CMP has ownership interests in three nuclear generating facilities: Maine Yankee in Wiscasset, Maine, 38%; Yankee Atomic in Rowe, Massachusetts, 9.5%; and Connecticut Yankee in Haddam, Connecticut, 6%. The three facilities have been permanently shut down and are in the process of being decommissioned.

CMP owns 301 substations in Maine having an aggregate transformer capacity of 6,540,084 kilovolt-amperes (Kva). The transmission system consists of 2,555 circuit miles of line. The distribution system consists of 22,555 pole miles of overhead lines and 152 miles of underground lines.

NYSEG owns 430 substations in New York having an aggregate transformer capacity of 12,710,587 Kva. The transmission system consists of 4,389 circuit miles of line. The distribution system consists of 34,201 pole miles of overhead lines and 2,452 miles of underground lines.

RG&E owns 162 substations in New York having an aggregate transformer capacity of 5,851,000 Kva. The transmission system consists of 763 circuit miles of overhead lines and 502 circuit miles of underground lines. The distribution system consists of 16,533 circuit miles of overhead lines and 4,551 circuit miles of underground lines.

The operating companies' natural gas systems consist of the following:

A portion of the company's utility plant is subject to liens or mortgages securing its subsidiaries' first mortgage bonds. None of CMP's or NYSEG's utility plant is subject to liens or mortgages securing first mortgage bonds. RG&E's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all of its properties. (See Item 8 - Note 7 to the company's and Note 5 to CMP's Consolidated Financial Statements, and Note 5 to NYSEG's and RG&E's Financial Statements.)

Item 3.  Legal proceedings
(See Item 7 - Electric Delivery Business and Natural Gas Delivery Business and Item 8 - Note 12 to the company's and Note 10 to CMP's Consolidated Financial Statements, and Note 10 to NYSEG's and RG&E's Financial Statements.)

Since the New York State Public Service Commission (NYPSC), Connecticut Department of Public Utility Control (DPUC), MPUC and Massachusetts Department of Telecommunications and Energy (DTE) have allowed the company's operating companies to recover in rates remediation costs for certain of the sites referred to in the second and fourth paragraphs of Note 12 to the company's and Note 10 to CMP's Consolidated Financial Statements and the second and fourth paragraphs of Note 10 to NYSEG's and RG&E's Financial Statements there is a reasonable basis to conclude that such operating companies will be permitted to recover in rates any remediation costs that they may incur for all of the sites referred to in those paragraphs. Therefore, the company, CMP, NYSEG and RG&E believe that the ultimate disposition of the matters referred to in the paragraphs of the Notes referred to above will not have a material adverse effect on their results of operations or financial position.

(a)  In August 1997 NYSEG was notified by the New York State Department of Environmental Conservation (NYSDEC) that NYSDEC was contemplating enforcement action against NYSEG with respect to violations of regulations concerning opacity of air emissions at all of the company's New York coal-fired stations. NYSEG is in the process of negotiating a consent order with the NYSDEC to resolve the NYSDEC's demand for a penalty of approximately $650,000. NYSEG sold its New York coal-fired stations to The AES Corporation (AES) in May 1999.

(b)  NYSEG received a letter in October 1999 from the New York State Attorney General's office alleging that NYSEG may have constructed and operated major modifications to certain emission sources at the Goudey and Greenidge generating stations, which it formerly owned, without obtaining the required prevention of significant deterioration or new source review permits. The Goudey and Greenidge plants were sold to AES in May 1999. The letter requested that NYSEG and AES provide the Attorney General's office with a large number of documents relating to this allegation. In January 2000 NYSEG received a subpoena from the NYSDEC ordering production of similar documents. The NYSDEC subsequently requested similar documents with respect to the Hickling and Jennison generating stations, which the company formerly owned. Those stations were also sold to AES in May 1999.

In April 2000 NYSEG received a letter from the EPA requesting information with respect to the operation of the Milliken and Kintigh generating stations, which the company formerly owned. Those stations were also sold to AES in May 1999. NYSEG furnished documents pursuant to the Attorney General's, NYSDEC's and EPA's requests.

In May 2000 NYSEG received a notice of violation from the NYSDEC alleging that two projects at Goudey and four projects at Greenidge were constructed without the necessary permits having been obtained.

In April 2001 EPA notified NYSEG by telephone that EPA would be issuing notices of violation alleging that various projects at the Milliken and Kintigh generating stations were constructed without the necessary permits having been obtained.

NYSEG believes it has complied with the applicable rules and regulations and there is no basis for the Attorney General's, NYSDEC's and EPA's allegations. NYSEG believes that any liability related to this matter will be the responsibility of AES in accordance with the asset purchase agreement.

In April 2002 the Attorney General's office and the NYSDEC entered into an agreement to delay the applicable statute of limitations with respect to alleged new source review violations. That agreement has been extended several times and remains in effect.

(c)  In October 2000 NYSEG and Pennsylvania Electric Company (Penelec) received a letter from EME Homer City Generation, L.P. (EME), a subsidiary of the purchaser of the Homer City generating station (Station) in which NYSEG and Penelec each formerly owned a one-half interest. The letter gave NYSEG and Penelec notice that the EPA has found alleged violations of the federal Clean Air Act related to the Station. EME has indicated that it will claim that certain fines, penalties and costs arising out of or related to these alleged violations, which NYSEG believes may be material, are liabilities retained by NYSEG and Penelec under the terms of the asset purchase agreement for the Station. While it will continue to examine this matter, NYSEG believes that such fines, penalties and costs are not liabilities retained by it.

(d)  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 complied with the subpoena and supplied documents.

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 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 NYSDEC's allegations. RG&E is not able to predict the outcome of this matter. A number of options that would resolve the notice of violation are under investigation.

Item 4.  Submission of matters to a vote of security holders

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

* * * * * * * * * * *

Wesley W. von Schack and Kenneth M. Jasinski each have an employment agreement for a term ending February 7, 2007. Mr. von Schack's agreement provides for his employment as Chairman, President & Chief Executive Officer of the company and Mr. Jasinski's agreement provides for his employment as Executive Vice President and Chief Financial Officer of the company. Each agreement provides for automatic one-year extensions unless either party to an agreement gives notice that such agreement is not to be extended. Michael I. German has an employment agreement for a term ending on July 31, 2005. Mr. German's agreement provides for his employment as President of The Southern Connecticut Gas Company, Connecticut Natural Gas Corporation, Maine Natural Gas Corporation and New Hampshire Gas Corporation.

Robert M. Allessio, Sara J. Burns and F. Michael McClain each have an employment agreement for a term of three years beginning September 1, 2000, which is automatically extended each month unless either party to an agreement gives written notice that it is not to be extended. Ms. Burns' agreement provides for her employment as President of CMP and Mr. Allessio's agreement provides for his employment as President and Chief Executive Officer of Berkshire Gas.

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

Item 5.  Market for Registrants' common equity and related stockholder matters

See Item 8 - Note 18 to the company's Consolidated Financial Statements.

CMP Group, a wholly-owned subsidiary of Energy East, owns all of CMP's common stock. See Item 8 - CMP's Consolidated Statements of Changes in Common Stock Equity for information regarding dividends declared.

RGS Energy, a wholly-owned subsidiary of Energy East, owns all of NYSEG's and all of RG&E's common stock. See Item 8 - NYSEG's and RG&E's Statements of Changes in Common Stock Equity for information regarding dividends declared.

Item 6.  Selected financial data

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

Item 7.  Management's discussion and analysis of financial condition and results of operations

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:

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

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 derivative transactions. (See Item 8 - Note 1 to the company'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. The companies estimate that, at December 31, 2003, a 1% change in average interest rates would change annual interest expense for variable rate debt by about $8 million for Energy East, including $0.3 million for CMP, $1.7 million for NYSEG and $0.7 million for RG&E. (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 12 to NYSEG's and Notes 5, 6 and 11 to RG&E's Financial Statements.)

The companies also use financial instruments to lock in the treasury rate component of future financings to mitigate risk resulting from interest rate changes.

Commodity Price Risk: Commodity price risk is a significant issue for the company, NYSEG and RG&E due to volatility experienced in both the electric and natural gas 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 and natural gas to customers, and through comprehensive risk management processes. These measures mitigate the companies' commodity price exposure, but do not completely eliminate it.

Although CMP has no long-term supply responsibilities, the MPUC can mandate that CMP be a standard-offer provider for supply service should bids by competitive suppliers be deemed unacceptable by the MPUC. CMP has no standard-offer obligations through August 2004. (See Item 7 - CMP Electricity Supply Responsibility.) In September 2001 the MPUC chose Constellation Power Source Maine, LLC as the new supplier of standard-offer electricity to CMP's residential and small commercial standard-offer class for a three-year period beginning March 1, 2002. In January 2004 the MPUC chose suppliers of standard-offer electricity for the six months beginning March 1, 2004, for the medium and large customer classes.

NYSEG and RG&E 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 a variable rate option, an option to purchase electricity supply from an alternative energy company, and a bundled rate option. Approximately 32% of NYSEG's total electric load is now provided by an alternative energy company 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. For 2004 the supply component is based on average electricity forward prices for 2004 during September 2002, plus a 35% margin to cover the costs and risk that NYSEG is assuming by providing a bundled rate option to retail customers. NYSEG actively hedges the load required to serve customers who select the bundled rate option. As of January 30, 2004, NYSEG's load was 94% hedged for on-peak periods and 83% hedged for off-peak periods in 2004 . A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.7 million in 2004. 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 differ as a result of changes in the load compared to the load forecast.

RG&E faces commodity price risk that relates to market fluctuations in the price of electricity. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. As of January 30, 2004, RG&E's load was 94% hedged for on-peak periods and fully hedged for off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of summer on-peak electricity would change earnings by $0.2 million in 2004. 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. RG&E filed a request with the NYPSC for new electric rates in May 2003. The NYPSC has not ruled on the rate request; therefore, RG&E's current electric rates will remain in effect until a new rate order is issued. A new rate order is expected to be iss ued in August 2004, subject to a make whole provision to April 2004. (See Item 7 - RG&E 2002 and 2003 Electric and Gas Rate Proceedings.)

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.

All of Energy East's natural gas utilities, except Maine Natural Gas, 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. (See Item 7 - Natural Gas Supply Agreements, NYSEG Natural Gas Rate Plan and Connecticut Regulatory Proceedings.)

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 when the related sales commitments are fulfilled.

The broad and continued decline in credit quality across the energy supply and marketing industries, combined with the withdrawal of many entities from energy trading operations, could limit the companies' ability to purchase electricity and place financial hedges with counterparties that meet their credit requirements. While the companies have been successful in implementing their hedging strategies by finding creditworthy counterparties or requiring adequate financial assurances in the form of cash or letters of credit, continued contraction and credit deterioration across the energy supply and marketing industries may adversely affect the companies' ability to effectively implement their hedging strategies going forward.

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, $3.5 million for NYSEG and $1.5 million for RG&E). A change of 1/4% in the discount rate would also result in a change in pension income of $6 million. (See Item 8 - Note 16 to the company's and Note 13 to CMP's Consolidated Financial Statements, and Note 13 to NYSEG's and Note 12 to RG&E's Financial Statements.)

This Form 10-K contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements.

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties and that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated industry; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of changing energy prices; the operation of the New York Independent System Operator and ISO New England, Inc.; the operation of a regional transmission organization; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements; the company's ability to expand its products and services, including its energy infrastructure in the Northeast; the compa ny's ability to integrate the operations of Berkshire Energy, CMP Group, CNE, CTG Resources and RGS Energy; the company's ability to achieve enterprise-wide integration synergies; market risk; the ability to obtain adequate and timely rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; and other considerations, such as the effect of the volatility in the equity markets on pension benefit cost, that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 8.  Financial statements and supplementary data

Index to 2003 Financial Statements

Item  9.  Changes in and disagreements with accountants on accounting and
financial disclosure

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

Item  9A.  Controls and Procedures

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 Securities and Exchange Commission'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, CMP, NYSEG and RG&E each maintain a system of internal control over financial reporting designed to provide reasonable assurance to its management and board of directors regarding the preparation of reliable published financial statements and the safeguarding of assets against loss or unauthorized use. Each company's system of internal control over financial reporting contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. 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.

Reclassifications: Certain amounts included in Selected Financial Data have been reclassified to conform to the 2003 presentation.

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. As discussed below, management has implemented plans to achieve savings through a company-wide restructuring, consolidation of utility support services and other changes.

In addition, because 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 operations and, therefore, its financial position and results of operations. Energy East has long-term rate plans for NYSEG, CMP, CNG, SCG and Berkshire Gas. The plans 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 five operating companies. As discussed below, the company is currently seeking approval of new rates for RG&E.

Over the last several years Energy East has changed its strategic focus to its electric and natural gas delivery operations, rather than on the more volatile electricity generation business, and has sought to rationalize its nonutility businesses to ensure they fit its strategic focus. As discussed below, during 2003 the company reached an agreement to sell its Ginna station and completed the sale of two of its nonutility businesses.

The continuing 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 those proceedings are difficult to predict. These proceedings could have an effect on the nature of the electric and natural gas utility industry in New York and New England and are described below.

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

In 2002 Energy East initiated a corporate restructuring designed to achieve optimum organizational efficiency and effectiveness. The savings from this initiative are essential for the company to meet the rate reduction or efficiency targets imputed in utility rates by regulators, as well as to meet the expectations of customers and investors. In the fourth quarter of 2002 Energy East recorded $41 million of restructuring expenses related to its voluntary early retirement and involuntary severance programs at six of its operating companies. The restructuring expenses would have been $36 million higher, however, RG&E was required by an NYPSC order approving RGS Energy's merger with the company to defer its portion of the

restructuring charge for future recovery in rates. During 2003 the entire related involuntary severance liability of $9 million was paid, including $4 million that was deferred for recovery by RG&E.

The voluntary early retirement program resulted in a reduction of 486 employees in the first quarter of 2003. Collectively the voluntary early retirement and involuntary severance programs resulted in a reduction in overall employee headcount of 678, or 8%, in 2003, including 79 from CMP, 255 from NYSEG and 253 from RG&E.

Integration savings are expected to be approximately $100 million annually by 2006. Those savings, which include reductions in operating expenses and capital expenditures, will come from the consolidation of functions such as accounting, finance, information services and purchasing, as well as the implementation of other merger-enabled initiatives across the six operating utilities. The company completed its consolidation of information systems and purchasing functions during the second quarter of 2003. On September 30, 2003, Energy East received authorization from the SEC to form a shared services company that provides services, including accounting, treasury, information services, payroll and purchasing functions, to six operating companies.

The company has consolidated the accounting and finance functions of five of its operating companies to one location and has reorganized and relocated the accounting and finance functions of its management subsidiary. In connection with this restructuring, in the fourth quarter of 2003 Energy East recognized $2 million of an estimated liability of $4 million for an enhanced severance program for certain accounting and finance employees who will be employed through March 31, 2004.

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

RG&E 2002 Electric and Gas Rate Proceeding: In February 2002 RG&E filed a request with the NYPSC for new electric and natural gas rates to go into effect on January 15, 2003. The single year filing, as updated, supported an increase in annual electric rates of $40 million, or 5.7%, and an increase in natural gas rates of $19 million, or 6.6%. In December 2002 the administrative law judge (ALJ) in this proceeding issued a recommended decision that, if approved, would have resulted in a $9 million, or 3.3%, overall increase for natural gas service and no increase for electric service.

On March 7, 2003, the NYPSC issued an order (Order) in the proceeding authorizing a $16 million electric revenue requirement reduction. The order requires a $16 million increase in the amortization of previously deferred costs. The NYPSC also limited the natural gas rate increase to $6 million, or 1.9%. The rate decision set the cost of equity at 9.96%, based on an equity ratio of 41.4% and an overall weighted cost of capital of 8.11%. The NYPSC also credited to customers $55 million of electric earnings that, according to the NYPSC, exceeded a preset level under the five-year rate plan that expired on June 30, 2002, subject to a final audit of the fifth year amount. The NYPSC also ignored the costs of replacement power that were incurred during the required Ginna refueling outage in the fall of 2003.

RG&E was disappointed with the Order because it ignored the record that was developed in the proceeding, reversed many of the recommendations of the ALJ without adequate explanation and did not provide adequate revenue for RG&E to earn its authorized rate of return. In May 2003 RG&E began a proceeding to appeal the most objectionable errors in the Order. That proceeding is now before the Appellate Division, Third Department, of the New York State Supreme Court. A decision on the proceeding is expected in 2004.

RG&E Cost Deferral Petitions: On April 9, 2003, RG&E filed a letter with the NYPSC requesting the deferral of costs, including interest, for restoration work resulting from a severe ice storm in April 2003 and replacement purchased power costs incurred in 2003 in connection with a scheduled refueling outage for Ginna. The deferred costs are $35 million for repairs required due to the ice storm and $15 million for the Ginna replacement purchased power. These costs are included in RG&E's 2003 Electric and Gas Rate Proceeding described below.

On April 29, 2003, RG&E received a response from the NYPSC that described the NYPSC's history of allowing net prudent costs of this nature, which have a material effect on earnings, to be deferred and recovered from customers. The letter acknowledged that the ice storm and the Ginna replacement purchased power costs are not currently included in RG&E's rates. In its litigation case filed on December 31, 2003 (see RG&E 2003 Electric and Gas Rate Proceeding), the Staff of the NYPSC recommends against recovery of the Ginna replacement purchased power costs as part of the rate case because it has not completed its review. Nevertheless, based on the NYPSC letter, RG&E believes that recovery is probable and has deferred those costs pending approval from the NYPSC, which is expected in 2004.

On May 15, 2003, RG&E filed a letter with the NYPSC seeking deferral and true up of an estimated $9 million of pension costs in accordance with the NYPSC's Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Post Retirement Benefits Other than Pensions. The request covers the 16-month period from January 1, 2003, through May 1, 2004, the expected effective date of rates in RG&E's 2003 Electric and Gas Rate Proceeding. In its litigation case filed on December 31, 2003, the Staff of the NYPSC recommends against recovery of these pension costs as part of the rate case because it has not completed its review.

RG&E 2003 Electric and Gas Rate Proceeding: On May 16, 2003, RG&E filed a new rate case with the NYPSC to recover costs that RG&E has incurred and will continue to incur in providing safe and reliable electric and natural gas service. The filing proposed an annual increase in electric rates of $105 million, or 16.2%, and an annual increase in natural gas rates of $25 million, or 7.6% overall and 19.7% on delivery rates. In August 2003 RG&E submitted rate revisions requesting a $98 million annual electric rate increase and a $25 million annual natural gas rate increase. In February 2004 RG&E submitted further rate revisions based on continued review of its filing, requesting instead an $80 million annual electric rate increase and a $21 million annual natural gas rate increase. RG&E's filing cites inadequate rate relief from the NYPSC's Order issued March 7, 2003, increased costs (see RG&E Cost Deferral Petitions) and the need for a fair and reasonable return on equity (ROE) of 11.25%. In order to allow negotiations for a long-term rate plan, the NYPSC issued four orders in October and November 2003 granting RG&E's requests for extensions of the date for rates to become effective, subject to a make whole provision back to April 29, 2004.

On November 19, 2003, RG&E, Staff of the NYPSC and other parties reached a detailed, comprehensive Agreement in Principle on five-year electric and natural gas rate plans. In the process of converting that Agreement in Principle to a Settlement Agreement, RG&E, Staff and certain intervenors reached an impasse. As a result, settlement discussions ceased on December 12, 2003, and the case was placed on a litigation track.

On December 22, 2003, Chairman Flynn of the NYPSC issued a one-Commissioner order transferring the ratemaking treatment for the sale of Ginna from RG&E's pending Section 70 filing (see Sale of Ginna Station and Relicensing) to the pending electric rate proceeding. RG&E filed a Petition for Rehearing of that one-Commissioner order on January 9, 2004, and two intervenors subsequently filed an opposition to RG&E's Petition for Rehearing.

Staff's litigation case under this proceeding was filed on December 31, 2003, and proposes to hold electric revenues constant through an electric base rate reduction of $7 million, an acceleration of the amortization of the NMP2 regulatory asset, and the implementation of a $7 million retail access surcharge. Staff is also proposing a natural gas delivery rate reduction of $7 million and the implementation of a $7 million merchant function charge. In January 2004 RG&E filed rebuttal testimony that addressed and took exception to the position taken by the Staff of the NYPSC. The Staff position, if adopted by the NYPSC, would be expected to result in an ROE in 2004 of about 4% for RG&E. Hearings on the electric and natural gas rate requests took place in February 2004. On February 25, 2004, RG&E proposed to further extend the date for rates to become effective and to extend the litigation schedule to provide an opportunity for further settlement negotiations. After the ALJ agreed to the pro posal, settlement discussions resumed on March 2, 2004. RG&E expects the NYPSC to issue a rate order in August 2004, unless long-term rate plans are negotiated and approved earlier.

RG&E Electric Rate Unbundling: On June 5, 2003, as required by the NYPSC's Order issued March 7, 2003, RG&E filed documentation with the NYPSC to unbundle commodity charges from delivery charges and to create electric commodity options for all customers. This filing has been incorporated into the ongoing 2003 Electric and Gas Rate Proceeding. In that proceeding RG&E proposes to continue to charge customers bundled rates, with an Electric Supply Reconciliation Mechanism, for the period May 1, 2004, through December 31, 2004. RG&E's unbundling filing proposes separate delivery and commodity service options (modeled on NYSEG's commodity service options) to become effective January 1, 2005, for two periods of two years: 2005 through 2006 and 2007 through 2008.

Sale of Ginna Station and Relicensing: On November 25, 2003, RG&E announced an agreement to sell Ginna to Constellation Generation Group LLC (CGG). On December 18, 2003, RG&E and CGG jointly filed a revised Section 70 petition with the NYPSC that includes, among other things, all the transaction documents, details of the auction process and RG&E's proposed accounting and ratemaking treatment for the sale. RG&E's ratemaking proposal includes an incentive payment for having maximized the proceeds from the sale of Ginna and 50/50 customer/stockholder sharing of any net gain on the sale of Ginna, to the extent that RG&E's earned ROE exceeds 10.45%, its currently authorized threshold for earnings sharing. RG&E's sale of Ginna is conditioned on receiving all required regulatory approvals, including reasonably satisfactory accounting and ratemaking treatment.

Upon closing of the proposed Ginna sale, RG&E will transfer approximately $202 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. The amount is expected to fully meet the Nuclear Regulatory Commission's (NRC) decommissioning funding requirements for Ginna. It is projected that $59 million in excess decommissioning funds will be retained by RG&E and will be shared with customers as directed by the NYPSC. The sale agreement includes a 10-year purchase power agreement so that RG&E's customers continue to receive the benefit of power from Ginna.

The sale of Ginna is subject to approvals by several regulatory agencies, including the NYPSC, the NRC and FERC. The outcome of these proceedings cannot be determined at this time.

Ginna's operating license expires in 2009. In July 2002 RG&E filed a license renewal application with the NRC, which, if approved, would extend the license to September 19, 2029. The NRC has deemed the application complete. The NRC held two sets of public meetings in 2002 and two in 2003. A decision on this matter is expected in the second quarter of 2004.

In October 2003 RG&E completed the 31st refueling of the reactor core at Ginna, which will support operations through the spring of 2005. During this refueling outage RG&E also successfully replaced Ginna's reactor vessel head as previously scheduled, without significantly extending the duration of the refueling outage as compared to previous outages. Several nuclear power plant operators had identified defects in their reactor vessel heads, which prompted heightened NRC oversight. RG&E thoroughly reviewed the issue and implemented an inspection plan during Ginna's spring 2002 refueling outage. Although the inspection demonstrated that Ginna could continue to operate with the existing reactor vessel head, RG&E decided to replace the reactor vessel head in order to avoid significant expenditures associated with maintenance, inspections and the length of future outages. The cost of the replacement was $14 million and is expected to be recovered in rates.

RG&E Transmission Project: On September 30, 2003, RG&E applied to the NYPSC for approval to upgrade its electric transmission system. The project includes building and rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, NY, area in order to assure adequate service to customers after the anticipated closing of RG&E's 257 megawatt coal-fired Russell Station in 2007. The estimated cost of the multi-year project is $75 million, which is expected to be recovered in rates, and actual construction on the project is expected to begin in the spring of 2005.

CMP Alternative Rate Plan: In September 2000 the MPUC approved CMP's Alternative Rate Plan (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. In March 2003 CMP submitted its annual ARP filing proposing a decrease of 7.82% on the distribution portion of rates, which reflects a decrease in ice storm amortization expense and other items. In June 2003 the MPUC approved the decrease, which became effective July 1, 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 does retain its power entitlements under long-term contracts from NUGs and a power purchase contract with Vermont Yankee and its ownership interests in

three nuclear facilities that have been shut down. CMP has sold the entitlements for a three-year period ending February 28, 2005. CMP's retail electricity prices are set to provide recovery of the costs associated with these ongoing obligations.

Under Maine State Law the MPUC can mandate that CMP be a standard-offer provider for supply service if the MPUC should deem bids by competitive suppliers to be unacceptable. CMP has no standard-offer obligations through August 2004. In January 2004 the MPUC chose a combination of three suppliers of standard-offer electricity for the six months beginning March 1, 2004, for the medium and large customer classes. If in the future CMP should have standard-offer obligations, there would be no effect on net income because CMP is ensured cost recovery through Maine State Law for any standard-offer obligation. CMP's revenues and purchased power costs would fluctuate, however, if its status as a standard-offer provider changes. (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.)

MPUC Stranded Cost Proceeding: In December 2002 the MPUC initiated an investigation to review CMP's current level of recovery of stranded costs, including the costs associated with decommissioning the Yankee Atomic plant. In June 2003 the MPUC approved a stipulation agreeing to a total reduction of $7 million in stranded cost rates over the period July 2003 through February 2005. The reduction reflects lower anticipated Maine Yankee costs and higher sales levels. The stipulation also provides for deferral and recovery of Yankee Atomic decommissioning costs not currently included in rates.

In response to a request from the Industrial Energy Consumers Group to mitigate high supply prices, the MPUC ordered CMP to lower stranded cost prices for medium and large commercial and industrial customers by $.003 per kilowatt-hour for the period July 2003 through February 2005. The mitigation is being funded from CMP's asset sale gain account.

NYSEG Electric Rate Plan: In February 2002 the NYPSC issued an Order (NYPSC February 2002 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 (one year earlier than expected) as a result of the electric rate plan because NYSEG's electric rates were adjusted to reflect the sale of generation assets that was 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 asset sale gain account 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 on 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 $700 million.

Nonutility Generation: In December 1999 NYSEG notified the owners of Allegheny Hydro No. 8 and Allegheny Hydro No. 9 demanding that they each provide adequate assurance that they will perform their individual contractual obligations under two power purchase agreements with NYSEG, including the obligation to pay back overpayments made by NYSEG over the course of the agreements. Such overpayments are the cumulative difference between the rate NYSEG pays for power under the agreements and its actual avoided costs. At the end of 2003 this cumulative overpayment was more than $194 million and is expected to grow substantially by 2030 when both agreements expire. Allegheny and its lenders filed a motion in the New York State Supreme Court (N.Y. County) seeking a declaration that NYSEG's demand for adequate assurance was improper. The parties reached a settlement in January 2004. The settlement included a dismissal of all of NYSEG's claims and all of Alleg heny's claims and a payment to NYSEG to secure continued operation of the plants.

CMP and NYSEG together expensed approximately $608 million for NUG power in 2003. They estimate that their combined NUG power purchases will total $642 million in 2004, $683 million in 2005, $609 million in 2006, $574 million in 2007 and $367 million in 2008. 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 2003, averaged 9.5 cents per kilowatt-hour for CMP and 8.7 cents per kilowatt-hour for NYSEG. Recovery of these NUG costs is provided for in CMP's and NYSEG's current regulatory plans. (See Note 10 to the company's Consolidated Financial Statements.)

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive electricity 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. A recommended decision (RD) addressing these matters is before the NYPSC.

In a separate phase of this proceeding, the NYPSC issued an order in November 2001 directing the development of embedded cost of service studies for use in implementing unbundled rates. A separate RD on the embedded cost of service studies filed by NYSEG and Consolidated Edison was issued on March 24, 2003. That RD discusses the utilities' cost studies and concludes that they generally comply with the NYPSC's directives. The RD recommended the adoption of NYSEG's lost revenue recovery mechanisms contained in NYSEG's electric and natural gas joint proposals. In April 2003 NYSEG and RG&E filed briefs on the recommended decision. NYSEG took exception to the RD's treatment of certain costs. RG&E filed its brief on exception, not taking formal exception to any of the RD's proposals, but commenting that given the material differences among utilities, it would be both impossible and improper to impose the conclusions in this RD on the remaining utilities in this proceeding. The companies are unable to pr edict the outcome of this proceeding.

Regional Transmission Organization: In January 2003 ISO New England, Inc. (ISO New England) announced that it would work with New England transmission owners to seek input and the advice of all market participants, regulators and other stakeholders to pursue the creation of a New England-only regional transmission organization (RTO). ISO New England and the New England transmission owners made a joint RTO filing with FERC on October 31, 2003. FERC has not yet ruled on the filing.

FERC Standard Market Design: In October 2001 FERC commenced a proceeding to consider national standard market design (SMD) issues, and in July 2002 issued a Notice of Proposed Rulemaking (the SMD NOPR). 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. On April 28, 2003, the FERC issued a white paper on SMD in which FERC accommodates greater regional flexibility and seeks further comments. The SMD white paper includes a preference for energy markets based on locational marginal pricing (LMP), which represents a significant change for some regio ns of the country. The NYISO and ISO New England already operate markets based on LMP. The companies are unable to predict the SMD's ultimate effect, if any, on their results of operations or financial position.

Transmission Planning and Expansion and Generation Interconnection: In June and July 2001 FERC issued orders that address a number of transmission planning and expansion issues that would directly affect CMP, NYSEG and RG&E as transmission owners. The FERC orders discuss giving exclusive responsibility for the transmission planning process to RTOs, rather than to the transmission owners, and also discuss redefining the cost-sharing responsibilities of interconnecting generators for transmission expansion costs. NYSEG, RG&E and other parties are in discussion with the NYISO on the establishment of a formal regional planning process. Additional transmission planning and expansion proposals are included in the SMD NOPR. On July 31, 2003, ISO New England and the New England Power Pool submitted a filing to FERC concerning transmission expansion cost allocation. On December 17, 2003, FERC approved that filing. CMP, among other parties, requested rehearing of the FERC orde r, arguing that it would require customers who would not benefit from new transmission projects to contribute to those project costs. On July 24, 2003, FERC issued orders regarding generation interconnection terms, conditions and cost allocation that would require modifications to the companies' interconnection processes. The companies are unable to predict the ultimate effect, if any, of these proceedings on their transmission systems or on future capital expenditures.

In January 2003 FERC issued a proposed policy statement on transmission pricing. FERC proposes a 50 basis point ROE adder on facilities for which transmission owners turn control over to an RTO. The NYISO and ISO New England satisfy most of the requirements of an RTO. In addition, FERC proposes that unaffiliated third parties will receive the equivalent of an additional 150 basis point adder applicable to transmission facilities that transmission-owning utilities divest. Finally, FERC proposes a 100 basis point adder for new transmission facilities found appropriate through an RTO planning process. The company filed comments on FERC's policy proposal in the first half of 2003. CMP has joined with the New England investor-owned transmission owners to request a joint baseline ROE and the above incentives as part of the proposal for a New England-only RTO.

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 (MGP) sites. The RG&E action is being litigated and mediated concurrently 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.

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: Four of Energy East's natural gas companies - NYSEG, SCG, CNG and Berkshire Gas - have a two-year strategic alliance with BP Energy Company, effective April 1, 2002, for the acquisition of natural gas supply and optimization of transportation and storage services. RG&E has a portfolio management agreement with Entergy-Koch Trading, LP that extends through March 31, 2004, to assist RG&E in the cost-effective management of RG&E's firm contractual rights to natural gas supply, transportation and storage services.

In anticipation of the expiration of these agreements, the companies are conducting a request for proposal process to identify a single strategic alliance partner for all of the Energy East natural gas companies. A new strategic alliance is expected to be effective April 1, 2004. The new alliance will provide the companies with greater supply flexibility, enhance the benefits of a larger natural gas portfolio and be based on sharing incremental savings. The companies will still own and control their natural gas assets and will work with the alliance partner to obtain the lowest cost supply while maintaining reliability of service.

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, implemented a gas supply charge to collect the actual costs of 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 $240 million.

SCG Request for Recovery of Exogenous Costs: On December 9, 2003, SCG filed an application with the DPUC to recover exogenous costs of approximately $21 million under its approved Incentive Rate Plan (IRP). The recovery for exogenous costs is for qualified pension and other postretirement benefits expense, taxes, uncollectible expense and the Customer Hardship Arrearage Forgiveness Program. These 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 has established a docket for this proceeding and initial interrogatories have been issued. SCG cannot predict the outcome of this proceeding at this time.

Connecticut Regulatory Proceedings: During 2001 the Connecticut Office of Consumer Counsel (OCC) filed appeals in State Superior Court arguing that the DPUC's order in December 2000 approving an SCG multi-year IRP and its order in May 2001 approving a CNG IRP were unlawful. In March 2001 the OCC filed a Motion to Stay the implementation of the DPUC's order concerning the SCG IRP, but the court denied the motion in June 2001. In August 2001 the court appeals for SCG's and CNG's IRPs were combined.

In October 2001 SCG and CNG reached a settlement with the OCC, also endorsed by Prosecutorial Staff of the DPUC, resolving numerous outstanding regulatory and legal proceedings. The proceedings resolved by the settlement include a review of past SCG affiliate transactions, SCG's Purchased Gas Adjustment Clause (PGA) charges and credits, alleged overearnings at SCG and CNG, and a court appeal of the DPUC-approved IRPs for SCG and CNG.

SCG and CNG received a final decision from the DPUC approving the settlement in February 2002. The settlement provided rate reductions of $1.5 million for SCG and $0.5 million for CNG, effective October 1, 2001. It extends the approved IRPs for an additional year through September 2005 and maintains an earnings sharing mechanism that generally shares any earnings above the authorized ROEs equally between shareholders and customers. The settlement also permits the recovery of SCG deferred gas costs through the PGA and through the customer portion of earnings sharing by the end of the IRP in 2005. Merger-enabled gas costs savings for both companies are also shared equally between customers and shareholders, with the shareholder portion recovered through the PGA.

CNG's Purchased Gas Adjustment Clause: In April 2002 the DPUC initiated a semiannual review of CNG's PGA. The DPUC issued its draft decision in December 2002, disallowing approximately $1 million of natural gas costs that would be returned to customers through the PGA. As a result, at December 31, 2002, CNG recognized a liability of $1 million for those costs. In May 2003 the DPUC issued its final decision in the matter, modifying the draft decision and removing the disallowance. The DPUC also notified CNG concerning transactions reviewed in an August 2003 semiannual review, for which a final decision is due in mid-2004. CNG is retaining its $1 million reserve contingency to cover the period November 1, 2001, through October 31, 2003, pending completion of the DPUC's review. CNG cannot predict the final outcome of this proceeding.

Connecticut Merger-Enabled Gas Supply Savings and Gas Cost Reduction Plan Filings: In 2001 CNG and SCG submitted filings to the DPUC regarding merger-enabled gas supply savings (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 their 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 by the DPUC's extended due date in April 2003. Hearings are ongoing and a final decision is expected in mid-2004. CNG and SCG cannot predict the final outcome of these proceedings.

Berkshire Gas Rate Plan: In January 2002 the DTE approved a rate increase of $2.3 million, or 4.5%, on total annual revenues for Berkshire Gas. The new rates became effective February 1, 2002. The DTE's approval included Berkshire Gas' proposal for a 10-year incentive-based rate plan with a midperiod review after five years. After the initial rate increase, rates will be frozen until September 2004, at which time rates will be adjusted annually based on inflation minus a 1% consumer dividend. The DTE also approved Berkshire Gas' proposed rate design based on seasonal rates for residential and small commercial and industrial customers that are the same in the winter and summer. Berkshire Gas implemented a service quality plan consistent with a DTE ruling for service quality standards. In September 2003 the DTE reviewed and approved Berkshire Gas' 2002 calendar year service quality filing.

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, utility locating and construction company.

Sale of Other Businesses: The company continues to rationalize its nonutility businesses to ensure they fit its strategic focus. In May 2003 Berkshire Propane, Inc., a subsidiary of Berkshire Energy Resources, sold about one-fourth of its assets and customers for approximately book value. In November 2003 Berkshire Propane, Inc. sold its remaining assets and in October 2003 Energetix sold its Griffith Oil Co., Inc. subsidiary. Energetix is a subsidiary of RGS Energy. The after tax loss on disposal of Berkshire Propane, Inc. was $2 million and the after tax gain on disposal of Griffith Oil Co., Inc. was $3 million. (See Note 2 to the company's Consolidated Financial Statements.)

Statement 150: In May 2003 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. Statement 150 requires that certain financial instruments be classified as liabilities in statements of financial position. Under previous guidance such instruments could be classified as equity. Energy East and RG&E adopted Statement 150 as of July 1, 2003. The adoption of Statement 150 did not have a material effect on Energy East's or RG&E's financial position or results of operations. (See Notes 1 and 7 to the company's Consolidated Financial Statements and Notes 1 and 5 to RG&E's Financial Statements.)

FIN 46R: In December 2003 the FASB issued its revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin (ARB) No. 51 (FIN 46R). FIN 46R addresses consolidation of variable interest entities. A variable interest entity is an entity that is not controllable through voting interests and/or in which the equity investor does not bear the residual economic risks and rewards. The company adopted the provisions of FIN 46R related to special purpose entities as of December 31, 2003. (See Notes 1 and 7 to the company's Consolidated Financial Statements.)

At December 31, 2003, the company's contractual obligations and commercial commitments are: