OR

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: Not applicable

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

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.

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 Act).

The aggregate market value of the common stock held by nonaffiliates of Energy East Corporation as of June 30, 2007, the last business day of Energy East's most recently completed second fiscal quarter, was $4.1 billion, based on the closing sale price as reported on the New York Stock Exchange.

The number of shares of common stock (Par value $.01 per share) outstanding as of February 15, 2008,
was 158,302,145.

DOCUMENTS INCORPORATED BY REFERENCE

Abbreviations for the Energy East companies mentioned in this report:

ii

Abbreviations or acronyms frequently used in this report:

iii

iv

The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. This Form 10-K 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 Item 1A - Risk Factors and Item 7 - MD&A - Market Risk, and also include, among others:

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

v

The following general developments have occurred in our businesses since January 1, 2007:

See Item 7 - MD&A - Electric Delivery Rate Overview, Electric Delivery Business Developments, Natural Gas Delivery Rate Overview and Natural Gas Delivery Business Developments.

On June 25, 2007, we announced that we had entered into a Merger Agreement with 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. On November 20, 2007, our shareholders approved the Merger Agreement.

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 our common stock will be converted into the right to receive $28.50 per share in cash, without interest. Consummation of the Merger is subject to customary conditions, including the absence of injunctions or restraints imposed by governmental entities, the receipt of required regulatory approvals and the absence of any material adverse event that would reasonably be expected to have a material adverse effect on Energy East.

I-1

For more discussion about the Merger, see Item 7 - MD&A - Recent Developments.

We operate under the authority of the NYPSC in New York, the MPUC in Maine, the DPUC in Connecticut and the MDPU in Massachusetts. We are also subject to regulation by the FERC. The FERC and state utility commissions have authority to regulate and monitor, among other things, various business practices and transactions and intercompany cost allocations of holding company systems such as Energy East.

See Item 8 - Note 14 to our Consolidated Financial Statements.

Our principal business consists of our regulated electricity transmission and distribution operations in upstate New York and Maine and our regulated natural gas transportation, storage and distribution operations in upstate New York, Connecticut, Maine and Massachusetts. We serve approximately two million electricity customers and one million natural gas customers. Our service territories reflect diversified economies, including high-technology firms, insurance, light industry, consumer goods manufacturing, pulp and paper, ship building, colleges and universities, agriculture, fishing and recreational facilities. Our operating revenues derived from regulated electricity sales were 56% in 2007, 58% in 2006 and 56% in 2005. Operating revenues derived from regulated natural gas sales were 34% in 2007, 32% in 2006 and 34% in 2005. No customer accounts for more than 5% of either electric or natural gas revenues.

See Item 7 - MD&A - Electric Delivery Rate Overview, Electric Delivery Business Developments, Natural Gas Delivery Rate Overview and Natural Gas Delivery Business Developments.

Our other businesses include retail energy marketing companies, a nonutility generating company, a FERC-regulated liquefied natural gas peaking plant, a natural gas delivery company, a propane air delivery company, telecommunications assets, a district heating and cooling system, and an energy consulting services company. We include their results of operation, financial condition and cash flows in our Other segment.

I-3

See Item 7 - MD&A - Electric Delivery Rate Overview, Electric Delivery Business Developments and Commodity Price Risk and Item 8 - Note 1 to our Consolidated Financial Statements.

RG&E satisfied the majority of its power requirements for 2007 through purchases under long-term contracts with the New York Power Authority, Constellation Nuclear, LLC, and Ginna Nuclear Power Plant, LLC. A small portion of its requirements was satisfied from its owned generation facilities including coal, natural gas, hydroelectric and peaking. RG&E managed fluctuations in the cost of electricity for its remaining power requirements through the use of electricity contracts, both physical and financial.

RG&E's 2008 coal requirements are expected to be approximately 114,000 tons and represents use by Russell Station until its planned closure in the second quarter of 2008 upon completion of RG&E's transmission project. RG&E's coal supply portfolio contains both spot and term agreements with multiple suppliers. In 2007, 73% of RG&E's coal requirements were purchased under contract and 27% was purchased on the spot market. RG&E maintains a reserve supply of coal ranging from 30 to 60 days.

Under a Maine state law, CMP was mandated to sell its generation assets and relinquish its supply responsibility. CMP no longer owns generating assets but retains its power entitlements under long-term contracts with NUGs and a power purchase contract with Entergy Nuclear Vermont Yankee, LLC. CMP sells its power entitlements under auctions approved by the MPUC. By its orders issued in December 2005, January 2007 and January 2008, the MPUC approved CMP's sale of its entitlements for various periods ranging from one to three years, through February 28, 2010. CMP's retail electricity prices are set to provide recovery of the costs associated with its ongoing power entitlement obligations, net of the revenue received under its entitlement sales. CMP's revenues and purchased power costs would increase if it were required to be the standard-offer provider of electricity supply for retail customers. There would be no effect on CMP's net income in such an event, however, because CMP is ensured cost recovery through Maine state law for any standard-offer obligations.

NYSEG, RG&E, CNG, SCG, Berkshire Gas and MNG satisfied their 2007 natural gas supply requirements through purchases from large natural gas producers and other natural gas suppliers, natural gas storage capacity contracts and winter peaking supplies and resources. A majority of the natural gas supply purchased was acquired under long- and short-term supply contracts and the remainder was acquired on the spot market. The operating companies used long-term contracts for firm underground natural gas storage capacity. Firm transportation capacity was acquired under long-term contracts and was utilized to transport both natural gas supply purchased and natural gas withdrawn from storage to local distribution systems. Winter peaking supplies and resources are either owned by Energy East's operating companies or are contracted for under long-term arrangements.

I-4

See Item 7 - MD&A - Natural Gas Delivery Rate Overview, Natural Gas Delivery Business Developments and Commodity Price Risk and Item 8 - Note 1 to our Consolidated Financial Statements.

Our operating utilities have valid franchises, with minor exceptions, from the municipalities in which they render service to the public.

Winter peak electricity loads are primarily due to space heating usage and fewer daylight hours. Summer peak electricity loads are due to the use of air-conditioning and other cooling equipment. Our sales of natural gas are highest during the winter months primarily due to space heating usage.

Our operating utilities have been granted, through the ratemaking process, an allowance for working capital to operate their ongoing electric and/or natural gas utility systems. Their major working capital requirements include natural gas inventories, which increase during the summer and fall for winter sales; accounts receivable, which are highest during periods of peak sales; and cash requirements to pay for utility construction and operating expenses.

In New York, the NYPSC has implemented policies that require utilities to actively encourage customers to migrate to ESCO suppliers. NYSEG and RG&E filed proposed ESCO referral program parameters and draft tariffs pursuant to their respective rate cases. To date the NYPSC has not acted on those filings. NYSEG is currently participating in collaborative discussions pursuant to its Supply Service Joint Proposal to develop an ESCO introduction program targeting new small customers that seek to initiate service. If parties reach consensus on a program that is ultimately approved by the NYPSC, the ESCO introduction program would replace the NYSEG ESCO referral program pending before the NYPSC. NYSEG and RG&E are unable to predict the ultimate effect of the programs on their ability to continue to provide commodity service to their customers.

See Item 1A - Risk Factors and Item 7 - MD&A - Electric Delivery Rate Overview, Electric Delivery Business Developments, Natural Gas Delivery Rate Overview, Natural Gas Delivery Business Developments and Critical Accounting Policies.

Our consolidated expenditures for research and development were $5 million in 2007 and 2006, and $4 million in 2005. Expenditures were for internal research programs and contributions to research administered by the NYSERDA, the Electric Power Research Institute, the Gas Technology Institute and the Northeast Gas Association. Research and development expenditures are intended to improve existing energy technologies and develop new technologies for the delivery and efficient customer use of energy.

I-5

We are subject to regulation by federal, state and local governmental entities with respect to environmental matters, such as the handling and disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. Electric utility companies generally use or generate a range of potentially hazardous products and by-products that are subject to such regulation. They are also subject to state laws requiring environmental approval and certification of proposed major transmission facilities.

From time to time, environmental laws, regulations and compliance programs may require changes in our operations and facilities and may increase the cost of energy delivery service. Historically, rate recovery has been authorized for environmental compliance costs.

We made capital expenditures totaling approximately $8 million to meet environmental requirements during the three years ended December 31, 2007. Future capital additions for current facilities to meet environmental requirements are not expected to be material. However, we have plans to voluntarily adopt a number of environmentally friendly initiatives, including an AMI. We would also have significant expenditures if we repower Russell Station using natural gas.

Water and air quality: We are required to comply with federal and state water quality statutes and regulations, including the Clean Water Act. The Clean Water Act requires that generating stations be in compliance with federally issued National Pollutant Discharge Elimination System permits or state issued SPDES permits, which reflect water quality considerations for the protection of the environment. RG&E has SPDES permits for two of its generating stations. The Energy Network owns interests in two natural gas-fired peaking generating stations and TEN Cos. Owns and operates two steam plants, all of which have the required federal or state operating permits.

We are required to comply with federal and state oil spill statutes and regulations including the Spill Prevention Control and Countermeasures (SPCC) regulations. Revisions to such regulations were recently finalized and require that we update current oil SPCC plans by July 1, 2009, and prepare new SPCC plans for locations that are covered under the regulations. The SPCC locations include electric operation service centers and substations, natural gas operation centers, liquefied natural gas facilities, Russell Station, Allegany Station and several RG&E and NYSEG hydroelectric generating stations.

We are required to comply with federal and state air quality statutes and regulations for operation of RG&E's coal-fired and combustion turbine generating stations. All of RG&E's generating stations have the required federal or state operating permits. Stack tests and continuous emissions monitoring indicate that the generating stations are generally in compliance with permit emission limitations, although occasional opacity exceedances occur. Efforts continue in the identification and elimination of the causes of opacity exceedances. Russell Station, RG&E's sole coal-fired station, is scheduled to close in the second quarter of 2008 upon the completion of RG&E's transmission project, which will substantially reduce our emissions. RG&E is currently preparing applications for regulatory approvals to repower Russell Station using natural gas.

The 1990 Clean Air Act Amendments limit emissions of sulfur dioxide and nitrogen oxides and require emissions monitoring. The EPA allocates annual emissions allowances to RG&E's coal-fired generating station based on statutory emissions limits under Phase II (which began January 1, 2000) of the 1990 Amendments. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide.

I-6

A similar allowance program under Title I of the 1990 Amendments regulates nitrogen oxides emissions from RG&E's coal-fired station and a combustion turbine generating station. Another requirement of the 1990 Amendments is for the coal-fired station and a combustion turbine generating station to have a facility operating permit (Title V permit). The Title V permits required for each station have been granted.

In 2005 the EPA finalized rules requiring further reductions in sulfur dioxide and nitrogen oxides emissions, as well as mercury emissions from coal-fired generating stations. Methods to achieve the reductions will be proposed by the individually affected states. New York has submitted its mercury emissions control implementation plan to the EPA for approval. The first phase of New York's plan is scheduled to take effect in 2010. New York also has adopted and submitted a nitrogen oxides and sulfur dioxide emissions control implementation plan to the EPA for approval. The reductions for the first phase will begin in 2009 for nitrogen oxides and 2010 for sulfur dioxide, and the second phase for both pollutants will begin in 2015.

Regulations adopted by the state of New York that further limit acid rain precursor emissions from electric generating units, at an additional cost to us, became effective on October 1, 2004, for nitrogen oxides and January 1, 2005, for sulfur dioxide. The current federal summertime limits for nitrogen oxides are now applied year round. Emissions reduction targets are set at 50% below the current federal limits for sulfur dioxide and are being phased in between 2005 and 2008. Emissions reductions will be achieved through a New York state only market-based allowance trading system similar to those under the 1990 Amendments.

RG&E purchases emissions allowances as necessary in order to comply with the Clean Air Act and New York state acid rain regulations and estimates its cost for allowances will be less than $1 million for 2008. In addition, RG&E has installed control equipment at its facilities at a cost of over $16 million as part of its compliance with the Clean Air Act.

A Regional Greenhouse Gas Initiative (RGGI) will set a cap on carbon dioxide emissions, from electric generators having a capacity of 25 megawatts or greater, at current emission levels starting in 2009, decreasing to 10% below the 2009 cap levels incrementally from 2015 to 2018. Seven northeastern states signed a memorandum of understanding concerning the RGGI in December 2005. A model rule for states to implement the RGGI was finalized in August 2006. Although the model rule specifies that at least 25% of carbon dioxide allowances or carbon credits are to be auctioned for consumer benefit or a strategic energy program, distribution of the remaining 75% is left up to the individual states.

New York has issued a draft of its RGGI rule that generally follows the model rule. One aspect of the rule is New York's proposal to auction 100% of allowances, with the proceeds to be used for "energy efficiency and clean energy technology purposes." Electricity generators would be required to purchase necessary allowances to continue operations and there would be an increase in the cost of the electricity produced by those generators. The final New York rule is expected by the second quarter of 2008.

I-7

In December 2007 the Maine Board of Environmental Protection (MBEP) adopted implementing regulations based on the model RGGI rule. Regulations require specific reductions and allowance purchases by affected emission sources in Maine and establish a framework for allowance trading and purchasing carbon dioxide offsets from eligible sources. The Maine regulations specify that all necessary carbon dioxide allowances must be purchased at auction and all auction proceeds will be held and managed by an independent trust. Auction proceeds will be used to fund energy efficiency and carbon dioxide emission reduction programs and to mitigate ratepayer impacts attributable to the trading program. As all allowances will be auctioned, affected electricity generators will be required to purchase necessary allowances to continue operations and there will likely be a corresponding increase in the cost of electricity produced by those generators and charged to electricity customers. We cannot predict the ultimate effect of this program on the price of electricity in Maine.

See Item 3 - Legal Proceedings, Item 7 - MD&A - Electric Delivery Rate Overview, Electric Delivery Business Developments, Natural Gas Delivery Rate Overview, Natural Gas Delivery Business Developments and Item 8 - Note 9 to our Consolidated Financial Statements.

As of January 31, 2008, we had 5,837 employees.

We have no foreign operations.

We make available free of charge through our Internet Web site, http://www.energyeast.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, as soon as reasonably practicable after those reports are electronically filed with the SEC. Access to the reports is available from the main page of our Internet Web site through "Financial Information" and then "SEC filings." Our Code of Conduct and Corporate Governance Guidelines and the charters of the Audit, Compensation and Management Succession, and Nominating and Corporate Governance committees are also available on our Internet Web site. Waivers of the Code of Conduct are not contemplated. However, in the unlikely event of an amendment to, or waiver from, the Code of Conduct applicable to our principal executive, financial and accounting officers, we will post such information through our Web site. Access to these documents is available from the main page of our Internet Web site through "Financial Information" and then "Corporate Governance." Printed copies of these documents are also available upon request by contacting Investor Relations at (207) 688-4386.

We regularly identify, monitor and assess our exposure to risk and seek to mitigate the risks inherent in our energy services and delivery businesses. However, there are risks that are beyond our control or that cannot be limited cost-effectively or that may occur despite our risk mitigation efforts. The risk factors discussed below could have a material effect on our financial position, results of operation or cash flows.

I-8

Consummation of the proposed Merger is subject to satisfaction of various closing conditions, including obtaining the approvals or consents from a number of United States federal and state public utility, antitrust and other regulatory authorities described in the Merger Agreement. To date, all regulatory approvals have been received except approval from the NYPSC. The NYPSC staff has taken the its position that the Merger does not satisfy the standard under the New York Public Service Law for approval. We cannot predict whether NYPSC authorization will be obtained on satisfactory terms or the timing of that approval. If the Merger is not completed and the Merger Agreement is terminated, the market price of our common stock may decline to the extent that the current market price of our shares reflects an assumption as to the completion of the Merger. While the Merger is pending, we have agreed to operate our businesses in the ordinary course and certain significant business actions or changes from our ordinary course would require the consent of Iberdrola. In addition, until consummation (or termination) of the Merger, we are prohibited from declaring and paying dividends in excess of the current dividend rate of $0.31 per share per quarter.

On the federal level, the FERC regulates our utilities' transmission rates, affiliate transactions, the issuance of certain short-term debt securities by our electric utilities and certain other aspects of our utilities' businesses. State commissions regulate the rates, terms and conditions of service, various business practices and transactions, financings, and transactions between the utilities and affiliates. Local regulation affects the siting of our transmission and distribution facilities and our ability to make repairs to such facilities. Our allowed rates of return, rate structures, operation and construction of facilities, rates of depreciation and amortization, and recovery of costs (including exogenous costs such as storm-related expenses), are all determined by the regulatory process. The timing and adequacy of regulatory relief directly affect our results of operation and cash flows. Furthermore, compliance with regulatory requirements may result in substantial costs in our operations that may not be recovered. We cannot predict the effect that any future changes or revisions to laws and regulations affecting the utility industry may have on our financial position, results of operation or cash flows.

We are a holding company whose material assets are the stock of our subsidiaries.

Accordingly, we conduct all of our operations through those subsidiaries. Our ability to pay dividends on our common stock and to pay principal and accrued interest on our debt depends upon our receipt of dividends from our principal subsidiaries. Payments to us by those subsidiaries depend, in turn, upon their results of operation and cash flows, which are subject to the risk factors discussed in this section. The ability of our subsidiaries to make payments to us is also affected by the level of their indebtedness, and the restrictions on payments to us imposed under the terms of such indebtedness.

Our natural gas companies may be affected by various factors that could limit their ability to obtain natural gas supplies.

Supply and demand factors including hurricanes or other natural disasters could affect our future ability to obtain natural gas supplies. Increases in demand and lower supplies can result in higher natural gas prices. While higher costs are generally passed on to customers pursuant to natural gas adjustment clauses, and therefore do not pose a direct risk to our earnings, we are unable to predict what effect increases in natural gas prices may have on our customers' energy consumption or ability to pay.

I-9

Our electric utility companies have substantial transmission capital investment programs including proposed transmission projects in Maine that could require investment in excess of $1 billion. The transmission projects are expected to increase reliability, meet new load growth requirements and interconnect with new generation, including renewable generation. The regulatory approval process for transmission projects is extensive and we may not be able to obtain the approvals required for these projects. Various factors beyond our control, including an increase in the cost of materials or labor, may increase the cost of completing construction projects and may delay construction.

Our new transmission projects are subject to the effects of new legislation, regulation and regional interpretations of applicable laws and regulations. Any changes to those laws and regulations may increase the costs or timing of our transmission projects.

The FERC has jurisdiction over transmission expansion and generation interconnection. The FERC has issued several orders regarding transmission expansion and generation interconnection cost allocation. Changes to the rules and regulations concerning transmission expansion and generation cost allocations may affect our future transmission rates.

RTOs and independent system operators now oversee wholesale transmission services in NYSEG's, RG&E's, and CMP's service territories and between regions. Our transmission facilities are operated by and subject to the rules and regulations of the NYISO and ISO-NE. Changes to those rules and regulations could cause us to incur additional expenses to maintain our facilities.

Third party facilities include independent system operators, electric generators from whom we purchase electricity, and natural gas pipeline operators from whom we receive shipments of natural gas. The loss of use or destruction of our facilities or the facilities of third parties that are used in providing our services, or with which our electric or natural gas facilities are interconnected, due to extreme weather conditions, breakdowns, war, acts of terrorism or other occurrences, could greatly reduce potential earnings and cash flows and increase our costs of repairs and/or replacement of assets. While we carry property insurance to protect certain assets and have regulatory agreements that provide for the recovery of losses for such incidents, our losses may not be fully recoverable through insurance or customer rates.

The demand for our services is directly affected by weather conditions.

The demand for our services, especially our natural gas delivery service, is directly affected by weather conditions. Milder winter months or cooler summer months could greatly reduce our earnings and cash flows. Loss of revenue due to power outages in severe weather could also reduce our earnings or require us to defer some costs for future recovery, thus reducing our cash flow. While our natural gas distribution companies mitigate the risk of warmer winter weather through weather normalization clauses or weather insurance, and we have historically been able to defer major storm costs for future recovery, we may not always be able to fully recover all lost revenues or increased expenses.

I-10

We could recognize financial losses as a result of volatility in the market values of those contracts. We also bear the risk of a counterparty failing to perform. While we employ prudent credit policies and obtain collateral where appropriate, counterparty credit exposure cannot be eliminated, particularly in volatile energy markets.

Our ability to hedge our commodity market risk depends on our ability to accurately forecast demand in future periods. Because of changes in weather and customer demand from period to period, we may hedge amounts that are greater or less than our actual commodity deliveries. Such differences may lead to financial gains or losses and, if the differences exceed certain levels, could result in our hedges becoming ineffective under accounting guidance. Gains or losses on ineffective hedges are marked-to-market on our income statement without reference to our underlying sale of the commodity.

Prices for electricity and natural gas are subject to volatility in response to changes in supply and other market conditions.

We pass commodity price increases on to electricity customers who receive default or variable price supply service and to all natural gas customers. We have a comprehensive hedging program in place to mitigate the price risk for the load requirements of electricity customers who choose a fixed price option under NYSEG's and RG&E's current commodity option programs. Higher prices that are passed on to customers can lead to higher bad debt expense and customer conservation resulting in reduced demand.

Our pension plan assets are primarily made up of equity and fixed income investments.

Any fluctuations in the performance of those markets, as well as changes in interest rates, could increase our funding requirements for pension and postretirement benefit obligations and cause us to recognize increased expense. In addition, the cost to implement regulatory requirements and potential revisions to accounting standards could affect our financial position, results of operation or cash flow.

A falling, slow or sluggish economy and reduced demand for electricity and/or natural gas in the areas in which we do business - through forced temporary plant shutdowns, closing operations or slow economic growth - would reduce our earnings potential.

Our subsidiaries' operations are subject to extensive federal, state and local environmental laws, rules and regulations that monitor, among other things, emission allowances, pollution controls, maintenance, site remediation, equipment upgrades and management of hazardous waste. Various governmental agencies require us to obtain environmental licenses, permits, inspections and approvals. Compliance with environmental laws and requirements could impose significant costs, reduce cash flows and result in plant shutdowns.

I-11

If any of our utility subsidiaries' credit ratings were downgraded, our ability to access the capital markets, including the commercial paper markets, could be adversely affected and our borrowing costs would increase. Some factors that affect credit ratings are cash flows, liquidity and the amount of debt as a component of total capitalization. A scenario that could cause a subsidiary's debt as a component of total capitalization to increase would be the need to borrow money to pay for unexpected repairs to its transmission and/or distribution systems due to a catastrophic event.

The application of our critical accounting policies reflects complex judgments and estimates.

Those policies include industry-specific accounting standards applicable to our rate-regulated utilities, accounting for goodwill, pension and other postretirement benefit plans, unbilled revenue and allowance for doubtful accounts. The adoption of new accounting standards, changes to current accounting standards or interpretations of such standards may materially affect our financial position, results of operation or cash flows.

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 earnings sharing mechanism (ESM) in NYSEG's electric rate plan that was in effect from 2002 through 2006. The staff claimed that its preliminary analysis shows an additional $67 million, including interest, should have been allocated to customers. The staff indicated that its analysis would be completed no later than NYSEG's next electric rate case. NYSEG vigorously disputes staff's claim. For each year 2002 through 2006 NYSEG made annual compliance filings, as required by the NYPSC. The NYPSC staff has never taken exception to those filings, including during the litigated rate proceeding that resulted in the NYPSC August 2006 rate order. 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.

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 these notes are insured. The investors' source of liquidity on these 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

I-12

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. To date, failed auction rates for NYSEG and RG&E have ranged from 3.3% to 10.5%. These rates are significantly higher than rates paid in previous auctions. Continued and prolonged illiquidity in the auction rate market could significantly increase our interest costs.

We have also invested in auction rate securities. A prolonged disruption in that market could result in a revaluation of those investments, which we have traditionally carried at par because they have been readily convertible to cash. We have reduced our exposure to those securities to $25 million at February 27, 2008, but cannot predict the effect of continued instability in the auction rate market on the valuation of those investments.

None.

NYSEG's electric system includes hydroelectric and gas turbine generating stations, substations and transmission and distribution lines, substantially all of which are located in the state of New York.

RG&E's electric system includes coal-fired, combustion turbine and hydroelectric generating stations, substations and transmission and distribution lines, all of which are located in the state of New York.

CMP's electric system includes substations and transmission and distribution lines, all of which are located in the state of Maine.

The Energy Network owns interests in two natural gas-fired peaking generating stations: one located in the state of New York and operated by Cayuga Energy, a wholly-owned subsidiary; and one located in the state of Pennsylvania for which Cayuga Energy manages fuel procurement and electricity sales.

Our operating companies' generating facilities consist of:

 ⁽¹⁾ Russell Station is scheduled to close in the second quarter of 2008 upon completion of RG&E's transmission project.
 ⁽²⁾ Cayuga Energy's 50.1% share of the generating capability.

CMP owns the following percentages of stock in three companies with previously operating nuclear generating facilities: Maine Yankee Atomic Power Company in Wiscasset, Maine, 38%; Yankee Atomic Electric Company in Rowe, Massachusetts, 9.5%; and Connecticut Yankee Atomic Power

I-13

Company in Haddam, Connecticut, 6%. The three facilities have been permanently shut down. Maine Yankee Atomic Power Company completed its decommissioning in 2005, Yankee Atomic Electric Company completed its decommissioning in 2006 and Connecticut Yankee Atomic Power Company completed its decommissioning in 2007. Each of the three facilities has an established NRC-licensed independent spent fuel storage installation on site to store spent nuclear fuel in dry casks until the DOE takes the fuel for disposal.

CMP owns 311 substations in the state of Maine having an aggregate transformer capacity of 6,862,205 kilovolt-amperes. The transmission system consists of 2,564 circuit miles of line. The distribution system consists of 22,140 pole miles of overhead lines and 1,324 miles of direct bury and network underground lines.

NYSEG owns 441 substations in the state of New York having an aggregate transformer capacity of 15,288,450 kilovolt-amperes. The transmission system consists of 4,400 circuit miles of line. The distribution system consists of 30,576 pole miles of overhead lines and 2,122 miles of direct bury and network underground lines.

RG&E owns 165 substations in the state of New York having an aggregate transformer capacity of 6,900,400 kilovolt-amperes. The transmission system consists of 763 circuit miles of overhead lines and 502 circuit miles of underground lines. The distribution system consists of 17,258 circuit miles of overhead lines and 5,274 circuit miles of underground lines.

Our operating utilities' natural gas systems consist of:

NYSEG owns the Seneca Lake Natural Gas Storage Facility, which is able to store approximately 1.4 billion cubic feet of natural gas. It is a high-deliverability storage facility that can be filled to capacity in 20 days and fully withdrawn in 10 days.

A portion of our utility plant is subject to liens or mortgages securing certain of our subsidiaries' first mortgage bonds. None of CMP's, NYSEG's or CNG's utility plant is subject to liens or mortgages securing first mortgage bonds. RG&E, Berkshire Gas and SCG have first mortgage bond indentures that constitute a direct first mortgage lien on substantially all of their respective properties. (See Item 8 - Note 5 to our Consolidated Financial Statements.)

I-14

See Item 7 - MD&A - Electric Delivery Rate Overview, Electric Delivery Business Developments, Natural Gas Delivery Rate Overview and Natural Gas Delivery Business Developments and Item 8 - Note 9 to our Consolidated Financial Statements.

The NYPSC, DPUC, MPUC and MDPU have allowed our operating utilities to recover in rates remediation costs for certain of the sites referred to in the second and fourth paragraphs of Note 9 to our Consolidated Financial Statements, therefore, there is a reasonable basis to conclude that such operating utilities will be permitted to recover in rates any remediation costs that they may incur for all of the sites referred to in those paragraphs. Consequently, we believe that the ultimate disposition of the matters referred to in the paragraphs of the Note referred to above will not have a material adverse effect on our results of operation, financial position or cash flows.

(a) On July 6, 2007, a purported class action complaint was filed in the Supreme Court of the State of New York for Kings County against the company and its directors. The complaint alleges that, among other things, the consideration for the proposed acquisition by Iberdrola is unfair and inadequate because it does not provide the company's stockholders with a sufficient premium for the company's common stock and the defendants have breached their fiduciary duty. The complaint seeks to enjoin the Merger in addition to an unspecified amount of damages. On September 26, 2007, the plaintiff and Energy East and its directors agreed, subject to confirmatory discovery and court approval, to settle the lawsuit. The settlement is based on Energy East's agreement to include certain additional disclosures in its proxy statement. As a result of the settlement, plaintiff will not seek to enjoin the transaction. The settlement, if approved by the court, will result in dismissal with prejudice of the lawsuit. The settlement also will result in a release of claims that have been or could have been asserted relating to the Merger, the Merger Agreement, or any disclosures relating to the Merger by the plaintiff and the purported class of Energy East shareholders. In connection with such settlement, the plaintiff's counsel will apply to the court for attorneys' fees and expenses not to exceed in the aggregate $340,000, which Energy East has agreed to pay, if awarded by the court, provided the court approves the settlement and dismisses the lawsuit with prejudice. Energy East and its directors continue to deny all of the substantive allegations in the complaint.

(b) 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 maintains 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 could be reached. Continued discussions led to a settlement agreement in December 2007 between the NYSDEC, the Attorney General's office and RG&E. To avoid the uncertainties and costs of litigation and to improve the environment, RG&E agreed to pay a $200,000 civil penalty and fund $500,000 for environmentally beneficial projects to be administered by the NYSERDA.

I-15

RG&E also agreed to restrictions on the use and sale of federal sulfur dioxide emission allowances and plans to close Russell Station in the second quarter of 2008 upon completion of RG&E's transmission project. A consent decree was issued accepting the settlement in February 2008.

(c) The state of Connecticut filed suit in February 2007 against Energy East and its affiliates - TEN Companies, CNG and CTG Resources - for an alleged $14 million overcharge for heating and cooling services supplied to state buildings since 1992. Subsequently, the state increased its overcharge claim to $30 million. In January 2008 the state filed a motion for injunctive relief to prevent TEN Companies from exercising its right to allow each of the various heating and cooling contracts to expire on their respective expiration dates, and to require TEN Companies to continue to provide heating and cooling service under the agreements. While we believe that there is no merit to these actions, we cannot predict their outcome.

(d) In January 2008, the trustee in the SGF Chapter 7 bankruptcy proceeding brought adversarial proceedings against NYSEG Solutions, Inc., Carthage Energy, LLC., Cayuga Energy, Inc. and The Energy Network, Inc. seeking repayment of alleged preferential payments made in the one year period preceding the bankruptcy filing to those SGF affiliates in amounts totaling $14 million. We are evaluating the claims and plan to file responsive pleadings by April 1, 2008. We do not believe there is merit to the claims, but cannot predict the outcome of this proceeding.

Energy East's Special Meeting of Stockholders was held on November 20, 2007. The following matter was voted on:

A proposal to adopt the Agreement and Plan of Merger, dated as of June 25, 2007, among Iberdrola, S.A., Green Acquisition Capital, Inc. and Energy East Corporation.

* * * * * * * * * * *

I-16

I-17

Wesley W. von Schack has an employment agreement for a term ending June 30, 2008. Mr. von Schack's agreement provides for his employment as Chairman, President & Chief Executive Officer of the company. The agreement provides for automatic one-year extensions unless either party gives notice that such agreement is not to be extended.

If the Merger becomes effective, Mr. von Schack's employment agreement will be amended to provide for a two-year term from the date the Merger becomes effective, during which term he will continue to serve as the company's Chairman, President & Chief Executive Officer. The term may be extended for an additional one-year period with the consent of Mr. von Schack, Iberdrola and the company.

Robert M. Allessio, Sara J. Burns and F. Michael McClain each have an employment agreement, which is automatically extended each month unless either party to an agreement gives written notice that it is not to be extended. Ms. Burns' agreement provides for her employment as President of CMP and Mr. Allessio's agreement provides for his employment as Chief Executive Officer of Berkshire Gas.

Each officer holds office for the term for which he or she is elected or appointed, and until his or her successor is elected and qualifies. The term of office for each officer extends to and expires at the meeting of the Board of Directors following the next annual meeting of shareholders.

I-18