CMP, NYSEG and RG&E had no issuer purchases of equity securities during the quarter ended December 31, 2004.

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:

Market risk represents the risk of changes in value of a financial or commodity instrument, derivative or nonderivative, caused by fluctuations in interest rates and commodity prices. The following discussion of the companies' risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those contemplated in the "forward-looking" statements. The companies handle market risks in accordance with established policies, which may include various offsetting, nonspeculative derivative transactions. (See Item 8 - Note 1 to the company's and CMP's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.)

The financial instruments held or issued by the companies are for purposes other than trading or speculation. Quantitative and qualitative disclosures are discussed as they relate to the following market risk exposure categories: Interest Rate Risk, Commodity Price Risk and Other Market Risk.

Interest Rate Risk: The companies are exposed to risk resulting from interest rate changes on their variable-rate debt and commercial paper. The company and its subsidiaries use interest rate swap agreements to manage the risk of increases in variable interest rates and to maintain desired fixed-to-floating rate ratios. Amounts paid and received under those agreements are recorded as adjustments to the interest expense of the specific debt issues. After giving effect to those agreements the company estimates that, at December 31, 2004, a 1% change in average interest rates would change annual interest expense for variable-rate debt by about $8.4 million for Energy East, including $0.5 million for CMP, $3.1 million for NYSEG and $1.1 million for RG&E. Pursuant to its current rate plans, RG&E defers any changes in variable-rate interest expense. (See Item 8 - Notes 7, 8 and 13 to the company's and Notes 5, 6 and 11 to CMP's Consolidated Financial Statements, and Notes 5, 6 and 10 to NYSE G's and Notes 6, 7 and 11 to RG&E's Financial Statements.)

The companies also use derivative instruments to mitigate risk resulting from interest rate changes on future financings. Amounts paid and received under those instruments are amortized to interest expense over the life of the corresponding financing.

Commodity Price Risk: Commodity price risk is a significant issue for the company, NYSEG and RG&E due to volatility experienced in the electric wholesale markets. The companies manage this risk through a combination of regulatory mechanisms, such as allowing for the pass-through of the market price of electricity to customers, and through comprehensive risk management processes. These measures mitigate the companies' commodity price exposure, but do not completely eliminate it.

NYSEG, RG&E, and Energy East's energy marketing subsidiaries use electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity. The cost or benefit of those contracts is included in the amount expensed for electricity purchased when the electricity is sold.

NYSEG's current electric rate plan offers retail customers choice in their electricity supply including fixed and variable rate options, and an option to purchase electricity supply from an ESCO. Approximately 40% of NYSEG's total electric load is now provided by an ESCO or at the market price. NYSEG's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the bundled rate option, which combines delivery and supply service at a fixed price. NYSEG actively hedges the load required to serve customers who select the bundled rate option. As of January 30, 2005, NYSEG's load was 99% hedged for on-peak periods and 97% hedged for off-peak periods in 2005. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings less than $250,000 in 2005. The percentage of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could diffe r as a result of changes in the load compared to the load forecast.

RG&E's current electric rate plan offers retail customers choice in their electricity supply including fixed and variable rate options, and an option to purchase electricity supply from an ESCO. Approximately 75% of RG&E's total electric load is now provided by an ESCO or at the market price. Two of Energy East's affiliates offer ESCO service and are among the options that NYSEG and RG&E customers have for their electricity supply. RG&E's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the fixed rate option, which combines delivery and supply service at a fixed price. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. RG&E actively hedges the load required to serve customers who select the fixed rate option. As of January 30, 2005, RG&E's load was 98% hedged for on-peak periods and fully hedged for off-peak periods in 2005. A fluctuation of $1.00 per megawatt-hour in the price of on-peak electricity would change earnings less than $100,000 in 2005. The percentage of RG&E's hedged load is based on RG&E's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

While owned generation provides RG&E with a natural hedge against electric price risk, it also subjects it to operating risk. Operating risk is managed through a combination of strict operating and maintenance practices.

Although CMP has no long-term supply responsibilities, the MPUC can mandate that CMP be a standard-offer provider of electricity supply service for retail customers if the MPUC should deem bids by competitive suppliers to be unacceptable. Competitive suppliers have provided all standard-offer obligations in CMP's service territory since March 2002. (See Item 7 - CMP Electricity Supply Responsibility.) In December 2004 the MPUC chose CEC Group as the new supplier of standard-offer electricity to CMP's residential and small commercial customers (100% for the first year, 66.6% for the second year and 33.3% for the third year) for a three-year period beginning March 1, 2005. CMP no longer owns any generating assets but retains its power entitlements under long-term contracts with NUGs and a power purchase contract with Vermont Yankee. In December 2004 the MPUC approved CMP's sale of those entitlements to CEC Group for one to three years and the residential and small commercial standard-offer is linked to the sale of CMP's entitlements.

In January 2005 the MPUC chose suppliers of standard-offer electricity for the six months beginning March 1, 2005, for CMP's medium and large customer classes. The MPUC will hold another auction to determine new suppliers for these classes of customers for the period beginning September 2005.

All of Energy East's natural gas utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk.

NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures and forwards is included in the commodity cost, which is passed on to customers when the related sales commitments are fulfilled.

Other Market Risk: The companies' pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in those markets as well as changes in interest rates cause the companies to recognize increased or decreased pension income or expense. If the expected return on plan assets were to change by 1/4%, pension income would change by approximately $6 million (including $0.4 million for CMP, $3.8 million for NYSEG and $1.4 million for RG&E). A change of 1/4% in the discount rate would result in a change in pension income of a similar amount for each company. Under the current rate plans for RG&E and NYSEG, changes in pension income resulting from changes in market conditions are deferred for RG&E's electric and natural gas delivery businesses and for NYSEG's natural gas delivery business. (See Item 8 - Note 16 to the company's and Note 13 to CMP's Consolidated Financial Statements, and Note 12 to NYSEG's and RG&E's Financial Statements.)

Index to 2004 Financial Statements

None for Energy East, CMP, NYSEG or RG&E.

The principal executive officers and principal financial officers of Energy East, CMP, NYSEG 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's 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, they 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 generally accepted accounting principles. 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, 2004.

Energy East management's assessment of the effectiveness of its internal control over financial reporting as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report on page 81.

There were no changes in the companies' internal control over financial reporting that occurred during each company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the respective company's internal control over financial reporting.

None for Energy East, CMP, NYSEG or RG&E.

Energy East's primary operations, its electric and natural gas utility operations, are subject to rate regulation. The approved regulatory treatment on various matters could significantly affect the company's financial position and results of operations. Energy East has long-term rate plans for NYSEG, RG&E, CMP, CNG, SCG and Berkshire Gas. The plans, which are discussed below, provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including exogenous and stranded costs, and provide stable rates for customers and revenue predictability for those six operating companies.

Energy East's management focuses its strategic efforts on those areas of the company that it believes would have the greatest effect on shareholder value. Efficient operations are a key aspect of increasing shareholder value. Management has implemented plans to achieve savings through a company-wide restructuring that was completed in early 2004 and continued consolidation of utility support services.

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 the outcomes of the proceedings are difficult to predict. Those proceedings could affect the nature of the electric and natural gas utility industries in New York and New England and are described below.

The company engages in various investing and financing activities to meet its strategic objectives. The primary goal of investing activities is to maintain a reliable energy delivery infrastructure. Investing activities are funded primarily with internally generated funds. Financing activities are focused on maintaining adequate liquidity, improving credit quality and minimizing the cost of capital.

Energy East has maintained a consistent "pipes and wires" strategy over the past several years, focusing on the transmission and distribution of electricity and natural gas rather than the more volatile generation and energy trading businesses. Achieving operating excellence and efficiencies throughout the company is central to this strategy. While Energy East has sold certain noncore businesses and the last of its substantial regulated generation assets, investment in infrastructure that supports the electric and natural gas delivery systems continued in 2004. Also, the creation of a "utility shared services" organization has improved efficiencies and achieved savings from the integration of the company's information systems, purchasing, accounting and finance functions.

The company's long-term regulatory agreements continue to be a critical component to its success. While specific provisions may vary among the company's public utility subsidiaries, the overall strategy includes creating a stable rate environment that allows the companies to earn a fair return while minimizing price increases and sharing benefits with customers.

The company's electric delivery business consists primarily of its regulated electricity transmission, distribution and generation operations in upstate New York and Maine.

RG&E 2004 Electric and Natural Gas Rate Agreements: In May 2003 RG&E filed a rate case with the NYPSC to recover costs that RG&E had incurred and will continue to incur in providing safe and reliable electric and natural gas service. On May 20, 2004, the NYPSC approved the Electric and Natural Gas Joint Proposals that had been negotiated with Staff of the NYPSC and other interested parties and that address RG&E's electric and natural gas rates through 2008.

Key features of the Electric Rate Agreement include:

• To compensate RG&E for incremental supply costs resulting from the sale of Ginna;
• To cover $6 million of replacement purchased power costs incurred in connection with a 2003 Ginna refueling outage;
• To provide RG&E with revenue equivalent to a $2 million annual increase in electric delivery rates; and
• To compensate RG&E for maximizing the sale value of Ginna through a credit to RG&E of $3.3 million annually over the term of the agreement.

• Establishing an earnings-sharing mechanism to allow customers and stockholders to share equally in earnings above a 12.25% ROE target. RG&E will be allowed to increase its earnings-sharing threshold to 12.50% by meeting yet-to-be-determined standards that will measure improvements in RG&E's retail access program. No sharing occurred in 2004 under this mechanism.
• Ensuring that RG&E continues to maintain the high quality of service and reliability it currently provides by specifying service quality and reliability standards and capital investment objectives.
  

RG&E estimates that $145 million will remain in the ASGA at the end of 2008. At that time the ASGA may be used at the discretion of the NYPSC for rate moderation, among other things.

Key features of the Natural Gas Rate Agreement include:

• Freezing natural gas delivery rates through December 2008, except for the implementation of a merchant function charge that will recover approximately $7 million annually beginning May 1, 2004.
• Implementing a weather normalization adjustment to protect both customers and RG&E from fluctuating revenues due to swings in temperature outside a normal range.
• Implementing gas cost incentive mechanisms to provide a means of sharing with customers any future gas supply cost savings that RG&E achieves.

• Establishing provisions similar to those in the Electric Rate Agreement regarding earnings sharing and service quality and reliability. The level for earnings sharing is 12.00%, with the opportunity to increase it to 12.25% if certain targets are achieved. No sharing occurred in 2004 under this mechanism.

The RG&E 2004 Electric and Natural Gas Rate Agreements resolve all outstanding issues related to RG&E's requests filed with the NYPSC in 2003. Those issues include:

• The deferral and recovery of costs, including interest, for restoration work resulting from a severe ice storm in April 2003.
• Recovery of replacement purchased power costs incurred in 2003 in connection with a scheduled refueling outage for Ginna.
• The deferral and true-up of estimated pension costs for the 16-month period through May 1, 2004, in accordance with the NYPSC's Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Post Retirement Benefits Other than Pensions.

In addition, RG&E has withdrawn its appeal of an order the NYPSC issued in March 2003 related to RG&E's February 2002 request filed with the NYPSC for new electric and natural gas rates that were to go into effect in January 2003.

Sale of Ginna: On June 10, 2004, after receiving all regulatory approvals, RG&E sold Ginna to CGG and received $429 million in cash at closing. RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna and provides for an ASGA, established at closing at approximately $357 million, and addresses the disposition of the asset sale gain. On September 9, 2004, RG&E received an additional $25 million from CGG related to certain post-closing adjustments, resulting in a $20 million increase to the ASGA. (See Note 2 to the company's Consolidated Financial Statements.)

Upon closing of the sale of Ginna, RG&E transferred $201 million of decommissioning funds to CGG. That amount fully meets the Nuclear Regulatory Commission's decommissioning funding requirements for Ginna. RG&E retained $77 million in excess decommissioning funds, which was credited to the ASGA. CGG is now responsible for all future decommissioning funding. The sale agreement included a 10-year, fixed-price power purchase agreement that calls for CGG to provide 90% of Ginna's output to RG&E.

RG&E Electric Rate Unbundling: In June 2003, as required by an NYPSC Order issued in March 2003 RG&E filed documentation with the NYPSC to unbundle commodity charges from delivery charges and to create electric commodity options for all customers. The Electric Rate Agreement provides for that unbundling and for the commodity options. Beginning January 1, 2005, customers have an opportunity to choose to purchase commodity service from RG&E at a fixed rate or at a price that varies monthly based on the market price of electricity. Alternatively, customers may continue to choose to purchase their commodity service from an ESCO. Customers enrolled in these new commodity options between October 1, 2004, and December 31, 2004. Customers who did not make a choice will be served under RG&E's variable price option. Approximately 77% of those customers who made a choice selected RG&E's f ixed price option. About 25% of RG&E's load is now served under this option.

RG&E Transmission Project: In September 2003 RG&E applied to the NYPSC for approval to upgrade its electric transmission system. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, NY area in order to assure adequate service to customers after the planned closing of RG&E's 257 megawatt coal-fired Russell Station in 2007. The estimated cost of the multi-year project is $75 million. Construction on the project is expected to begin in the spring of 2005.

On September 28, 2004, RG&E executed a Joint Proposal with Staff of the NYPSC, the NYSDEC and the New York State Department of Agriculture & Markets, requesting that the NYPSC issue a Certificate of Environmental Compatibility and Public Need for the project subject to certain terms and conditions. RG&E received the certificate from the NYPSC on December 15, 2004.

CMP Alternative Rate Plan: In September 2000 the MPUC approved CMP's ARP 2000. ARP 2000 applies only to CMP's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services. ARP 2000 began January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007. Effective July 1, 2004, CMP's distribution prices decreased by about 2% as a result of inflation being less than the productivity offset for 2004. In addition, CMP decreased its transmission rates to eliminate billings for congestion costs that have been fully recovered and, pursuant to its formula rate approved by the FERC, to reflect CMP's and the New England Power Pool's actual costs for 2003.

CMP Electricity Supply Responsibility: Under a Maine State Law adopted in 1997, CMP was mandated to sell its generation assets and relinquish its supply responsibility. CMP no longer owns any generating assets but retains its power entitlements under long-term contracts with NUGs and a power purchase contract with Vermont Yankee. In December 2004 the MPUC approved CMP's sale of those entitlements for various periods ranging from one to three years, through February 29, 2008, depending on the type of entitlement. CMP's retail electricity prices are set to provide recovery of the costs in excess of the entitlement sale associated with its ongoing power entitlement obligations.

Under Maine State Law the MPUC can mandate that CMP be a standard-offer provider of electricity supply service for retail customers if the MPUC should deem bids by competitive suppliers to be unacceptable. In January 2005 the MPUC chose suppliers of standard-offer electricity for the six months ending August 31, 2005, for the medium and large customer classes. In December 2004 the MPUC chose CEC Group as the new supplier of standard-offer electricity to CMP's residential and small commercial customers (100% for the first year, 66.6% for the second year and 33.3% for the third year) for a three-year period beginning March 1, 2005. CMP has no standard-offer obligations through August 2005 and has not had any standard-offer obligations since March 2002. If in the future CMP should have standard-offer obligations, there would be no effect on its net income because CMP is ensured cost recovery through Maine State Law for any standard-offer obligations. CMP's revenues and purchased power costs would fluctuate, however, if it were required to be a standard-offer provider. (See the company's Operating Results for the Electric Delivery Business, CMP's Results of Operations and Note 10 to the company's and Note 8 to CMP's Consolidated Financial Statements.)

CMP Stranded Cost Proceeding: Through its stranded cost rates, 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, pursuant to Maine statute. In January 2005 the MPUC approved new stranded cost rates for the three-year period ending February 2008.

Pursuant to the 2000 Settlement, on July 1, 2004, Connecticut Yankee filed a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of the costs of decommissioning. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars compared to the April 2000 estimate of $434 million approved in the 2000 Settlement. The revised estimate reflects the fact that Connecticut Yankee is now self-performing all work to complete the decommissioning of the plant due to the termination of Bechtel, the turnkey decommissioning contractor, in July 2003. In addition, the revised estimate reflects increases in the projected costs for spent fuel storage, security, and liability and property insurance. The estimated remaining costs for decommissioning and long-term spent fuel storage as of December 31, 2003, totaled approximately $504 million in 2003 dollars.

Connecticut Yankee is seeking recovery of incremental decommissioning costs and other damages from Bechtel and, if necessary, its surety. In response, Bechtel has filed a complaint in Connecticut Superior Court seeking damages of $93 million for wrongful termination of the decommissioning contract. Connecticut Yankee has filed counterclaims for excess completion costs and other damages. Discovery is under way and a trial is scheduled for May 2006. CMP cannot predict the outcome of this litigation.

The revised schedule for decommissioning collections is based on the 2003 estimate. Based on the revised schedule, increased collections of $93 million annually commenced in January 2005 and extend through December 2010. Any increase in rates approved by the FERC will be charged to Connecticut Yankee's owners, including CMP, whose share of a $93 million increase would be approximately $6 million. Under regulatory settlements, CMP is allowed to defer for future recovery any increases in decommissioning costs. Pursuant to a recent stranded cost settlement, CMP will begin to collect the higher Connecticut Yankee decommissioning costs through rates in March 2005.

On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel filed a petition with the FERC asking it to determine that, if the FERC should find any of Connecticut Yankee's decommissioning costs were not prudently incurred, the owners may not recover those costs in rates that are ultimately charged to retail customers. Instead, the DPUC believes that the owners of Connecticut Yankee must bear the costs. Connecticut Yankee and its owners, including CMP, filed protests to contest this petition. On August 30, 2004, the FERC rejected the DPUC's petition; approved Connecticut Yankee's rate increase effective February 1, 2005, subject to refund; and set for hearing the remaining issues. The DPUC has requested rehearing of the FERC's August 30, 2004 Order. CMP cannot predict the outcome of these proceedings.

NYSEG Electric Rate Plan: In February 2002 the NYPSC issued an order approving a five-year NYSEG electric rate plan, which extends through December 31, 2006, and Energy East's merger with RGS Energy. NYSEG's and the company's earnings were lower in 2002 as a result of the electric rate plan because NYSEG's electric rates were adjusted to reflect the sale of generation assets completed in 1999.

The NYPSC February 2002 Order reduced annualized electric rates by $205 million for NYSEG customers effective March 1, 2002, which amounted to an overall average reduction of 13% for most customers. In the first rate year ending December 31, 2002, approximately $55 million of the annualized reduction was funded with the partial amortization of an ASGA created as a result of NYSEG's sale in 2001 of its interest in NMP2. The NYPSC February 2002 Order also requires equal sharing of earnings between NYSEG customers and shareholders of ROEs in excess of 15.5% for 2002, and equal sharing of the greater of ROEs in excess of 12.5% on electric delivery, or 15.5% on the total electric business (including supply) 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, which approximates $720 million. Earnings levels were sufficient to generate estimated sharing with customers of $17 million in 2004 and $7 million in&nbs p;2003.

Nonutility Generation: CMP and NYSEG together expensed approximately $613 million for NUG power in 2004. They estimate that their combined NUG power purchases will total $674 million in 2005, $615 million in 2006, $563 million in 2007, $381 million in 2008 and $229 million in 2009. 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 2004, averaged 9.5 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 NYSEG's current electric rate plan. (See Note 10 to the company's and Note 8 to CMP's Consolidated Financial Statements and Note 8 to NYSEG's Financial Statements.)

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a 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. In January 2004 the NYPSC issued a notice seeking additional comments in light of the passage of time and the evolution of competitive markets. In March and April 2004 NYSEG and RG&E submitted comments supporting periodic assessment of the retail competitive marketplace and opposing the adoption of any policies restricting customer choice of supplier or limiting the availability of supply options from any particular supplier. 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.

On August 25, 2004, the NYPSC issued a Statement of Policy on Further Steps Toward Competition in Retail Energy Markets 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 will be required to prepare plans to foster the development of retail energy markets. The plans can vary by individual utility, and NYSEG and RG&E do not expect that statement of policy to affect their commodity service options under their current rate plans.

In a separate phase of this proceeding, on August 25, 2004, the NYPSC issued a Statement of Policy on Unbundling and Order Directing Tariff Filings. Utilities are directed to file embedded cost studies and competitive rates in future rate plans or requests for extensions and to begin tracking the costs of and revenues generated by competitive energy services. The order also allows parties to file comments and replies on rate design issues discussed in the order.

NYSEG and RG&E are not able to predict what effect, if any, these latest developments will have on future operations.

New England RTO: In January 2003, in order to promote RTOs, the FERC issued a proposed policy statement on transmission pricing. The FERC proposed a 50 basis point ROE incentive adder on facilities for which transmission owners turn control over to an RTO and a 100 basis point ROE incentive adder for new transmission facilities found appropriate through an RTO planning process. In October 2003 ISO New England and the New England transmission owners, including CMP, made a joint filing with the FERC to establish ISO New England as a qualified RTO. As an RTO, ISO New England will be responsible for the independent operation of the regional transmission system and regional wholesale energy market. The transmission owners will retain ownership of their transmission facilities and control over their revenue requirements. In a related filing, in November 2003 the New England transmission owners, including CMP, requested a joint baseline ROE and the above incentives as part of the proposal for a 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. The order approved the 50 basis point and the 100 basis point ROE incentive adders, but limited application of the 100 basis point adder to regional facilities, subject to suspension, hearing and application of the

FERC's Pricing Policy Statement, when it is issued. The order also accepted, subject to suspension and hearing, the New England transmission owners' proposed base level ROE of 12.8% applicable to rates for local and regional transmission service, to be effective, subject to refund, on the New England RTO operational commencement date, February 1, 2005. Evidentiary hearings on the final base level ROE and the incentive for new transmission investment began on January 25, 2005. A final decision from the FERC on those issues is not expected until the end of 2005. The New England transmission owners and ISO New England implemented the New England RTO effective February 1, 2005.

FERC Standard Market Design: In October 2001 FERC commenced a proceeding to consider national SMD issues, and in July 2002 issued a NOPR concerning those issues. The SMD NOPR proposes rules that would require, among other things, changes in the wholesale power markets, transmission planning, services and charges, market power monitoring and mitigation, and the organization and structure of ISOs. CMP, NYSEG and RG&E filed comments jointly with other transmission owners in November 2002 and in early 2003. In April 2003 the FERC issued a white paper on SMD in which the FERC accommodates greater regional flexibility and seeks further comments. The SMD white paper includes a preference for energy markets based on LMP, which represents a significant change for some regions of the country. The NYISO and ISO New England already operate markets based on LMP. The comp anies are not able to predict the SMD's ultimate effect, if any, on their results of operations or financial position. The LMP market design was incorporated into the New England RTO filing approved by the FERC, which is discussed above.

Transmission Planning and Expansion and Generation Interconnection: In July 2003 ISO New England and the NEPOOL submitted a filing to the FERC concerning transmission expansion cost allocation, which the FERC approved in December 2003. CMP, among other parties, requested rehearing of that FERC decision, arguing that it would require customers who would not benefit from new transmission projects to contribute to those project costs. On December 2, 2004, the FERC denied rehearing of its order. ISO New England and other parties filed a motion for clarification. The FERC issued an order on January 5, 2005, granting clarification and deciding that all of the pending transmission projects would be subject to the ISO New England cost allocation process.

The FERC approved the NYISO's comprehensive planning process for reliability needs on December 28, 2004, requiring several relatively minor changes to the NYISO proposal. NYSEG and RG&E support the NYISO plan. The NYISO made a related compliance filing on February 28, 2005. On February 25, 2005, the FERC issued an order giving itself more time to issue a decision on requests for rehearing related to this issue. Discussions continue among the NYISO market participants on an economic planning process.

In July 2003 the FERC issued Order 2003 regarding generation interconnection terms, conditions and cost allocation that would require modifications to the companies' interconnection processes. The FERC issued Order 2003-A in March 2004 and Order 2003-B in December 2004, reaffirming its determinations in Order 2003, clarifying certain provisions, and directing compliance. On February 18, 2005, the NYISO and the NYTOs submitted a joint compliance filing, pursuant to Order 2003-B, to modify certain sections of the Large Facility Interconnection Procedures and Large Facility Interconnection Agreement contained in the NYISO Open Access Transmission Tariff. Comments on the filing were due on March 11, 2005.

In January and April 2004 the NEPOOL and the New England transmission owners made separate compliance filings in response to Orders 2003 and 2003-A. In November 2004 the FERC issued an order that accepted the NEPOOL filing in part and rejected the New England transmission owners' filing. On January 28, 2005, ISO New England and the New England transmission owners made a joint compliance filing, to supersede and replace their earlier separate filings, proposing a standardized agreement and single set of procedures for generators rated 5 megawatts or greater seeking interconnection service under the RTO tariff on or after February 1, 2005.

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. The RG&E action is also being mediated and the parties are in the final stages of discovery. RG&E and NYSEG are unable to predict the outcome of these actions at this time.

NYISO Billing Adjustment: The NYISO frequently bills transmission owners on a retroactive basis when adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission revenue or expense as appropriate when revised amounts can be estimated. On January 25, 2005, the NYISO notified NYTOs, including NYSEG and RG&E, of a revenue allocation formula error related to transmission congestion contracts for periods including May 2000 through October 2002. The NYISO has not yet provided any further details. The correction of the error may result in revised billings for NYSEG and RG&E. The companies cannot predict at this time either the magnitude or the direction of any billing adjustments.

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 locational installed capacity (LICAP) market proposal based on an administratively set demand curve. The FERC has refused to consider alternatives to ISO New England's proposal and has set issues regarding the exact LICAP parameters and its implementation for hearing before a FERC administrative law judge. CMP and other parties representing customers who would ultimately pay the cost of the LICAP charges as a component of energy supply costs have opposed the FERC orders requiring an administratively set capacity market and ISO New England's partic ular proposal. Generators that supply capacity in ISO New England's market have generally supported the FERC's order and the basic design of ISO New England's proposal. A recommended decision by the FERC administrative law judge is expected by June 1, 2005. CMP cannot predict how the FERC will rule on the filing or what modifications the FERC might make to the filing.

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, which is outside the company's service territory. All New York utilities were directed to respond by February 19, 2005, with a report that provides 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. In addition, penalties for failure to achieve annual performance targets for testing and inspections were establi shed at 75 basis points each. NYSEG and RG&E have reviewed the NYPSC order and jointly filed in early February 2005, with two other New York State utilities, a petition for rehearing 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. NYSEG and RG&E do not know what actions will be taken on the petitions for rehearing. In late February 2005 NYSEG and RG&E filed a testing and inspection plan in response to the order consistent with the timetable identified in the above noted joint petition for rehearing.

CMP Union Contract: Effective April 30, 2004, the union contract expired between CMP and the local union of the International Brotherhood of Electrical Workers. On May 5, 2004, the union membership voted to accept CMP's offer for a new contract, which expires on April 30, 2009. The contract provides for wage increases of 3.25% in 2004, 3.0% in each year 2005, 2006 and 2007, and 2.75% in 2008. It also includes provisions for active employees to contribute to medical insurance plans by the end of the contract period and for employees who retire on or after July 1, 2005, to contribute toward the cost of medical insurance according to a predetermined schedule.

NYSEG Union Contract: The contract between NYSEG and the local unions of the International Brotherhood of Electrical Workers was scheduled to expire effective July 1, 2005. On October 19, 2004, the union membership voted to accept NYSEG's offer to extend the contract until June 30, 2010. The contract provides for annual 3% wage increases for 2005 through 2009. It includes provisions for active employees to contribute to medical insurance plans by the end of the contract period.

RG&E Union Contract: In April 2003 RG&E's electric and natural gas field operations personnel voted to be represented by the International Brotherhood of Electrical Workers. RG&E recognizes the employees' right to make this decision and respects the collective votes of its employees. A negotiated labor agreement is in effect for the period September 2003 through May 2008. The agreement provides for annual 3% wage increases.

The company's natural gas delivery business consists of its regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts.

Natural Gas Supply Agreements: Energy East's natural gas companies - NYSEG, RG&E, SCG, CNG, Berkshire Gas and Maine Natural Gas - 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.

NYSEG Natural Gas Rate Plan: NYSEG's Natural Gas Rate Plan, which became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, implements a natural gas supply charge to collect the actual costs of natural gas and contains an earnings-sharing 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 2004 or 2003.

On June 30, 2004, NYSEG filed a Joint Proposal, executed by NYSEG and other parties, to resolve outstanding issues in NYSEG's Natural Gas Rate Plan related to its natural gas delivery rate design, natural gas economic development plan and its natural gas Affordable Energy Program. Pursuant to NYSEG's Natural Gas Rate Plan, delivery rate designs in the Joint Proposal were developed for each of the remaining years on an overall revenue neutral manner, consistent with the billing units and firm delivery revenues contained in NYSEG's Natural Gas Rate Plan. The NYPSC approved all provisions of the Joint Proposal effective September 23, 2004. The first year of a five-year phase-in of delivery rates for nonresidential customers went into effect October 1, 2004. The first of four annual changes to residential rates will become effective October 1, 2005.

SCG Request for Recovery of Exogenous Costs: In December 2003 SCG filed an application with the DPUC to recover approximately $21 million of exogenous costs under its approved IRP. The exogenous costs to be recovered include qualified pension and other postretirement benefits expenses, taxes, uncollectible expense and the cost of SCG's Customer Hardship Arrearage Forgiveness Program. Those costs were the result of events that were unanticipated and beyond SCG's control. SCG's IRP decision from the DPUC allows SCG to petition for relief from substantial and material costs resulting from such exogenous events. The DPUC established a docket for this proceeding and hearings were held in April 2004. On October 27, 2004, the DPUC issued a final decision that denied current recovery of exogenous costs but recognized that the costs would be reviewed in SCG's next rate case. On December 9, 2004, SCG filed an appeal with the Connecticut Superior Court concerning certain aspects of the DPUC's decision.

Connecticut Regulatory Proceedings: SCG's IRP expires September 30, 2005. As a result of the DPUC's decision denying recovery of exogenous costs, SCG anticipates filing for rate relief in the second quarter of 2005. The rate filing will request, among other items, a greater level of recovery of deferred costs, similar to SCG's request for recovery of exogenous costs. CNG's IRP expires September 30, 2005, and CNG has notified the DPUC that it intends to continue to operate under an IRP for another multi-year period.

Connecticut Merger-Enabled Gas Supply Savings and Gas Cost Reduction Plan Filings: In 2001 CNG and SCG submitted filings to the DPUC regarding MEGS and a gas-cost reduction plan, which covered the initial period April 1, 2001, through September 30, 2001. CNG provided calculations for total MEGS of $1.3 million and SCG provided calculations for total MEGS of $2.2 million. In February 2003, based on its understanding of the components of the MEGS, the DPUC issued a draft decision on CNG's and SCG's filed MEGS and gas-cost reduction plan results, modifying the MEGS amounts to $134,000 for CNG and $9,000 for SCG. CNG and SCG filed comments and additional detail with regard to the draft decision. On March 26, 2004, the DPUC issued a notice that encouraged the parties to settle the MEGS issue, which resulted in the assignment of Prosecutorial Staff of the DPUC to assist in the settlement process. The docket was suspended to allow the settlement process to proceed. On September 22, 2004, Prosecutorial St aff reported that the parties had reached an agreement in principle to settle these proceedings. On December 17, 2004, a settlement between SCG, CNG, the Office of Consumer Counsel and the Prosecutorial Division of the Department was filed with the DPUC. The settlement fully resolves the companies' claims to MEGS. Hearings took place in February 2005 and the final decision on this settlement was approved on February 23, 2005.

Berkshire Gas Union Contract: Effective April 1, 2003, the union contract expired between Berkshire Gas and the local union of the United Steelworkers of America. In 2004 the union members voted to accept Berkshire Gas' offer of a new contract that will expire on March 31, 2009. The contract provides for wage increases of 3% for each year of the contract.

The company's other businesses include a nonutility generating company, retail energy marketing companies, telecommunications assets, a district heating and cooling system, a FERC-regulated liquefied natural gas peaking plant and an energy services company.

Sale of Other Businesses: The company continues to rationalize its nonutility businesses to ensure that they fit its strategic focus. On July 26, 2004, UWP, a subsidiary of CMP Group, sold all of the assets related to its utility locating and construction divisions. The after-tax loss resulting from the sale was approximately $7 million and includes a reduction in the goodwill that was assigned to UWP at the time of Energy East's purchase of CMP Group. On October 1, 2004, Energy East Solutions, Inc., a subsidiary of The Energy Network, Inc., completed the sale of its New England and Pennsylvania natural gas customer contracts and related assets. (See Note 3 to the company's Consolidated Financial Statements.)

Statement 123R: In December 2004 the FASB issued Statement 123R, which is a revision of Statement No. 123. Statement 123R 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 123R also requires a public entity to initially measure the cost of employee services received in exchange for an award of liability instruments 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. The company's adoption of Statement 123R is not expected to have a material effect on its fin ancial position or results of operations. (See Note 1 to the company's Consolidated Financial Statements.)

At December 31, 2004, the company's contractual obligations and commercial commitments are: