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, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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 April 30, 2008, was 158,299,059.

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, 2007, Item 1A - Risk Factors and Item 7A - MD&A - Quantitative and Qualitative Disclosures About Market Risk, and also include, among others:

• the occurrence of any event, change or other circumstances that could give rise to the termination of our Merger Agreement with Iberdrola,
• the outcome of any legal or regulatory proceedings that have been instituted following the announcement of the Merger,
• our ability to compete in the rapidly changing and competitive electric and/or natural gas utility markets,
• 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 rising commodity costs on customer usage and uncollectible expense,
• 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 continuation of current rate plans,
• the possible discontinuation or further modification of fixed-price supply programs in New York,
• 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 effects of changes in the credit markets on our variable rate debt,
• 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.

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

On June 25, 2007, we announced that we had entered into a Merger Agreement 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.

Consummation of the Merger is subject to various customary closing conditions, including the absence of injunctions or restraints imposed by governmental entities, the receipt of required regulatory approvals and the absence of any event that would reasonably be expected to have a material adverse effect on Energy East. To date, all regulatory approvals have been received except approval from the NYPSC. Subject to NYPSC approval, we expect the Merger to be completed by the end of the first half of 2008. Until the Merger is completed, Energy East will continue to operate as a separate company.

The accompanying unaudited financial statements should be read in conjunction with the financial statements and notes contained in the report on Form 10-K filed for the fiscal year ended December 31, 2007. 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 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 ended March 31 were: 1.5 million in 2008 and 2.1 million in 2007.

EITF 06-10: Effective January 1, 2008, Energy East began applying the consensus of EITF 06-10, which the FASB ratified in late March 2007. EITF 06-10 requires an employer to recognize a liability for a postretirement benefit related to a collateral assignment split-dollar life insurance arrangement. In a collateral assignment split-dollar life insurance arrangement, the employee, versus the employer, owns and controls the insurance policy. 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. 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. CNG is the only Energy East subsidiary with collateral assignment split-dollar life insurance arrangements. Energy East elected to recognize the effects of applying the consensus as a change in accounting principle through a cumulative-effect adjustment that resulted in a decrease in retained earnings of $2.3 million. The application of EITF 06-10 did not affect Energy East's results of operation or cash flows.

Statement 141(R) and Statement 160: In December 2007 the FASB issued Statement 141(R) and Statement 160, both the result of a joint project between the FASB and the International Accounting Standards Board. The objective of Statement 141(R) is "to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports about a business combination and its effects." Some key changes that will result from the application of Statement 141(R) are: all transaction costs and most restructuring costs will be expensed, acquired in-process research and development costs will not be expensed at acquisition, and equity securities issued as part of the purchase price will be measured on the closing date instead of the announcement date. Statement 141(R) will apply to business combinations for which the acquisition date is on or after the beginning of an entity's first annual reporting period beginning on or after December 15, 2008 (Energy East's annual reporting period beginning January 1, 2009). It may not be applied before that date and must be applied prospectively.

Statement 160 is intended "to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements" about noncontrolling (sometimes called minority) interests. Minority interest earnings will no longer be excluded from net income as a result of applying Statement 160. Statement 160 is effective for fiscal years (including interim periods) beginning on or after December 15, 2008 (January 1, 2009, for Energy East), with earlier adoption prohibited and prospective application required, except that the presentation and disclosure requirements are to be applied retrospectively. We expect that our application of both Statements will not affect our financial position, results of operation or cash flows.

Statement 161: In March 2008 the FASB issued Statement 161, which requires enhanced disclosures about an entity's derivative instruments and hedging activities to enable investors to better understand their effects on the entity's financial position, financial performance and cash flows. It is intended to improve transparency about the location and amounts of derivative instruments in the financial statements and how the entity accounts for derivative instruments and related hedged items. Requirements include: disclosure of fair values of derivative instruments and their gains and losses in a tabular format, disclosure of derivative features that are credit risk-related, and cross-referencing within notes to enable financial statement users to locate important information about derivative instruments. Statement 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009, for Energy East). Early application is encouraged. Disclosures for earlier periods presented for comparative purposes are encouraged but not required at initial adoption. In years after initial adoption, comparative disclosures are required only for periods subsequent to initial adoption. We expect that our adoption of Statement 161 will not affect our financial position, results of operation or cash flows.

In September 2006 the FASB issued Statement 157, which we adopted effective January 1, 2008, for financial assets and financial liabilities. Changes from current practice that 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. Statement 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. Our adoption of Statement 157 and related FASB Staff Positions (FSPs), below, had no effect on our financial position, results of operation and cash flows.

The FASB issued FSP FAS 157-1 and FSP FAS 157-2 in February 2008. FSP FAS 157-1 amends Statement 157 to exclude FASB Statement No. 13, Accounting for Leases (Statement 13), and other accounting pronouncements related to leases or that address fair value measurements for purposes of lease classification or measurement under Statement 13. The exclusion of Statement 13 from the scope of Statement 157 does not apply to assets acquired and liabilities assumed that are required to be measured at fair value in connection with a business combination, regardless of whether those assets and liabilities are related to leases. FSP FAS 157-1 also, for the time being, redefines the term fair value used in Statement 13, to read: "Fair value of the leased property. The price for which the property could be sold in an arm's-length transaction between unrelated parties." FSP FAS 157-1 is effective upon the initial adoption of Statement 157.

FSP FAS 157-2 delays the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity's financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Nonfinancial assets and nonfinancial liabilities include all assets and liabilities other than those that meet the definitions of financial asset and financial liability as defined in paragraph 6 of Statement 159. FSP FAS 157-2 also requires additional disclosures concerning application of the provisions of Statement 157. FSP FAS 157-2 was effective upon issuance.

Valuation techniques: We value our current investments available for sale - auction rate securities - at par due to the variable rate earned on the investments and our expectation that they will be sold at par within the next 12 months. Such securities ordinarily earn interest at rates established at periodic auctions, typically every seven or 35 days. However, periodic auctions for the securities began to fail during the first quarter of 2008 and we are earning formulaic failure rates on our investments. We held $19.9 million of those securities on March 31, 2008. In April 2008 $10 million of these auction rate securities were called and redeemed at par, and we sold an additional $1.7 million at a successful auction. As of April 22, 2008, we are holding $8.2 million of auction rate securities, which are earning pretax equivalent rates averaging 6.3%. Our intention is to sell the investments when the auction rate markets stabilize, to redeem them when they are called or to sell them in the secondary market. We have received call notices on an additional $3.4 million of our auction rate securities and have been able to sell small amounts at par in the secondary market. At January 1, 2008, these investments would have been classified as Level 1 investments. Due to uncertainties that began to develop in the auction rate securities markets in the first quarter of 2008 and the need for management to use judgment to value these securities, we include the fair value measurements as of March 31, 2008, in Level 3.

We measure the fair value of our noncurrent investments available for sale using quoted market prices in active markets for identical assets and include these measurements in Level 1. These are primarily money market funds, but also include some fixed income and equity investments.

We determine the fair value of our various derivative assets and liabilities utilizing market approach valuation techniques:

• NYSEG, RG&E and our energy marketing subsidiaries enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. Those companies hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. Forward market price quotes for some NYISO locations are not actively traded and not readily available outright from market dealers. We derive forward market prices for some locations based on the historical relationship of prices in those locations to prices in locations where an active market exists. The resulting value represents the derived forward market price for each location, which we use to value the open derivative contracts. Because we adjust quoted market prices for our own load characteristics, we include these fair value measurements in Level 3.
• NYSEG, RG&E and our energy marketing subsidiaries enter into natural gas derivative contracts to hedge the forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value our open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange. Because we use quoted prices in an active market, we include these fair value measurements in Level 1.
• We enter into treasury-related derivative contracts to hedge the forecasted issuance of debt, to manage the risk of changes in interest rates associated with existing debt, and to maintain desired fixed-to-floating rate ratios. We value those derivatives based on indicative values provided by transaction counterparties and calculated based upon proprietary models that use well-recognized financial principles and reasonable, market-based estimates of relevant future market conditions. We assess the reasonableness of the transaction counterparty valuations utilizing a model that constructs forward LIBOR (London Interbank Offer Rate) rates from a spot LIBOR curve, applies the forward rates to construct pro forma cash flows and discounts the pro forma cash flows to the present using forward rates. Because the valuations provided by the counterparties are only indicative and do not represent prices at which the counterparties would be willing to transact, we include these fair value measurements in Level 3.

The amounts of realized and unrealized gains and losses included in earnings for the period (above), which are reported in the various categories indicated are:

NYSEG and RG&E have issued $776 million of tax-exempt pollution control notes, $518 million of which have rates that are reset periodically through an auction process that occurs every 7 days for $416 million and every 35 days for the remaining $102 million. The principal and interest on those notes are insured by XL Capital Assurance, Inc., Ambac Assurance Corporation or MBIA Insurance Corporation. The investors' source of liquidity on those notes is the auction market itself. As the financial strength of bond insurers has been called into question, due in part to their exposure to rising mortgage default rates, investors have reacted by withdrawing from the market, thereby significantly reducing market liquidity and resulting in higher and more volatile interest rates. More recently, as the market became illiquid and broker-dealers withdrew their capital support, an increasing percentage of the auctions, including NYSEG and RG&E auctions, have failed to receive sufficient bids to set new interest rates. In such instances, the issuer is obligated to pay a formulaic failure rate until sufficient bids are received at a scheduled auction. For NYSEG and RG&E, the interest rates resulting from failed auctions are a function of current short-term money market rates multiplied by a factor, ranging from 175% to 300%, based on the rating of the applicable bond insurer. As of April 22, 2008, NYSEG and RG&E were paying failure rates averaging 4.6% on all $518 million of auction rate debt. Continued and prolonged illiquidity in the auction rate market could increase our interest costs. NYSEG and RG&E are in the process of restructuring their auction rate portfolios. As part of that effort, NYSEG and RG&E have issued notices of their intent to convert certain series of bonds ($70 million NYSERDA Pollution Control Revenue Bonds, 2004 Series B (NYSEG Project) maturing December 1, 2028, and $50 million NYSERDA Pollution Control Revenue Bonds, 2004 Series B (RG&E Project) maturing May 15, 2032) to fixed rate to maturity. We expect the NYSEG conversion to occur on May 9 and the RG&E conversion to occur later in May 2008.

Our accounts receivable include unbilled revenues of $248 million at March 31, 2008, and $273 million at December 31, 2007, and are shown net of an allowance for doubtful accounts of $55 million at March 31, 2008, and $51 million at December 31, 2007.

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.

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 include:

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

Energy East's primary operations, our electric and natural gas utility operations, are subject to rate regulation established predominantly by state utility commissions. The approved regulatory treatment on various matters significantly affects our results of operation, financial position and cash flows. We have rate plans for NYSEG's natural gas segment, RG&E's electric and natural gas segments, 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 rate plans are not in effect, or as we approach the end of the term of existing plans, we monitor the adequacy of rate levels and file for new rates when necessary. NYSEG's current electric rates went into effect on January 1, 2007. CNG's current rates became effective April 1, 2007. CMP's rate plan expired at the end of 2007 and NYSEG's natural gas rate plan and RG&E's electric and natural gas rate plans have terms that extend at least through the end of 2008. Under certain conditions those rate plans may continue.

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 approximate $4.2 billion through 2012, including $660 million in 2008. Major spending programs include the installation of an AMI in New York and Maine requiring an investment of approximately $360 million; in excess of $1 billion 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. We estimate that about one-half of our capital spending program will be funded with internally-generated funds and the remainder through the issuance of a combination of debt and equity securities.

This MD&A for the quarter ended March 31, 2008, should be read in conjunction with our MD&A, financial statements and related notes contained in our report on Form 10-K for the fiscal year ended December 31, 2007. 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 in an environmentally sensitive manner. Our operating companies have become increasingly efficient through realization of merger-enabled synergies. We intend to augment this strategic focus by addressing many of the precepts of the Energy Policy Act of 2005 including investing in: a) transmission to increase reliability, meet new load growth and connect new, renewable generation to the grid; b) an AMI to promote customer conservation and peak load management; c) our distribution infrastructure to make it more efficient by reducing losses; and d) new regulated generation to the extent that it is approved by state legislators or regulators.

NYPSC Staff Allegations Concerning Earnings Sharing Calculations: The NYPSC staff in its testimony in the Merger proceeding has alleged that NYSEG did not properly compute the amount due to customers under the electric ESM in NYSEG's electric rate plan that was in effect from 2002 through 2006. The staff claims that its preliminary analysis shows an additional $67 million, including interest, should have been allocated to customers. NYSEG vigorously disputes the staff's claim. For each year 2002 through 2006 NYSEG made annual compliance filings, as required by the NYPSC. The NYPSC staff has never formally presented its findings to NYSEG indicating its disagreements with NYSEG's 2002 - 2006 electric annual compliance filings. The NYPSC staff stated in its direct testimony in the Merger proceeding that its audits have not been completed and the staff will provide its response to NYSEG no later than NYSEG's next rate case. NYSEG is unable to predict when or how the issue will be resolved. The staff also raised issues in the Merger proceeding with regard to the ESM under the RG&E electric rate plan currently in effect, but has not completed its analysis. RG&E believes that it has been properly calculating the amount due to customers in its annual compliance filings since 2004, but cannot predict how the matter will be resolved.

RG&E Transmission Project: In December 2004 RG&E received approval from the NYPSC to upgrade its electric transmission system in order to provide sufficient transmission and ensure reliable service to customers in anticipation of the shutdown of the Russell Station. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, New York area. Construction on the project began in the first quarter of 2006 and is expected to be completed by May 2008. The estimated cost of the project is approximately $125 million.

CMP FERC Rate Update: CMP uses formula rates for transmission that are regulated by the FERC. The formula rates provide for the recovery of CMP's cost of owning, operating and maintaining local and regional transmission facilities and a local control center. On March 24, 2008, the FERC issued an order approving a base level return on equity (ROE) of 11.1%, plus a 50 basis point adder for regional facilities and a 100 basis point incentive adder applicable to regional facilities placed in service after December 31, 2003, and before January 1, 2009, that have been approved as part of the ISO-NE regional planning process. In compliance with the FERC order, CMP will revise its prior transmission service billing to recover approximately $870,000 of additional revenue from transmission customers. Project owners seeking a transmission investment incentive for a project scheduled to be completed after December 31, 2008, are required to make a separate project-specific filing to the FERC, justifying the requested incentive in accordance with the FERC's stated criteria.

CMP Alternative Rate Plan 2008: 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 ended 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 proposed 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 an AMI project to deploy smart meters.

On February 8, 2008, the MPUC staff filed its updated testimony and recommended an annual rate decrease of $39 million. On the same date, the OPA filed testimony recommending a rate decrease of $22 million. The recommended price decreases result from lower cost of capital recommendations, higher sales expectations and no investment in AMI. The OPA recommends a five-year rate plan while the staff recommended no long-term rate plan. Hearings were conducted in March 2008 and the MPUC is expected to reach a decision in the case in May 2008. CMP cannot predict the outcome of this proceeding.

April 2007 Storms: CMP experienced two significant storms in April 2007 that resulted in extensive outages for its customers and significant damage to its distribution facilities. CMP incurred approximately $11 million in incremental costs to restore electric service to its customers after the storms. CMP believes that it is entitled to recover approximately $5 million of those costs under ARP 2000 and has deferred that amount as a regulatory asset. On March 17, 2008, CMP requested recovery of the $5 million in its final compliance filing under ARP 2000. On March 21, 2008, the OPA submitted a motion to dismiss CMP's request, arguing that the termination of ARP 2000 on December 31, 2007, prohibits CMP's requested recovery. An MPUC decision with respect to the OPA motion is expected in late April 2008 and, if the motion to dismiss is denied, a decision on the amount of storm-related costs to be recovered by CMP is expected in late May 2008. CMP cannot predict the outcome of this proceeding.

MPUC Inquiries into Continued Participation in New England RTO: Maine lawmakers have enacted legislation requiring the MPUC to undertake an inquiry concerning whether or not CMP and other Maine electric utilities should continue to participate in the New England RTO, as operated by the ISO-NE. The MPUC has issued various reports to the Maine Legislature concerning continued participation, including its final report on January 15, 2008. As a result of the inquiry, the MPUC concluded that there are serious and valid concerns with the status quo regulatory structure of transmission projects in Maine and New England. The MPUC developed and assessed three options: market reform, a Maine Independent transmission company and a Maine/New Brunswick market. The Maine Legislature considered the report during its 2008 session but deferred any action until the conclusion of further MPUC proceedings, as discussed below.

As part of a stipulation resolving the Merger approval in Maine, Iberdrola, Energy East and CMP agreed to take no action with regard to CMP's position in any RTO, including whether to extend, consent to, amend, or renew or otherwise modify the terms of CMP's contract with ISO-NE without explicit approval of the MPUC. The parties to the Merger proceeding in Maine and the MPUC agreed that CMP will initiate and the MPUC will conduct a proceeding to determine if extension or renewal of CMP's contract with ISO-NE is in the public interest. CMP expects to submit its initial filing in the required proceeding in early May 2008 and, in accordance with the stipulation terms, the MPUC expects to issue a ruling in January 2009.

Any change in CMP's participation in the New England RTO could affect the process for siting and approval of new transmission investments and the cost recovery and rate of return for those investments.

CNG Billing Issue: In early February 2008 the Connecticut Department of Public Utility Control opened an investigation regarding CNG's billing of certain customers during January 2008. Four of CNG's meter readers had intermittently and inappropriately approximated gas consumption for 3,000 customers during November and December 2007. The approximations were half of the actual usage by the customers. This led to lower bills to the customers during November and December than actual usage would have produced. When actual readings were made in January 2008, the unbilled usage was included in customer's bills, resulting in higher bills than January usage would have produced. Connecticut's attorney general has stated that CNG violated Connecticut law by erroneously billing customers in January 2008 for the full amount of the underbilling, $1.3 million, rather than pro-rating the amount over a number of months as Connecticut law requires. CNG believes that its practice is in accordance with Connecticut law but cannot predict the outcome of the proceeding.

See Item 1 - Note 7 to our Condensed Consolidated Financial Statements for explanations about the following new accounting standards from the FASB and when they will become effective:

• Statement 141(R) and Statement 160 issued in December 2007, and
• Statement 161 issued in issued in March 2008.

Operating Activities: Significant operating activities that affected cash flows during the three months ended March 31, 2008, included the following:

• A decrease in accounts payable and accrued liabilities that reduced cash by $39 million,
• An increase in receivables that reduced cash by $78 million,
• A reduction in fuel inventories that increased cash $180 million, and
• An increase in taxes accrued that increased cash by $44 million.

The above activities are normal for the first quarter of the year when sales and revenues are high and when inventories of natural gas are being drawn down. We also made a $52 million cash contribution to NYSEG's VEBA, and a $1 million contribution to our pension plans.

Investing Activities: Utility capital spending for the three months ended March 31, 2008, was $99 million. We project utility capital spending of $660 million for 2008, about one-half of which is expected to be paid for with internally-generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates, and transmission investments.

Cash flows from investing activities include proceeds from the sale of auction rate securities, which are recorded as current investments available for sale. We have used auction rate securities in a manner similar to cash equivalents and the amount invested in such securities increased as short-term funds were available. We decreased our investments in auction rate securities by $157 million during the first quarter of 2008, in response to uncertainties in the auction rate securities markets. We replaced those investments with items classified as cash or cash equivalents.

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

We repurchased 275,000 shares of our common stock in January 2008, primarily for grants of restricted stock. We awarded 334,505 shares of our common stock in February 2008, issued out of treasury stock, to certain employees through our Restricted Stock Plan, at a grant date fair value of $25.91 per share of common stock.

NYSEG and RG&E are in the process of restructuring their auction rate portfolios. As part of that effort, NYSEG and RG&E have issued notices of their intent to convert certain series of bonds ($70 million NYSERDA Pollution Control Revenue Bonds, 2004 Series B (NYSEG Project) maturing December 1, 2028, and $50 million NYSERDA Pollution Control Revenue Bonds, 2004 Series B (RG&E Project) maturing May 15, 2032) to fixed rate to maturity. We expect the NYSEG conversion to occur on May 9 and the RG&E conversion to occur later in May 2008.

Earnings per share, basic, for the first quarter of 2008 decreased 6 cents compared to the first quarter of 2007. The major decreases in EPS were:

• 8 cents due to lower electric margins, primarily related to electric commodity programs under which NYSEG and RG&E provide supply, and
• 5 cents due to an increase in average common shares outstanding resulting from the issuance of 10 million shares of common stock in 2007.

Those decreases were partially offset by increases in EPS of:

• 3 cents due to higher natural gas margins, primarily resulting from a 2007 rate increase for CNG, and
• 4 cents resulting from a lower estimated annualized effective income tax rate for 2008.

Comparisons of energy deliveries and electricity commodity sales for the three months ended March 31, 2008 and 2007, are shown below.

Several factors influence the volume of energy deliveries, but the major factor is weather. Temperatures in the first quarter of 2008 were slightly warmer than in 2007. The effects of warmer or colder winter weather are especially significant to the demand for natural gas by our residential and commercial customers. Comparative weather data is shown in the following table.

Based on the number of heating degree days, weather for the first quarter of 2008 was slightly warmer than for the same period in 2007, and slightly warmer than normal for the period.

Operating Revenues: The $67 million decrease in operating revenues for the first quarter of 2008 was primarily the result of:

• A decrease of $34 million in average delivery prices,
• A decrease of $30 million in wholesale revenues, reflecting a 32% decline in wholesale volume,
• A decrease of $6 million resulting from lower average prices for electricity sold under supply service programs in New York,
• A decrease of $7 million resulting from a net decline in commodity sales under NYSEG's and RG&E's commodity supply programs, and
• A decrease of $3 million resulting from lower residential and commercial deliveries.

Those decreases were partially offset by:

• An increase of $8 million resulting from higher accruals for recovery of NBC and stranded costs, and
• An increase of $5 million resulting from higher earnings sharing accruals, which are included in other revenues.

Operating Expenses: The $50 million decrease in operating expenses for the first quarter of 2008 was primarily the result of:

• A decrease of $46 million due to lower electricity purchased, including $5 million as a result of the expiration of a major NUG contract in 2007,
• A decrease of $6 million because of lower amortization of regulatory assets,
• A decrease of $4 million resulting from lower stock option expenses, and
• A decrease of $3 million in various operating and maintenance costs.

Those decreases were partially offset by:

• An increase of $3 million in other taxes, primarily resulting from an NYPSC-mandated change in the Power for Jobs tax credit,
• An increase of $3 million resulting from increased storm costs, and
• An increase of $3 million in bad debt expenses.

Operating Revenues: The $15 million increase in operating revenues for the first quarter of 2008 was primarily the result of:

• An increase of $10 million from higher base rates for CNG effective April 1, 2007,
• An increase of $17 million resulting from higher market prices for natural gas,
• An increase of $5 million due to higher weather normalization accruals,
• An increase of $4 million in transportation revenues, primarily as a result of more retail customers taking supply from other providers,
• An increase of $2 million resulting from higher wholesale sales, and
• An increase of $12 million in other revenues, primarily due to increased accruals to offset lower margins.

Those increases were partially offset by:

• A decrease of $34 million resulting from a 6% decline in retail deliveries, excluding transportation, primarily due to warmer weather this quarter.

Operating Expenses: The $8 million increase in operating expenses for the first quarter of 2008 was primarily the result of:

• An increase of $31 million in natural gas purchases resulting from higher market prices,
• An increase of $3 million in natural gas purchases due to an increase in wholesale sales, and
• An increase of $5 million due to higher bad debt reserves.

Those increases were partially offset by:

• A decrease of $30 million in natural gas purchases due to lower retail delivery volumes.

Operating Revenues: The $5 million increase in operating revenues for the first quarter of 2008 was primarily the result of:

• An increase of $6 million due to higher electricity sales as a result of adding new customers, and
• An increase of $3 million due to higher electricity prices.

Those increases were partially offset by:

• A decrease of $3 million due to lower natural gas volumes because of warmer weather this quarter and attrition of some large commercial customers.

Operating Expenses: The $5 million increase in operating expense for the first quarter of 2008 was primarily the result of:

• An increase of $6 million in electricity purchased as a result of higher sales,
• An increase of $3 million in electricity purchased due to higher prices, and
• An increase of $1 million in other operating expenses due to increased billing and collection costs.

Those increases were partially offset by:

• A decrease of $3 million in natural gas purchased due to warmer weather and attrition of some large commercial customers, and
• A decrease of $2 million in natural gas purchased due to lower market prices.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk
(See our report on Form 10-K for the fiscal year ended December 31, 2007, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

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

As of April 2008 the expected load for NYSEG's fixed rate option customers is 84% hedged for May through December 2008. A fluctuation of $1.00 per MWh in the average price of electricity would change NYSEG's earnings less than $200 thousand for May through December 2008. RG&E expects to meet its fixed price load obligations for 2008 with owned generation or long-term supply contracts. The estimated percentage of NYSEG's hedged load and RG&E's expectation that it can meet load requirements with current resources are 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 also uses electricity contracts to manage fluctuations in prices for electricity in order to provide price stability to customers served under the variable price option. NYSEG includes the cost or benefit of those contracts 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 electricity hedge contracts for variable rate customers as regulatory assets or regulatory liabilities.

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. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts as regulatory assets or regulatory liabilities.

Energetix and NYSEG Solutions, Inc. offer retail electric and natural gas service to customers in New York state and actively hedge the load required to serve customers that have chosen them as their commodity supplier. As of April 2008 the energy marketing subsidiaries' expected fixed price loads were 92% hedged for May through December 2008. A fluctuation of $1.00 per MWh in the average price of electricity would change their earnings less than $135,000 for May through December 2008. 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. NYSEG and RG&E are currently in the process of restructuring their auction rate debt portfolios to reduce exposure to variable rate debt.

We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of default on or termination of any one contract. Our obligation to return cash collateral under master netting arrangements was $8 million at March 31, 2008, and $7 million at December 31, 2007.

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.