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

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):

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.

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.

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.

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:

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.

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.

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

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.

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 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.

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.

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.

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 plan 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 million 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.

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.

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.

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:

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

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.

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.

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.

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:

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 and 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 approximately $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 NYSDEC and the Attorney General continue to discuss this matter and no suit has been filed to date. RG&E is not able to predict the outcome of this matter.

CMP Alternative Rate Plan: 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 with major storm restoration and environmental clean-up costs for manufactured gas sites and PCB-contaminated facilities. CMP's ARP 2008 proposal also incorporates incremental investment and operating expenses for new initiatives including: (1) an AMI project to deploy advanced meters and communications to all of CMP's customers 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.

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.

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.

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

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.

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