retail	$289,528	$276,658	$1,088,661	$1,034,281
Wholesale	2,438	12	5,934	29
Other	2,438	6,536	(2,809)	5,795
Total Operating Revenues	$294,404	$283,206	$1,091,786	$1,040,105
Operating Expenses
Natural gas purchased	$174,232	$172,663	$712,738	$682,432
Other operating and maintenance expenses	60,551	67,955	116,427	124,082
Depreciation and amortization	21,431	21,375	43,526	42,718
Other taxes	20,578	19,941	56,065	52,663
Total Operating Expenses	$276,792	$281,934	$928,756	$901,895
Operating Income	$17,612	$1,272	$163,030	$138,210

Three Months

Operating Revenues: The $11 million increase in operating revenues for the second quarter of 2007 was primarily the result of:

• An increase of $5 million resulting from a 1% increase in retail deliveries,
• An increase of $5 million resulting from higher base rates for CNG, and
• An increase of $6 million resulting from an increase in wholesale and transportation revenues.

Those increases were partially offset by:

• A decrease of $5 million in other revenue, including $2 million from lower weather normalization accruals.

Operating Expenses: The $5 million decrease in operating expenses for the second quarter of 2007 was primarily the result of:

• A decrease of $7 million in operating and maintenance expense attributable primarily to lower bad debt expense.

That decrease was partially offset by:

• An increase of $2 million in natural gas purchases due to increased delivery volumes.

Six Months

Operating Revenues: The $52 million increase in operating revenues for the six months ended June 30, 2007 was primarily the result of:

• An increase of $94 million resulting from a 7% increase in retail deliveries. About one-half of the increase was due to colder temperatures in 2007 than in 2006,
• An increase of $13 million resulting from an increase in wholesale and transportation revenues, and
• An increase of $5 million resulting from higher base rates for CNG.

Those increases were partially offset by:

• A decrease of $44 million resulting from lower market prices for natural gas that were passed on to customers, and
• A decrease of $16 million in other revenues, including $8 million resulting from lower weather normalization accruals.

Operating Expenses: The $27 million increase in operating expenses for the six months ended June 30, 2007, was primarily the result of:

• An increase of $66 million in natural gas purchases due to increased delivery volumes,
• An increase of $3 million in gross receipts taxes resulting from higher revenues, and
• An increase of $4 million in natural gas purchases resulting from an increase in wholesale sales.

Those increases were partially offset by:

• A decrease of $40 million in natural gas purchases resulting from lower market prices, and
• A decrease of $8 million in operating and maintenance expenses primarily attributable to a reduction in bad debt expense.

Operating Results for the Energy Marketing Business

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

	Three Months		Six Months
Periods ended June 30,	2007	2006	2007	2006
(Thousands)
Electricity sales (MWh)	1,118	1,086	2,167	2,285
Natural gas sales (Dth)	1,005	1,076	4,961	4,566
Operating Revenues
Electric	$86,591	$88,586	$180,648	$181,900
Natural gas	12,002	10,507	53,873	55,875
Total Operating Revenues	$98,593	$99,093	$234,521	$237,775
Operating Expenses
Electricity purchased	$82,729	$84,249	$171,773	$173,610
Natural gas purchased	11,321	9,631	51,720	50,554
Other operating expenses	3,566	2,572	6,688	5,526
Total Operating Expenses	$97,616	$96,452	$230,181	$229,690
Operating Income	$977	$2,641	$4,340	$8,085

Three Months

Operating Revenues: The less than $1 million decrease in operating revenues for the second quarter of 2007 was primarily the result of:

• A decrease of $5 million in retail electric revenues resulting from lower average rates from variable rate customers due to lower market prices for electricity, and
• A decrease of $1 million due to lower natural gas sales volumes.

Those decreases were partially offset by:

• An increase of $3 million due to an increase in retail electricity sales volumes resulting from increased customer counts, and
• An increase of $2 million due to higher natural gas prices.

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

• An increase of $3 million in purchased electricity due to higher electric volumes resulting from increased customer counts, and

• An increase of $2 million in purchased natural gas due to higher natural gas prices.

Those increases were partially offset by:

• A decrease of $4 million in purchased electricity due to lower electric prices, and
• A decrease of $1 million in natural gas purchases due to lower natural gas sales volumes.

Six Months

Operating Revenues: The $3 million decrease in operating revenues for the six months ended June 30, 2007, was primarily the result of:

• A decrease of $9 million due to lower electric sales volumes resulting from the loss of some large customers to other suppliers, and
• A decrease of $7 million due to lower natural gas prices.

Those decreases were partially offset by:

• An increase of $8 million due to higher retail electric revenues from variable rate customers, and
• An increase of $5 million due to an increase natural gas sales volumes.

Operating Expenses: The less than $1 million increase in operating expense for the six months ended June 30, 2007, was primarily the result of:

• An increase of $7 million in purchased electricity prices, and
• An increase of $4 million in purchased natural gas due to higher natural gas sales volumes.
• An increase of $1 million in other operating expenses due to additional sales and marketing expenses as well as increased billing costs.

Those increases were offset by:

• A decrease of $9 million in purchased electricity due to lower electric sales volumes, and
• A decrease of $3 million in natural gas purchases due to lower natural gas prices.

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

NYSEG's and RG&E's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the fixed rate option, which effectively combines delivery and supply service at a fixed price. NYSEG uses electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity required to serve customers who select the fixed rate option. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. Owned electric generation and long-term supply contracts reduce NYSEG's exposure, and significantly reduce RG&E's exposure, to market fluctuations for procurement of their fixed rate option electricity supply.

As of July 2007 the expected load for NYSEG's fixed rate option customers is fully hedged for August through December 2007. A fluctuation of $1.00 per MWh in the average price of electricity would change NYSEG's earnings less than $250,000 for August through December 2007. RG&E expects to meet its fixed price load obligations for 2007 with owned generation or long-term supply contracts. The percentage of NYSEG's and RG&E's hedged load is based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the loadforecasts.

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

Energetix and NYSEG Solutions, Inc. offer retail electric and natural gas service to customers in New York state and actively hedge the load required to serve customers that have chosen them as their commodity supplier. As of July 2007 the energy marketing subsidiaries' expected fixed price loads were fully hedged for August through December 2007. A fluctuation of $1.00 per MWh in the average price of electricity would change their earnings less than $120,000 for August through December 2007. The percentage of hedged load for the energy marketing subsidiaries is based on load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecasts.

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

We use interest rate swap agreements to manage the risk of increases in variable interest rates and to maintain desired fixed-to-floating rate ratios. We record amounts paid and received under those agreements as adjustments to the interest expense of the specific debt issues. As required by DIG Issue G26 (see Part I, Item 1, Note 9. New Accounting Standards) we dedesignated the hedging relationships as of April 1, 2007, for NYSEG's two cash flow hedges related to its auction rate notes. We are investigating our options concerning the future management of interest rate risk for those instruments.

Item 4.  Controls and Procedures

Our principal executive officer and principal financial officer evaluated the effectiveness of our 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, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

We 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. Our 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 our internal control over financial reporting that occurred during the most recent fiscal quarter that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.    Legal Proceedings

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

Merger-related Lawsuit: In connection with Iberdrola's proposed acquisition of Energy East, Howard Lasker, an alleged shareholder of Energy East, filed a purported class action complaint on or about July 6, 2007, in the Supreme Court of the State of New York for Kings County, against us and our directors. The complaint alleges that, among other things, that the consideration for the proposed acquisition is unfair and inadequate because it does not provide Energy East shareholders with a sufficient premium and the defendants have breached their fiduciary duty. The complaint seeks an injunction on our completion of the Merger as well as monetary damages in an amount not specified. A response to the complaint is currently due September 5, 2007. We and our directors dispute these allegations and intend to vigorously defend this suit.

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 of Form 10-K for Energy East for the fiscal year ended December 31, 2006, Part I, Item 1A. Risk Factors.)

There can be no assurance that Iberdrola's acquisition of the company will be completed:

Consummation of the proposed merger is subject to satisfaction of various closing conditions, including obtaining approvals or consents from a number of United States federal and state public utility, antitrust and other regulatory authorities described in the Merger Agreement. We cannot predict whether such authorizations will be obtained on satisfactory terms or the timing of required regulatory approvals. If the Merger is not completed and the Merger Agreement is terminated, the market price of our common stock may decline to the extent that the then current market price of those shares reflects an assumption as to the completion of the Merger. Under certain circumstances, we could be obligated to pay Iberdrola a termination fee of $45 million. While the Merger is pending, we have agreed to operate our businesses in the ordinary course and certain significant business actions or changes from our ordinary course will require the consent of Iberdrola. In addition, management's attention may be diverted f rom day-to-day business operations.

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

(c) Issuer Purchases of Equity Securities

Period		(a)      Total number of shares purchased (1)		(b)        Average price paid per share		(c)        Total number of shares purchased as part of publicly announced plans or programs		(d)        Maximum number of shares that may yet be purchased under the plans or programs
Month #1   (April 1, 2007 to   April 30, 2007)	5,256(1)		$24.90		- -		- -
Month #2   (May 1, 2007 to   May 31, 2007)	4,725(1)		$24.38		- -		- -
Month #3   (June 1, 2007 to   June 30, 2007)	4,966(1)		$23.19		- -		- -
Total	14,947		$24.17		-		-
(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.

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

Energy East's Annual Meeting of Stockholders was held on June 14, 2007. The following matters were voted on:

(a) The election of 11 directors for a term expiring at the 2008 Annual Meeting:

Nominees	Votes For	Votes Withheld
James H. Brandi	115,644,604	12,114,811
John T. Cardis	125,304,772	2,454,643
Thomas B. Hogan, Jr.	125,341,767	2,417,648
G. Jean Howard	125,524,502	2,234,913
David M. Jagger	125,604,903	2,154,512
Seth A. Kaplan	125,582,623	2,176,792
Ben E. Lynch	124,715,863	3,043,552
Peter J. Moynihan	125,576,104	2,183,311
Patricia M. Nazemetz	125,368,811	2,390,604
Walter G. Rich	125,321,210	2,438,205
Wesley W. von Schack	125,017,396	2,742,019

(b) Ratification of the appointment of PricewaterhouseCoopers LLP as the company's independent registered public accounting firm for 2007:

Shares For:	125,809,824
Shares Against:	1,029,059
Shares Abstain:	920,532

Item 6.  Exhibits

See Exhibit Index.

Signature

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

Date:  August 2, 2007 ENERGY EAST CORPORATION
                  (Registrant)

By   /s/Robert D. Kump                              
           Robert D. Kump
           Senior Vice President and Chief Financial Officer
           (Principal Accounting Officer)

EXHIBIT INDEX

The following exhibits are delivered with this report:

Exhibit No.	Description of Exhibit
(A)10-31	ERISA Excess Plan Amendment No. 1.
(A)10-32	Supplemental Executive Retirement Plan Amendment No. 4.
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.

_________________________________
(A) Management contract or compensatory plan or arrangement.

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

Energy East agrees to furnish, upon request, a copy of a First Amendment, dated as of May 16, 2007, to 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.

EX-10.31

Exhibit 10-31

AMENDMENT NO. 1
TO THE
ENERGY EAST CORPORATION
ERISA EXCESS PLAN
EFFECTIVE AS OF
JANUARY 1, 2005

WHEREAS, Energy East Corporation (the "Company") established the Energy East Corporation ERISA Excess Plan (the "Plan"), effective as of January 1, 2005; and

WHEREAS, the Company desires to amend the Plan, as permitted by Section 7.1 of the Plan, to permit a limited timing of payment election.

          NOW, THEREFORE, the Plan is amended, effective as of August 1, 2007 as follows:

1.     Section 4.2 of the Plan is hereby amended by adding the following paragraph to the end of Section 4.2:

"If Wesley von Schack so elects on or prior to 12/31/07, then, notwithstanding anything else contained herein, he will receive the retirement benefit described in Article 4, as actuarially determined pursuant to his Employment Agreement (dated December 31, 2006), in a single lump sum upon the earlier of (i) the date of the consummation of a transaction which is a "change in the ownership or effective control of the corporation or in the ownership of a substantial portion of the assets of the corporation" (as such term is defined in Treasury Regulation Section 1.409A), (for this purpose the Company is the "corporation"), or (ii) the date payment would be made as a result of his termination of employment with the Company and it affiliates in accordance with the termination of employment provisions in Article 4."

All the provisions of the Plan not specifically mentioned in this Amendment No. 1 shall be considered modified to the extent necessary to be consistent with the changes made in this Amendment No. 1.

IN WITNESS WHEREOF OF THE ADOPTION OF THIS AMENDMENT NO. 1, Energy East Corporation has set its hand and seal to this Amendment No. 1 as of the 31st day of July, 2007.

	ENERGY EAST CORPORATION
Witness: /s/Michelle Taylor	By: /s/R.R. Benson
	Its:

EX-10.32

Exhibit 10-32

AMENDMENT NO. 4
TO THE
ENERGY EAST CORPORATION
SUPPLEMENTAL RETIREMENT PLAN
EFFECTIVE AS OF
AUGUST 1, 2001

WHEREAS, Energy East Corporation (the "Company") established the Energy East Corporation Supplemental Executive Retirement Plan (the "Plan"), effective as of August 1, 2001; and

WHEREAS, the Company desires to amend the Plan, as permitted by Section 7 of the Plan, to permit a limited timing of payment election.

        NOW, THEREFORE, the Plan is amended, effective as of August 1, 2007 as follows:

1.   Paragraph 6C of the Plan is hereby amended by adding the following subparagraph to the end of Paragraph 6C:

"If Wesley von Schack so elects on or prior to 12/31/07, then, notwithstanding anything else contained herein, he will receive the retirement benefit described in Paragraph 6, as actuarially determined pursuant to his Employment Agreement (dated December 31, 2006), in a single lump sum upon the earlier of (i) the date of the consummation of a transaction which is a "change in the ownership or effective control of the Corporation or in the ownership of a substantial portion of the assets of the Corporation" (as such term is defined in Treasury Regulation Section 1.409A) or (ii) the date payment would be made as a result of his termination of employment with the Corporation and it affiliates in accordance with the termination of employment provisions in Paragraph 6."

All the provisions of the Plan not specifically mentioned in this Amendment No. 4 shall be considered modified to the extent necessary to be consistent with the changes made in this Amendment No. 4.

IN WITNESS WHEREOF OF THE ADOPTION OF THIS AMENDMENT NO. 4, Energy East Corporation has set its hand and seal to this Amendment No. 4 as of the 31^st day of July, 2007.

	ENERGY EAST CORPORATION
Witness: /s/Michelle Taylor	By: /s/R.R. Benson
	Its:

EX-31.1

Exhibit 31-1

Certification

I, Wesley W. von Schack, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy East Corporation for the quarter ended June 30, 2007;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 2, 2007    /s/ Wesley W. von Schack                       
       Wesley W. von Schack
       Chairman, President &
       Chief Executive Officer

EX-31.2

Exhibit 31-2

Certification

I, Robert D. Kump, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy East Corporation for the quarter ended June 30, 2007;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 2, 2007    /s/ Robert D. Kump                                    
       Robert D. Kump
       Senior Vice President &
       Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION OF PERIODIC REPORT OF
PRINCIPAL EXECUTIVE OFFICER
AND OF
PRINCIPAL FINANCIAL OFFICER
OF

ENERGY EAST CORPORATION

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

          We, Wesley W. von Schack, Chairman, President & Chief Executive Officer, and Robert D. Kump, Vice President, Controller & Chief Accounting Officer, of Energy East Corporation, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) Energy East Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (the "Report"), fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Energy East Corporation.

Date: August 2, 2007	/s/Wesley W. von Schack                                     Wesley W. von Schack         Chairman, President &         Chief Executive Officer
	/s/Robert D. Kump                                               Robert D. Kump         Senior Vice President &         Chief Financial Officer