(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, 2006.

RG&E meets the conditions set forth in General Instruction I (1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, the Item 6 information related to RG&E is not presented.

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

Index to 2006 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, 2006.

On October 1, 2006, RG&E modified certain internal controls over financial reporting to accommodate the implementation of a new customer care system. The customer care system is used for customer bill production and integrates RG&E's revenue, accounts receivable and cash management transactions with Energy East's centralized accounting system.

There were no other 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's natural gas segment, RG&E, CMP and Berkshire Gas that currently allow for recovery of certain costs, including stranded costs; and provide stable rates for customers and revenue predictability. Where long-term rate plans are not in effect, we monitor the adequacy of rate levels and file for new rates when necessary. NYSEG's five-year electric rate plan expired December 31, 2006, and new rates went into effect on January 1, 2007. SCG received approval for new rates that became effective January 1, 2006, and CNG recently entered into a settlement agreement that, if approved, will result in new rates effective April 1, 2007. As of January 31, 2007, Energy East had 5,884 employees.

We continue to focus our strategic efforts on the areas that have the greatest effect on customer satisfaction and shareholder value. NYSEG implemented a new customer care system in the first quarter of 2006 and RG&E implemented a similar system in October 2006.

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 our operations and the rates that our customers pay for energy. Those proceedings, which are discussed below, could affect the nature of the electric and natural gas utility industries in New York and New England.

We expect to make significant capital investments to enhance the safety and reliability of our distribution systems and to meet the growing energy needs of our customers in an environmentally responsible manner. Capital spending is expected to exceed $3 billion through 2011, including $496 million in 2007. Major spending programs include the installation of advanced metering infrastructure in New York and Maine requiring a $500 million investment; $500 million of transmission investments, predominantly in Maine; a high efficiency transformer replacement program; and a "green" fleet initiative. The majority of these planned transmission investments will be pursuant to a regional reliability planning process and will qualify for the FERC's transmission investment ROE incentive adders. (See New England RTO.) We will also be investigating the repowering of the Russell Station using clean coal technologies, at a potential estimated cost of approximately $500 million. We estimate that over one-half of our capital spending program will be funded with internally generated funds and the remainder through the issuance of a combination of debt and equity securities.

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

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

Our electric delivery business consists primarily of our regulated electricity transmission, distribution and generation operations in upstate New York and Maine. 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: NYSEG had an electric rate plan that took effect as of January 1, 2002, and expired on December 31, 2006. That rate plan provided 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 was required to use the lower of its actual equity or a 45% equity ratio. At December 31, 2006, the equity NYSEG used for earnings sharing approximated $740 million, which was based on the 45% equity ratio limitation. Earnings levels were sufficient to generate estimated pretax sharing with customers of $5 million in 2006, $28 million in 2005, and $17 million in 2004.

On August 23, 2006, the NYPSC issued an order requiring that NYSEG reduce its electric delivery rates by approximately $36 million, or approximately 6%, effective January 1, 2007. (See NYSEG Electric Rate Order .)

RG&E's current rates were established by the 2004 Electric Rate Agreement, which addresses RG&E's electric rates through at least 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 was originally 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 $6 million of pretax sharing in 2006 and $23 million in 2005.

NYSEG and RG&E currently 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 actual cost of electricity purchases and an option to purchase electricity supply from an ESCO. Both NYSEG's and RG&E's customers make their supply choice annually. Those customers who do not make a choice are served under a variable price option. Customers also pay nonbypassable wires charges, which include recovery of stranded costs. The table below shows the percentages of load that are projected to be served under the various commodity supply options for 2007.

Experience has shown that the majority of our residential and small commercial customers want their utility to remain a supply option and prefer a fixed price option. NYSEG and RG&E believe that their programs are 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 customer benefits in excess of $130 million through 2006. Customer benefits include the customer's portion of earnings sharing and costs that were absorbed by NYSEG and RG&E that would otherwise have been deferred for future recovery had earnings levels been insufficient to generate sharing.

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 2006 and 2.9% in 2007. Price adjustments since 2002 have generally resulted in rate decreases.

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-approved base level ROE of 10.9%, plus a 50 basis point adder for regional facilities and a 100 basis point adder applicable to regional facilities placed in service after December 31, 2003, and approved as part of the ISO-NE regional planning process. The formula rates are updated annually in a filing to the FERC on June 1st. CMP's transmission rates increased approximately $20 million for the rate year effective June 1, 2006. The increase enables CMP to recover its share of ISO-NE 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 Order: In September 2005 NYSEG filed a six-year Electric Rate Plan Extension with the NYPSC, to commence on January 1, 2007. NYSEG's Electric Rate Plan Extension, as subsequently amended, proposed, beginning on January 1, 2007, to reduce the nonbypassable wires charge by $168 million and increase delivery rates by $104 million, thereby resulting in an annualized overall electricity delivery rate decrease of $64 million, or 8.6%. NYSEG proposed to accomplish the reduction in its nonbypassable wires charge by accelerating benefits from certain expiring above-market NUG contracts and capping the amount of above-market NUG costs over the term of the rate plan extension (referred to as NYSEG's NUG levelization proposal). NYSEG also proposed to increase its equity ratio from 45% to 50%. In addition, NYSEG's proposal would have allowed customers to continue to benefit from merger synergies and savings.

In early February 2006 Staff of the NYPSC (Staff) and six other parties submitted their direct cases. Staff presented only a one-year rate case. In its presentation, Staff proposed a delivery rate decrease of approximately $83 million, or about 13.4%. Staff neither rebutted nor addressed NYSEG's revised and updated rate plan extension proposal, including its NUG levelization proposal, and opposed NYSEG's proposal to extend its Voice Your Choice commodity program. Staff also raised several retroactive accounting issues that will be addressed in a future proceeding. The most significant of those issues concerns NYSEG's internal other post employment benefits (OPEB) reserve (explained below), which, if accepted by the NYPSC, would have a material effect on earnings.

On August 23, 2006, the NYPSC issued its order in this proceeding. Major provisions of the Order include:

• A decrease in delivery rates of $36 million. NYSEG's most recent update in the proceeding requested a $58 million increase in delivery rates.

• A 9.55% ROE. NYSEG had requested an 11% ROE.

• An equity ratio of 41.6% (approximately $610 million of equity) based on Energy East's consolidated capital structure. NYSEG had requested a 50% equity ratio based on its actual capital structure.

• A refund of $77 million to be paid from NYSEG's ASGA that had previously been reserved for customers. The ASGA was initially created in 1998 as a result of the sale of NYSEG's generating stations and had been enhanced during NYSEG's prior electric rate plans with the customers' share of earnings from the earnings sharing mechanism. Payment of the refund will be made through a credit to customers' bills by the end of April 2007.

• One retroactive accounting issue raised by Staff concerns $57 million of interest associated with NYSEG's internal OPEB reserve, which NYSEG has offset against other OPEB costs in its income statement over the past decade. The NYPSC determined that $3.6 million in annual revenues that NYSEG receives will remain subject to refund pending further examination of NYSEG's accounting for OPEB costs. A proceeding related to this issue began in the fourth quarter of 2006 and could result in NYSEG treating all or a portion of the $57 million as an addition to its internal OPEB reserve, with a corresponding charge to income. NYSEG is vigorously defending its position and contends that the NYPSC staff is engaged in retroactive ratemaking, but is unable to predict its outcome.

• Significant modifications to NYSEG's previously approved Voice Your Choice commodity program, including:

NYSEG believes that the commodity options program in the Order is unworkable in the long-term and inconsistent with the development of a competitive retail market for supply. In particular, NYSEG believes that the lower cost allowance used to set the supply rate does not cover the cost and risk of providing fixed price electricity at retail, and will stifle participation by retail energy service providers.

NYSEG estimates that the effect of the order will be to reduce its earnings by $35 million to $45 million. This estimate includes the effects of the delivery rate reduction, the lower ROE, the lower equity base that NYSEG is allowed to earn on and the changes in the commodity program, including the revised sharing provisions.

On September 7, 2006, NYSEG filed a petition with the NYPSC for rehearing and request for oral argument responding to certain aspects of the Order including the disallowance of system implementation costs. On December 15, 2006, the NYPSC denied NYSEG's petition.

Niagara Power Project Relicensing: The NYPA's FERC license with respect to the Niagara Power Project expires on August 31, 2007. In order to continue to operate the Niagara Power Project, the NYPA filed a relicensing application in August 2005. The NYPA's relicensing process is important to NYSEG's and RG&E's customers because an aggregate of over 360 MWs of Niagara Power Project power has been allocated to the companies 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 FERC license. The annual value of the Niagara allocation to the companies at current electricity market prices is approximately $77 million and the loss of the

Advanced Metering Infrastructure: In February 2007 in response to an August 2006 NYPSC order, NYSEG and RG&E filed a plan to install advanced metering infrastructure (smart meters) for all of their electric and natural gas customers. Smart meters would enable customers to better control their energy usage by providing time-differentiated rates. Smart meters would also improve the companies' response to service interruptions, enhance safety, and provide internal usage and demand data that will ultimately lead to peak demand reduction and defer the need for generation sources. The plan calls for a total capital investment of approximately $370 million between 2008 and 2010.

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 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 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 are implementing 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. In August 2006 NYSEG and RG&E completed their first complete cycle of testing and at the request of the NYPSC, submitted an interim report on October 23, 2006, detailing their results. Under the provisions of their respective rate plans, they are allowed to defer and recover these costs.

For 2006, costs incurred to comply with the order were approximately $4 million for NYSEG and $2 million for RG&E. For 2007, estimated additional costs to comply with the order are approximately $6 million for NYSEG and $3 million for RG&E.

RG&E Transmission Project: In December 2004 RG&E received approval from the NYPSC to upgrade its electric transmission system in order to provide sufficient transmission and ensure reliable service to customers in anticipation of the shutdown of the Russell Station. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, New York area. 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 began in the first quarter of 2006 and is expected to be completed by December 2007. The estimated cost of the project is approximately $119 million.

RG&E Dispute Settlement Related to NMP2 Exit Agreement: In November 2001 RG&E and three other NMP2 joint owners, including Niagara Mohawk Power Corporation (Niagara Mohawk), sold their interests in NMP2 to Constellation Nuclear, LLC. In connection with the sale of NMP2, RG&E informed Niagara Mohawk that RG&E's payment obligations and rights to certain TCCs would cease according to the terms of an exit agreement executed by RG&E and Niagara Mohawk in June 1998. Niagara Mohawk disagreed with RG&E's position, claiming that RG&E must continue to make annual payments that were to decline from about $7 million per year in 2002 to $4 million per year in 2007, and remain at that level until 2043. In August 2001, RG&E filed a complaint asking the New York State Supreme Court, Monroe County, to find that, as a result of the sale of its interest in NMP2, RG&E has no further obligation to make payments under the exit agreement and that the TCCs to which RG&E was entitled under the exit agreement should be returned to and accepted by Niagara Mohawk.

In the first quarter of 2006, RG&E and Niagara Mohawk stayed the litigation and entered into confidential mediation with an ALJ appointed by the NYPSC. On June 29, 2006, the parties executed a settlement agreement that provides for RG&E's one-time payment of $34 million to Niagara Mohawk and further provides that RG&E retain the rights and obligations related to the TCCs until 2043, including the value accumulated to date of approximately $4 million. The settlement agreement was contingent upon the fulfillment of certain closing conditions, including FERC acceptance of an amendment to and restatement of the exit agreement. All of the necessary closing conditions were fulfilled, including a favorable judgment from the FERC and the lack of a negative finding by the Director of Accounting and Finance of the NYPSC, and RG&E made the required payment. In accordance with the 2001 settlement and order associated with the transfer of RG&E's share of NMP2 to Constellation Nuclear and RG&E's Electric Rate Agreement, RG&E adjusted its regulatory asset established as a result of the sale of NMP2 for the amount of the $34 million payment to Niagara Mohawk, which was offset by the accumulated TCC amount of approximately $4 million. The payment will also be adjusted by any future TCC amounts. RG&E's results of operations were not affected by the settlement of this dispute. The current amortization and recovery of this regulatory asset in rates remains unchanged.

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

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

Were the Attorney General and the NYSDEC to commence a Clean Air Act lawsuit against RG&E, they would need to demonstrate, among other things, that the challenged modifications to the Russell generating station cause an "increase" in emissions from the station. The issue of what constitutes the appropriate test for an emissions increase currently is before the United States Supreme Court in Environmental Defense v. Duke Energy Corporation, Docket No. 05-848. Oral argument was held on November 2006, and a decision is expected in the first half of 2007. RG&E, the NYSDEC and the Attorney General continue to discuss this matter and no suit has been filed to date. RG&E is not able to predict the outcome of this matter.

CMP Alternative Rate Plan: In December 2005 CMP and the Maine Office of the Public Advocate filed with the MPUC a stipulation for an extension of CMP's ARP 2000. The stipulation was also supported by low-income customer advocates, and a coalition of industrial energy customers signed the stipulation agreement. The stipulation maintained the provisions of CMP's ARP 2000 and proposed a three-year extension with four additional items: (i) a 0.5% increase in the scheduled productivity offset of 2.75% for July 2006 and provided for productivity offsets

averaging 2% for 2008, 2009 and 2010, (ii) an additional $2.2 million in assistance for low-income customers annually starting in 2006, (iii) CMP agreed to educate its customers on the regional benefits of adjusting usage during peak hours and demand periods and also agreed to limit the promotion of increased usage during specified higher demand periods and (iv) CMP agreed to commit to investing an additional $25 million through 2010 for enhancements to the reliability, safety and security of its distribution system.

In February 2006 the MPUC approved that portion of the stipulation increasing assistance to low-income customers for one year. On April 28, 2006, the Staff of the MPUC filed its analysis and recommendations with the MPUC commissioners, opposing the stipulation other than the portion that was approved. CMP and the other stipulating parties responded to the Staff's recommendations in a brief filed on May 19, 2006. On June 5, 2006, the MPUC determined that the stipulation was not in the public interest unless substantially modified, and on June 21, 2006, the MPUC agreed to dismiss the proceeding at the request of the stipulating parties. CMP will file a proposal for a new alternative rate plan by May 1, 2007, to be effective January 1, 2008. In the interim, CMP continues to operate under the terms of ARP 2000.

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 2007, 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 include costs through 2010, the earliest year the DOE expects that it will begin removing fuel.

On September 30, 2006, the U.S. Court of Federal Claims issued a favorable ruling for the three Yankee companies in their litigation with the federal government over its failure to remove spent nuclear fuel from the three former nuclear power plant sites. In the ruling, Yankee Atomic was awarded $33 million in damages for costs through 2001, Connecticut Yankee was awarded $34 million for costs through 2001, and Maine Yankee was awarded $76 million for costs through 2002. CMP's sponsor-weighted share of the award is approximately $34 million. Since spent nuclear fuel continues to be stored at the sites, the Yankee companies will have the opportunity to recover more damages in future lawsuits. On December 4, 2006, the federal government appealed the decision, delaying payment of the damage awards. Any awards ultimately received will be credited to the Yankee companies' respective electric ratepayer-funded, decommissioning or spent fuel trust funds. CMP cannot predict the ultimate outcome of this matter.

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. On August 11, 2006, Connecticut Yankee filed a settlement agreement supported by all parties, including the FERC trial staff, that resolved all of the issues contested and will allow Connecticut Yankee to collect the increased decommissioning costs. FERC approved the settlement agreement in November 2006. The revised decommissioning charges will be collected in wholesale rates effective January 1, 2007, until December 2015.

Nonutility Generation: We expensed approximately $560 million for NUG power in 2006 and we estimate that our combined NUG power purchases will total $568 million in 2007, $392 million in 2008, $229 million in 2009, $84 million in 2010 and $85 million in 2011. 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 2006, averaged 10.2 cents per kilowatt-hour for CMP and 11.3 cents per kilowatt-hour for NYSEG. Recovery of these NUG costs is provided for in CMP's stranded cost rates and in NYSEG's rates through a nonbypassable wires charge. (See Item 8 - Note 9 to our Consolidated Financial Statements.)

New England RTO: In March 2004 the FERC issued an order that accepted a six-state New England RTO that CMP participates in and which is operated by ISO-NE and the New England transmission owners. The RTO began operations effective February 1, 2005. As an RTO, ISO-NE 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 approved as part of the regional planning process. The New England transmission owners appealed the application of the adders to local facilities to the Circuit Court of Appeals for the District of Columbia. Other parties appealed the FERC's decision to grant the adders to regional facilities. On June 30, 2006, the Court denied the appeals and upheld the FERC's decisions. On October 31, 2006, the FERC issued an Opinion and Order on Initial Decision establishing the ROE applicable to the RTO, including CMP's transmission system. The October 31 order adopts a base-level ROE of 10.2 percent, with three adjustments as follows: a 50 basis point incentive for RTO participation; a 100 basis point incentive for new transmission investment; and a 74 basis point adjustment reflecting updated bond data, as applicable to the period commencing with the date of the order. The resulting ROEs for existing regional transmission facilities were 10.7 percent for the period February 1, 2005, through October 31, 2006, and are 11.4 percent for the going-forward period.

The ROEs that will apply to post-2003 regional transmission facilities approved as part of the regional reliability planning process will include an incremental 100 basis point adder, and are 11.7 percent prior to the date of the order, and 12.4 percent for the going-forward period. Several parties have filed for rehearing of the order and can appeal the final order. The New England transmission owner filing parties submitted a filing in compliance with the order on December 21, 2006 to establish a refund and billing procedure as required by the final Order. On February 6, 2007, several parties filed a late protest to this compliance filing. CMP cannot predict the outcome of these proceedings.

Locational Installed Capacity Markets: In 2003 the FERC required ISO-NE 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-NE developed and filed with the FERC a market proposal based on an administratively set demand curve (previously referred to as locational installed capacity or LICAP). In June 2005 the FERC ALJ issued an initial decision, essentially adopting the ISO-NE market proposal, with minor modifications.

CMP and other parties that oppose the ISO-NE 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 proposal in the recommended decision. Following oral arguments, the FERC granted the request to conduct settlement discussions to consider alternatives. Settlement discussions began in November 2005 and in January 2006 the settlement ALJ reported to the FERC that most of the parties had reached an agreement in principle on an alternative. The alternative would provide fixed transitional capacity payments from 2006 until 2010 and provide capacity payments based on a Forward Capacity Market Auction thereafter. CMP opposed this settlement agreement because of the cost of the transition payments to electric customers in Maine. The ISO-NE and a majority of New England Power Pool (NEPOOL) participants supported the settlement agreement. That alternative has been filed with the FERC as a component of a comprehensive settlement agreement.

The MPUC, among other parties, filed comments opposing the settlement agreement, because the proposal could have an adverse effect on Maine's economy by increasing its generation supply rates, including standard offer rates, by an estimated 5% to 10%. On June 15, 2006, the FERC issued an order accepting the settlement agreement without modification. The MPUC and other parties opposed to the settlement agreement filed a request with the FERC asking it to reconsider its June 15 order. On October 31, 2006, the FERC issued an Order on Rehearing and Clarification denying requests for rehearing and affirming its approval of the settlement agreement. With the FERC's denial of the rehearing requests, the resulting increased costs associated with regional installed capacity have been reflected in Maine consumers' generation supply rates since December 2006. Several parties, including the MPUC, have filed notices of appeal in the US Circuit Court of Appeals, seeking to overturn the FERC's orders approving the settlement agreement. CMP cannot predict the outcome of these proceedings.

MPUC Inquiries into Long-Term Utility Contracting and Continued Participation in New England RTO: Maine lawmakers enacted legislation in 2005 that requires the MPUC to conduct two inquiries. The first concerns whether or not CMP and other Maine electric utilities should continue to participate in the New England RTO, as operated by the ISO-NE. In this inquiry, the MPUC issued an interim report to the Maine Legislature on January 16, 2007, reporting its preliminary findings: inequities exist in the current cost allocation system of the ISO-NE tariff; no insurmountable legal, economic or technical barriers preclude withdrawal from the ISO-NE; and reasonable alternatives exist. The MPUC has begun the next phase of this inquiry in which three options will be explored: altering the transmission cost allocation formula; exiting the RTO and creating a state-wide independent transmission company; or joining with New Brunswick and other Maritime provinces to create a Maine-Canada market. The MPUC has set a June 2007 target date for a draft report to the legislature containing recommendations for further action.

The second inquiry concerns regional energy markets and generation deregulation. The MPUC conducted an initial inquiry into the development of a Maine electric resource adequacy plan and the use of long-term generating capacity contracts between utilities and capacity suppliers and developed provisional long-term contracting rules and the first report on resource adequacy, which were submitted to the legislature for further action in early 2007. Because the proposed long-term contracting rules are considered major, substantive rules, the Maine Legislature must vote on their adoption.

CMP will continue to participate in the MPUC and subsequent legislative proceedings and cannot predict the outcome of the inquiries.

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 12.5% 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 2006, 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 2006, 2005 or 2004.

SCG's current rates became effective on January 1, 2006, pursuant to a settlement agreement that is 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 including bad debts.

CNG's IRP expired on September 30, 2005, and its rates have continued in effect since then, but the earnings sharing mechanism, the rate stay-out commitment and the exogenous cost provision were no longer applicable. On September 29, 2006, CNG filed for new rates to become effective on April 1, 2007. On December 21, 2006, CNG and other participants in the proceeding filed a settlement agreement with the DPUC for an increase of $15.5 million that would be in effect through March 31, 2008. (See CNG Regulatory Proceeding.)

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. The plan has no ROE cap and has an annual inflationary rate adjustment that is determined based on the gross domestic product minus 1% as a productivity offset. The adjustment is made on September 1^st each year. Berkshire Gas does not believe the mid-period review will result in any significant changes to its rate plan.

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 ending on March 31, 2007, that gives them the right to acquire natural gas supply and optimizes transportation and storage services. We are exploring our options for a new alliance.

CNG Regulatory Proceeding: On March 21, 2006, the DPUC notified CNG that it had initiated a general rate review of CNG pursuant to Connecticut General Statutes, which state that the DPUC must conduct a financial review or require a rate case every four years. On September 29, 2006, CNG submitted a general rate filing, requesting a net rate increase of $28.2 million, or 7.9%, in base delivery revenues effective April 1, 2007, based on an 11.0% ROE. The requested increase includes $6.7 million for increased bad debt expense, including a hardship program, $5.6 million for sharing of achieved management efficiencies and $4.3 million to offset lower normalized customer usage.

On December 21, 2006, CNG and the OCC filed with the DPUC a proposed Settlement Agreement in which the parties have agreed to a net increase in firm revenues of $15.5 million (4.2% of total firm revenues), and a 10.1% ROE. CNG has also agreed to freeze its base distribution rates for a period of at least 30 months, until October 2009, to implement an automated meter reading system by July 2008, and to a non-firm delivery margin threshold of $8.6 million with sharing of 86% to customers and 14% to shareholders. A final decision by the DPUC is expected in April 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. Discovery is ongoing in both actions. A trial date for the RG&E action has been set for the fourth quarter of 2007. 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.

Environmental Insurance Settlements: In 2005 we served demands on three of our liability insurance carriers seeking coverage for environmental investigation and clean-up costs incurred at three former manufactured gas plant sites located in Massachusetts. In 2006 we settled claims against two carriers for substantial cash payments from each. We are still in negotiations with the third carrier and cannot, at this time, predict the results of these negotiations. Pursuant to Massachusetts regulations, we are allowed to retain a share of these settlement proceeds for shareholders.

The FASB released FIN 48 in July 2006 and issued Statements 157 and 158 in September 2006. See Item 8 - Note 1 to our Consolidated Financial Statements for explanations about these new accounting standards and when they will become or became effective.

At December 31, 2006, our contractual obligations and commercial commitments are: