(1) Represents shares of our common stock (Par Value $.01) purchased in open-market transactions on behalf of our Employees' Stock Purchase Plan.

RG&E had no issuer purchases of equity securities during the quarter ended December 31, 2005.

See the information under the heading Selected Financial Data for each registrant, which is included in this report as follows:

See the information under the heading Management's Discussion and Analysis of Financial Condition and Results of Operations for each registrant, which is included in this report as follows:

See Item 7 - MD&A - Market Risk for each registrant and see the Notes to Financial Statements in Item 8 that are referred to in each registrant's Market Risk disclosure.

Index to 2005 Financial Statements

None for Energy East or RG&E.

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

Energy East Management's Annual Report on Internal Control Over Financial Reporting

Energy East's management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process 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. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, an evaluation was conducted of the effectiveness of the internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by The Committee of Sponsoring Organizations of the Treadway Commission. Based on Energy East's evaluation under the framework in Internal Control - Integrated Framework, management concluded that Energy East's internal control over financial reporting was effective as of December 31, 2005.

There were no changes in Energy East's or RG&E's internal control over financial reporting that occurred during each company's most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the respective company's internal control over financial reporting.

None for Energy East or RG&E.

Energy East's primary operations, our electric and natural gas utility operations, are subject to rate regulation established predominately by state utility commissions. The approved regulatory treatment on various matters significantly affects our financial position, results of operations and cash flows. We have long-term rate plans for NYSEG, RG&E, CMP and Berkshire Gas that currently provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including stranded costs, and provide stable rates for customers and revenue predictability. CNG is currently operating under existing rates from an incentive rate plan that expired in September 2005, with no earnings sharing. SCG received approval for new rates that became effective January 1, 2006. As of January 31, 2006, Energy East had 6,114 employees.

We continue to focus our strategic efforts in the areas that have the greatest effect on customer satisfaction and shareholder value. In doing this, management has implemented a company-wide restructuring effort that focuses on efficiently providing utility support services. In 2004 we formed Utility Shared Services Corporation to consolidate support services functions for our operating utilities.

The continuing uncertainty in the evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings that could significantly affect operations, although their outcomes are difficult to predict. Those proceedings, which are discussed below, could affect the nature of the electric and natural gas utility industries in New York and New England.

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

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

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

Our long-term rate plans continue to be a critical component of our success. While specific provisions may vary among our public utility subsidiaries, our overall strategy includes creating stable rate environments that allow the companies to earn a fair return while minimizing price increases and sharing achieved savings with customers.

The electric industry is regulated by various state and federal agencies, including state utility commissions and the FERC. The following is a brief overview of the principal rate agreements in effect for each of our electric utilities.

Electric Rate Plans: The current NYSEG rate plan was approved by the NYPSC February 2002 Order, which provides for equal sharing of the greater of ROEs in excess of 12.5% on electric delivery, or 15.5% on the total electric business (including commodity earnings that over the term of the rate plan were estimated to be $25 million to $40 million on an annual basis based on future energy prices at the time the plan was approved) for each of the years 2003 through 2006. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio. At December 31, 2005, the equity NYSEG uses for earnings sharing approximates $740 million, which is based on the 45% equity ratio limitation. Earnings levels were sufficient to generate estimated pretax sharing with customers of $22 million in 2005 and $17 million in 2004.

RG&E's current rates were established by the 2004 Electric Rate Agreement, which addresses RG&E's electric rates through 2008. Key features of the Electric Rate Agreement include freezing electric delivery rates through December 2008, except for the implementation of a retail access surcharge effective May 1, 2004, to recover $7 million annually. An ASGA was established that is estimated to be $145 million at the end of 2008 and will be used at that time for rate moderation or other purposes at the discretion of the NYPSC. The Electric Rate Agreement also established an earnings-sharing mechanism to allow customers and shareholders to share equally in earnings above a 12.25% ROE target. Earnings levels were sufficient to generate $23 million of pretax sharing in 2005. There was no sharing in 2004.

NYSEG's and RG&E's current electric rate plans offer their retail customers choice in their electricity supply including a fixed rate option, a variable rate option under which rates vary monthly based on the market price of electricity and an option to purchase electricity supply from an ESCO. RG&E customers make their supply choice annually. NYSEG customers make their election every two years, most recently in late 2004 for the 2005 and 2006 plan years. RG&E customers who do not make a choice are served under RG&E's variable price option. NYSEG customers who do not make a choice are served under the fixed rate option. Both NYSEG's and RG&E's customers also pay nonbypassable wires charges, which include recovery of stranded costs. Approximately 45% of NYSEG's and 75% of RG&E's total electric load is now provided by an ESCO or at the market price.

In March 2000 the NYPSC instituted the Collaborative on End State of Energy Competition proceeding to address the future of competitive electric and natural gas markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets

and providing recommendations concerning provider of last resort and related issues. NYSEG and RG&E believe that the NYPSC should not adopt a single end-state vision for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.

In August 2004 the NYPSC issued a Policy Statement recommending that all potentially competitive utility functions be opened to competition. While it is not possible to determine when markets will become workably competitive, all utilities were required to prepare plans to foster the development of retail energy markets. The plans vary by individual utility and NYSEG and RG&E do not expect the statement of policy to affect their commodity service options under their current electric rate plans, which extend through December 31, 2006, for NYSEG and December 31, 2008, for RG&E.

NYSEG and RG&E filed their retail access plans with the NYPSC on April 14, 2005. As part of its filing, NYSEG proposed to continue offering its current commodity options to customers, with new two-year commodity offerings beginning January 1, 2007, that are the same as its current program except for the addition of a program to facilitate ESCO market participation by allowing NYSEG to bill and collect from ESCO customers directly. In June and July 2005 parties filed comments both in support of and in opposition to NYSEG's and RG&E's retail access plans. NYSEG's proposal is consistent with the commodity options included in its recently filed Electric Rate Plan Extension.

NYSEG and RG&E believe that their current commodity option programs are the most comprehensive in New York State, providing a full menu of electric supply choices, including a fixed price option for customers who do not want to be subjected to volatile wholesale electricity prices. Experience has shown that the vast majority of customers want their utility to remain a supply option and prefer a fixed price option. NYSEG and RG&E believe that their programs are also among the most successful of any retail access plans in New York State in terms of active participation and customer migration. In addition, their programs have produced $100 million in customer benefits through 2005.

CMP's distribution costs are recovered under the ARP 2000, which became effective January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1. CMP's annual delivery rate adjustments are based on inflation with productivity offsets of 2.75% in 2005 and 2006 and 2.9% in 2007. Price adjustments have resulted in rate decreases in each year that the agreement has been in effect since 2002.

CMP uses formula rates for transmission that are FERC regulated. The formula rates provide for the recovery of CMP's cost of owning, operating and maintaining its local and regional transmission facilities and local control center, including a FERC-recommended base level ROE of 10.72%, plus a 50 basis point adder for regional facilities. The formula rates are updated annually in a filing to the FERC on June 1st. CMP's transmission rates increased approximately $15 million for the year effective July 1, 2005. The increase enables CMP to recover its share of ISO New England regional transmission costs and its local transmission costs.

Pursuant to Maine statutes, CMP recovers the above-market costs of its purchased power agreements, as well as costs incurred to decommission and dismantle the nuclear facilities in which CMP has an ownership share, through its stranded cost rates. In January 2005 the MPUC approved new stranded cost rates for the three-year period ending February 2008. Any difference between actual and projected stranded costs is deferred for future refund or recovery. CMP is prohibited by state law from providing commodity service to its customers.

NYSEG Electric Rate Plan Extension: On September 30, 2005, NYSEG filed a six-year Electric Rate Plan Extension with the NYPSC, to commence on January 1, 2007, which is the day after the end of its current rate plan. As part of its filing, NYSEG proposed to decrease customers' bills prior to the commencement of the Electric Rate Plan Extension by implementing a bill credit to customers effective for the four-month period from September 1, 2006 through December 31, 2006. In particular, NYSEG proposed to return to its electric customers $23.7 million from its ASGA, which was initially created as a result of the sale of NYSEG's generating stations. The ASGA has been enhanced during NYSEG's current rate plan with the customers' share of excess earnings. Beginning on January 1, 2007, NYSEG also proposed to reduce its nonbypassable wires charge by $162.8 million and increase delivery rates by $91.6 million, thus maintaining an annualized overall electricity delivery rate decrease of approximately $71.2 million, or 9.5%. NYSEG proposed to accomplish the reduction in the nonbypassable wires charge, which would more than offset the increase in delivery rates, by accelerating benefits from the expiration of certain above-market NUG contracts and capping the amount of above-market NUG costs over the term of the rate plan extension, also known as NYSEG's NUG levelization proposal. NYSEG also proposed to increase its equity ratio from 45% to 50%. In addition, NYSEG's proposal would allow customers to continue to benefit from merger synergies and savings.

On October 28, 2005, NYSEG filed a motion with the NYPSC asking that the chairman of the NYPSC recuse himself from any consideration of NYSEG's Electric Rate Plan Extension filing and of NYSEG's proposed Retail Access Plan filed in April 2005. The motion maintained that the chairman's recusal is necessary because his public statements demonstrate that he is biased against NYSEG and its Voice Your Choice program, in violation of NYSEG's due process rights for a fair and impartial adjudication. The chairman denied the motion on December 7, 2005.

On January 9, 2006, NYSEG filed with the NYPSC revisions and updates to its September 30, 2005 filing. By this filing, NYSEG proposed to further reduce its nonbypassable wires charge by an additional $5 million for a total reduction of $167.8 million, and proposed to further increase its delivery rates by an additional $12 million for a total increase of $103.6 million. As a result of these revisions and updates, NYSEG's proposed annualized overall electricity delivery rate decrease was reduced by $7 million, to $64.2 million, or 8.6%. These revisions and updates did not change the overall framework of NYSEG's Electric Rate Plan Extension proposal.

On January 16, 2006, two ESCOs submitted a motion to the ALJ to dismiss the portion of NYSEG's rate filing requesting NYPSC approval of the commodity option program. The Consumer Protection Board and the Public Utility Law Project opposed that motion in their responses filed with the NYPSC on January 19 and 30, 2006, respectively. NYSEG filed its

opposition to the motion with the NYPSC on January 25, 2006. NYSEG stated in its filing that the motion is not supported by law, would deny NYSEG due process, including an evidentiary hearing, and distorts the evidence presented by NYSEG regarding the Voice Your Choice program. The ALJ denied the ESCOs' motion in a Ruling issued on February 10, 2006. In the Ruling, the ALJ concluded that the NYPSC's August 2004 Policy Statement was not intended as a binding order and, as a matter of law, does not preclude NYSEG's proposal to extend its Voice Your Choice program. The ALJ also determined that NYSEG's Electric Rate Plan Extension proceeding is the proper forum for consideration of issues presented by NYSEG's proposal to extend its Voice Your Choice program.

In early February 2006, Staff of the NYPSC (Staff) and six other parties submitted their direct cases. Staff presented a one-year rate case only. In its presentation, Staff proposed an overall delivery rate decrease of approximately $82.8 million, or about 13.4%, for the 2007 rate year. Staff neither rebutted nor addressed NYSEG's six-year rate plan extension proposal, including NYSEG's NUG levelization proposal. Staff also opposed NYSEG's proposal to extend its Voice Your Choice program.

NYSEG filed its rebuttal case on February 21, 2006, responding to Staff's one-year rate case proposal by proposing to increase delivery rates commencing January 1, 2007, by approximately $58.3 million, which would be offset by an equal amortization of the ASGA back to customers. NYSEG also proposed to amortize an equivalent portion of the ASGA liability through a bill credit in the nonbypassable wires charge to offset the delivery increase, resulting in no change in 2007. Although NYSEG's rebuttal testimony responds to Staff's one-year rate case proposal, NYSEG continues to support the adoption of a six-year rate plan extension proposal, including its NUG levelization proposal to moderate the delivery rate increase and its proposal to extend the Voice Your Choice program.

Hearings are scheduled to commence on March 22, 2006. NYSEG cannot predict the outcome of this proceeding.

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 following the shutdown of RG&E's 257 MW coal-fired Russell Station, which is expected to occur in 2007. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, New York area. In August 2005 RG&E selected the team of EPRO Engineering, E.S. Boulos and O'Connell Electric Company for the project. Construction on the project is expected to begin in the first quarter of 2006. The estimated cost of the project is approximately $110 million.

Niagara Power Project Relicensing: The NYPA's FERC license with respect to the Niagara Power Project expires on August 31, 2007. In order to continue operating the Niagara Power Project, the NYPA filed a relicensing application in August 2005. The NYPA's relicensing process is important to NYSEG's and RG&E's customers because the companies are allocated an aggregate of over 360 MWs of Niagara Power Project power based on their contracts with the NYPA. (NYSEG and RG&E also receive allocations from the St. Lawrence Project pursuant to those same contracts.) The contracts expire on August 31, 2007, upon termination of the NYPA's license. The annual value of the Niagara allocation to the companies

at current electricity market prices, is approximately $100 million and the loss of the allocation would increase NYSEG's and RG&E's residential customer rates. However, the NYPA has stated that the allocation of Niagara power to NYSEG and RG&E should not be addressed in the relicensing proceeding and that the disposition of the power will be in accordance with state and federal requirements.

NYSEG and RG&E filed a motion to intervene in the relicensing proceeding on November 3, 2005, and on December 16, 2005, NYSEG and RG&E submitted comments arguing that the FERC should: (1) consider power allocation issues (including to NYSEG and RG&E) in its review of the application; (2) require the NYPA to update the record with information concerning the benefits of the allocation to NYSEG and RG&E customers; and (3) require the NYPA to meet with NYSEG and RG&E to discuss their allocations and the effects of withdrawal of the allocations on their customers. On January 3, 2006, the NYPA filed an answer arguing that certain issues raised in our comments should be ignored by the FERC and that allocation issues are not an appropriate question in the relicensing proceeding. On January 10, 2006, NYSEG and RG&E filed a response to NYPA's answer. We are unable to predict the outcome of this proceeding.

CMP Alternative Rate Plan: On December 7, 2005, CMP and the Office of the Public Advocate filed with the MPUC a stipulation for an extension of CMP's ARP 2000. This stipulation is also supported by low-income customer advocates and a coalition of industrial energy customers has signed the stipulation agreement. The stipulation maintains the provisions of CMP's ARP 2000 and proposes a three-year extension with four additional items. The stipulation provides for a 0.5% increase in the scheduled productivity offset for July 2006 and provides for productivity offsets averaging 2% for 2008, 2009 and 2010. The stipulation adds $2.2 million in assistance for low income customers annually starting in 2006. Under the stipulation, CMP agrees to educate its customers on the regional benefits of adjusting usage during peak hours and demand periods and also agrees to limit the promotion of increased usage during specified higher demand periods. Finally, CMP agrees to commit to investing an additional $25 million through 2010 for enhancements to the reliability, safety and security of its distribution system.

On February 1, 2006, the MPUC approved that portion of the stipulation increasing assistance to low income customers. The MPUC has established a schedule to review the remaining terms of the stipulation, and its decision is expected in the second quarter of 2006. CMP cannot predict the outcome of this proceeding.

CMP Electricity Supply Responsibility: Under Maine statutes, CMP's customers can choose to arrange for competitive energy supply or take default supply under standard-offer service as arranged by the MPUC. The MPUC conducts periodic supply solicitations for standard-offer service by customer class. If the MPUC does not accept any competitive supply bid for a standard offer arrangement, the MPUC can mandate that CMP be a standard-offer provider of electricity supply service for retail customers and CMP would recover all costs of such an arrangement in rates. As of January 2006, the MPUC has approved standard-offer service arrangements for all of CMP's customer classes through competitive solicitation. The supply prices and terms of the arrangements vary by class, including a laddered three-year arrangement for residential and small commercial customers that solicits one-third of the supply each year and a six-month arrangement for medium and large commercial and industrial customers.

CMP Nuclear Costs: CMP owns shares of stock in three companies that own nuclear generating facilities in New England that have been permanently shut down, and are decommissioned or in process of being decommissioned: Maine Yankee Atomic Power Company (38% ownership), Connecticut Yankee Atomic Power Company (6% ownership) and Yankee Atomic Electric Power Company (9.5% ownership). 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. The Yankee companies commenced litigation in 1998 charging that the federal government had breached the contracts it entered into with each of the Yankee companies in 1983 for spent nuclear fuel disposal. The contracts provided for the federal government to begin removing spent nuclear fuel from the Yankee companies, no later than January 31, 1998, in return for payments by each of the Yankee companies. Two federal courts found that the federal government breached its contracts with the Yankee companies and other utilities. A trial in the U.S. Court of Federal Claims to determine the monetary damages owed to the Yankee companies for the DOE's continued failure to remove spent nuclear fuel concluded in January 2005. The Yankee companies' individual damage claims are specific to each plant and included costs through 2010, the earliest year the DOE expects that it will begin removing fuel. The Yankee companies' damage claims through 2002 totaled approximately $263 million and CMP's sponsor-weighted share is approximately $45 million. The claims also note additional costs that will be incurred for each year that fuel remains at the sites beyond 2010. If the Yankee companies prevail in these cases, any damages awarded would be credited to their respective decommissioning or spent fuel trust funds. Any remaining trust funds would be returned to electric customers when decommissioning is complete. The Yankee companies expect a trial court decision in the first half of 2006. CMP cannot predict the outcome of this litigation.

Pursuant to a FERC approved settlement, in July 2004 Connecticut Yankee filed for FERC approval of a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of decommissioning costs. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars and result in annual collections of $93 million from Connecticut Yankee's owners, including CMP. The revised estimate reflects increases in the projected costs for spent fuel storage, security, liability and property insurance and the fact that Connecticut Yankee had to take over all work to complete the decommissioning of the plant due to its termination of its contract with Bechtel, the turnkey decommissioning contractor, in July 2003. Bechtel filed a lawsuit in Connecticut state court challenging that termination and Connecticut Yankee filed a counterclaim to recover damages caused by Bechtel's breach of contract and termination. Any amount that Connecticut Yankee recovers from Bechtel would be credited to its decommissioning costs and any remaining decommissioning funds would be returned to electric customers when decommissioning is complete. This matter is scheduled for trial in mid-2006 and CMP cannot predict the outcome of this litigation.

The FERC authorized Connecticut Yankee to begin collecting the revised decommissioning charges in January 2005 from Connecticut Yankee's owners, including CMP, whose share of a $93 million increase is approximately $6 million. Under Maine statutes, CMP is allowed to recover any increases in decommissioning costs and pursuant to the January 2005 stranded cost settlement, CMP began collecting the higher Connecticut Yankee decommissioning costs through rates in March 2005. (See Item 7 - MD&A - Electric Delivery Rate Overview.)

In June 2004 the DPUC and the OCC filed a petition with the FERC asking it to determine if any of Connecticut Yankee's increased decommissioning costs were not prudently incurred. In August 2004 the FERC issued an initial Order rejecting the DPUC's petition; approved a rate increase for Connecticut Yankee effective February 1, 2005, subject to refund; and set for hearing the costs to be recovered. The DPUC requested rehearing of the FERC's August 2004 Order and on October 20, 2005, the FERC issued an order denying the request for rehearing. In December 2005 the DPUC filed a notice of appeal of the initial August 2004 Order with the United States Court of Appeals, District of Columbia Circuit.

The DPUC has alleged to the FERC that Connecticut Yankee imprudently managed and wrongfully terminated Bechtel, the turnkey decommissioning contractor, and as a result, concludes that approximately $225 million to $235 million of Connecticut Yankee's rate increase should be denied. The FERC Staff and Bechtel also allege that the cost increase was imprudently incurred. On November 22, 2005, the FERC's ALJ issued an Initial Decision that found in favor of Connecticut Yankee on all imprudence claims, finding that no disallowance was warranted. Because the ALJ found that Connecticut Yankee had refuted all claims of imprudence, the ALJ did not address any party's proposed disallowance. The interveners who unsuccessfully raised imprudence claims before the ALJ have taken exception to the ruling before the FERC, which is expected to issue a final decision in 2006. CMP is unable to predict the outcome of this proceeding.

Nonutility Generation: We expensed approximately $631 million for NUG power in 2005 and we estimate that our combined NUG power purchases will total $571 million in 2006, $575 million in 2007, $410 million in 2008, $244 million in 2009 and $83 million in 2010. CMP and NYSEG continue to seek ways to provide relief to their customers from above-market NUG contracts that state regulators ordered the companies to sign, and which, in 2005, averaged 10.0 cents per kilowatt-hour for CMP and 10.2 cents per kilowatt-hour for NYSEG. Recovery of these NUG costs is provided for in CMP's stranded cost rates and in NYSEG's current electric rate plan through a nonbypassable wires charge. (See Item 8 - Note 9 to our Consolidated Financial Statements.)

In a related matter, on July 26, 2005, the NYPSC issued a notice soliciting comments on an NYPSC Staff proposal on statewide guidelines for ESCO Referral Programs. As a result of experience gained since the Policy Statement was issued in August 2004, the NYPSC Staff has

identified a need for statewide simplicity, consistency and uniformity, to the extent practicable, in ESCO Referral Programs. In September and October 2005 NYSEG and RG&E filed comments urging rejection of the proposal and objecting to the proposal to the extent that it will require all utilities to adopt a "PowerSwitch" type program. At its session on December 14, 2005, the NYPSC established procedures for utilities to follow in implementing ESCO Referral Programs based on the Orange & Rockland model for those programs, as modified and enhanced with additional consumer protection measures. The NYPSC also approved, with modifications, Central Hudson's proposed ESCO Referral Program. The NYPSC ordered RG&E to begin a collaborative with interested parties for the purpose of implementing an ESCO Referral Program at RG&E. The NYPSC further permitted NYSEG to address the ESCO Referral Program within the context of its current rate case described above. Based on these latest developments, it is unclear whether or not NYSEG will be able to extend its Voice Your Choice program as a part of its ongoing electric rate proceeding.

New England RTO: In March 2004 the FERC issued an order that accepted a six-state New England RTO as proposed by ISO New England and the New England transmission owners. As an RTO, ISO New England is responsible for the independent operation of the regional transmission system and regional wholesale energy market. The transmission owners retain ownership of their transmission facilities and control over their revenue requirements. The FERC also approved both a 50 basis point ROE incentive adder for regional transmission facilities subject to RTO control and a 100 basis point ROE incentive adder for new regional transmission facilities developed by an RTO. The New England transmission owners have appealed the application of the adders to regional facilities to the Circuit Court of Appeals for the District of Columbia. Other parties have appealed the FERC's decision to grant the adders to regional facilities. The appeals are pending before the Court and no decision is expected until mid-2006. The FERC order also accepted, subject to suspension and hearing, the New England transmission owner's proposed base level ROE of 12.8% applicable to rates for local and regional transmission service. Those rates became effective, subject to refund, February 1, 2005. The FERC conducted evidentiary hearings on the final base level ROE and the incentive for new transmission investment in January and February 2005, and issued an initial decision in May 2005 recommending a base level ROE of 10.72%, plus the 50 basis point adder for regional facilities. The New England transmission owners have filed exceptions to the initial decision both with respect to the base level ROE and also seeking application of the 100 basis point adder for new investments applicable to both the local and regional transmission rates. A final decision from the FERC on those issues is not expected until early 2006. The New England transmission owners and ISO New England implemented the New England RTO effective February 1, 2005.

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

The FERC issued an order directing the NYISO to modify certain energy prices for May 8 and 9, 2000, and to back bill NYISO market participants, including NYSEG and RG&E. The NYISO and many market participants filed requests for rehearing with the FERC concerning that order. While the FERC has not ruled on those requests for rehearing, on July 8, 2005, and October 7, 2005, the NYISO issued back billings that reflected the FERC order concerning the May 2000 issues. NYSEG's updated back billing relating to May 8 and 9, 2000, was approximately $2 million and RG&E's was approximately $1 million. In the third quarter of 2005 NYSEG and RG&E deferred the amounts associated with the back billings as regulatory mandates, pursuant to their Electric Rate Agreements approved by the NYPSC.

Locational Installed Capacity Markets: In 2003 the FERC required ISO New England to file a proposed mechanism to implement by January 1, 2006, location or deliverability requirements in the installed capacity or resource adequacy market to ensure that generators that provide capacity within areas of New England are appropriately compensated for reliability. In response, in 2004 ISO New England developed and filed with the FERC a LICAP market proposal based on an administratively set demand curve. In June 2005 the FERC ALJ issued an initial decision essentially adopting the ISO New England LICAP market proposal with minor modifications. CMP and other parties that oppose the ISO New England LICAP market proposal filed exceptions to the recommended decision in July 2005. The Energy Policy Act of 2005 included a "sense of Congress" provision to the effect that the FERC should carefully consider the objections of the New England states to the LICAP proposal in the recommended decision. In addition, the MPUC, CMP, the DPUC representing the state of Connecticut and the OCC, joined with several Massachusetts parties and filed briefs with the FERC asking that the parties conduct settlement discussions to consider alternatives and that the FERC consider other alternatives to the LICAP market proposal. In response to these protests, the FERC has delayed any possible implementation of LICAP until October 1, 2006, at the earliest and granted oral arguments to consider opposition to LICAP and possible alternatives. Following oral arguments, the FERC granted the request to conduct settlement discussions to consider alternatives. The discussions began in November 2005 and on January 31, 2006, the Settlement ALJ reported to the FERC that most of the parties had reached an agreement in principle on an alternative to LICAP. This alternative will be filed with the FERC by April 12, 2006, and thereafter parties will be allowed to submit comments or opposition before the FERC issues a decision. CMP will review and evaluate the settlement as filed with the FERC. Presently, CMP and the MPUC, among other parties, are opposed to the LICAP proposal and the alternative, as either proposal could have an adverse effect on Maine's economy by increasing rates 5% to 10%. Maine lawmakers are holding hearings in early 2006 on the possibility of Maine withdrawing from ISO New England. CMP cannot predict the outcome of these settlement discussions, how the FERC will rule or what modifications the FERC might make to the filing. Any increase in costs associated with LICAP or any negotiated alternative will be reflected in Maine's standard offer rates.

Errant Voltage: In January 2005 the NYPSC issued an Order Instituting Safety Standards in response to a pedestrian being electrocuted from contact with an energized service box cover in New York City. The incident occurred outside of our service territory. All New York utilities were directed to respond to that order by February 19, 2005, with a report that provided a detailed voltage testing program, an inspection program and schedule, safety criteria applied to each program, a quality assurance program, a training program for testing and inspections and a description of current or planned research and development activities related to errant voltage

and safety issues. The Order Instituting Safety Standards also denies utility requests for recovery of implementation costs and establishes criteria for utilities seeking authorization to recover costs as an incremental expense. The order also established penalties for failure to achieve annual performance targets for testing and inspections, at 75 basis points each.

In early February 2005 NYSEG and RG&E filed, with two other New York State utilities, a joint petition for rehearing that focused on several areas including the impracticability of the timetable established in the order. In addition, NYSEG and RG&E filed a separate petition for rehearing dealing with the recovery of incremental costs of complying with the order. In response to the order, in late February 2005 NYSEG and RG&E filed a testing and inspection plan that is consistent with the timetable identified in the joint petition for rehearing. NYSEG and RG&E have begun to implement their plans, including testing of equipment. On July 21, 2005, in response to the petition for rehearing, the NYPSC issued an order detailing the revised requirements for stray voltage testing and reduced penalties during the first year to 37.5 basis points. NYSEG and RG&E filed the required annual reports with the NYPSC on January 17, 2006. NYSEG and RG&E have incurred costs of approximately $3 million as of December 31, 2005, including more than $1 million incurred by RG&E. RG&E estimates that it will incur additional costs of approximately $3 million, and NYSEG estimates it will incur another approximately $9 million of costs, by the end of 2006 to comply with the order.

Hurricanes' Effects on Natural Gas Supply: While none of our operating utilities were directly affected by Hurricane Katrina or Hurricane Rita, the hurricanes' effects on natural gas supply and subsequent price increases, including wholesale electricity prices, have affected our electricity customers. Electricity prices for customers who elected variable rate options have risen dramatically since the hurricanes struck the Gulf Coast in late August and September 2005. Current prices remain high due to economic conditions. We are unable to predict what effect the sharp increase in natural gas prices may have on wholesale electricity prices and our customers' energy consumption or ability to pay.

Our natural gas delivery business consists of our regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Massachusetts and Maine. The natural gas industry is regulated by various state and federal agencies, including state utility commissions. All of our natural gas utilities have a natural gas supply charge or a purchased gas adjustment clause to defer and recover actual natural gas costs. The following is a brief overview of the current rate agreements in effect for each of our natural gas utilities.

Natural Gas Rate Plans: NYSEG's Natural Gas Rate Plan, which became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, and contains an earnings-sharing mechanism, a weather normalization adjustment mechanism and a gas cost incentive mechanism. The earnings-sharing mechanism requires equal sharing of earnings between NYSEG customers and shareholders of ROEs in excess of 11.5% for the 27-month period ended December 31, 2004, and in excess of 12.5% for each of the calendar years from 2005 through 2008. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $250 million. No sharing occurred in 2005 or 2004.

RG&E's current rates were established by the 2004 Natural Gas Rate Agreement, which addresses RG&E's natural gas rates through 2008. Key features of the Natural Gas Rate Agreement include freezing natural gas delivery rates through December 2008, except for the implementation of a natural gas merchant function charge to recover approximately $7 million annually beginning May 1, 2004. The Natural Gas Rate Agreement also implemented a weather normalization adjustment to protect both customers and RG&E from fluctuating revenues due to swings in temperature outside a normal range, and a gas cost incentive mechanism to provide a means of sharing with customers any future gas supply cost savings that RG&E achieves. An earnings-sharing mechanism was established to allow customers and shareholders to share equally in earnings above a 12.0% ROE target. No sharing occurred in 2005 or 2004. The ROE target can be increased to 12.25% if certain incentive targets are met.

SCG's current rates became effective on January 1, 2006, pursuant to a settlement agreement that will be in effect through December 31, 2007. The total increase in revenue requirements for firm rates was set at 8.4% or about $26.7 million and included amounts for recovery of previously deferred costs. (See Item 7 - MD&A - Natural Gas Delivery Business Developments.)

On March 29, 2005, CNG responded to a DPUC request pertaining to the September 30, 2005, expiration of CNG's IRP. CNG notified the DPUC that CNG's existing rates would continue in effect after the expiration of the IRP, but the earnings sharing mechanism, the rate stay-out commitment, the exogenous cost provision and provisions involving merger-enabled gas cost savings would no longer be applicable.

Berkshire Gas' current rate plan is a 10-year rate plan that went into effect on February 1, 2002, and runs through January 31, 2012, with a mid-period review in 2007. This plan has no ROE cap and has an annual inflationary rate adjustment that is determined through the formula of the gross domestic product minus 1% as a productivity offset. The adjustment is made on September 1^st each year.

Natural Gas Supply Agreements: Our natural gas companies - NYSEG, RG&E, SCG, CNG, Berkshire Gas and MNG - each have a three-year strategic alliance with BP Energy Company, effective April 1, 2004, that provides the companies the right to acquire natural gas supply and optimizes transportation and storage services.

SCG Regulatory Proceeding: SCG's IRP expired on September 30, 2005. SCG filed a rate case on April 29, 2005, as a result of a DPUC decision in October 2004 to deny recovery of approximately $21 million of exogenous costs that included qualified pension and other postretirement benefits, taxes, uncollectible expense and SCG's Customer Hardship Arrearage Forgiveness Program. SCG requested approximately $35 million of additional revenues, or an increase of approximately 11% compared with revenues based on current rates. On December 28, 2005, the DPUC approved a settlement agreement and allowed an annual revenue increase of $26.7 million or 8.4%. The rate increase includes approximately $5 million annually for six years for recovery of amounts previously deferred under SCG's Customer Hardship Arrearage

Forgiveness Program and its Three-Way Payment Plan and approximately $12 million for uncollectible expense. The DPUC approval allows for an ROE of 10% effective from January 1, 2006, through December 31, 2007.

Manufactured Gas Plant Remediation Recovery: RG&E and NYSEG independently began cost contribution actions against FirstEnergy Corp. (formerly GPU, Inc.) in federal district court; RG&E in the Western District of New York in August 2000 and NYSEG in the Northern District of New York in April 2003. The actions are for both past and future costs incurred for the investigation and remediation of inactive manufactured gas plant sites. Motions to end the RG&E action are pending and discovery is ongoing in the NYSEG action. Any proceeds from these actions will go to customers. RG&E and NYSEG are unable to predict the outcome of these actions at this time.

Hurricanes' Effects on Natural Gas Supply: While none of our operating utilities were directly affected by Hurricane Katrina or Hurricane Rita, the hurricanes' effects on natural gas supply and subsequent price increases have affected our customers. Natural gas prices have risen dramatically since the hurricanes struck the Gulf Coast in late August and September 2005. Current prices remain high due to economic conditions. We are unable to predict what effect the sharp increase in natural gas prices may have on our customers' energy consumption or ability to pay.

South Glens Falls Energy Bankruptcy Filing: In the fourth quarter of 2005 South Glens Falls Energy, LLC decided to shut down operations of its 67 MW natural gas-fired peaking co-generation facility located in South Glens Falls, New York. Our subsidiary, Cayuga Energy, owns 85% of SGF. The determination to shut down operations was based on SGF's inability to recover costs given the current and forecasted prices for natural gas and electricity. SGF also had an agreement to sell steam that was resulting in ongoing losses. On January 26, 2006, SGF filed for bankruptcy under Chapter 7 of the United States Bankruptcy Code. SGF has ceased operations and in 2005 we recorded an after-tax loss of $5.2 million, representing the impairment of SGF's assets.

Statement 123(R): In December 2004 the FASB issued Statement 123(R), which is a revision of Statement 123. Statement 123(R) requires a public entity to measure the cost of employee services that it receives in exchange for an award of equity instruments based on the grant-date fair value of the award and recognize that cost over the period during which the employee is required to provide service in exchange for the award. Statement 123(R) also requires a public entity to initially measure the cost of employee services received in exchange for an award of liability instruments (e.g. instruments that are settled in cash) based on the award's current fair value, subsequently remeasure the fair value of the award at each reporting date through the settlement date and recognize changes in fair value during the required service period as compensation cost over that period. We early adopted Statement 123(R) effective October 1, 2005, using the modified version of prospective application. Our adoption of

Statement 123(R) did not have a material effect on our financial position, results of operations or cash flows as of December 31, 2005. (See Item 8 - Note 1 and Note 12 to our Consolidated Financial Statements.)

FIN 47: In March 2005 the FASB issued FIN 47, which clarifies that the term "conditional asset retirement obligation" as used in Statement 143 refers to an entity's "legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity." FIN 47 requires that if an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional asset retirement obligation, it must recognize that liability at the time the liability is incurred. We began applying FIN 47 effective December 31, 2005, as required. Our application of FIN 47 did not have a material effect on our financial position, results of operations or cash flows. (See Item 8 - Note 1 to our Consolidated Financial Statements.)

At December 31, 2005, our contractual obligations and commercial commitments are: