SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.  20549

FORM 10-K

(Mark one)
 X  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003

OR

    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to              

Commission file number	Exact name of Registrant as specified in its charter, State of incorporation, Address and Telephone number	IRS Employer Identification No.
1-14766	Energy East Corporation (A New York Corporation) P. O. Box 12904 Albany, New York 12212-2904 (518) 434-3049 www.energyeast.com	14-1798693
1-5139	Central Maine Power Company(A Maine Corporation) 83 Edison Drive Augusta, Maine 04336 (207) 623-3521	01-0042740
1-3103-2	New York State Electric & Gas Corporation(A New York Corporation) P. O. Box 5224 Binghamton, New York 13902-5224 (607) 762-7200	15-0398550
1-672	Rochester Gas and Electric Corporation (A New York Corporation) 89 East Avenue Rochester, New York 14649 (585) 546-2700	16-0612110

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

Registrant	Title of each class	Name of each exchange on which registered
Energy East Corporation	Common Stock (Par Value $.01)	New York Stock Exchange
Rochester Gas and   Electric Corporation	6.65% Series UU First Mortgage Bonds, due 2032	New York Stock Exchange

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

Registrant	Title of each class
Central Maine Power Company	6% Preferred Stock (Par Value $100) Dividend Series Preferred Stock (Par Value $100): 3.50% Series 4.60% Series 4.75% Series 5.25% Series

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

Registrant	Title of each class
New York State Electric & Gas Corporation	Cumulative Preferred Stock (Par Value $100): 3.75% Series 41/2%  Series (Series 1949) 4.40% Series 4.15% Series (Series 1954)
Rochester Gas and Electric Corporation	Preferred Stock (Par Value $100): 4% Series F 4.10% Series H 4.75% Series I 4.10% Series J 4.95% Series K 4.55% Series M 6.60% Series V

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.        Yes     X        No           

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [   X   ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Registrant
Energy East Corporation	Yes     X	No
Central Maine Power Company	Yes	No     X
New York State Electric & Gas Corporation	Yes	No     X
Rochester Gas and Electric Corporation	Yes	No     X

The aggregate market value of the common stock held by nonaffiliates of Energy East Corporation, as of June 30, 2003, the last business day of Energy East's most recently completed second fiscal quarter, was $3,026,399,298.

As of February 25, 2004, shares of common stock outstanding for each registrant were:

Registrant	Description	Shares
Energy East Corporation	Par value $.01 per share	146,473,616
Central Maine Power Company	Par value $5 per share	31,211,471(1)
New York State Electric & Gas Corporation	Par value $6.66 2/3 per share	64,508,477(2)
Rochester Gas and Electric Corporation	Par value $5 per share	34,506,513(2)

(1) All shares are owned by CMP Group, a wholly-owned subsidiary of Energy East Corporation.
⁽²⁾ All shares are owned by RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Document	10-K Part
Energy East Corporation has incorporated by reference certain portions of its Proxy Statement, which will be filed with the Commission on or before April 29, 2004.	III

This combined Form 10-K is separately filed by Energy East Corporation, Central Maine Power Company, New York State Electric & Gas Corporation and Rochester Gas and Electric Corporation. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

TABLE OF CONTENTS

PART I

		Page
Item 1.	Business	1
	(a) General development of business	1
	(b) Financial information about segments	2
	(c) Narrative description of business	2
	Principal business	2
	Other businesses	3
	New product or segment	4
	Sources and availability of raw materials	4
	Franchises	5
	Seasonal business	5
	Working capital items	5
	Single customer	5
	Backlog of orders	5
	Business subject to renegotiation	5
	Competitive conditions	5
	Research and development	6
	Environmental matters	6
	Water and air quality	6
	Waste disposal	7
	Number of employees	8
	(d) Disposition of assets	8
	(e) Financial information about geographic areas	8
Item 2.	Properties	8
Item 3.	Legal proceedings	10
Item 4.	Submission of matters to a vote of security holders	11
Executive officers of the registrants		12

PART II

Item 5.	Market for registrants' common equity and related stockholder matters	14
Item 6.	Selected financial data	14
Item 7.	Management's discussion and analysis of financial condition and results of operations	14
Item 7A.	Quantitative and qualitative disclosures about market risk	14
Item 8.	Financial statements and supplementary data	18
Item 9.	Changes in and disagreements with accountants on accounting and financial disclosure	19
Item 9A.	Controls and procedures	19

TABLE OF CONTENTS (Cont'd)

PART III

		Page
Item 10.	Directors and executive officers of the registrants	169
Item 11.	Executive compensation	169
Item 12.	Security ownership of certain beneficial owners and management	169
Item 13.	Certain relationships and related transactions	169
Item 14.	Principal accountant fees and services	170
	PART IV
Item 15.	Exhibits, financial statement schedule, and reports on Form 8-K	170
	(a) List of documents filed as part of this report
	Financial statements	170
	Financial statement schedule	170
	Exhibits
	Exhibits delivered with this report	171
	Exhibits incorporated herein by reference	172
	(b) Reports on Form 8-K	185

Signatures 186

PART I

Item 1.  Business

Energy East Corporation (Energy East or the company) makes available free of charge through its Internet Web site, http://www.energyeast.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after those reports are electronically filed with the Securities and Exchange Commission (SEC). Access to the reports is available from the main page of Energy East's Internet Web site through "Financial Information" and then "SEC filings." The company's Code of Conduct and corporate governance guidelines are also available on its Internet Web site. Access to these documents is available from the main page of Energy East's Internet Web site. Printed copies of these documents are also available upon request by contacting Investor Relations at (207) 688-4336.

(a)  General development of business

Energy East: Energy East is a public utility holding company that was organized under the laws of the State of New York in 1997 and became the parent of New York State Electric & Gas Corporation (NYSEG) in May 1998. Energy East is a super-regional energy services and delivery company with operations in New York, Connecticut, Massachusetts, Maine and New Hampshire, with corporate offices in New York and Maine.

The company's mergers within the last four years are: Connecticut Energy Corporation (CNE) in February 2000, CMP Group, Inc. (CMP Group), CTG Resources, Inc. (CTG Resources) and Berkshire Energy Resources (Berkshire Energy) in September 2000, and RGS Energy Group, Inc. (RGS Energy) in June 2002. All of these companies are wholly-owned Energy East subsidiaries. In connection with the mergers in 2000, the company registered as a holding company with the SEC under the Public Utility Holding Company Act of 1935.

CNE is engaged in the retail distribution of natural gas in Connecticut through its wholly-owned subsidiary, The Southern Connecticut Gas Company (SCG). CMP Group's principal operating subsidiary, Central Maine Power Company (CMP), is primarily engaged in transmitting and distributing electricity generated by others to retail customers in Maine. CTG Resources is the parent of Connecticut Natural Gas Corporation (CNG), a regulated natural gas distribution company in Connecticut. Berkshire Energy's wholly-owned subsidiary, The Berkshire Gas Company (Berkshire Gas), is a regulated natural gas distribution company that operates in western Massachusetts. RGS Energy's principal operating subsidiaries are NYSEG and Rochester Gas and Electric Corporation (RG&E). NYSEG is primarily engaged in purchasing and delivering electricity and natural gas in the central, eastern and western parts of the State of New York. RG&E is primarily engaged in generating, purchasing and delivering electricity and purchasing and delivering natural gas in an area centered around the city of Rochester, New York.

Central Maine Power Company: CMP is a public utility incorporated in Maine in 1905. In September 1998 CMP was reorganized into a holding company structure pursuant to a Plan of Merger with CMP Group. All of the shares of CMP common stock were converted into an equal number of shares of CMP Group common stock and CMP Group became CMP's parent. Effective September 2000, pursuant to a Plan of Merger, CMP Group became a wholly-owned subsidiary of Energy East.

New York State Electric & Gas Corporation: NYSEG is a public utility organized under the laws of the State of New York in 1852. It was reorganized into a holding company structure in May 1998 pursuant to an Agreement and Plan of Share Exchange with Energy East. In connection with Energy East's merger with RGS Energy in June 2002, NYSEG became a wholly-owned subsidiary of RGS Energy.

Rochester Gas and Electric Corporation: RG&E is a public utility organized under the laws of the State of New York in 1904. RGS Energy was incorporated in 1998 in the State of New York and became the holding company for RG&E in August 1999. In June 2002, pursuant to a Plan of Merger, RGS Energy became a wholly-owned subsidiary of Energy East.

The following general developments have occurred in the companies' businesses since January 1, 2003:

Regulatory and Rate Matters(See Item 7 - Electric Delivery Business and Natural Gas Delivery Business.)

(b)  Financial information about segments
(See Item 8 - Note 17 to the company's and Note 14 to CMP's Consolidated Financial Statements, and Note 14 to NYSEG's and Note 13 to RG&E's Financial Statements.)

(c)  Narrative description of business
(See Item 7 - Electric Delivery Business, Natural Gas Delivery Business and Other Businesses.)

(i)  (a)  Principal business

The company's principal energy delivery business consists primarily of its regulated electricity transmission, distribution and generation operations in upstate New York and Maine and its regulated natural gas transportation, storage and distribution operations in upstate New York, Connecticut, Maine and Massachusetts. The company serves approximately 1.8 million electricity customers and 900,000 natural gas customers. The service territories reflect diversified economies, including high-technology firms, insurance, light industry, consumer goods manufacturing, pulp and paper, ship building, colleges and universities, agriculture, fishing and recreational facilities. The percentage of Energy East's operating revenues derived from electricity deliveries was 60% in 2003 and 67% in 2002 and 2001. The percentage of its operating revenues derived from natural gas deliveries was 32% in 2003 and 27% in 2002 and 2001. No customer accounts for more than 5% of either electric or natural gas revenues.

CMP's principal business consists of its regulated electricity transmission and distribution operations in Maine. CMP serves approximately 572,000 customers in its service territory of approximately 11,000 square miles in the southern and central areas of Maine. The service territory contains most of Maine's industrial and commercial centers, including the city of Portland and the Lewiston-Auburn, Augusta-Waterville and Bath-Brunswick areas, and has a population of approximately one million people. All of CMP's operating revenues for 2003, 2002 and 2001 were derived from electricity deliveries, and no customer accounts for more than 5% of revenues.

NYSEG's principal business consists of its regulated electricity transmission and distribution operations and its regulated natural gas transportation, storage and distribution operations in upstate New York. NYSEG also generates electricity primarily from its several hydroelectric stations. NYSEG serves approximately 848,000 electricity and 253,000 natural gas customers in its service territory of approximately 20,000 square miles. The service territory, 99% of which is located outside the corporate limits of cities, is in the central, eastern and western parts of the State of New York and has a population of approximately 2.5 million. The larger cities in which NYSEG serves both electricity and natural gas customers are Binghamton, Elmira, Auburn, Geneva, Ithaca and Lockport. Approximately 78% of NYSEG's operating revenues for 2003, and 82% for 2002 and 2001 were derived from electricity deliveries, with the balance each year derived from natural gas deliveries. No customer accounts for more than 5% of either electric or natural gas revenues.

RG&E's principal business consists of its regulated electricity generation, transmission and distribution operations and regulated natural gas transportation and distribution operations in western New York. RG&E generates electricity from one nuclear plant, one coal-fired plant, three gas turbine plants and several smaller hydroelectric stations. RG&E serves approximately 356,000 electricity and 292,000 natural gas customers in its service territory of approximately 2,700 square miles. The service territory contains a substantial suburban area and a large agricultural area in parts of nine counties including and surrounding the city of Rochester, New York with a population of approximately one million people. Approximately 66% of RG&E's operating revenues for 2003, and 70% of RG&E's operating revenues for 2002 and 2001 were derived from electricity deliveries, with the balance each year derived from natural gas deliveries. No customer accounts for more than 5% of either electric or natural gas revenues.

SCG and CNG conduct natural gas transportation and distribution operations in Connecticut, and Berkshire Gas conducts natural gas distribution operations in western Massachusetts. SCG serves approximately 171,000 customers in its service territory of approximately 500 square miles with a population of approximately 800,000. SCG's service territory extends along the southern Connecticut coast from Westport to Old Saybrook and includes the urban communities of Bridgeport and New Haven. CNG serves approximately 153,000 customers in its service territory of approximately 800 square miles with a population of approximately 800,000, principally in the greater Hartford-New Britain area and Greenwich. Berkshire Gas serves approximately 35,000 customers in its service territory of approximately 1,000 square miles with a population of approximately 190,000. Berkshire Gas' service territory includes the cities of Pittsfield and North Adams.

(i)  (b)  Other businesses

The company's other businesses include a nonutility generating company, retail energy marketing companies, telecommunications assets, a district heating and cooling system, a Federal Energy Regulatory Commission (FERC) regulated liquefied natural gas peaking plant and an energy services, utility locating and construction company.

Cayuga Energy, Inc. (Cayuga Energy) owns electric generation facilities that sell power in the New York Independent System Operator (NYISO) and PJM Interconnection, LLC wholesale markets at times of high demand.

TEN Companies, Inc. (TEN Companies) owns and manages a district heating and cooling network in Hartford, Connecticut and owns an interest in the Iroquois Gas Transmission System.

CNE Energy Services Group has an interest in two small natural gas pipelines that serve power plants in Connecticut. CNE Energy Services Group also leases a liquefied natural gas plant that serves the peaking gas markets in the Northeast and has an equity interest in an energy technology venture partnership.

The Union Water-Power Company provides energy services, utility construction and utility locating services throughout New England and New York State.

Energy East Solutions sells electricity and natural gas in wholesale and retail markets in the Northeast and mid-Atlantic regions.

Energy East Telecommunications owns fiber optic lines in central New York that it leases to retail communications companies. MaineCom Services owns fiber optic lines and provides telecommunications services in Maine.

Energy East Enterprises includes Maine Natural Gas, a small natural gas delivery company, New Hampshire Gas, a propane air delivery company, and Seneca Lake Storage, which is considering the development of high-deliverability natural gas storage in upstate New York.

Energetix, Inc. (Energetix) and NYSEG Solutions, Inc. market electricity and natural gas services throughout upstate and central New York.

(ii)  New product or segment - Not applicable.

(iii)  Sources and availability of raw materials

Electric
(See Item 7 - Electric Delivery Business, Item 7A - Commodity Price Risk and Item 8 - Note 1 to the company's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.)

Under a Maine State Law adopted in 1997, CMP was mandated to sell its generation assets and relinquish its supply responsibility. However, the Maine Public Utilities Commission (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 no longer owns any generating assets but does retain its power entitlements under long-term contracts from nonutility generators (NUGs) and contract for power from Vermont Yankee, which was sold in July 2002. CMP has sold these 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. CMP's revenues and purchased power costs will fluctuate as its status as a standard-offer provider changes. There is no effect on net income as its status fluctuates, however, because CMP is ensured cost recovery through Maine State Law for any standard-offer obligations.

NYSEG satisfied the majority of its power requirements for 2003 through purchases under long-term contracts from NUGs, the New York Power Authority and Constellation Nuclear and from generation from its several hydroelectric stations. NYSEG managed fluctuations in the cost of electricityfor its remaining power requirements through the use of electricity contracts, both physical and financial.

RG&E satisfied the majority of its power requirements for 2003 through generation from its facilities (nuclear - 67%, coal and natural gas-fired - 30%, and hydroelectric and peaking - 3%) and purchases under long-term contracts from the New York Power Authority and Constellation Nuclear. RG&E managed the fluctuations in the cost of electricity for its remaining power requirements through the use of electricity contracts, both physical and financial.

Nuclear - In October 2003 RG&E, the owner/operator of Ginna nuclear generating station (Ginna), completed the 31st refueling of the reactor core at Ginna. This refueling will support Ginna's operations through the spring of 2005. Uranium concentrates, enrichment, conversion and fabrication services are under contract for all of the requirements through 2009. (See Item 7 - Sale of Ginna Station and Relicensing.)

Coal - RG&E's 2004 coal requirements are expected to be approximately 700,000 tons. RG&E's coal supply portfolio contains both spot and term agreements with multiple suppliers. In 2003, 70% of RG&E's coal requirements were purchased under contract and 30% were purchased on the spot market. RG&E maintains a reserve supply of coal ranging from 30 to 60 days' supply at maximum burn rates.

Natural Gas
(See Item 7 - Natural Gas Delivery Business, Item 7A - Commodity Price Risk and Item 8 - Note 1 to the company's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.)

NYSEG, RG&E, CNG, SCG and Berkshire satisfy their gas supply requirements through gas supply purchases and gas storage capacity contracts plus winter peaking supplies and resources. A majority of the gas supply purchased is acquired under long- and short-term supply contracts and the remainder is acquired on the spot market. Firm underground gas storage capacity is contracted for under long-term contracts. Firm transportation capacity is acquired under long-term contracts and is utilized to transport both gas supply purchased and gas withdrawn from storage into local distribution systems. Winter peaking supplies and resources are either owned by the company, NYSEG and RG&E, and are attached to the distribution system, or contracted for under long-term arrangements.

(iv)  Franchises

The company's operating companies, including CMP, NYSEG and RG&E, have valid franchises, with minor exceptions, from the municipalities in which they render service to the public.

Effective in September 2001 Maine State Law authorized any natural gas utility providing gas distribution service in the State of Maine to provide gas distribution service to any municipality in Maine that is not already being served by another natural gas utility.

(v)  Seasonal business

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

(vi)  Working capital items

The company's operating utilities, including CMP, NYSEG and RG&E, have been granted, through the ratemaking process, an allowance for working capital to operate their ongoing electric and/or natural gas utility systems.

(vii)  Single customer - Not applicable.

(viii)  Backlog of orders - Not applicable.

(ix)  Business subject to renegotiation - Not applicable.

(x)  Competitive conditions
(See Item 7 - Electric Delivery Business, Natural Gas Delivery Business, Other Businesses and Critical Accounting Estimates.)

(xi)  Research and development

The company's expenditures on research and development were $5 million in 2003, $5 million in 2002 (including $1 million for RGS Energy from July 2002) and $5 million in 2001, principally by NYSEG. RG&E's expenditures on research and development were $2 million in 2003 and $2 million each year in 2002 and 2001. These expenditures were for internal research programs and for contributions to research administered by the New York State Energy Research and Development Authority, the Electric Power Research Institute and the Northeast Gas Association. These expenditures are designed to improve existing energy technologies and to develop new technologies for the delivery and customer use of energy.

(xii)  Environmental matters
(See Item 3 - Legal proceedings, Item 7 - Electric Delivery Business, and Item 8 - Notes 10, 11 and 12 to the company's and Notes 8, 9 and 10 to CMP's Consolidated Financial Statements, and Notes 8, 9 and 10 to NYSEG's and RG&E's Financial Statements.)

The company, CMP, NYSEG and RG&E are subject to regulation by the federal government and by state and local governments with respect to environmental matters, such as the handling and disposal of toxic substances and hazardous and solid wastes and the handling and use of chemical products. Electric utility companies generally use or generate a range of potentially hazardous products and by-products that are subject to such regulation. They are also subject to state laws regarding environmental approval and certification of proposed major transmission facilities.

From time to time, environmental laws, regulations and compliance programs may require changes in the company's, CMP's, NYSEG's and RG&E's operations and facilities and may increase the cost of energy delivery service. Historically, rate recovery has been authorized for environmental compliance costs.

Capital additions to meet environmental requirements during the three years ended December 31, 2003, were approximately $17 million for Energy East, including $4million for CMP, $4 million for NYSEG and $5 million for RG&E. For the period January 1, 2001, to June 30, 2002, RG&E had an additional $3 million of capital additions to meet environmental requirements. Future capital additions to meet environmental requirements are not expected to be material.

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

The company, CMP, NYSEG and RG&E are required to comply with federal and state oil spill statutes and regulations including the Spill Prevention Control and Countermeasures regulations.

RG&E is required to comply with federal and state air quality statutes and regulations for operation of its coal-fired and combustion turbine generating stations. All of RG&E's stations have the required federal or state operating permits. Stack tests and continuous emissions monitoring indicate that the stations are generally in compliance with permit emission limitations, although occasional opacity exceedances occur. Efforts continue in the identification and elimination of the causes of opacity exceedances.

The Clean Air Act Amendments of 1990 (1990 Amendments) limit emissions of sulfur dioxide and nitrogen oxides and require emissions monitoring. The U. S. Environmental Protection Agency (EPA) allocates annual emissions allowances to each of RG&E's coal-fired and combustion turbine generating stations based on statutory emissions limits under Phase II (which began January 1, 2000) of the 1990 Amendments. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. A similar allowance program under Title I of the 1990 Amendments controls nitrogen oxides emissions from RG&E's coal-fired station and a combustion turbine generating station. Another requirement of the 1990 Amendments is for the coal-fired station and a combustion turbine generating station to have a facility operating permit (Title V permit). The Title V permits required for each station have been granted. Future requirements of the 1990 Amendments may require further reduction of sulfur dioxide and nitrogen oxides emissions, as well as new limits on mercury emissions from coal-fired combustion generating stations. However, specific control requirements have not been determined by the EPA.

Regulations were adopted on April 17, 2003 by the State of New York that further limit acid rain precursor emissions from electric generating units, possibly at an additional cost to RG&E. Emissions reduction targets are set 50% below the current federal limits for sulfur dioxide and will be phased in between 2005 and 2008. In addition, current federal summertime limits for nitrogen oxides will need to be applied year round starting in October 2004. Emissions reductions will be achieved through a market-based allowance trading system similar to those under the 1990 Clean Air Act Amendments. The cost of allowances beyond those allocated to RG&E is unknown.

RG&E purchases emission allowances as necessary in order to comply with the Clean Air Act, and estimates its cost for allowances will be $6 million for 2004. In addition, control equipment was installed at RG&E facilities as part of compliance with the Clean Air Act, at a cost of over $7 million. If RG&E were unable to satisfy some of its environmental commitments with emission allowances, either because of regulatory changes or an inability to obtain emission allowances, RG&E would be required to take alternative actions, which may include reduced plant operation or shutdown, or making additional capital expenditures to comply with the Clean Air Act.

Waste disposal: A low level radioactive waste management and contingency plan for Ginna provides assurance that RG&E is properly prepared to handle interim storage of Ginna's low level radioactive waste until 2010 should permanent or long-term disposal facilities not be available. Licensing and construction of additional storage facilities would extend on-site storage capability for low level radioactive waste beyond 2009, whether or not RG&E's license to operate Ginna is extended. (See Item 7 - Sale of Ginna Station and Relicensing.)

RG&E has contracted with the U. S. Department of Energy (DOE) for disposal of high level radioactive waste including spent fuel from Ginna (currently at a cost of approximately $1 per megawatt-hour of net generation). The DOE's schedule for start of operations of their high level radioactive waste repository will be no sooner than 2010, one year after RG&E's current license to operate Ginna is scheduled to expire. RG&E's Ginna Spent Fuel Storage Pool has a capacity for spent fuel that is adequate beyond 2009. If further DOE schedule slippage should occur, construction of pre-licensed dry storage facilities would extend the on-site storage capability for spent fuel at Ginna, whether or not RG&E's license to operate Ginna is extended. (See Item 7 - Sale of Ginna Station and Relicensing.)

(xiii)  Number of employees

As of January 31, 2004, Energy East had 6,288 employees, which includes 1,248 CMP employees, 2,648 NYSEG employees and 1,552 RG&E employees.

RG&E Union Contract: In April 2003 RG&E's electric and 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 labor agreement was negotiated for the period September 2003 through May 2008.

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. Berkshire Gas and the local union had been unable to negotiate a new contract and a work stoppage involving approximately 57% of the workforce was in effect for nine months. On January 5, 2004, the local union returned to work under the old contract while both parties continue negotiating a new agreement.

(d) Disposition of assets
(See Item 7 - Electric Delivery Business and Other Businesses.)

(e) Financial information about geographic areas  Not applicable.

Item 2.  Properties
(See Item 7 - Electric Delivery Business and Other Businesses.)

CMP's electric system includes substations and transmission and distribution lines, all of which are located in the State of Maine. NYSEG's electric system includes hydroelectric and gas turbine generating stations, substations and transmission and distribution lines, substantially all of which are located in the State of New York. RG&E's electric system includes nuclear, coal-fired, combustion turbine and hydroelectric generating stations, substations and transmission and distribution lines, all of which are located in the State of New York. The Energy Network owns interests in three natural gas-fired peaking generating stations, two that are located in the State of New York and operated by Cayuga Energy, a wholly-owned subsidiary, and one that is located in Pennsylvania for which Cayuga Energy manages fuel procurement and electricity sales.

The operating companies' generating facilities consist of the following:

Operating Company	Type and location of station		Generating capability (megawatts)
RG&E	Nuclear(1)	(Ontario, NY)	480
NYSEG RG&E	Hydroelectric Hydroelectric	(Various - 7 locations) (Rochester, NY - 3 locations)	60    47
RG&E RG&E RG&E The Energy Network The Energy Network The Energy Network NYSEG NYSEG	Coal-fired Gas turbine Gas turbine Gas turbine Gas turbine Gas turbine Gas turbine Gas turbine	(Greece, NY) (Hume, NY) (Rochester, NY - 2 locations) (Carthage, NY) (South Glens Falls, NY) (Archbald, PA) (Newcomb, NY) (Auburn, NY)	257    63    28    67    57(2) 24(3) 2        7
Total - all stations			1,092

(1) In November 2003 RG&E signed an agreement to sell Ginna to Constellation Generation Group LLP for
   $422.6 million (including nuclear fuel). (See Item 7 - Sale of Ginna Station and Relicensing.)
⁽²⁾Cayuga Energy's 85% share of the generating capability.
⁽³⁾ Cayuga Energy's 50.1% share of the generating capability.

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:

Operating Company	Location	Miles of Transmission Pipeline	Miles of Distribution Pipeline
NYSEG	New York State	74	7,706
RG&E	New York State	109	4,556
SCG	Connecticut	-	3,634
CNG	Connecticut	-	3,547
Berkshire Gas	Massachusetts	-	720
Maine Natural Gas	Maine	2	71
New Hampshire Gas (Propane air)	New Hampshire	-	27

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.

* * * * * * * * * * *

Executive Officers of the Registrants

Name	Age	Positions, offices and business experience - January 1999 to date
Energy East Corporation
Wesley W. von Schack	59	Chairman, President & Chief Executive Officer to date; Chairman, President & Chief Executive Officer of NYSEG to April 1999.
Kenneth M. Jasinski	55	Executive Vice President and Chief Financial Officer, February 2002 to date; Executive Vice President, General Counsel & Secretary, August 2000 to February 2002; Executive Vice President and General Counsel, April 1999 to August 2000; Senior Vice President and General Counsel to April 1999; Executive Vice President of NYSEG to April 1999.
Robert D. Kump	42	Vice President, Treasurer & Secretary, February 2002 to date; Vice President and Treasurer, November 1999 to February 2002; Treasurer to November 1999; Treasurer of NYSEG to August 2000.
Robert E. Rude	51	Vice President and Controller, November 1999 to date; Controller to November 1999; Executive Director, Corporate Planning of NYSEG to October 2000.
Robert M. Allessio	53	President and Chief Executive Officer of Berkshire Energy Resources and The Berkshire Gas Company, September 2000 to date; Senior Vice President, Operating Services of Connecticut Natural Gas Corporation and The Southern Connecticut Gas Company, May 2003 to date; President and Chief Operating Officer of The Berkshire Gas Company, August 1999 to September 2000; Vice President, Utility Operations of The Berkshire Gas Company to August 1999.
Richard R. Benson	46	Vice President, Human Resources of Energy East Management Corporation, October 2000 to date; Executive Director, Human Resources of NYSEG to October 2000.
Sara J. Burns	48	President of CMP to date.
Michael I. German	53	President of Connecticut Natural Gas Corporation and The Southern Connecticut Gas Company, May 2003 to date; Senior Vice President, Business Development of Energy East Management Corporation, March 2002 to May 2003; Senior Vice President of Energy East Corporation to March 2002; President and Chief Executive Officer of The Energy Network, Inc., October 2000 to May 2003; President and Chief Operating Officer of NYSEG, April 1999 to October 2000; Executive Vice President and Chief Operating Officer of NYSEG to April 1999.
James P. Laurito	47	President and Chief Executive Officer of RGS Energy Group, Inc., June 2003 to date; President of NYSEG, May 2003 to date; Treasurer of NYSEG, May 2003 to July 2003; President of RG&E, July 2003 to date; President and Chief Operating Officer of Connecticut Natural Gas Corporation and The Southern Connecticut Gas Company, October 2000 to May 2003; President of TEN Companies, Inc., January 1999 to October 2000; Vice President, Business Development of TEN Companies, Inc. to January 1999.

Name	Age	Positions, offices and business experience - January 1999 to date
F. Michael McClain	54	Vice President, Finance and Chief Integration Officer of Energy East Management Corporation, October 2000 to date; Vice President, Corporate Development of CMP Group, Inc. to October 2000.
Angela M. Sparks-Beddoe	39	Vice President, Public Affairs of Energy East Management Corporation, January 2001 to date; Director, Legislative Affairs of NYSEG, February 1999 to January 2001; Manager, Federal Government Affairs of NYSEG to February 1999.
Denis E. Wickham	55	Executive Vice President and Chief Operating Officer of NYSEG and RG&E, July 2003 to date; Senior Vice President, Transmission and Energy Supply of Energy East Management Corporation, October 2000 to July 2003; Senior Vice President, Energy Operating Services of NYSEG to October 2000.

Central Maine Power Company

Sara J. Burns
48
President to date.

New York State Electric & Gas Corporation and
Rochester Gas and Electric Corporation

James P. Laurito
47
President and Chief Executive Officer of RGS Energy Group, Inc., June 2003 to date; President of NYSEG, May 2003 to date; Treasurer of NYSEG, May 2003 to July 2003; President of RG&E, July 2003 to date; President and Chief Operating Officer of Connecticut Natural Gas Corporation and The Southern Connecticut Gas Company, October 2000 to May 2003; President of TEN Companies, Inc. January 1999 to October 2000; Vice President, Business Development of TEN Companies, Inc. to January 1999.

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.

PART II

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:

Energy East - page 20
CMP - page 79
NYSEG - page 107
RG&E - page 139

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:

Energy East - pages 21 to 41
CMP - pages 79 to 83
NYSEG - pages 107 to 113
RG&E - pages 139 to 145

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 issued 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.)

Forward-looking 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 company'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

	Page
Energy East Corporation
Consolidated Balance Sheets	42
Consolidated Statements of Income	44
Consolidated Statements of Cash Flows	45
Consolidated Statements of Changes in Common Stock Equity	46
Notes to Consolidated Financial Statements	47
Report of Independent Auditors	77
Financial Statement Schedule
II. Consolidated Valuation and Qualifying Accounts	78
Central Maine Power Company
Consolidated Balance Sheets	84
Consolidated Statements of Income	86
Consolidated Statements of Cash Flows	87
Consolidated Statements of Changes in Common Stock Equity	88
Notes to Consolidated Financial Statements	89
Report of Independent Auditors	105
Financial Statement Schedule
II. Consolidated Valuation and Qualifying Accounts	106
New York State Electric & Gas Corporation
Balance Sheets	114
Statements of Income	116
Statements of Cash Flows	117
Statements of Changes in Common Stock Equity	118
Notes to Financial Statements	119
Report of Independent Auditors	137
Financial Statement Schedule
II. Valuation and Qualifying Accounts	138
Rochester Gas and Electric Corporation
Balance Sheets	146
Statements of Income	148
Statements of Cash Flows	149
Statements of Changes in Common Stock Equity	150
Notes to Financial Statements	151
Report of Independent Auditors	167
Financial Statement Schedule
II. Valuation and Qualifying Accounts	168

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.

Selected Financial Data

Energy East Corporation

	2003	2002 (1)		2001		2000 (6)		1999
(Thousands, except per share amounts)
Operating Revenues	$4,593,819	$3,836,469		$3,749,843		$2,955,661		$2,278,608
Depreciation and amortization	$301,264	$242,111		$203,310		$165,216		$648,970	(7)
Other taxes	$270,478	$229,434		$192,505		$165,674		$179,028
Interest Charges, Net	$284,802	$256,292		$216,388		$152,520		$132,908
Income From Continuing   Operations	$207,387	$190,516		$188,712		$235,312		$218,751
Net Income	$210,446	$188,603	(2)	$187,607	(3) (4)	$235,034	(4)	$218,751
Earnings Per Share from   Continuing Operations, basic	$1.43	$1.45	(2)	$1.62	(3)	$2.06		$1.88
Earnings Per Share from   Continuing Operations, diluted	$1.42	$1.45	(2)	$1.62	(3)	$2.06		$1.88
Earnings Per Share, basic	$1.45	$1.44	(2)	$1.61	(3)	$2.06		$1.88
Earnings Per Share, diluted	$1.44	$1.44	(2)	$1.61	(3)	$2.06		$1.88
Dividends Paid Per Share	$1.00	$.96		$.92		$.88		$.84
Average Common   Shares Outstanding, basic	145,535	131,117		116,708		114,213		116,316
Average Common   Shares Outstanding, diluted	145,730	131,117		116,708		114,213		116,316
Book Value Per Share of   Common Stock at Year End	$17.59	$16.97		$15.26		$14.59		$12.84
Capital Spending	$302,512	$229,387		$222,875		$168,320		$82,674
Total Assets	$11,306,432	$10,944,347		$7,269,232	(5)	$7,013,728	(5)	$3,773,171	(5)
Long-term Obligations,   Capital Leases and   Redeemable Preferred Stock	$4,017,846	$3,721,959		$2,816,278		$2,346,814		$1,235,089

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

(1) Due to the completion of the company's merger transaction during 2002 the consolidated financial statements include RGS Energy's results beginning with July 2002.
⁽²⁾ Includes the writedown of the company's investment in NEON Communications, Inc. that decreased net income $7 million and earnings per share 6 cents and the effect of restructuring expenses that decreased net income $24 million and earnings per share 19 cents.
⁽³⁾ Includes the writedown of the company's investment in NEON Communications, Inc. that decreased net income $46 million and earnings per share 39 cents.
⁽⁴⁾ Includes goodwill amortization of $25 million in 2001 and $18 million in 2000.
⁽⁵⁾ Does not reflect the reclassification of accrued removal costs from accumulated depreciation to a regulatory liability.
⁽⁶⁾ Due to the completion of the company's merger transactions during 2000 the consolidated financial statements include CNE's results beginning with February 2000 and include CMP Group's, CTG Resources' and Berkshire Energy's results beginning with September 2000.
⁽⁷⁾ Depreciation and amortization includes accelerated amortization of the Nine Mile Point 2 nuclear generating station (NMP2) related to the sale of the company's coal-fired generation assets, authorized by the NYPSC.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Overview

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.

Liquidity and Capital Resources

Restructuring

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

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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.

Electric Delivery Business

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.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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 proposal, 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.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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 Allegheny'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 predict 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.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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 regions 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 order, 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.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Natural Gas Delivery Business

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.

RG&E 2002 Electric and Gas Rate Proceeding: See Electric Delivery Business.

RG&E 2003 Electric and Gas Rate Proceeding: See Electric Delivery Business.

NYPSC Collaborative on End State of Energy Competition: See Electric Delivery Business.

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.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

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.

Other Businesses

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.)

Other Matters

Accounting Issues

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.)

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Contractual Obligations and Commercial Commitments

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

	Total	2004	2005	2006	2007	2008	After 2008
(Thousands)
Contractual  Obligations
Long-term debt	$4,018,265	$29,713	$58,684	$339,433	$231,433	$92,433	$3,266,569
Capital lease  obligations	31,820	2,526	2,379	2,194	2,053	2,120	20,548
Operating  leases	67,732	13,173	11,491	9,586	9,181	9,153	15,148
Nonutility  generator  purchase  power  obligations	3,696,200	641,809	683,130	609,375	574,014	366,510	821,362
Nuclear plant  obligations(1)	481,227	64,223	85,087	78,966	82,136	104,410	66,405
Unconditional  purchase  obligations	1,519,345	335,958	236,935	189,254	178,194	141,563	437,441
Pension and  other  postretirement  benefits(2)	2,295,708	177,741	184,517	194,066	203,178	215,252	1,320,954
Other long-term  obligations	35,850	7,800	7,850	5,700	4,400	3,200	6,900
Total  Contractual  Obligations	$12,146,147	$1,272,943	$1,270,073	$1,428,574	$1,284,589	$934,641	$5,955,327
Other Commercial  Commitments
Committed  lines of credit	$680,000	$455,000	$225,000	-	-	-	-
Uncommitted  lines of credit	16,000	16,000	-	-	-	-	-
Total  Commercial  Commitments	$696,000	$471,000	$225,000	-	-	-	-

(1) See Sale of Ginna Station and Relicensing.
⁽²⁾ Amounts are through 2013 only.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Energy East has two revolving credit agreements in which it covenants to maintain certain debt ratios. CMP has a revolving credit facility, secured by its accounts receivable, in which it covenants to maintain certain debt and earnings ratios. NYSEG and RG&E have a joint revolving credit agreement in which they each covenant to maintain certain debt and earnings ratios. NYSEG has a letter of credit and reimbursement agreement in which it covenants to maintain certain debt ratios. (See Note 8 to the company's and Note 6 to CMP's Consolidated Financial Statements, and Note 6 to NYSEG's and RG&E's Financial Statements.)

Critical Accounting Estimates

In preparing the financial statements in accordance with generally accepted accounting principles, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. The company's most critical accounting estimates include the effects of utility regulation on its financial statements, and the estimates and assumptions used to calculate the asset retirement obligation, perform the annual impairment analyses for goodwill and other intangible assets and calculate pension and other postretirement benefits.

Statement 71: Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, allows companies that meet certain criteria to capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future periods. Those companies record, as regulatory liabilities, obligations to refund previously collected revenue or obligations to spend revenue collected from customers on future costs.

The company believes its public utility subsidiaries will continue to meet the criteria of Statement 71 for their regulated electricity and natural gas operations in New York State, Maine, Connecticut and Massachusetts; however, the company cannot predict what effect a competitive market or future actions of the NYPSC, MPUC, DPUC, DTE or FERC will have on their ability to continue to do so. If the company's public utility subsidiaries can no longer meet the criteria of Statement 71 for all or a separable part of their regulated operations, they may have to record as expense or revenue certain regulatory assets and liabilities.

Approximately 90% of the company's revenues are derived from operations that are accounted for pursuant to Statement 71. The rates the utilities charge their customers are based on cost basis regulation reviewed and approved by those regulatory commissions.

Asset Retirement Obligation: As required by Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, the company recorded a liability for the fair value of its asset retirement obligation on January 1, 2003. The company will adjust the liability to its present value periodically over time, and the capitalized cost will be depreciated over the useful life of the related asset. The determination of the liability includes various assumptions, the primary assumptions being the discount rate and forecasted cash flows. Changes in those assumptions could have a significant effect on the amount of the company's asset retirement obligation. The company's asset retirement obligation is recovered through rates collected from customers, therefore, the depreciation of the capitalized costs and adjustments to the liability are deferred until those amounts are included in rates. (See Note 1 to the company's and CMP's Consolidated Financial Statements and Note 1 to NYSEG's and RG&E's Financial Statements.)

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Substantially all of Energy East's asset retirement obligation is related to Ginna. (See Sale of Ginna Station and Relicensing.)

Goodwill and Other Intangible Assets: The company no longer amortizes goodwill and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized and are reviewed for impairment. The impairment testing includes various assumptions, primarily the discount rate and forecasted cash flows. Impairment testing was done over a range of discount rates representing the company's marginal, weighted average cost of capital as well as a range of assumptions for cash flows. Changes in those assumptions outside of the ranges analyzed could have a significant effect on the company's determination of an impairment. (See Note 5 to the company's and Note 3 to CMP's Consolidated Financial Statements and Note 3 to NYSEG's and RG&E's Financial Statements.)

Pension and Other Postretirement Benefit Plans: The company has pension and other postretirement benefit plans covering substantially all of its employees. In accordance with Statement of Financial Accounting Standards No. 87, Employer's Accounting for Pensions, and Statement of Financial Accounting Standards No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, the valuation of benefit obligations and the performance of plan assets are subject to various assumptions. The primary assumptions include the discount rate, expected return on plan assets, rate of compensation increase, health care cost inflation rates, expected years of future service under the pension benefit plans and the methodology used to amortize gains or losses. Changes in those assumptions could have a significant effect on the company's noncash pension income or expense or on the company's postretirement benefit costs. As of December 31, 2003, the company decreased the discount rate from 6.5% to 6.25%. (See 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.)

Investing and Financing Activities

Investing Activities: Capital spending totaled $303 million in 2003, $229 million in 2002 and $223 million in 2001, including capital spending for RGS Energy and nuclear fuel for RG&E beginning July 1, 2002. Capital spending does not include the amount for the company's merger transaction for RGS Energy in 2002. (See Note 4 to the company's Consolidated Financial Statements.) Capital spending in all three years was financed with internally generated funds and was primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration in 2003.

Capital spending is projected to be $345 million in 2004, including nuclear fuel. It is expected to be paid for with internally generated funds and will be primarily for the same purposes described above. (See Note 10 to the company's Consolidated Financial Statements.)

The company's pension plans generated pretax noncash pension income (net of amounts capitalized) of $40 million in 2003, $70 million in 2002, and $76 million in 2001. The decrease in 2003 was due to significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute the company's pension

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

liability (reduced from 7.0% to 6.50% as of December 31, 2002) and return on assets (reduced from 9% to 8.75% effective January 1, 2003). Pension income for 2004 is estimated at $40 million. The company estimates funding requirements of only $7 million to $12 million in 2004 since, in the aggregate, total plan assets exceed the projected benefit obligation. (See Note 16 to the company's Consolidated Financial Statements.)

Financing Activities: (See Notes 7 and 8 to the company's Consolidated Financial Statements.)

The financing activities discussed below include those activities necessary for the company and its subsidiaries to maintain adequate liquidity, improve credit quality and ensure current access to capital markets to finance certain refundings. These include maintenance of credit facilities, minimal common stock issuances and various medium-term and long-term debt arrangements.

The company raised its common stock dividend 4% in January 2004 to a new annual rate of $1.04 per share.

Since August 2001 the company has been issuing new common shares through its Dividend Reinvestment and Stock Purchase Plan, now called the Investor Services Program, rather than purchasing them on the open market. The company expects to issue approximately one million shares per year under this plan. During 2003 the company issued 1,063,640 shares of common stock at an average price of $20.41 per share through this plan. The shares issued included 328,797 treasury shares and 734,843 original issue shares.

In February 2003 the company awarded 229,230 shares of common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan, and recorded deferred compensation of $4 million based on the market price of $19.20 per share of common stock on the date of the award. (See Note 14 to the company's Consolidated Financial Statements.)

In February 2004 the company awarded 240,138 shares of its common stock, to be issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of $6 million based on the market price of $23.89 per share of common stock on the date of the award.

The company and its subsidiaries have committed credit agreements with various expiration dates in 2004 and 2005 and pay fees in lieu of compensating balances in connection with these credit agreements. These agreements provided for maximum borrowings of $680 million at December 31, 2003, and $755 million at December 31, 2002. Uncommitted credit agreements, which expire in 2004, provide for additional borrowings of $16 million. (See Contractual Obligations and Commercial Commitments.)

The company and its subsidiaries use short-term, unsecured notes and drawings on their credit agreements (see above) to finance certain refundings and for other corporate purposes. There was $308 million of such short-term debt outstanding at December 31, 2003, and $322 million outstanding at December 31, 2002. The weighted-average interest rate on short-term debt was 1.8% at December 31, 2003, and 2.1% at December 31, 2002.

The company filed a shelf registration statement with the SEC in June 2003 to sell up to $1 billion in an unspecified combination of debt, preferred stock, common stock and trust preferred securities. The company plans to use the net proceeds from the sale of securities

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

under this shelf registration for general corporate purposes, such as the repurchase or refinancing of securities. The company had $5 million available under a previous shelf registration statement. The company currently has $805 million available under the shelf registration statement filed in June 2003.

In September 2003 Energy East issued $200 million of 6.75% unsecured notes due in September 2033 under the shelf registration statements described above. The notes were issued as part of an exchange of securities for $156 million aggregate principal amount of the company's 7.75% Putable Asset Term Securities (PATS), putable/callable November 15, 2003, from the holders thereof. The remaining cash proceeds were used to finance the cancellation of the related call option with respect to the exchange of the PATS, to finance expenses associated with the offering and for general corporate purposes. Energy East called the remaining $144 million aggregate principal amount of the PATS in mid-November and funded the transaction with proceeds from the sale of certain nonutility businesses and short-term debt.

In August 2003 Energy East entered into a fixed-to-floating interest rate swap on a portion of its 8 1/4% junior subordinated debt securities. The company receives a fixed rate of 8 1/4% and will pay a rate based on the three-month London Interbank Offered Rate (LIBOR) plus 2.00% on a notional amount of $250 million through July 2031.

In August 2003 Energy East terminated a fixed-to-floating interest rate swap on its 5.75% notes due November 2006. The company received $4 million, the value of the swap on the date of termination, that it will amortize over the remaining life of the notes.

CMP Financing Activities: In August 2003 CMP issued $36 million of Series E Medium Term Notes at a fixed rate of 5.1%, due August 2013. Through financial instruments issued in March 2003 CMP locked in the 10-year treasury rate component of that financing at a fixed rate of 4.105%, which reduced the effective rate on the notes by 10 basis points. The proceeds from the notes were used to help repay $50 million of medium term notes that matured in August 2003.

NYSEG Financing Activities: In March 2003 NYSEG filed a shelf registration statement with the SEC to sell up to $300 million in an unspecified combination of debt and preferred stock. NYSEG plans to use the net proceeds from the sale of securities under this shelf registration primarily for the retirement or repurchase of certain of its indebtedness or preferred stock, the reduction of short-term debt and other general corporate purposes. NYSEG had $50 million available under a previous shelf registration statement. NYSEG currently has $150 million available under the shelf registration statement filed in March 2003.

In April 2003 NYSEG redeemed, at a premium, $50 million of 7.55% Series first mortgage bonds callable on April 1, 2003, using commercial paper. NYSEG redeemed $100 million of 7.45% Series first mortgage bonds: $23 million was redeemed at par on June 30, 2003, pursuant to a sinking fund provision in NYSEG's mortgage indenture and $77 million was redeemed at a premium on July 15, 2003. NYSEG has redeemed all of its outstanding first mortgage bonds. NYSEG's first mortgage indenture was discharged in the fourth quarter of 2003.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

In May 2003 NYSEG issued $200 million of 5 3/4% unsecured notes due in May 2023 under the shelf registration statements described above. The proceeds of this unsecured issuance were used to refund commercial paper that was used in April 2003 to redeem the $50 million of 7.55% Series first mortgage bonds, and to redeem in June and July 2003 the $100 million of 7.45% Series first mortgage bonds. NYSEG used the remainder of the net proceeds for general corporate purposes. NYSEG will amortize, over the term of the 5 3/4% unsecured notes, a $1 million premium on the redemption of its 7.55% Series first mortgage bonds, a $3 million premium on the redemption of its 7.45% Series first mortgage bonds and related unamortized debt expenses and debt issuance costs for both redemptions.

RG&E Financing Activities: In January 2003 RG&E used an equity contribution from its parent, RGS Energy, along with internally generated funds, to pay off the remaining $80 million balance of a 7% promissory note that was due in 2014.

RG&E paid at maturity in February 2003 $39 million of first mortgage bonds and in March 2003 $1 million of first mortgage bonds using temporary cash investments and internally generated funds. RG&E filed a shelf registration statement with the SEC in May 2003 to sell up to $300 million in debt. RG&E plans to use the net proceeds from the sale of securities under that shelf registration for general corporate purposes, such as retirement or repurchase of certain of its indebtedness or preferred stock, reduction of short-term debt and additions to working capital. RG&E had $75 million available under a previous shelf registration statement. RG&E currently has $300 million available under the shelf registration statement filed in May 2003.

In July 2003 RG&E paid at maturity $40 million of first mortgage bonds using primarily temporary cash investments and short-term debt.

In September 2003 RG&E issued $75 million of 6 3/8% first mortgage bonds due September 2033 under the shelf registration statements described above. A portion of the net proceeds was used to repay short-term debt, including short-term debt that was issued to pay $40 million of first mortgage bonds that matured in July 2003. RG&E used the remainder of the net proceeds for general corporate purposes.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Results of Operations

Due to its merger completed on June 28, 2002, the company's results of operations include RGS Energy beginning with July 2002.

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands, except per share amounts)
Operating Revenues	$4,593,819	$3,836,469	$3,749,843	20%	2%
Operating Income	$650,114	$592,795	$637,870	10%	(7%)
Income from Continuing   Operations	$207,387	$190,516	$188,712	9%	1%
Net Income	$210,446	$188,603	$187,607	12%	1%
Average Common   Shares Outstanding, basic	145,535	131,117	116,708	11%	12%
Earnings Per Share from   Continuing Operations, basic	$1.43	$1.45	$1.62	(1%)	(10%)
Earnings Per Share, basic	$1.45	$1.44	$1.61	1%	(11%)
Dividends Paid Per Share	$1.00	$.96	$.92	4%	4%

Earnings Per Share

Earnings per share for 2003 increased1cent compared to the prior year. Earnings from continuing operations for 2003 were $1.43 per share compared to $1.45 per share for the prior year. During 2003 the company recognized income from discontinued operations of 2 cents per share for two businesses that were sold.

Items contributing to the 2 cent per share decline in earnings from continuing operations for 2003 include lower noncash pension income that reduced earnings 15 cents per share, and an electric rate reduction of $205 million ordered by the NYPSC for NYSEG. The rate reduction, effective March 1, 2002, reduced 2003 earnings 11 cents per share. Other items that reduced earnings in 2003 include: 4 cents per share for lower transmission revenue, 3 cents per share for higher purchased energy costs and 2 cents per share for losses on the retirement of debt. 2003 earnings were also reduced 9 cents per share as a result of a higher effective tax rate due to changes in estimates of income tax accruals in 2002 and 2003. Those decreases were offset by 8 cents per share for higher electric and natural gas deliveries (primarily residential and commercial) due in part to colder winter weather in the first quarter of 2003 partially offset by unfavorable weather in the third and fourth quarters of 2003, and 8 cents per share due to cost control efforts, including lower interest charges. The change in earnings also reflects the negative effects in 2002 of 19 cents per share for restructuring expenses and 6 cents per share for a writedown of the company's investment in NEON Communications.

Earnings per share decreased 17 cents for 2002 compared to 2001. The decrease was primarily the result of an electric rate reduction of $205 million ordered by the NYPSC for NYSEG, effective March 1, 2002, which reduced earnings 50 cents per share. Other items that reduced earnings in 2002 include: 19 cents per share for restructuring expenses; 16 cents per share for higher operating costs, such as the cost of merger integration efforts; 15 cents per share for fewer

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

wholesale sales at lower market prices; 7 cents per share for a loss on early retirement of debt; and 6 cents per share for a writedown of an investment in NEON Communications. Those decreases were significantly offset by increases of 29 cents per share due to lower natural gas costs, which include the benefit of NYSEG's natural gas supply charge that went into effect October 1, 2002; 13 cents per share for higher electric deliveries (primarily residential and commercial) due to warmer summer weather in 2002 and colder winter weather in the fourth quarter of 2002; 19 cents per share due to the elimination of goodwill amortization in 2002; and 39 cents per share due to the effect of a writedown of the investment in NEON Communications in 2001.

Other Items

Other operating expenses include net periodic pension benefit income of $40 million in 2003, $70 million in 2002 and $76 million in 2001. Other operating expenses would have been $30 million lower for 2003 and would have been $6 million lower for 2002 without those decreases in net periodic pension benefit income. Net periodic pension benefit income represented 11% of net income for 2003, 22% for 2002 and 24% for 2001. The earnings effect from changes in pension benefit income reflects any earnings sharing or deferral mechanisms approved by state utility commissions.

Other (income) decreased $4 million in 2003 as a result of lower interest income and $9 million in 2002 primarily due to decreases in miscellaneous income. Other deductions increased $4 million in 2003 and $9 million in 2002 primarily due to losses on retirement of debt. (See Note 1 to the company's Consolidated Financial Statements.)

Interest charges increased $29 million in 2003, including $27 million because of the addition of RG&E, $15 million because the company recognized as interest expense in 2003 distributions that it had previously recognized as preferred dividends and $14 million that reflects borrowings in June 2002 to finance the company's merger transaction with RGS Energy. (See Notes 1 and 7 to the company's Consolidated Financial Statements.) Those increases were partially offset by $26 million of interest savings primarily due to refinancings and repayments of first mortgage bonds. Interest charges increased $40 million in 2002, including $34 million because of the addition of RG&E and $17 million for additional borrowings to finance the company's merger transaction with RGS Energy. Those increases were partially offset by $10 million of interest savings due to NYSEG's refinancings and repayments of first mortgage bonds.

The $18 million increase in preferred stock dividends in 2002 includes $16 million due to the company's issuance of trust preferred securities in July 2001 and $2 million because of the addition of RG&E.

The effective tax rate for continuing operations was 36% in 2003 and 31% in 2002. The increase was primarily due to the recognition as interest expense in 2003 distributions that the company had previously recognized as preferred dividends and the effect of depreciation and amortization not normalized related to RG&E for a full year in 2003 compared to six months in 2002. The effective tax rate was 31% in 2002 and 43% in 2001. The decrease was the result of various factors including the elimination of goodwill amortization in 2002, the flow-through effect (in 2001 only) of the sale of NMP2, a lower state income tax rate in 2002 due to combined filing benefits, and an increase in distributions on trust preferred securities that were outstanding for a full year in 2002.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Operating Results for the Electric Delivery Business

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Deliveries - Megawatt-hours   Retail   Wholesale	30,593 5,734	26,869 5,330	23,238 6,048	14%  8%	16%  (12%)
Operating Revenues	$2,758,695	$2,568,247	$2,504,896	7%	3%
Operating Expenses	$2,311,801	$2,119,218	$1,951,475	9%	9%
Operating Income	$446,894	$449,029	$553,421	-	(19%)

Operating Revenues: Operating revenues were $190 million higher for 2003 primarily as a result of the addition of RG&E delivery revenues of $343 million. That increase was partially offset by decreases of $35 million due to cooler summer weather for RG&E; $18 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002; $24 million due to the combined effects of NYSEG's rate reduction, effective March 2002, and customers choosing alternate suppliers; $46 million due to the elimination in 2002 of the partial amortization of an asset sale gain account that was used to fund a portion of NYSEG's rate reduction effective March 2002; and $11 million due to lower transmission revenues.

The $63 million increase in operating revenues for 2002 was primarily due to the addition of RG&E delivery revenues of $369 million and increased retail deliveries of $33 million primarily due to warmer summer weather in 2002. Those increases were partially offset by reductions of $138 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002; $114 million due to a rate reduction for NYSEG, effective March 2002; and $64 million of lower wholesale revenues primarily due to lower market prices for electricity.

Operating Expenses: The $193million increase in operating expenses for 2003 was primarily due to the addition of RG&E operating expenses of $282 million. That increase was partially offset by decreases in purchased power costs. Purchased power decreased $18 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002 and $12 million because of a decrease in NUG purchases. Purchased power decreased an additional $53 million due to the effect of customers choosing alternate suppliers partially offset by increases caused by both higher market prices and higher retail deliveries because of colder winter weather.

Operating expenses for 2002 increased $168 million. That increase includes $291 million for the addition of RG&E operating expenses; $25 million for restructuring expenses; $15 million of purchased power costs for higher retail deliveries due to warmer summer weather in 2002 and colder winter weather in the fourth quarter of 2002; $15 million for merger integration efforts; $44 million for purchased power costs to replace energy previously provided by NMP2, which was partially offset by a $35 million decrease in certain operating expenses due to the sale of NMP2; and $12 million for the effect of the sale of NYSEG's share of NMP2 in 2001.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Those increases were partially offset by decreases including $138 million of electricity purchased because CMP is no longer the standard-offer provider for the supply of electricity, $32 million due to lower market prices for electricity and $9 million due to the elimination of goodwill amortization in 2002.

Operating Results for the Natural Gas Delivery Business

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Deliveries - Dekatherms   Retail   Wholesale	212,745 5,360	181,859 7,074	148,000 9,298	17%  (24%)	23%  (24%)
Operating Revenues	$1,462,127	$1,032,539	$1,026,124	42%	1%
Operating Expenses	$1,263,182	$882,883	$936,606	43%	(6%)
Operating Income	$198,945	$149,656	$89,518	33%	67%

Operating Revenues: Operating revenues for 2003 were $430 million higher than the prior year primarily due to the addition of RG&E delivery revenues of $213 million and increases of $50 million due to higher retail deliveries because of colder winter weather in the first quarter of 2003 and $158 million primarily due to higher market prices of natural gas that were passed on to customers.

Operating revenues increased $6 million for 2002. Operating revenues increased $126 million due to the addition of RG&E delivery revenues and $8 million due to increased deliveries primarily because of colder winter weather in the fourth quarter of 2002. Those increases were partially offset by a $98 million decrease because of lower market prices of natural gas that were passed on to customers and a $30 million decrease due to fewer wholesale customers.

Operating Expenses: Operating expenses for 2003 increased $380 million primarily due to the addition of RG&E operating expenses of $178 million, higher natural gas costs of $171 million due to market conditions net of the effect of various rate case deferrals and $28 million due to higher retail deliveries because of colder winter weather in the first quarter of 2003.

Operating expenses decreased $54 million for 2002. That decrease was primarily due to a $159 million decrease in purchased gas costs caused by lower market prices, a $33 million decrease in purchased gas due to fewer wholesale customers and a $15 million decrease due to the elimination of goodwill amortization in 2002. Those decreases were partially offset by increases of $115 million for the addition of RG&E operating expenses, $15 million for restructuring expenses, $9 million for increased purchases of natural gas due to higher deliveries because of colder winter weather in the fourth quarter of 2002, $9 million for higher uncollectible expenses and $6 million for merger integration efforts.

Energy East Corporation
Consolidated Balance Sheets

December 31	2003	2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$113,187	$250,490
Special deposits	34,669	47,643
Accounts receivable, net	753,328	737,876
Fuel, at average cost	159,163	117,678
Materials and supplies, at average cost	22,491	22,953
Accumulated deferred income tax benefits, net	26,262	20,151
Prepayments and other current assets	81,746	86,167
Total Current Assets	1,190,846	1,282,958
Utility Plant, at Original Cost
Electric	5,992,001	5,803,576
Natural gas	2,405,795	2,347,011
Common	361,737	360,776
	8,759,533	8,511,363
Less accumulated depreciation	3,216,927	3,201,158
Net Utility Plant in Service	5,542,606	5,310,205
Construction work in progress	235,503	179,557
Total Utility Plant	5,778,109	5,489,762
Other Property and Investments, Net	452,843	452,710
Regulatory and Other Assets
Nuclear plant obligations	414,432	524,679
Unfunded future income taxes	254,977	234,487
Unamortized loss on debt reacquisitions	47,509	45,353
Environmental remediation costs	122,846	106,262
Nonutility generator termination agreements	106,631	116,782
Asset retirement obligation	163,530	-
Other	407,432	370,354
Total regulatory assets	1,517,357	1,397,917
Goodwill, net	1,533,123	1,518,173
Prepaid pension benefits	608,933	540,426
Other	225,221	262,401
Total other assets	2,367,277	2,321,000
Total Regulatory and Other Assets	3,884,634	3,718,917
Total Assets	$11,306,432	$10,944,347

The notes on pages 47 through 76 are an integral part of the financial statements.

Energy East Corporation
Consolidated Balance Sheets

December 31	2003	2002
(Thousands)
Liabilities
Current Liabilities
Current portion of preferred stock of subsidiary subject to   mandatory redemption requirements	$1,250	-
Current portion of long-term debt	30,989	$545,404
Notes payable	308,406	322,200
Accounts payable and accrued liabilities	339,812	361,499
Interest accrued	48,989	44,310
Taxes accrued	43,710	30,036
Other	191,873	200,927
Total Current Liabilities	965,029	1,504,376
Regulatory and Other Liabilities
Accrued removal obligation	731,621	676,006
Deferred income taxes	181,211	147,018
Gain on sale of generation assets	129,640	152,648
Pension benefits	51,970	67,205
Other	96,509	104,937
Total regulatory liabilities	1,190,951	1,147,814
Deferred income taxes	853,489	770,788
Nuclear plant obligations	277,643	314,013
Other postretirement benefits	408,903	391,049
Asset retirement obligation	437,076	-
Environmental remediation costs	145,446	133,933
Other	346,630	408,841
Total other liabilities	2,469,187	2,018,624
Total Regulatory and Other Liabilities	3,660,138	3,166,438
Debt owed to subsidiary holding solely parent debentures	355,670	-
Preferred stock of subsidiary subject to mandatory    redemption requirements	23,750	-
Other long-term debt	3,638,426	3,351,959
Total long-term debt	4,017,846	3,351,959
Total Liabilities	8,643,013	8,022,773
Commitments	-	-
Preferred Stock of Subsidiaries  Company-obligated mandatorily redeemable trust preferred    securities of subsidiary holding solely parent debentures  Subject to mandatory redemption requirements  Redeemable solely at the option of subsidiaries	-       -       91,095	345,000  25,000  90,962
Common Stock Equity  Common stock ($.01 par value, 300,000 shares authorized,    146,262 shares outstanding at December 31, 2003, and    144,966 shares outstanding at December 31, 2002)	1,463	1,455
Capital in excess of par value	1,458,802	1,447,664
Retained earnings	1,126,457	1,061,428
Accumulated other comprehensive income (loss)	(11,214)	(34,167)
Deferred compensation	(2,820)	-
Treasury stock, at cost (13 shares at December 31, 2003, and    574 shares at December 31, 2002)	(364)	(15,768)
Total Common Stock Equity	2,572,324	2,460,612
Total Liabilities and Stockholders' Equity	$11,306,432	$10,944,347

The notes on pages 47 through 76 are an integral part of the financial statements.

Energy East Corporation
Consolidated Statements of Income

Year Ended December 31	2003	2002	2001
(Thousands, except per share amounts)
Operating Revenues
Sales and services	$4,593,819	$3,836,469	$3,749,843
Operating Expenses
Electricity purchased and fuel used in generation	1,329,443	1,276,087	1,334,507
Natural gas purchased	1,001,649	603,258	694,038
Other operating expenses	837,953	691,987	560,572
Maintenance	202,918	160,230	139,321
Depreciation and amortization	301,264	242,111	203,310
Other taxes	270,478	229,434	192,505
Restructuring expenses	-	40,567	-
Gain on sale of generation assets	-	-	(84,083)
Deferral of asset sale gain	-	-	71,803
Total Operating Expenses	3,943,705	3,243,674	3,111,973
Operating Income	650,114	592,795	637,870
Writedown of Investment	-	12,209	78,422
Other (Income)	(22,073)	(26,496)	(35,202)
Other Deductions	33,302	29,307	20,216
Interest Charges, Net	284,802	256,292	216,388
Preferred Stock Dividends of Subsidiaries	19,009	32,129	14,455
Income From Continuing Operations   Before Income Taxes	335,074	289,354	343,591
Income Taxes	127,687	98,838	154,879
Income From Continuing Operations	207,387	190,516	188,712
Discontinued Operations   Loss from businesses sold (including loss on   disposal in 2003 of $13,360)   Income taxes (benefits)	(9,953) (13,012)	(2,227) (314)	(1,605) (500)
Income (Loss) From Discontinued Operations	3,059	(1,913)	(1,105)
Net Income	$210,446	$188,603	$187,607
Earnings Per Share From Continuing   Operations, basic	$1.43	$1.45	$1.62
Earnings Per Share From Continuing   Operations, diluted	$1.42	$1.45	$1.62
Total Earnings Per Share, basic	$1.45	$1.44	$1.61
Total Earnings Per Share, diluted	$1.44	$1.44	$1.61
Average Common Shares Outstanding, basic	145,535	131,117	116,708
Average Common Shares Outstanding, diluted	145,730	131,117	116,708

The notes on pages 47 through 76 are an integral part of the financial statements.

Energy East Corporation
Consolidated Statements of Cash Flows

Year Ended December 31	2003	2002	2001
(Thousands)
Operating Activities
Net income	$210,446	$188,603	$187,607
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	419,237	255,782	247,847
Income taxes and investment tax credits deferred, net	103,236	43,564	4,588
Restructuring expenses	-	40,567	-
Gain on sale of generation assets	-	-	(84,083)
Deferral of asset sale gain	-	-	71,803
Pension income	(40,128)	(70,189)	(76,229)
Writedown of investment	-	12,209	78,422
Changes in current operating assets and liabilities
Accounts receivable, net	(56,188)	(24,247)	125,121
Sale of accounts receivable program	-	-	(152,000)
Inventory	(50,775)	6,111	(25,445)
Prepayments and other current assets	8,732	(3,998)	3,119
Accounts payable and accrued liabilities	(3,351)	5,551	(123,832)
Other current liabilities	15,941	5,866	(51,373)
Other assets	(134,472)	(66,279)	(44,163)
Other liabilities	9,737	16,896	(6,848)
Net Cash Provided by Operating Activities	482,415	410,436	154,534
Investing Activities
Acquisitions, net of cash acquired	-	(681,397)	-
Utility plant additions	(289,320)	(224,450)	(208,677)
Sale of generation assets	-	59,442	59,441
Other property and investments additions	(39,060)	(29,177)	(30,271)
Other property and investments sold	72,478	12,138	18,967
Special deposits	6,313	(5,166)	19,909
Other	(6,678)	1,490	(19,344)
Net Cash Used in Investing Activities	(256,267)	(867,120)	(159,975)
Financing Activities
Issuance of common stock	4,234	2,574	740
Repurchase of common stock	-	(2,139)	(24,116)
Issuance of mandatorily redeemable trust    preferred securities	-	-	345,000
Repayments of first mortgage bonds and preferred    stock of subsidiaries, including net premiums	(242,066)	(435,720)	(1,890)
Long-term note issuances	504,769	767,807	355,553
Long-term note repayments	(488,654)	(97,124)	(29,965)
Notes payable three months or less, net	(7,044)	166,702	(269,012)
Notes payable issuances	11,000	28,400	54,445
Notes payable repayments	(17,750)	(50,154)	(31,045)
Dividends on common stock	(127,940)	(110,186)	(100,881)
Net Cash (Used in) Provided by Financing Activities	(363,451)	270,160	298,829
Net (Decrease) Increase in Cash and Cash Equivalents	(137,303)	(186,524)	293,388
Cash and Cash Equivalents, Beginning of Year	250,490	437,014	143,626
Cash and Cash Equivalents, End of Year	$113,187	$250,490	$437,014

The notes on pages 47 through 76 are an integral part of the financial statements.

Energy East Corporation
Consolidated Statements of Changes in Common Stock Equity

(Thousands, except per share amounts)	Common Stock Outstanding $.01 Par Value Shares     Amount		Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Deferred Compensation	Treasury Stock	Total
Balance, January 1, 2001	117,656	$1,191	$871,078	$918,016	$(34,823)	-	$(38,940)	$1,716,522
Net income				187,607				187,607
Other comprehensive income, net of tax					12,488			12,488
Comprehensive income								200,095
Common stock dividends     declared ($.92 per share)				(107,342)				(107,342)
Common stock issued - dividend reinvestment     and stock purchase plan	368	4	7,197					7,201
Common stock repurchased	(1,306)	(13)	(24,103)					(24,116)
Capital stock issue expense			(11,498)					(11,498)
Amortization of capital stock issue expense			315					315
Balance, December 31, 2001	116,718	1,182	842,989	998,281	(22,335)	-	(38,940)	1,781,177
Net income				188,603				188,603
Other comprehensive income, net of tax					(11,832)			(11,832)
Comprehensive income								176,771
Common stock dividends     declared ($.96 per share)				(125,456)				(125,456)
Common stock issued - merger transaction	27,509	275	611,807					612,082
Common stock issued - dividend reinvestment     and stock purchase plan	853		17,844					17,844
Common stock repurchased	(114)	(1)	(2,138)					(2,139)
Capital stock issue expense			(52)					(52)
Treasury stock transactions, net		(1)	(23,171)				23,172	-
Amortization of capital stock issue expense			385					385
Balance, December 31, 2002	144,966	1,455	1,447,664	1,061,428	(34,167)	-	(15,768)	2,460,612
Net income				210,446				210,446
Other comprehensive income, net of tax					22,953			22,953
Comprehensive income								233,399
Common stock dividends     declared ($1.00 per share)				(145,417)				(145,417)
Common stock issued - dividend reinvestment     and stock purchase plan	1,064	8	21,703					21,711
Common stock issued - restricted stock plan	229		(1,893)			$(4,401)	6,294	-
Amortization of deferred compensation     under restricted stock plan						1,581		1,581
Capital stock issue expense			(11)					(11)
Treasury stock transactions, net	3		(9,046)				9,110	64
Amortization of capital stock issue expense			385					385
Balance, December 31, 2003	146,262	$1,463	$1,458,802	$1,126,457	$(11,214)	$(2,820)	$(364)	$2,572,324

The notes on pages 47 through 76 are an integral part of the financial statements.

Notes to Consolidated Financial Statements

Energy East Corporation

Note 1. Significant Accounting Policies

Background: Energy East Corporation (Energy East or the company) is a registered public utility holding company under the Public Utility Holding Company Act of 1935. Energy East is a super-regional energy services and delivery company with operations in New York, Connecticut, Massachusetts, Maine and New Hampshire and corporate offices in New York and Maine. Its wholly-owned subsidiaries - and their principal operating utilities - are: Berkshire Energy Resources - The Berkshire Gas Company; CMP Group - Central Maine Power Company (CMP); Connecticut Energy Corporation (CNE) - The Southern Connecticut Gas Company (SCG); CTG Resources, Inc. - Connecticut Natural Gas Corporation (CNG); and RGS Energy Group, Inc. (RGS Energy) - New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E).

Accounts receivable: Accounts receivable include unbilled revenues of $219 million at December 31, 2003, and $237 million at December 31, 2002, and are shown net of an allowance for doubtful accounts of $53 million at December 31, 2003, and $59 million at December 31, 2002. Bad debt expense was $48 million in 2003, $46 million in 2002 and $34 million in 2001. Bad debt expense for 2003 includes RGS Energy for a full year and for 2002 includes RGS Energy beginning July 1, 2002.

In August 2001 NYSEG terminated its agreement to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allowed NYSEG to receive up to $152 million from the sale of such interests. All fees related to the agreement beginning April 1, 2001, are included in interest expense and were approximately $3 million. Fees related to the sale of accounts receivable through March 31, 2001, are included in other deductions and were approximately $2 million in 2001. NYSEG's sale of accounts receivable before the agreement was terminated did not constitute a securitization transaction because the accounts receivable were not transferred to a special purpose entity, and therefore, were not transformed into securities.

Basic and diluted earnings per share: Basic earnings per share (EPS) is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the year. The weighted-average common shares outstanding for diluted EPS include the incremental effect of restricted stock and stock options issued and exclude stock options issued in tandem with stock appreciation rights (SARs). However, all stock options are issued in tandem with SARs and, historically, substantially all stock option plan participants have exercised the SARs instead of the stock options. The numerator used in calculating both basic and diluted EPS for each period is the reported net income. The reconciliation of basic and dilutive average common shares for each year follows:

Year Ended December 31	2003	2002	2001
(Thousands)
Basic average common shares outstanding	145,535	131,117	116,708
Restricted stock awards	195	-	-
Potentially dilutive common shares	197	215	198
Options issued with SARs	(197)	(215)	(198)
Dilutive average common shares	145,730	131,117	116,708

Notes to Consolidated Financial Statements

Energy East Corporation

Options to purchase shares of common stock are excluded from the determination of EPS when the exercise price of the options is greater than the average market price of the common shares during the year. Shares excluded from the EPS calculation were: 2.9 million in 2003, 4.7 million in 2002 and 2.1 million in 2001.

On February 13, 2003, the company awarded 229,230 shares of its common stock, issued out of its treasury stock, to certain employees under its Restricted Stock Plan. (See Note 14.)

Consolidated statements of cash flows: The company considers all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and those investments are included in cash and cash equivalents.

Supplemental Disclosure of Cash Flows Information	2003	2002	2001
(Thousands) Cash paid during the year ended December 31:
Interest, net of amounts capitalized	$245,223	$238,305	$208,431
Income taxes, net of benefits received	$(12,879)	$54,418	$113,274
Acquisitions:
Fair value of assets acquired	-	$3,264,093	-
Liabilities assumed	-	(1,826,528)	-
Preferred stock of subsidiaries	-	(72,000)	-
Common stock issued	-	(612,082)	-
Cash acquired	-	(72,086)	-
Net cash paid for acquisitions	-	$681,397	-

Decommissioning expense: Other operating expenses include nuclear decommissioning expense accruals, which result in corresponding decreases in the regulatory asset for the asset retirement obligation. Contributions are made to the decommissioning trust funds, which are included in other property and investments. Increases in the fair value of fund investments also result in decreases in the regulatory asset for the asset retirement obligation.

Depreciation and amortization: The company determines depreciation expense substantially using straight-line rates, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. The weighted-average service lives of certain classifications of property are: transmission property - 52 years, distribution property - 43 years, generation property - 45 years, gas production property - 25 years, gas storage property - 24 years, and other property - 29 years. RG&E determines depreciation expense for generation property using remaining service life rates, which include estimated cost of removal, based on operating license expiration or anticipated closing dates. The remaining service lives of RG&E's generation property range from six years for nuclear facilities to 32 years for hydroelectric facilities. The company's depreciation accruals were equivalent to 3.4% of average depreciable property for 2003; 3.5% for 2002, which was weighted for the effect of the merger completed in June 2002; and 3.1% for 2001.

Estimates: Preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Notes to Consolidated Financial Statements

Energy East Corporation

Goodwill: The excess of the cost over fair value of net assets of purchased businesses is recorded as goodwill. The company evaluates the carrying value of goodwill for impairment at least annually and on an interim basis if there are indications that goodwill might be impaired. Any impairment would be recognized when the fair value of goodwill is less than its carrying value. Goodwill was amortized on a straight-line basis over five to 40 years until December 31, 2001. (See Note 5.)

Income taxes: The company files a consolidated federal income tax return. Income taxes are allocated among Energy East and its subsidiaries in proportion to their contribution to consolidated taxable income. SEC regulations require that no Energy East subsidiary pay more income taxes than it would pay if a separate income tax return were to be filed. The determination and allocation of the income tax provision and its components are outlined and agreed to in the tax sharing agreements among Energy East and its subsidiaries.

Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.

Other (Income) and Other Deductions:

Year Ended December 31	2003	2002	2001
(Thousands)
Dividends	-	$(233)	$(1,844)
Interest income	$(6,529)	(13,174)	(13,125)
Noncash returns	(1,602)	(6,693)	(2,404)
Allowance for funds used during construction	(1,965)	(1,401)	(652)
Gains from the sale of nonutility property	(347)	(231)	(3,628)
Earnings from equity investments	(4,702)	(4,631)	(7,162)
Miscellaneous	(6,928)	(133)	(6,387)
Total other (income)	$(22,073)	$(26,496)	$(35,202)
Retirement of debt	$22,784	$16,145	-
Fees on sale of accounts receivable	-	-	$2,495
Miscellaneous	10,518	13,162	17,721
Total other deductions	$33,302	$29,307	$20,216

Principles of consolidation: These financial statements consolidate the company's majority-owned subsidiaries after eliminating intercompany transactions, except variable interest entities for which the company is not the primary beneficiary.

Reclassifications: Certain amounts have been reclassified on the consolidated financial statements to conform to the 2003 presentation.

Regulatory assets and liabilities: Pursuant to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, the company capitalizes, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.

Notes to Consolidated Financial Statements

Energy East Corporation

Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Unamortized loss on debt reacquisitions is amortized over the lives of the related debt issues. Nuclear plant obligations, demand-side management program costs, gain on sale of generation assets, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with the company's current rate plans. The company earns a return on substantially all regulatory assets for which funds have been spent.

Revenue recognition: The company recognizes revenues upon delivery of energy and energy-related products and services to its customers.

Pursuant to Maine State Law, since March 1, 2000, CMP has been prohibited from selling power to its retail customers. CMP does not enter into any purchase and sales arrangements for power with the ISO New England, the New England Power Pool, or any other independent system operator or similar entity. All of CMP's power entitlements under its NUG and other purchase power contracts are sold to unrelated third parties under bilateral contracts for the period March 1, 2002, through February 28, 2005.

NYSEG and RG&E enter into power purchase and sales transactions with the NYISO. When electricity from owned generation is sold to the NYISO, and subsequently repurchased from the NYISO to serve their customers, the transactions are recorded on a net basis in the consolidated statements of income.

Risk management: 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. The company uses 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 company uses 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.

The company uses interest rate swap agreements to manage the risk of increases in variable interest rates and to maintain desired fixed-to-floating rate ratios. It records amounts paid and received under the agreements as adjustments to the interest expense of the specific debt issues. The company also uses financial instruments to lock in the treasury rate component of future financings to mitigate risk resulting from interest rate changes.

The company does not hold or issue financial instruments for trading or speculative purposes.

The company recognizes the fair value of its natural gas futures and forwards, financial electricity contracts and interest rate agreements as assets or liabilities. The company's derivative asset was $65 million at December 31, 2003, and $80 million at December 31, 2002, and its derivative liability was $3 million at December 31, 2003, and $9 million at December 31,

Notes to Consolidated Financial Statements

Energy East Corporation

2002. All of the arrangements are designated as cash flow hedging instruments except for the company's $250 million fixed-to-floating interest rate swap agreement, which is designated as a fair value hedge. Changes in the fair value of the cash flow hedging instruments are recognized in other comprehensive income until the underlying transaction occurs. When the underlying transaction occurs, the amounts in accumulated other comprehensive income are reported on the consolidated statements of income. Changes in the fair value of the interest rate swap agreement are reported on the consolidated statements of income in the same period as the offsetting change in the fair value of the underlying debt instrument.

The company uses quoted market prices to fair value derivatives and adjusts for volatility and inflation when the period of the derivative exceeds the period for which market prices are readily available.

As of December 31, 2003, the maximum length of time over which the company is hedging its exposure to the variability in future cash flows for forecasted transactions is 72 months. The company estimates that gains of $22 million will be reclassified from accumulated other comprehensive income into earnings in 2004, as the underlying transactions occur.

The company has commodity purchase and sales contracts for both capacity and energy that have been designated and qualify for the normal purchases and normal sales exception in Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, (Statement 133), as amended.

Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability.

The company's adoption of Statement 143 as of January 1, 2003, did not have a material effect on its financial position or results of operations. There was no effect on net income. The company recognized various amounts on its balance sheets. Changes in the assumptions underlying the items shown in the following table could affect the balance sheet amounts and future costs related to the obligations.

Substantially all of Energy East's asset retirement obligation is related to Ginna.

Notes to Consolidated Financial Statements

Energy East Corporation

As of January 1, 2003	NYSEG	RG&E	Other	Consolidated Energy East
(Thousands)
Asset retirement obligation	$(539)	$(413,988)	$(942)	$(415,469)
Regulatory asset	$350	$139,611	$942	$140,903
Regulatory liability	$(3,689)	$(635)	-	$(4,324)
Increase in utility plant	$30	$74,064	-	$74,094
Decrease in accumulated depreciation	$3,848	$200,948	-	$204,796

Statement 143 provides that if the requirements of Statement 71 are met, a regulatory liability should be recognized for the difference between removal costs collected in rates and actual costs incurred. In previous years, those amounts were included in accumulated depreciation in accordance with industry practice. Accrued removal obligations totaling approximately $732 million as of December 31, 2003 ($80 million for CMP, $304 million for NYSEG, $185 million for RG&E and $163 million for Other), and $676 million as of December 31, 2002 ($74 million for CMP, $286 million for NYSEG, $169 million for RG&E and $147 million for Other), that had previously been embedded within accumulated depreciation were reclassified as a regulatory liability.

Statement 150: In May 2003 the 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. In accordance with Statement 150, Energy East and RG&E are required to classify their mandatorily redeemable preferred stock as a liability on their statements of financial position, which they had previously classified as equity, and to recognize as interest expense distributions that they had previously recognized as dividends. RG&E has $25 million of mandatorily redeemable preferred stock that is consolidated by Energy East. 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.

FIN 46R: In December 2003 the FASB issued its revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of 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. FIN 46R requires a business enterprise to consolidate a variable interest entity if that enterprise has a variable interest that will absorb a majority of the entity's expected losses. The company has a variable interest in Energy East Capital Trust I, a Delaware business trust that is a wholly-owned finance subsidiary of the company. Based on the trust's structure the company is not considered the primary beneficiary of the trust. The company had consolidated the trust under ARB No. 51. The company adopted the provisions of FIN 46R related to special purpose entities as of December 31, 2003, and ceased consolidating the trust as of December 31, 2003.

CMP and NYSEG have independent, ongoing, long-term power purchase contracts with NUGs. (See Note 10.) In accordance with FIN 46R, the company is evaluating if either CMP or NYSEG has a variable interest in any NUG and, to the extent that either company has a variable interest, whether it is a primary beneficiary. To the extent that CMP or NYSEG is a primary

Notes to Consolidated Financial Statements

Energy East Corporation

beneficiary of a NUG, consolidation would be required at March 31, 2004, unless the company is unable to obtain sufficient information to do so. CMP and NYSEG were not involved in the formation of any NUGs, do not have ownership interests in any NUGs and may not be able to obtain sufficient information from the NUGs to determine if either company is a primary beneficiary. The company is presently unable to determine the effect on its financial statements, if any, of applying FIN 46R to CMP's and NYSEG's power purchase contracts with NUGs.

As of December 31, 2003, the company no longer reflects company-obligated mandatorily redeemable trust preferred securities of subsidiary holding solely parent debentures on its Consolidated Balance Sheet, but instead reports its junior subordinated debt held by the trust as long-term debt owed to subsidiary holding solely parent debentures. (See Note 7.)

Utility plant: The company charges repairs and minor replacements to operating expense accounts, and capitalizes renewals and betterments, including certain indirect costs. The original cost of utility plant retired or otherwise disposed of is charged to accumulated depreciation.

Note 2. Sale of Other Businesses

In keeping with its focus on regulated electric and natural gas delivery businesses, during the past few years the company has been systematically exiting certain noncore businesses. 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. Berkshire Energy Resources is a wholly-owned subsidiary of Energy East. In October 2003 Energetix sold its Griffith Oil Co., Inc. subsidiary at an after tax gain of $3 million and in November 2003 Berkshire Propane, Inc. sold its remaining assets at an after tax loss of $2 million. Both businesses were reported in the company's Other business segment. In 2003 the company recognized income from discontinued operations of $3 million or 2 cents per share for the two businesses.

On August 12, 2002, Berkshire Service Solutions, Inc., an energy service provider and a subsidiary of Berkshire Energy Resources, was sold at an after tax loss of approximately $2 million.

Notes to Consolidated Financial Statements

Energy East Corporation

The results of discontinued operations of the businesses sold were:

Year Ended December 31	2003	2002	2001
(Thousands)
Griffith Oil Co., Inc.
Revenues	$321,447	$164,464	-
Pretax (loss) income from discontinued operations    (including loss on disposal in 2003 of $11,553)	$(7,798)	$1,786	-
Income taxes (benefits) (including realization of capital loss    deduction in 2003 of $8,114)	(13,387)	882	-
Income from discontinued operations	$5,589	$904	-
Berkshire Propane, Inc.
Revenues	$5,494	$6,051	$6,562
Pretax (loss) income from discontinued operations    (including loss on disposal in 2003 of $1,807)	$(2,155)	$74	$(259)
Income taxes (benefits)	375	30	(21)
(Loss) income from discontinued operations	$(2,530)	$44	$(238)
Berkshire Service Solutions, Inc.
Revenues	-	$1,934	$3,383
Pretax loss from discontinued operations	-	$(4,087)	$(1,346)
Income taxes (benefits)	-	(1,226)	(479)
Loss from discontinued operations	-	$(2,861)	$(867)
Total income (loss) from discontinued operations	$3,059	$(1,913)	$(1,105)

The major classes of assets and liabilities at the date of sale of the businesses were:

	Griffith Oil Co., Inc	Berkshire Propane, Inc.	Berkshire Service Solutions, Inc.
(Thousands)
Assets   Other property and investments, net	$111,950	$4,809	$287
Liabilities   Current liabilities	$32,248	$447	$322

Note 3. Restructuring

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 $41 million of restructuring expenses included $5 million for CMP, $26 million for NYSEG and a total of $10 million for Berkshire Gas, CNG and SCG. 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. The employee positions affected by the restructuring were identified in the fourth quarter of 2002. The restructuring expenses reduced the company's 2002 net income by $24 million or 19 cents per share. Included in those amounts were $20 million for the voluntary early retirement program that will be paid from the companies' pension plans and $3 million for the involuntary severance program, primarily for salaried employees, and $1 million for other associated costs. During 2003 the entire related involuntary severance liability of $9 million was paid, including $4 million that was deferred for recovery by RG&E.

Notes to Consolidated Financial Statements

Energy East Corporation

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.

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 latest restructuring, the company began to recognize an expected $4 million total liability for an enhanced severance program for certain accounting and finance employees who will be employed through March 31, 2004. Approximately $3 million of the expected total liability will be incurred by the electric delivery business and $1 million by the natural gas delivery business. During the fourth quarter of 2003, 40% of the total liability for each business segment was charged to other operating expenses and represents the company's cumulative expense and liability as of December 31, 2003.

Note 4. Acquisition of RGS Energy Group

Due to the completion of the company's merger with RGS Energy on June 28, 2002, the company's consolidated financial statements include RGS Energy's results beginning with July 2002. RGS Energy did not push goodwill down to RG&E. As of December 31, 2002, $29 million of the purchase price for RGS Energy was allocated to intangible assets, based on an appraisal.

The following pro forma information for the company for the years ended December 31, 2002 and 2001, which is based on unaudited data, gives effect to the company's merger with RGS Energy as if it had been completed at the beginning of each period presented. This information does not reflect future revenues or cost savings that may result from the merger and is not indicative of actual results of operations had the merger occurred at the beginning of the periods presented or of results that may occur in the future.

Year Ended December 31	2002	2001
(Thousands, except per share amounts)
Operating revenues	$4,690,489	$5,290,279
Net income	$201,521	$262,741
Earnings per share of common stock, basic	$1.39	$1.82

Pro forma adjustments reflected in the amounts presented include: (1) adjusting RGS Energy's nonutility assets to fair value based on an independent appraisal, (2) adjusting depreciation and amortization of assets to the accounting base recognized in recording the combination, (3) elimination of amortization of goodwill, (4) amortization of other intangible assets with finite lives, (5) elimination of merger costs, (6) additional interest expense and preferred stock dividends due to the issuance of merger-related debt and securities, (7) adjustments for estimated tax effects of the above adjustments and (8) additional common shares issued in connection with the merger. The pro forma results include a loss of 19 cents per share for restructuring expenses and the writedown of CMP Group's investment in NEON Communications of 6 cents per share in 2002 and 39 cents per share in 2001. The pro forma

Notes to Consolidated Financial Statements

Energy East Corporation

results of operations for 2002 include the results of operations of RGS Energy for the six months ended June 30, 2002, as follows: Operating revenues - $681,571, Operating expenses - $615,851, Operating income - $65,720, Income before income taxes - $36,850, and Net income - $15,550.

Note 5. Goodwill and Other Intangible Assets

The company no longer amortizes goodwill effective January 1, 2002, and does not amortize intangible assets with indefinite lives (unamortized intangible assets). The company tests both goodwill and unamortized intangible assets for impairment at least annually. The company amortizes intangible assets with finite lives (amortized intangible assets) and reviews them for impairment. Annual impairment testing was completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for the companies at September 30, 2003.

Changes in the carrying amount of goodwill, by operating segment, for the year ended December 31, 2003, are shown in the table below. The increase in goodwill related to excess earnings was recorded by RGS Energy. It resulted from the refund to customers of RG&E's excess earnings recorded prior to its acquisition by Energy East, as part of RG&E's 2002 electric and gas rate proceeding, which was a preacquisition contingency related to RG&E.

	Electric Delivery	Natural Gas Delivery	Other	Total
(Thousands)
Balance, January 1, 2003	$819,992	$677,952	$20,229	$1,518,173
Goodwill related to additional   excess earnings	26,486	-	-	26,486
Goodwill related to businesses sold	-	-	(7,799)	(7,799)
Preacquisition income tax and   other adjustments	(1,947)	(833)	(957)	(3,737)
Balance, December 31, 2003	$844,531	$677,119	$11,473	$1,533,123

Other Intangible Assets: The company's unamortized intangible assets had a carrying amount of $10 million at December 31, 2003, and primarily consisted of pension assets, and had a carrying amount of $17 million at December 31, 2002, and primarily consisted of trade names and pension assets. The company's amortized intangible assets had a gross carrying amount of $31 million at December 31, 2003, and $47 million at December 31, 2002, and primarily consisted of investments in pipelines and customer lists. The decreases in the carrying amounts of intangible assets in 2003 represent assets associated with businesses sold. Accumulated amortization was $12 million at December 31, 2003, and $15 million at December 31, 2002. Estimated amortization expense for intangible assets for the next five years is approximately $3 million for 2004, $2 million for 2005 and $1 million each year for 2006 through 2008.

Notes to Consolidated Financial Statements

Energy East Corporation

Transitional Information: Results of operations information for the company as though goodwill had not been amortized for all years presented is:

Year Ended December 31	2003	2002	2001
(Thousands, except per share data)
Reported net income	$210,446	$188,603	$187,607
Add back: Goodwill amortization	-	-	25,379
Adjusted net income	$210,446	$188,603	$212,986
Reported basic earnings per share	$1.45	$1.44	$1.61
Add back: Goodwill amortization	-	-	.22
Adjusted basic earnings per share	$1.45	$1.44	$1.83

Note 6. Income Taxes

Year Ended December 31	2003	2002	2001
(Thousands)
Current	$19,420	$52,407	$148,016
Deferred, net
Accelerated depreciation	44,544	19,120	12,452
Pension benefits	38,426	36,864	31,179
Statement 106 postretirement benefits	(7,119)	(4,627)	(4,079)
Demand-side management	(650)	(2,189)	(9,295)
Asset sale gain account amortization	(12,325)	29,367	-
Restructuring expenses	3,615	(15,816)	-
Contract termination payments	30,801	122	102
Miscellaneous	14,626	(13,886)	(21,381)
ITC	(3,651)	(2,524)	(2,115)
Total for Continuing Operations	$127,687	$98,838	$154,879

The company's effective tax rate differed from the statutory rate of 35% due to the following:

Year Ended December 31	2003	2002	2001
(Thousands)
Tax expense at statutory rate	$123,929	$112,523	$125,301
Depreciation and amortization not normalized	10,715	5,125	26,373
ITC amortization	(3,651)	(2,524)	(2,115)
Trust preferred securities	(4,978)	(9,932)	(4,389)
State taxes, net of federal benefit	12,254	9,793	14,881
Other, net	(10,582)	(16,147)	(5,172)
Total for Continuing Operations	$127,687	$98,838	$154,879

The effective tax rate for continuing operations was 36% in 2003 and 31% in 2002. The increase was primarily due to the recognition as interest expense in 2003 distributions that the company had previously recognized as preferred dividends and the effect of depreciation and amortization not normalized related to RG&E for a full year in 2003 compared to six months in 2002. The effective tax rate was 31% in 2002 and 43% in 2001. The decrease was the result of various factors including the elimination of goodwill amortization in 2002, the flow-through effect (in 2001 only) of the sale of NMP2, a lower state income tax rate in 2002 due to combined filing benefits, and an increase in distributions on trust preferred securities that were outstanding for a full year in 2002.

Notes to Consolidated Financial Statements

Energy East Corporation

The company's deferred tax assets and liabilities consisted of the following:

December 31	2003	2002
(Thousands)
Current Deferred Tax Assets	$26,262	$20,151
Noncurrent Deferred Tax Liabilities
Depreciation	$821,783	$750,739
Unfunded future income taxes	144,705	129,481
Accumulated deferred ITC	41,494	45,039
Deferred gain on sale of generation assets	35,211	63,969
Pension benefits	151,559	87,717
Statement 106 postretirement benefits	(84,327)	(92,182)
Nuclear decommissioning	(49,681)	(44,093)
Other	(26,044)	(22,864)
Total Noncurrent Deferred Tax Liabilities	1,034,700	917,806
Less amounts classified as regulatory liabilities
Deferred income taxes	181,211	147,018
Noncurrent Deferred Income Taxes	$853,489	$770,788

Energy East and its subsidiaries have no federal tax credit carryforwards. A subsidiary of Energy East has a loss carryforward of less than $1 million, with no valuation allowance.

Note 7. Long-term Debt

Debt owed to subsidiary holding solely parent debentures: The debt owed to subsidiary holding solely parent debentures consists of the company's 8 1/4% junior subordinated debt securities maturing on July 1, 2031, that are due to Energy East Capital Trust I.

Energy East Capital Trust I is a Delaware business trust that is a wholly-owned finance subsidiary of the company. Based on the trust's structure the company is not considered the primary beneficiary of the trust and as of December 31, 2003, the company no longer consolidates the trust. (See Note 1.) The assets of the trust consist of the company's 8 1/4% junior subordinated debt securities. The trust has issued $345 million of mandatorily redeemable trust preferred securities that are 8 1/4% Capital Securities. The company has fully and unconditionally guaranteed the trust's payment obligations with respect to the Capital Securities.

Preferred stock of subsidiary subject to mandatory redemption requirements: The preferred stock subject to mandatory redemption requirements is RG&E's 6.60% Series V, Par Value $100, with a redemption price per share of $100 and 250,000 shares authorized and outstanding. This series is subject to a mandatory sinking fund sufficient to redeem, at par, on March 1 of each year from 2004 through 2008, 12,500 shares, and on March 1, 2009, the balance of the shares. RG&E has the option to redeem up to an additional 12,500 shares on the same terms and dates as applicable to the mandatory sinking fund. In the event RG&E should be in arrears in the sinking fund requirement, RG&E may not redeem or pay dividends on any stock subordinate to the preferred stock.

Notes to Consolidated Financial Statements

Energy East Corporation

Voting rights: If preferred stock dividends on RG&E's 6.60% Series V preferred stock are in default in an amount equivalent to four full quarterly dividends, the holders of the preferred stock are entitled to elect a majority of RG&E's directors and their privilege continues until all dividends in default have been paid. The holders of preferred stock are not entitled to vote in respect of any other matters except those, if any, in respect of which voting rights cannot be denied or waived under some mandatory provision of law, and except that RG&E's charter contains provisions to the effect that such holders shall be entitled to vote on certain matters affecting the rights and preferences of the preferred stock.

Whenever holders of preferred stock shall be entitled to vote, they shall be entitled to cast one vote for each share of preferred stock held by them. Holders of RG&E common stock are entitled to one vote per share on all matters.

Other long-term debt: At December 31, 2003 and 2002, the company's consolidated other long-term debt was:

			Amount
	Maturity Dates	Interest Rates	2003	2002
(Thousands)
First mortgage bonds (1)	2008 to 2033	5.84% to 10.06%	$735,500	$890,500
Pollution control notes - fixed	2006 to 2034	5 3/8% to 6.15%	351,000	351,000
Pollution control notes - variable	2015 to 2032	0.95% to 4.30%	408,900	408,900
Various long-term debt	2004 to 2033	1.20% to 10.48%	2,173,355	1,924,130
Putable asset term securities	-	-	-	300,000
Obligations under capital leases			31,821	34,447
Unamortized premium and discount on debt, net			(31,161)	(11,614)
			3,669,415	3,897,363
Less debt due within one year, included in current liabilities			30,989	545,404
Total			$3,638,426	$3,351,959

As a registered holding company under the Public Utility Holding Company Act of 1935, Energy East is prohibited from obtaining upstream guarantees and credit support from its subsidiaries. Energy East has no secured indebtedness and none of its assets are mortgaged, pledged or otherwise subject to lien. None of Energy East's debt obligations are guaranteed or secured by its subsidiaries.

(1)For Energy East, on a consolidated basis, in addition to the information provided below for CMP, NYSEG and RG&E: Berkshire Gas and SCG have first mortgage bonds that are secured by liens on substantially all of their respective utility properties. CTG Resources and CNE have subsidiaries with long-term debt that is secured by properties of those subsidiaries.

CMP has no long-term debt obligations that are secured. CMP has no intercompany collateralizations and has no guarantees to affiliates or subsidiaries. CMP's debt has no guarantees from parent or affiliates or any additional credit supports.

NYSEG has no secured indebtedness. None of NYSEG's debt obligations are guaranteed or secured by any of its affiliates.

Notes to Consolidated Financial Statements

Energy East Corporation

RG&E's first mortgage bonds, totaling $701 million at December 31, 2003, are secured by a first mortgage lien on substantially all of its properties. RG&E has no other secured indebtedness. None of RG&E's other debt obligations are guaranteed or secured by any of its affiliates.

At December 31, 2003, other long-term debt, including sinking fund obligations, and capital lease payments (in thousands) that will become due during the next five years are:

2004	2005	2006	2007	2008
$30,989	$59,813	$340,377	$232,236	$93,303

Cross-default Provisions: Energy East has a provision in its senior unsecured indenture, which provides that default by the company with respect to any other debt in excess of $40 million will be considered a default under the company's senior unsecured indenture.

NYSEG has provisions in its unsecured indenture and the reimbursement agreements relating to certain series of pollution control bonds, which provide that default by NYSEG with respect to any other debt in excess of $40 million in the case of the unsecured indenture and $5 million in the case of the reimbursement agreements will be considered a default under those respective documents.

RG&E has a provision in a participation agreement relating to certain series of pollution control bonds, which provides that default by RG&E with respect to bonds issued under its first mortgage indenture will be considered a default under the participation agreement.

Note 8. Bank Loans and Other Borrowings

The company and its subsidiaries have committed credit agreements with various expiration dates in 2004 and 2005 and pay fees in lieu of compensating balances in connection with these agreements. These agreements provided for maximum borrowings of $680 million at December 31, 2003, and $755 million at December 31, 2002. Uncommitted credit agreements, which expire in 2004, provide for additional borrowings of $16 million.

The company and its subsidiaries use short-term, unsecured notes and drawings on their credit agreements to finance certain refundings and for other corporate purposes. There was $308 million of such short-term debt outstanding at December 31, 2003, and $322 million outstanding at December 31, 2002. The weighted-average interest rate on short-term debt was 1.8% at December 31, 2003, and 2.1% at December 31, 2002.

In its revolving credit agreements Energy East covenants not to permit, without the consent of the lenders, its ratio of consolidated indebtedness to consolidated total capitalization at the last day of any fiscal quarter to exceed 0.65 to 1.00. Continued unremedied failure to comply with this covenant for 15 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. Energy East's ratio of consolidated indebtedness to consolidated total capitalization pursuant to the revolving credit agreements was 0.57 to 1.00 at December 31, 2003.

Notes to Consolidated Financial Statements

Energy East Corporation

In its revolving credit facility, secured by its accounts receivable, CMP covenants that (i) its consolidated total debt shall at all times be no more than 65% of the sum of its consolidated total debt and its total stockholder's equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00. Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2003, CMP's consolidated total debt ratio was 31% and its interest coverage ratio was 4.0 to 1.00.

In their joint revolving credit agreement NYSEG and RG&E each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2003, the ratio of earnings before interest expense and income tax to interest expense was 5.2 to 1.0 for NYSEG and 1.9 to 1.0 for RG&E. At December 31, 2003, the ratio of total indebtedness to total capitalization was 0.53 to 1.00 for NYSEG and 0.50 to 1.00 for RG&E.

NYSEG has a letter of credit and reimbursement agreement in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 as of the last day of any fiscal quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2003.

Notes to Consolidated Financial Statements

Energy East Corporation

Note 9. Preferred Stock Redeemable Solely at the Option of Subsidiaries

At December 31, 2003 and 2002, the consolidated preferred stock was:

Subsidiary and Series	Par Value Per Share	Redemption Price Per Share	Shares Authorized and Outstanding(1)	Amount             (Thousands)              2003                2002
CMP, 6% Noncallable	$100	-	5,180	$518	$518
CMP, 3.50%	100	$101.00	220,000	22,000	22,000
CMP, 4.60%	100	101.00	30,000	3,000	3,000
CMP, 4.75%	100	101.00	50,000	5,000	5,000
CMP, 5.25%	100	102.00	50,000	5,000	5,000
NYSEG, 3.75%	100	104.00	78,379	7,838	7,838
NYSEG, 4 1/2% (1949)	100	103.75	11,800	1,180	1,180
NYSEG, 4.40%	100	102.00	7,093	709	709
NYSEG, 4.15% (1954)	100	102.00	4,317	432	432
RG&E, 4% F	100	105.00	120,000	12,000	12,000
RG&E, 4.10% H	100	101.00	80,000	8,000	8,000
RG&E, 4.75% I	100	101.00	60,000	6,000	6,000
RG&E, 4.10% J	100	102.50	50,000	5,000	5,000
RG&E, 4.95% K	100	102.00	60,000	6,000	6,000
RG&E, 4.55% M	100	101.00	100,000	10,000	10,000
Berkshire, 4.80%	100	100.00	2,499	250	257
CNG, 6.00%	100	110.00	4,104	411	411
CNG, 8.00% Noncallable	3.125	-	108,706	339	340
Preferred stock issuance costs				(2,582)	(2,723)
Total				$91,095	$90,962

(1) At December 31, 2003, the company and its subsidiaries had 15,790,801 shares of $100 par value preferred stock, 16,800,000 shares of $25 par value preferred stock, 775,335 shares of $3.125 par value preferred stock, 600,000 shares of $1 par value preferred stock, 10,000,000 shares of $.01 par value preferred stock, 1,000,000 shares of $100 par value preference stock and 6,000,000 shares of $1 par value preference stock authorized but unissued.

The company's subsidiaries redeemed or purchased the following amounts of preferred stock during the three years 2001 through 2003:

Subsidiary	Date	Series	Amount
CNG	Various 2001	6.00%	$45,900*
CNG	Various 2001	8.00%	$41,222**
CNG	June 7, 2002	6.00%	$2,500*
CNG	September 16, 2003	8.00%	$428*
Berkshire	September 30, 2001	4.80%	$41,000*
Berkshire	September 30, 2002	4.80%	$1,500*
Berkshire	September 9, 2003	4.80%	$7,500*

  * Redeemed  ** Substantially all purchased at a premium

Voting rights: If preferred stock dividends on any series of preferred stock of a subsidiary, other than the 6% Noncallable series and the 8.00% series, are in default in an amount equivalent to four full quarterly dividends, the holders of the preferred stock of such subsidiary are entitled to

Notes to Consolidated Financial Statements

Energy East Corporation

elect a majority of the directors of such subsidiary (and, in the case of the 6.00% series, the largest number of directors constituting a minority of the board) and their privilege continues until all dividends in default have been paid. The holders of preferred stock, other than the 6% Noncallable series and the 8.00% series, are not entitled to vote in respect of any other matters except those, if any, in respect of which voting rights cannot be denied or waived under some mandatory provision of law, and except that the charters of the respective subsidiaries contain provisions to the effect that such holders shall be entitled to vote on certain matters affecting the rights and preferences of the preferred stock.

Holders of the 6% Noncallable series and the 8.00% series are entitled to one vote per share and have full voting rights on all matters.

Whenever holders of preferred stock shall be entitled to vote, they shall be entitled to cast one vote for each share of preferred stock held by them. Holders of NYSEG common stock are entitled to one vote per share on all matters, except in the election of directors with respect to which NYSEG common stock has cumulative voting rights. Holders of CMP common stock are entitled to one-tenth of one vote per share on all matters. Holders of the common stock of the other subsidiaries are entitled to one vote per share on all matters.

Note 10. Commitments

Capital spending: The company has commitments in connection with its capital spending program. Capital spending is projected to be $345 million in 2004, including nuclear fuel, and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. The company's capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

Nonutility generator power purchase contracts: CMP and NYSEG together expensed approximately $608 million for NUG power in 2003, $611 million in 2002 and $593 million in 2001. CMP and NYSEG estimate that their combined NUG power purchases will be $642 million in 2004, $683 million in 2005, $609 million in 2006, $574 million in 2007 and $367 million in 2008.

Note 11. Jointly-Owned Generation Assets and Nuclear Generation Insurance
and Decommissioning

Cayuga Energy, Inc.: Cayuga Energy owns an 85% interest in South Glens Falls Energy, LLC, the owner of a 67-megawatt natural gas-fired combined cycle generating station operating as an exempt wholesale generator.

As part of a joint venture with PEI Power Corporation, Cayuga Energy owns 50.1% of a
44-megawatt natural gas-fired peaking-power plant. The joint venture company, PEI Power II, LLC, operates the plant as an exempt wholesale generator.

Notes to Consolidated Financial Statements

Energy East Corporation

CMP: CMP has ownership interests in three nuclear generating facilities in New England. The largest is a 38% interest in Maine Yankee Atomic Power Company. CMP also owns a 9.5% interest in Yankee Atomic Electric Company and a 6% interest in Connecticut Yankee Atomic Power Company. Maine Yankee, Yankee Atomic and Connecticut Yankee have been permanently shut down and are in the process of being decommissioned. CMP expects the decommissioning of Maine Yankee and Yankee Atomic to be completed in 2005 and the decommissioning of Connecticut Yankee to be completed in 2006.

In July 2002 Vermont Yankee Nuclear Power Corporation sold the Vermont Yankee nuclear power plant, including CMP's 4% ownership interest, to Entergy Corporation. Benefits realized by CMP from the sale, which were less than $1 million, were used to reduce CMP customers' future obligations for stranded costs. The transaction included a power purchase agreement that calls for Entergy to provide all of the plant's electricity to the sellers through 2012, the year the initial operating license for the plant expires.

Sale of Nine Mile Point 2: In November 2001 NYSEG and RG&E sold their interests in NMP2 to Constellation Nuclear. In October 2001 the NYPSC issued an order approving the sale.

NYSEG: NYSEG's 18% share of NMP2's operating expenses until it was sold is included in various categories on the statements of income. Upon completion of the sale of NMP2, NYSEG recorded an asset sale gain of approximately $110 million, in accordance with the NYPSC's order approving the sale, as a regulatory liability under Statement 71. The gain includes a gross up for unfunded future income taxes and is being returned to customers in accordance with NYSEG's current electric rate plan, which was approved by the NYPSC in February 2002.

RG&E: For its 14% share of NMP2, the October 2001 NYPSC order provided for RG&E to establish a regulatory asset of approximately $326 million at the time of closing. RG&E agreed to a one-time $20 million pretax accelerated amortization of the regulatory asset that was recorded in the third quarter of 2001. In addition, RG&E accelerated its recognition of approximately $13 million of previously deferred investment tax credits. RG&E also agreed to amortize the regulatory asset by an additional $30 million per year during the period from the closing of the sale of NMP2 until RG&E's base electric rates are reset. The $30 million annual amortization reflects RG&E's projected savings for its share of NMP2 operating expenses compared to the estimated cost of electricity purchases to replace RG&E's presale share of the output. The terms associated with the recovery of the remaining regulatory asset will be established in future RG&E rate proceedings. The settlement further provides that it constitutes a final and irrevocable resolution of all RG&E ratemaking issues associated with the sale of NMP2 and RG&E's ability to recover through rates the costs associated with its investment in NMP2.

NYSEG and RG&E's pre-existing decommissioning funds for NMP2 were transferred to Constellation, which has taken responsibility for all future decommissioning funding.

The transaction included a power purchase agreement that calls for Constellation to provide electricity to NYSEG and RG&E, at fixed prices, for 10 years. The power purchase agreement is a contract for physical delivery of NYSEG's 18% share and RG&E's 14% share of 90% of the output from NMP2. NYSEG and RG&E record expenses for electricity purchased in accordance with the agreement at the time the power is physically delivered, at prices pursuant to the

Notes to Consolidated Financial Statements

Energy East Corporation

agreement. The contract is not required to be marked-to-market and is not considered to be a derivative instrument because it qualifies for the normal purchases and normal sales exception in Statement 133, as amended.

After the power purchase agreement is completed a revenue sharing agreement will begin. The revenue sharing agreement could provide additional revenue to NYSEG and RG&E through 2021, which would mitigate increases in electricity prices. Both agreements are based on plant output. No amounts are recorded under the revenue sharing agreement because any benefit that may occur between 2011 and 2021 cannot be estimated. Any benefits from the revenue sharing agreement will be deferred for customers.

Nuclear insurance: The Price-Anderson Act is a federal statute providing, among other things, a limit on the maximum liability of nuclear reactor owners for damages resulting from a single nuclear incident. The public liability limit for a nuclear incident is approximately $10.9 billion and is subject to inflation and changes in the number of licensed reactors. RG&E carries the maximum available commercial insurance of $300 million and participates in the mandatory financial protection pool for the remaining $10.6 billion. Under the Price-Anderson Act, RG&E would be liable for up to $101 million per incident payable at a rate not to exceed $10 million per incident per year.

In addition to the insurance required by the Price-Anderson Act, RG&E also carries nuclear property damage insurance and accidental outage insurance through Nuclear Electric Insurance Limited. Under those insurance policies, RG&E could be subject to assessments if losses exceed the accumulated funds available to the insurers. The maximum amounts of the assessments for the current policy year are $13 million for nuclear property damage insurance and $4 million for accidental outage insurance.

Nuclear plant decommissioning costs: The present value of the estimated liability for decommissioning the various interests in nuclear plants, including spent fuel storage, is $134 million for CMP, which was updated in 2003 to include long-term spent fuel storage and increases in projected costs, and $421 million for RG&E. The amount currently billed or accrued for those costs is recovered by CMP and RG&E through their electric rates.

Note 12. Environmental Liability

From time to time environmental laws, regulations and compliance programs may require changes in the company's operations and facilities and may increase the cost of electric and natural gas service.

The U.S. Environmental Protection Agency and various state environmental agencies, as appropriate, notified the company that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at 19 waste sites. The 19 sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the 19 sites, 10 sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites, one is included in Maine's Uncontrolled Sites Program, one is included on the Massachusetts Non-Priority Confirmed Disposal Site list and seven sites are also included on the National Priorities list.

Notes to Consolidated Financial Statements

Energy East Corporation

Any liability may be joint and several for certain of those sites. The company has recorded an estimated liability of $2 million related to 13 of the 19 sites. Remediation costs have been paid at the remaining six sites, and the company expects no additional liability to be incurred. An estimated liability of $4 million has been recorded related to 12 sites where the company believes it is probable that it will incur remediation costs and/or monitoring costs, although it has not been notified that it is among the potentially responsible parties. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to the company.

The company has a program to investigate and perform necessary remediation at its 60 sites where gas was manufactured in the past. Eight sites are included in the New York State Registry, eight sites are included in the New York Voluntary Cleanup Program, four sites are part of Maine's Voluntary Response Action Program and three of those four sites are part of Maine's Uncontrolled Sites Program, three sites are included in the Connecticut Inventory of Hazardous Waste Sites, and three sites are on the Massachusetts Department of Environmental Protection's list of confirmed disposal sites. The company has entered into consent orders with various environmental agencies to investigate and, where necessary, remediate 39 of its 60 sites.

The company's estimate for all costs related to investigation and remediation of its 60 sites ranges from $138 million to $234 million at December 31, 2003. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations.

The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites was $138 million at December 31, 2003, and $126 million at December 31, 2002. The company recorded a corresponding regulatory asset, net of insurance recoveries, since it expects to recover the net costs in rates.

Energy East's environmental liabilities are recorded on an undiscounted basis unless payments are fixed and determinable. Nearly all of Energy East's environmental liability accruals, which are expected to be paid through the year 2017, have been established on an undiscounted basis. Insurance settlements have been received by Energy East subsidiaries during the last three years, which they accounted for as reductions in their related regulatory assets.

Notes to Consolidated Financial Statements

Energy East Corporation

Note 13. Fair Value of Financial Instruments

The carrying amounts and estimated fair values of the company's financial instruments are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.

December 31	2003		2002
	Carrying Amount	Estimated Fair Value	Carrying Amount	Estimated Fair Value
(Thousands)
Investments - classified as   available-for-sale	$342,267	$342,217	$296,425	$296,392
Debt owed to affiliate	$355,670	$389,814	-	-
Preferred stock of subsidiary subject to   mandatory redemption requirements	$25,000	$25,000	-	-
First mortgage bonds	$734,111	$810,677	$888,870	$973,232
Pollution control notes - fixed	$351,000	$367,385	$351,000	$364,865
Pollution control notes - variable	$408,900	$408,900	$408,900	$408,900
Various long-term debt	$2,143,583	$2,370,463	$1,915,160	$2,088,303
Putable asset term securities	-	-	$298,986	$335,288

The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values. Special deposits may include restricted funds set aside as collateral for first mortgage bonds and collateral received from counterparties. The carrying amount approximates fair value because the special deposits have been invested in securities that mature within one year. A majority of the investments classified as held for sale represents decommissioning trust funds for Ginna. In December 2003 those funds were converted to short-term, highly liquid investments in preparation for the sale of Ginna.

In 2001 the company evaluated the carrying value of its investment in NEON Communications, Inc. because there had been a significant decline in the market value of NEON common shares. That decline was consistent with the market performance of telecommunications businesses as a whole. A decline was determined to be other than temporary during the third quarter and the investment was written down to its fair market value of $12 million. That writedown totaled $46 million after taxes, or 39 cents per share.

During the first half of 2002 the company determined that additional declines in NEON's market value were other than temporary and further wrote down the cost basis of that investment. The investment was written down to $2 million based on the closing market price of NEON common shares on March 31, 2002. That writedown totaled $6 million after taxes, or 5 cents per share. In the second quarter of 2002 the NEON common shares were delisted from NASDAQ and

NEON filed a reorganization plan under the U.S. Bankruptcy Code. The company wrote off its remaining $2 million investment during the second quarter, which was $1 million after taxes, or 1 cent per share.

The investment in NEON was classified as available-for-sale, accounted for by the cost method and carried at its fair value, with changes in fair value recognized in other comprehensive

Notes to Consolidated Financial Statements

Energy East Corporation

income. No income or loss related to the investment in NEON was included in the company's operating income in earlier periods.

Note 14. Stock-Based Compensation

The company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, to account for its stock-based compensation plans. Compensation expense would have been the same in 2003, 2002 and 2001 had it been determined consistent with Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, because stock appreciation rights (SARs) were granted along with any options granted. SARs will continue to be issued along with any options granted.

The company may grant options and SARs to senior management and certain other key employees under its stock option plan. Options granted in 2001, 2002 and 2003 vest over either one-year or two-year periods, subject to, with certain exceptions, continuous employment. All options expire 10 years after the grant date. Of the 13 million shares authorized at December 31, 2003, and the 10 million shares authorized at December 31, 2002, unoptioned shares totaled 5.5 million at December 31, 2003, and 1.9 million at December 31, 2002.

The company recorded compensation expense (benefit) for options/SARs of $3 million in 2003, $12 million in 2002 and less than $(1) million in 2001.

During 2003, 639,500 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $19.10. 3,000 options with a weighted-average exercise price of $18.55 and 882,970 SARs with a weighted-average exercise price of $18.67 were exercised in 2003. 763,355 options/SARs with an exercise price of $22.67 were forfeited in 2003. The 6,014,522 options/SARs outstanding at December 31, 2003, had a weighted-average exercise price of $20.87. Of those outstanding at December 31, 2003, 28,309 options/SARs with exercise prices ranging from $10.88 to $14.69 and a weighted-average remaining life of three years had a weighted-average exercise price of $10.89 and 5,986,213 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of seven years had a weighted-average exercise price of $20.92. Of those exercisable at December 31, 2003, 28,309 options/SARs with exercise prices ranging from $10.88 to $14.69 had a weighted-average price of $10.89 and 4,658,043 options/SARs with exercise prices ranging from $17.94 to $28.72 had a weighted-average exercise price of $21.17.

During 2002, 2,810,500 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $20.34. 347,863 SARs with a weighted-average exercise price of $16.26 were exercised in 2002. 74,337 options/SARs with an exercise price of $19.43 were forfeited in 2002. The 7,024,347 options/SARs outstanding at December 31, 2002, had a weighted-average exercise price of $20.95. Of those outstanding at December 31, 2002, 91,309 options/SARs with exercise prices ranging from $10.88 to $14.69 and a weighted-average remaining life of four years had a weighted-average exercise price of $10.88 and 6,933,038 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of eight years had a weighted-average exercise price of $21.08. Of those

Notes to Consolidated Financial Statements

Energy East Corporation

exercisable at December 31, 2002, 91,309 options/SARs with exercise prices ranging from $10.88 to $14.69 had a weighted-average price of $10.88 and 4,611,209 options/SARs with exercise prices ranging from $17.94 to $28.72 had a weighted-average exercise price of $21.66.

During 2001, 1,799,000 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $18.88. 54,332 SARs with a weighted-average exercise price of $17.51 were exercised in 2001. 34,000 options/SARs with an exercise price of $21.03 were forfeited in 2001. The 4,636,047 options/SARs outstanding at December 31, 2001, had a weighted-average exercise price of $20.95. Of those outstanding at December 31, 2001, 191,309 options/SARs with exercise prices ranging from $10.88 to $14.69 and a weighted- average remaining life of five years had a weighted-average exercise price of $10.88 and 4,444,738 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of eight years had a weighted-average exercise price of $21.38. Of those exercisable at December 31, 2001, 191,309 options/SARs with exercise prices ranging from $10.88 to $14.69 had a weighted-average price of $10.88 and 2,939,545 options/SARs with exercise prices ranging from $17.94 to $28.72 had a weighted-average exercise price of $22.17.

The company's Long-term Executive Incentive Share Plan provided participants cash awards if certain shareholder return criteria were achieved. There were no performance shares outstanding at December 31, 2003, and 59,130 performance shares outstanding at December 31, 2002. There was no compensation expense under this plan for 2003, $0.4 million for 2002 and no compensation expense for 2001. Beginning January 1, 2001, no new performance shares were granted under this plan (other than dividend performance shares). The plan was eliminated in 2003.

On February 13, 2003, the company awarded 229,230 shares of its common stock, issued out of its treasury stock, to certain employees under its Restricted Stock Plan and recorded deferred compensation of $4 million based on the market price of $19.20 per share of common stock on the date of the award. An aggregate two million shares may be granted under the Restricted Stock Plan, subject to adjustment. Shares of restricted stock are awarded in the name of the employee, who has all the rights of a shareholder, subject to certain restrictions on transferability and a risk of forfeiture. The shares vest based on the conditions outlined in the restricted stock award grants, including the achievement of targeted shareholder returns, but no later than January 1, 2009.

Notes to Consolidated Financial Statements

Energy East Corporation

Note 15. Accumulated Other Comprehensive Income

(Thousands)	Balance January 1, 2001	2001 Change	Balance December 31, 2001	2002 Change	Balance December 31, 2002	2003 Change	Balance December 31, 2003
Foreign currency translation adjustment, net of income tax benefit of $ - for 2001, 2002 and 2003	$(86)	$86	-	-	-	-		-
Unrealized gains (losses) on investments:  Unrealized holding gains   losses) during period, net of   income tax benefit (expense)   of $7,980 for 2001, $6,803 for   2002 and $(253) for 2003  Reclassification adjustment for   losses included in net income,   net of income tax benefit of   $32,674 for 2001 and $5,087   for 2002		(10,400) 45,748		$(9,654) 7,122		$744 -
Net unrealized gains (losses) on investments	(34,107)	35,348	$1,241	(2,532)	$(1,291)	744		$(547)
Minimum pension liability  adjustment, net of income tax  benefit (expense) of $1,828 for  2001, $39,378 for 2002 and  $(14,484) for 2003	(630)	(2,546)	(3,176)	(58,485)	(61,661)	21,192		(40,469)
Unrealized gains (losses) on derivatives qualified as hedges:  Unrealized gains on derivatives   qualified as hedges arising   during the period due to   cumulative effect of a change   in accounting principle, net of   income tax expense of   $(38,671) for 2001  Unrealized gains (losses) during   period on derivatives qualified   as hedges, net of income tax   benefit (expense) of $59,510 for   2001, $(26,984) for 2002 and   $(14,391) for 2003  Reclassification adjustment for   (gains) losses included in net   income, net of income tax   (benefit) expense of $(7,416)   for 2001, $(7,351) for 2002 and   $14,123 for 2003		58,250  (89,955) 11,305		-      37,692  11,493		-      22,320  (21,303)
Net unrealized gains (losses) on derivatives qualified as hedges	-	(20,400)	(20,400)	49,185	28,785	1,017		29,802
Accumulated Other Comprehensive Income (Loss)	$(34,823)	$12,488	$(22,335)	$(11,832)	$(34,167)	$22,953		$(11,214)

(See Risk management in Note 1.)

Notes to Consolidated Financial Statements

Energy East Corporation

Note 16. Retirement Benefits

	Pension Benefits		Postretirement Benefits
	2003	2002	2003	2002
(Thousands)
Change in benefit obligation
Benefit obligation at January 1	$2,093,864	$1,369,448	$557,270	$408,427
Service cost	31,216	29,318	6,686	6,040
Interest cost	132,491	111,943	36,712	32,215
Plan participants' contributions	-	-	303	212
Plan amendments	9	465	(785)	(11,922)
Actuarial loss	62,881	114,742	44,371	55,240
Business combination	-	501,454	-	92,198
Curtailment	(655)	-	-	-
Special termination benefits	-	64,909	-	-
Benefits paid	(179,687)	(98,415)	(33,321)	(25,140)
Benefit obligation at December 31	$2,140,119	$2,093,864	$611,236	$557,270
Change in plan assets
Fair value of plan assets at January 1	$2,064,401	$1,822,052	$34,088	$38,634
Actual return on plan assets	487,346	(244,955)	5,905	(3,248)
Employer contributions	20,006	329	30,044	23,215
Plan participants' contributions	-	-	303	212
Business combination	-	585,390	-	-
Adjustment	-	-	-	415
Benefits paid	(179,687)	(98,415)	(33,321)	(25,140)
Fair value of plan assets at December 31	$2,392,066	$2,064,401	$37,019	$34,088
Funded status	$251,947	$(29,463)	$(574,217)	$(523,182)
Unrecognized net actuarial loss	312,856	527,617	140,940	106,401
Unrecognized prior service cost (benefit)	45,360	50,741	(48,221)	(54,929)
Unrecognized net transition   (asset) obligation	(1,230)	(8,469)	72,595	80,661
Prepaid (accrued) benefit cost	$608,933	$540,426	$(408,903)	$(391,049)
Amounts recognized on the balance sheet
Prepaid benefit cost	$608,933	$540,426	-	$99
Accrued benefit cost	-	-	$(408,903)	(391,148)
Additional minimum liability	(149,101)	(185,321)	-	-
Intangible asset	5,847	6,226	-	-
Regulatory liability	76,914	76,913	-	-
Accumulated other comprehensive income	66,340	102,182	-	-
Net amount recognized	$608,933	$540,426	$(408,903)	$(391,049)

The company uses a December 31 measurement date for its pension and postretirement benefit plans.

The company's accumulated benefit obligation for all defined benefit pension plans was $1.9 billion at December 31, 2003 and 2002.

CMP Group's, CNE's and CTG Resources' postretirement benefits were partially funded as of December 31, 2003 and 2002.

Notes to Consolidated Financial Statements

Energy East Corporation

The minimum liability included in other comprehensive income for pension benefits decreased $36 million in 2003 and increased $98 million in 2002. The company recorded a minimum pension liability of $149 million at December 31, 2003, as required by Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions. The effect of the minimum pension liability was recognized in other long-term liabilities, intangible assets, regulatory liability and other comprehensive income, as appropriate, and is prescribed when the accumulated benefit obligation in the plan exceeds the fair value of the underlying pension plan assets and accrued pension liabilities. The decrease in the unfunded accumulated benefit obligation in 2003 was primarily due to a higher than estimated actual return on plan assets.

Weighted-average assumptions used to determine benefit	Pension Benefits		Postretirement Benefits
obligations at December 31	2003	2002	2003	2002
Discount rate	6.25%	6.50%	6.25%	6.50%
Rate of compensation increase	4.00%	4.00%	4.00%	4.00%

As of December 31, 2003, the company decreased its discount rate from 6.5% to 6.25%.

	Pension Benefits			Postretirement Benefits
	2003	2002	2001	2003	2002	2001
(Thousands)
Components of net periodic benefit cost
Service cost	$31,216	$29,318	$23,967	$6,686	$6,040	$5,091
Interest cost	132,491	111,943	90,949	36,712	32,215	25,024
Expected return   on plan assets	(204,173)	(190,541)	(161,731)	(2,801)	(2,993)	(3,378)
Amortization of prior   service cost	4,985	8,035	7,822	(6,879)	(6,761)	(6,753)
Recognized net   actuarial gain	(6,185)	(36,686)	(41,750)	6,729	1,647	(4,122)
Amortization of transition   (asset) obligation	(7,238)	(7,238)	(7,238)	8,066	9,126	9,126
Special termination benefits	-	64,909	2,551	-	-	-
Curtailment	403	-	-	(614)	-	-
Deferral for future recovery	-	(32,086)	-	-	-	-
Net periodic benefit cost	$(48,501)	$(52,346)	$(85,430)	$47,899	$39,274	$24,988

Net periodic benefit cost is included in other operating expenses. The net periodic benefit cost for postretirement benefits represents the cost the company charged to expense for providing health care benefits to retirees and their eligible dependents. The amount of postretirement benefit cost deferred was $80 million as of December 31, 2003, and $88 million as of December 31, 2002. The company expects to recover any deferred postretirement costs by 2012. The transition obligation for postretirement benefits is being amortized over a period of 20 years.

Notes to Consolidated Financial Statements

Energy East Corporation

Weighted-average assumptions used    to determine net periodic benefit cost	Pension Benefits			Postretirement Benefits
Year ended December 31	2003	2002	2001	2003	2002	2001
Discount rate	6.50%	7.00%	7.25%	6.50%	7.00%	7.25%
Expected return on plan assets	8.75%	9.00%	9.00%	8.75%	9.00%	9.00%
Rate of compensation increase	4.00%	4.00%	4.00%	4.00%	4.00%	4.00%

The company's expected rate of return on plan assets assumption was developed based on a review of historical returns for the major asset classes. This analysis also considered both current capital market conditions and projected future conditions. Given the current low interest rate environment, the company selected an assumption of 8.75% per year, which is lower than the rate otherwise determined solely based on historical returns.

The company assumed a 10.0% annual rate of increase in the per capita cost of covered health care benefits for 2004 that gradually decreases to 5.0% by the year 2007. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase	1% Decrease
Effect on total of service and interest cost components	$2 million	$(2 million)
Effect on postretirement benefit obligation	$35 million	$(30 million)

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

In accordance with FASB Staff Position No. FAS 106-1, any measures of the accumulated pension benefit obligation (APBO) or net periodic postretirement benefit cost in the company's financial statements or accompanying notes do not reflect the effects of the Act on its plans. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require a sponsor to change previously reported information. Moreover, the issues of how and when the federal subsidy should be accounted for are not yet resolved by the FASB. The company has not yet determined the potential effects of the Act on its future postretirement costs, including the participation rates in its benefit plans, nor whether any amendments to its benefit plans are appropriate given the provisions of the Act.

The company's weighted-average asset allocations at December 31, 2003 and 2002, by asset category are:

	Pension Benefits			Postretirement Benefits
Asset Category	Target Allocation	2003	2002	Target Allocation	2003	2002
Equity securities	60%	64%	59%	50%	53%	49%
Debt securities	30%	34%	41%	45%	45%	48%
Real estate	5%	-	-	-	-	-
Other	5%	2%	-	5%	2%	3%
Total	100%	100%	100%	100%	100%	100%

Notes to Consolidated Financial Statements

Energy East Corporation

The company's pension plan assets are held in a master trust with a trustee and are invested among and within various asset classes in order to achieve sufficient diversification in accordance with the company's risk tolerance. This is achieved through the utilization of multiple asset managers and systematic allocation to investment management styles, providing a broad exposure to different segments of the fixed income and equity markets.

The company's postretirement benefits plan assets are held with various trustees in multiple voluntary employee's beneficiary association (VEBA) and 401(h) arrangements and are invested among and within various asset classes in order to achieve sufficient diversification in accordance with the company's risk tolerance. This is achieved through the utilization of multiple institutional mutual and money market funds, which provide exposure to different segments of the fixed income, equity and short-term cash markets.

Equity securities included no Energy East common stock as of December 31, 2003 and 2002.

As of December 31, 2003 and 2002, the accumulated benefit obligation and the projected benefit obligation exceeded the fair value of pension plan assets for CMP's, CNG's and SCG's plans. As of December 31, 2002, the projected benefit obligation exceeded the fair value of pension plan assets for RG&E's plan. The following table shows the aggregate projected and accumulated benefit obligations and the fair value of plan assets for those four companies' plans.

	Projected Benefit Obligation Exceeds Fair Value of Plan Assets		Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets
December 31	2003	2002	2003	2002
(Thousands)
Projected benefit obligation	$478,899	$1,008,967	$478,899	$455,666
Accumulated benefit obligation	$430,754	$901,229	$430,754	$408,131
Fair value of plan assets	$365,431	$825,134	$365,431	$298,810

The company expects to contribute between $7 million and $12 million to its pension plans and $10 million to its other postretirement benefit plans in 2004.

Expected benefit payments, which reflect expected future service, as appropriate, are as follows:

	Pension Benefits	Postretirement Benefits
(Thousands)
2004	$132,127	$45,614
2005	$135,585	$48,932
2006	$141,743	$52,323
2007	$147,573	$55,605
2008	$157,399	$57,853
2009 - 2013	$987,632	$333,322

Notes to Consolidated Financial Statements

Energy East Corporation

Note 17. Segment Information

Selected financial information for the company's business segments is presented in the table below. The company's electric delivery segment consists of its regulated transmission, distribution and generation operations in New York and Maine and its natural gas delivery segment consists of its regulated transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts. Other includes: the company's corporate assets, interest income, interest expense and operating expenses; intersegment eliminations; and nonutility businesses.

	Electric Delivery	Natural Gas Delivery	Other	Total
(Thousands)
2003
Operating Revenues	$2,758,695	$1,462,127	$372,997	$4,593,819
Depreciation and Amortization	$211,120	$81,433	$8,711	$301,264
Operating Income	$446,894	$198,945	$4,275	$650,114
Interest Charges, Net	$201,684	$76,113	$7,005	$284,802
Income Taxes	$89,337	$50,096	$(11,746)	$127,687
Discontinued Operations	-	-	$3,059	$3,059
Net Income	$152,720	$70,837	$(13,111)	$210,446
Total Assets	$7,293,829	$3,536,280	$476,323	$11,306,432
Capital Spending	$192,409	$99,746	$10,357	$302,512
2002
Operating Revenues	$2,568,247	$1,032,539	$235,683	$3,836,469
Depreciation and Amortization	$162,515	$71,329	$8,267	$242,111
Operating Income	$449,029	$149,656	$(5,890)	$592,795
Interest Charges, Net	$183,716	$73,177	$(601)	$256,292
Income Taxes	$94,238	$26,557	$(21,957)	$98,838
Discontinued Operations	-	-	$(1,913)	$(1,913)
Net Income	$170,337	$51,128	$(32,862)	$188,603
Total Assets	$7,032,043	$3,428,956	$483,348	$10,944,347
Capital Spending	$137,414	$86,301	$5,672	$229,387
2001
Operating Revenues	$2,504,896	$1,026,124	$218,823	$3,749,843
Depreciation and Amortization	$118,882	$75,432	$8,996	$203,310
Operating Income	$553,421	$89,518	$(5,069)	$637,870
Interest Charges, Net	$154,011	$55,785	$6,592	$216,388
Income Taxes	$178,125	$18,144	$(41,390)	$154,879
Discontinued Operations	-	-	$(1,105)	$(1,105)
Net Income	$228,782	$17,938	$(59,113)	$187,607
Total Assets	$4,175,280	$2,467,647	$626,305	$7,269,232
Capital Spending	$95,627	$106,116	$21,132	$222,875

Notes to Consolidated Financial Statements

Energy East Corporation

Note 18. Quarterly Financial Information (Unaudited)

Quarter Ended	March 31		June 30		September 30	December 31
(Thousands, except per share amounts)
2003
Operating Revenues	$1,508,295		$986,082		$903,124	$1,196,318
Operating Income	$291,922		$124,951		$72,229	$161,012
Income from   Continuing Operations	$130,509		$28,852		$2,083	$45,943
Net Income (Loss)	$135,464		$27,717		$(5,979)	$53,244
Earnings (Loss) Per Share,   basic	$.93		$.19		$(.04)	$.37
Earnings (Loss) Per Share,   diluted	$.93		$.19		$(.04)	$.36
Dividends Per Share	$.25		$.25		$.25	$.25
Average Common   Shares Outstanding, basic	145,096		145,415		145,684	145,936
Average Common Shares   Outstanding, diluted	145,215		145,640		145,901	146,150
Common Stock Price (1)   High   Low	$23.71 $17.40		$21.95  $17.70		$22.48  $19.39	$23.71 $21.64
2002
Operating Revenues	$1,025,426		$713,114		$939,308	$1,158,621
Operating Income	$238,823		$81,971		$119,074	$152,927
Income from   Continuing Operations	$105,614		$5,679		$27,531	$51,692
Net Income	$105,570	(2)	$5,323	(2)	$23,742	$53,968	(3)
Earnings Per Share,   basic and diluted	$.90	(2)	$.05	(2)	$.16	$.37	(3)
Dividends Per Share	$.24		$.24		$.24	$.24
Average Common   Shares Outstanding,   basic and diluted	116,720		117,820		144,621	144,849
Common Stock Price (1)   High   Low	$21.92 $18.50		$23.13 $20.92		$22.53  $15.75	$22.70  $18.25

 ⁽¹⁾ The company's common stock is listed on the New York Stock Exchange. The number of shareholders of record was 37,674 at December 31, 2003.
 ⁽²⁾ Includes the effect of writedowns of the company's investment in NEON Communications, Inc. in 2002 that decreased net income and earnings per share as follows: $6 million and 5 cents in the first quarter and $1 million and 1 cent in the second quarter.
 ⁽³⁾ Includes the effect of restructuring expenses recorded in the fourth quarter of 2002 that decreased net income $24 million and earnings per share 17 cents.

Report of Independent Auditors

To the Shareholders and Board of Directors,
Energy East Corporation and Subsidiaries

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 170 present fairly, in all material respects, the financial position of Energy East Corporation and its subsidiaries ("the Company") at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing in Item 15(a)(2) on page 170 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 1 and 15 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative and hedging activities pursuant to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133). As discussed in Notes 1 and 5 to the consolidated financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, and effective July 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. In addition, as discussed in Note 1 to the consolidated financial statements, effective December 31, 2003, the Company changed its method of accounting for its capital trust subsidiary in accordance with Financial Accounting Standards Board Interpretation No. 46R, Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin (ARB) No. 51.

PricewaterhouseCoopers LLP

New York, New York
January 30, 2004

ENERGY EAST CORPORATION

SCHEDULE II - Consolidated Valuation and Qualifying Accounts

Years Ended December 31, 2003, 2002 and 2001

Classification	Beginning of Year	Additions	Write-offs (a)	Adjustments		End of Year
(Thousands)
2003
Allowance for Doubtful     Accounts - Accounts     Receivable	$58,640	$47,919	$(48,211)	$(5,500)		$52,848
2002
Allowance for Doubtful     Accounts - Accounts     Receivable	$17,783	$45,782	$(36,455)	$31,530	(b)	$58,640
2001
Allowance for Doubtful     Accounts - Accounts     Receivable	$18,781	$27,435	$(28,417)	$(16)		$17,783	(c)

(a)  Uncollectible accounts charged against the allowance, net of recoveries.
^(b)  Includes $30,750 due to the merger with RGS Energy.
^(c)  Includes $6,300 which represents an estimate for NYSEG of write-offs that would not be recovered in rates.

Selected Financial Data

Central Maine Power Company

					Predecessor
	2003	2002	2001	From   Acquisition   2000	To Acquisition 2000	1999
(Thousands)
Operating Revenues	$610,590	$653,521	$815,050	$277,518	$613,475	$954,463
Depreciation and amortization	$41,102	$38,793	$36,537	$13,830	$23,661	$49,517
Other taxes	$20,396	$24,172	$20,925	$6,621	$12,961	$22,291
Interest Charges, Net	$26,438	$28,584	$27,338	$8,506	$31,072	$53,175
Net Income	$49,832	$54,933	$54,440 (1)	$23,651 (1)	$29,878	$68,740
Capital Spending	$42,174	$37,985	$46,273	$23,031	$56,026	$65,097
Total Assets	$1,806,853	$1,860,182	$1,865,800 (2)	$1,928,797 (2)	-	$1,946,757 (2)
Long-term Obligations,   Capital Leases and   Redeemable Preferred Stock	$314,511	$291,796	$235,133	$222,309	-	$121,096

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

(1) Includes goodwill amortization of $9 million in 2001 and $3 million in 2000.
⁽²⁾ Does not reflect the reclassification of accrued removal costs from accumulated depreciation to a regulatory liability.

Management's discussion and analysis of financial condition and results of operations

Central Maine Power Company

Liquidity and Capital Resources

Restructuring

See Energy East's Item 7 - Restructuring, for this discussion.

Electric Delivery Business

CMP's electric delivery business consists of its regulated electricity transmission and distribution operations.

CMP Alternative Rate Plan: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

CMP Electricity Supply Responsibility: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

MPUC Stranded Cost Proceeding: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Management's discussion and analysis of financial condition and results of operations

Central Maine Power Company

Nonutility Generation: CMP expensed approximately $210 million for NUG power in 2003. It estimates that its NUG purchases will total $215 million in 2004, $219 million in 2005, $166 million in 2006, $153 million in 2007 and $129 million in 2008. CMP continues to seek ways to provide relief to its customers from above-market NUG contracts that state regulators ordered it to sign, and which, in 2003, averaged 9.5 cents per kilowatt-hour. Recovery of these NUG costs is provided for in CMP's current regulatory plans. (See Note 8 to CMP's Consolidated Financial Statements.)

Regional Transmission Organization: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

FERC Standard Market Design: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Transmission Planning and Expansion and Generation Interconnection: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Other Matters

Accounting Issues

FIN 46R: See Energy East's Item 7 - Other Matters, for this discussion. (See Note 1 to CMP's Consolidated Financial Statements.)

Management's discussion and analysis of financial condition and results of operations

Central Maine Power Company

Contractual Obligations and Commercial Commitments

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

	Total	2004	2005	2006	2007	2008	After 2008
(Thousands)
Contractual  Obligations
Long-term debt	$293,769	$1,183	$21,183	$41,183	$16,183	$6,183	$207,854
Capital lease  obligations	23,741	1,816	1,820	1,568	1,353	1,353	15,831
Operating leases	742	208	164	159	38	38	135
Nonutility generator  purchase  power obligations	1,366,214	214,854	219,234	165,720	153,178	129,284	483,944
Nuclear plant  obligations	196,545	31,053	35,473	30,511	29,149	26,554	43,805
Unconditional purchase  obligations	58,644	7,231	6,678	6,997	6,760	6,931	24,047
Pension and  other  postretirement  benefits(1)	239,430	20,528	20,600	21,458	22,177	22,909	131,758
Other long-term  obligations	35,100	7,200	7,700	5,700	4,400	3,200	6,900
Total Contractual  Obligations	$2,214,185	$284,073	$312,852	$273,296	$233,238	$196,452	$914,274
Other Commercial Commitments
Committed line of credit	$75,000	-	$75,000	-	-	-	-
Uncommitted line of credit	$5,000	$5,000	-	-	-	-	-
Total Commercial  Commitments	$80,000	$5,000	$75,000	-	-	-	-

(1) Amounts are through 2013 only.

CMP has a revolving credit facility, secured by its accounts receivable, in which it covenants to maintain certain debt and earnings ratios. (See Note 6 to CMP's Consolidated Financial Statements.)

Critical Accounting Estimates

See Energy East's Item 7 - Critical Accounting Estimates for the discussion of Goodwill and Other Intangible Assets, Pension and Other Postretirement Benefit Plans and Utility Regulation.

Management's discussion and analysis of financial condition and results of operations

Central Maine Power Company

Investing and Financing Activities

Investing Activities: Capital spending totaled $42 million in 2003, $38 million in 2002 and $46 million in 2001. Capital spending is projected to be $50 million in 2004 and is expected to be paid for with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements, governmental mandates and merger integration. (See Note 8 to CMP's Consolidated Financial Statements.)

CMP's pension plans generated pretax noncash pension expense (net of amounts capitalized) of $9 million in 2003, $2 million in 2002 and less than $1 million in 2001. The increase in 2003 was due to significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute CMP's pension liability (reduced from 7% to 6.5% as of December 31, 2002) and return on assets (reduced from 9% to 8.75% effective January 1, 2003). CMP contributed $15 million to the plan in 2003 and expects to contribute from $5 million to $10 million to its plans in 2004 as total plan assets are less than the projected benefit obligation. (See Note 13 to CMP's Consolidated Financial Statements.)

Financing Activities: CMP has a committed revolving credit facility, secured by its accounts receivable, that expires in December 2005. The facility provides for maximum borrowings of $75 million. CMP's uncommitted credit agreement, which expires in 2004, provides for additional borrowings of $5 million. CMP uses short-term borrowings and drawings on its committed credit facility to finance certain refundings and for other corporate purposes. There was $15 million of such short-term debt outstanding at December 31, 2003, and none outstanding at December 31, 2002. The weighted-average interest rate on short-term debt was 1.7% at December 31, 2003.

See Energy East's Item 7 - CMP Financing Activities, for more discussion.

Results of Operations

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Deliveries - Megawatt-hours   Retail   Wholesale	8,926 2,400	8,709 2,555	9,284 3,333	2% (6%)	(6%) (23%)
Operating Revenues	$610,590	$653,521	$815,050	(7%)	(20%)
Operating Expenses	$507,047	$549,974	$701,306	(8%)	(22%)
Operating Income	$103,543	$103,547	$113,744	-	(9%)
Earnings Available for   Common Stock	$48,390	$53,491	$52,998	(10%)	1%

Earnings

The $5 million decrease in earnings for 2003 was primarily due to lower operating income. The majority, but not all, of the lower revenues in 2003 was offset by lower expenses. The offsets are the result of various regulatory mechanisms that provide for a direct matching of standard-offer

Management's discussion and analysis of financial condition and results of operations

Central Maine Power Company

supply costs and revenues, provide for rate reductions under the Alternative Rate Plan to reflect ending amortizations for ice storm costs and demand side management (DSM) costs, allow deferral of incurred costs for DSM and transmission congestion costs, and reflect through lower stranded cost rates certain benefits including higher sales and lower purchased power costs. Net income also declined in 2003 as a result of the recognition in 2002 of certain tax benefits resulting from the 2001 tax return filing.

Earnings for 2002 increased less than $1 million primarily due to the elimination of goodwill amortization in 2002 of $9 million, offset by a restructuring charge of $3 million and the cessation of amortization for the voluntary earnings credit of $6 million.

Operating Revenues: Operating revenues decreased $43 million in 2003 primarily as a result of CMP no longer being the standard-offer provider for the supply of electricity for residential and small commercial class customers effective March 2002, which reduced revenues $18 million; lower revenues from NUG entitlement sales of $5 million; reduced other revenues of $5 million and lower accrued revenues of $14 million. The lower accrued revenue resulted primarily from a decrease in accrued DSM revenues of $5 million, and a decrease in accrued transmission congestion revenue of $4 million, both resulting from lower incurred costs. In addition, revenues from higher sales volume, which would have resulted in an additional $14 million were offset by a rate reduction for distribution rates pursuant to the Alternative Rate Plan of $12 million and lower stranded cost rates of $3 million.

The $161 million decrease in operating revenues for 2002 is primarily due to CMP no longer being the standard-offer provider for the supply of electricity effective March 2002, which reduced revenues $138 million.

Operating Expenses: Operating expenses for 2003 decreased $43 million primarily as a result of CMP no longer being the standard-offer provider for the supply of electricity effective March 2002, which reduced operating expenses $18 million; a decrease in NUG power purchases and other purchase costs of $7 million; and lower operating and maintenance costs of $15 million. The major reductions in O&M costs consisted of lower amortization of ice storm expenses of $6 million; reduced transmission congestion costs of $6 million; lower DSM costs including amortization of past expenses of $6 million, lower administrative costs of $3 million and a decrease in restructuring costs of $5 million. These reductions were offset by higher costs totaling $11 million which primarily consisted of increased tree trimming of $2 million, increased environmental costs of $2 million and increased distribution costs of $3 million.

The $151 million decrease in operating expenses for 2002 is primarily due to a decrease in electricity purchased of $162 million, including $138 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002. Operating expenses also decreased $9 million due to the elimination of goodwill amortization in 2002. Those decreases were partially offset by an increase of $5 million due to restructuring expenses, a $3 million increase in other taxes primarily due to an MPUC conservation assessment and the cessation of amortization for the voluntary earnings credit of $11 million.

Other Items: Other operating expenses include net periodic pension benefit cost of $9 million in 2003, $2 million in 2002 and less than $1 million in 2001. Other operating expenses would have been $7 million lower for 2003 without the change in net periodic pension benefit cost.

Central Maine Power Company
Consolidated Balance Sheets

December 31	2003	2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$11,627	$20,415
Accounts receivable, net	113,992	124,711
Materials and supplies, at average cost	6,571	7,096
Accumulated deferred income tax benefits, net	1,232	1,902
Prepayments and other current assets	7,135	6,411
Total Current Assets	140,557	160,535
Utility Plant, at Original Cost
Electric	1,337,931	1,316,023
Less accumulated depreciation	451,407	425,522
Net Utility Plant in Service	886,524	890,501
Construction work in progress	15,953	2,952
Total Utility Plant	902,477	893,453
Other Property	5,839	5,880
Investment in Associated Companies, at Equity	19,636	27,137
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	173,548	211,268
Unfunded future income taxes	104,276	101,791
Unamortized loss on debt reacquisitions	8,646	9,722
Demand-side management program costs	5,281	8,394
Environmental remediation costs	2,614	4,440
Nonutility generator termination agreement	5,944	7,195
Other	65,145	58,259
Total regulatory assets	365,454	401,069
Other assets
Goodwill, net	324,938	325,580
Prepaid pension benefits	29,623	23,124
Other	18,329	23,404
Total other assets	372,890	372,108
Total Regulatory and Other Assets	738,344	773,177
Total Assets	$1,806,853	$1,860,182

The notes on pages 89 through 104 are an integral part of the financial statements.

Central Maine Power Company
Consolidated Balance Sheets

December 31		2003	2002
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt		$2,999	$52,975
Notes payable		15,000	-
Accounts payable and accrued liabilities		45,815	45,551
Interest accrued		5,397	6,056
Taxes accrued		1,206	6,118
Other		48,322	48,575
Total Current Liabilities		118,739	159,275
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	80,128		73,859
Deferred income taxes		77,849	81,981
Gain on sale of generation assets		76,998	112,009
Other		17,127	11,926
Total regulatory liabilities		252,102	279,775
Other liabilities
Deferred income taxes		65,555	34,743
Nuclear plant obligations		173,548	211,268
Other postretirement benefits		73,181	71,236
Environmental remediation costs		3,017	2,987
Other		113,880	127,986
Total other liabilities		429,181	448,220
Total Regulatory and Other Liabilities		681,283	727,995
Long-term debt		314,511	291,796
Total Liabilities		1,114,533	1,179,066
Commitments		-	-
Preferred Stock  Preferred stock		35,571	35,571
Capital in excess of par value		(2,582)	(2,723)
Common Stock Equity  Common stock ($5 par value, 80,000 shares authorized,    31,211 shares outstanding at December 31, 2003 and 2002)		156,057	156,057
Capital in excess of par value		485,376	485,297
Retained earnings		35,072	31,682
Accumulated other comprehensive (loss)		(17,174)	(24,768)
Total Common Stock Equity		659,331	648,268
Total Liabilities and Stockholder's Equity		$1,806,853	$1,860,182

The notes on pages 89 through 104 are an integral part of the financial statements.

Central Maine Power Company
Consolidated Statements of Income

Year Ended December 31	2003	2002	2001
(Thousands)
Operating Revenues
Sales and services	$610,590	$653,521	$815,050
Operating Expenses
Electricity purchased	240,601	264,325	430,284
Other operating expenses	172,146	180,038	173,553
Maintenance	32,453	37,151	40,007
Depreciation and amortization	41,102	38,793	36,537
Other taxes	20,396	24,172	20,925
Restructuring expenses	349	5,495	-
Total Operating Expenses	507,047	549,974	701,306
Operating Income	103,543	103,547	113,744
Other (Income)	(3,919)	(5,041)	(6,745)
Other Deductions	1,428	2,035	3,450
Interest Charges, Net	26,438	28,584	27,338
Income Before Income Taxes	79,596	77,969	89,701
Income Taxes	29,764	23,036	35,261
Net Income	49,832	54,933	54,440
Preferred Stock Dividends	1,442	1,442	1,442
Earnings Available for Common Stock	$48,390	$53,491	$52,998

The notes on pages 89 through 104 are an integral part of the financial statements.

Central Maine Power Company
Consolidated Statements of Cash Flows

Year Ended December 31	2003	2002	2001
(Thousands)
Operating Activities
Net income	$49,832	$54,933	$54,440
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	60,458	65,836	62,045
Income taxes and investment tax credits deferred, net	19,631	8,613	23,346
Restructuring expenses	-	5,495	-
Pension expense	8,501	2,467	54
Changes in current operating assets and liabilities
Accounts receivable, net	10,719	1,154	15,721
Inventory	525	1,921	34
Prepayments and other current assets	(724)	4,028	(827)
Accounts payable and accrued liabilities	(2,254)	(18,553)	(10,319)
Interest accrued	(659)	874	97
Taxes accrued	(4,912)	6,118	-
Other current liabilities	(233)	11,303	(13,798)
Asset sale gain amortization	(35,011)	(39,979)	(41,262)
Prepaid pension benefits	(15,000)	-	(433)
Asset sale settlement costs	-	-	(12,000)
Deferred NUG costs	-	-	(17,871)
Other assets	(1,540)	(12,942)	5,228
Other liabilities	2,832	(11,307)	(4,298)
Net Cash Provided by Operating Activities	92,165	79,961	60,157
Investing Activities
Utility plant additions	(42,412)	(38,054)	(46,279)
Contributions in aid of construction, net	-	-	(19,130)
Other	238	69	6
Net Cash Used in Investing Activities	(42,174)	(37,985)	(65,403)
Financing Activities
Long-term note issuances	35,700	120,000	75,000
Long-term note repayments	(63,037)	(61,283)	(20,483)
Notes payable three months or less, net	15,000	(23,000)	(23,500)
Notes payable issuances	-	(28,500)	-
Notes payable repayments	-	5,000	23,500
Dividends on common and preferred stock	(46,442)	(54,555)	(46,427)
Net Cash (Used in) Provided by Financing Activities	(58,779)	(42,338)	8,090
Net (Decrease) Increase in Cash and Cash Equivalents	(8,788)	(362)	2,844
Cash and Cash Equivalents, Beginning of Year	20,415	20,777	17,933
Cash and Cash Equivalents, End of Year	$11,627	$20,415	$20,777

The notes on pages 89 through 104 are an integral part of the financial statements.

Central Maine Power Company
Consolidated Statements of Changes in Common Stock Equity

(Thousands)	Common Stock Outstanding $5 Par Value Shares         Amount		Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Total
Balance, January 1, 2001	31,211	162,213	500,897	23,291	-	(19,000)	667,401
Net income				54,440			54,440
Other comprehensive income, net of tax					$(2,148)		(2,148)
Comprehensive income							52,292
Dividends declared
Preferred stock				(1,442)			(1,442)
Common stock				(44,985)			(44,985)
Merger transaction, net			(2,756)				(2,756)
Balance, December 31, 2001	31,211	162,213	498,141	31,304	(2,148)	(19,000)	670,510
Net income				54,933			54,933
Other comprehensive income, net of tax					(22,620)		(22,620)
Comprehensive income							32,313
Dividends declared
Preferred stock				(1,442)			(1,442)
Common stock				(53,113)			(53,113)
Cancellation of treasury stock		(6,156)	(12,844)			19,000	-
Balance, December 31, 2002	31,211	156,057	485,297	31,682	(24,768)	-	648,268
Net income				49,832			49,832
Other comprehensive income, net of tax					7,594		7,594
Comprehensive income							57,426
Equity contribution from parent			79				79
Dividends declared
Preferred stock				(1,442)			(1,442)
Common stock				(45,000)			(45,000)
Balance, December 31, 2003	31,211	$156,057	$485,376	$35,072	$(17,174)	-	$659,331

The notes on pages 89 through 104 are an integral part of the financial statements.

Notes to Consolidated Financial Statements

Central Maine Power Company

Note 1. Significant Accounting Policies

Background: Central Maine Power Company (CMP) is primarily engaged in the transmission and distribution of electricity generated by others to retail customers in Maine. CMP is the principal operating utility of CMP Group, which is a wholly-owned subsidiary of Energy East Corporation.

Accounts receivable: Accounts receivable include unbilled revenues of $25 million at December 31, 2003, and $33 million at December 31, 2002, and are shown net of an allowance for doubtful accounts of $2 million at December 31, 2003 and 2002. Bad debt expense was $2 million in 2003 and $3 million in 2002 and 2001.

Consolidated statements of cash flows: CMP considers all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and those investments are included in cash and cash equivalents.

Supplemental Disclosure of Cash Flows Information	2003	2002	2001
(Thousands)
Cash paid during the year ended December 31:
Interest, net of amounts capitalized	$23,723	$24,213	$23,813
Income taxes, net of benefits received	$14,423	$1,739	$4,228

Depreciation and amortization: CMP determines depreciation expense using the straight-line method. The average service lives of certain classifications of property are: transmission property - 40 years, distribution property - 38 years and other property - 26 years. CMP's depreciation accruals were equivalent to 3.0% of average depreciable property for 2003 and 2.9% for 2002 and 2001.

Estimates: Preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Goodwill: The excess of the cost over fair value of net assets and as a result of push down accounting is recorded as goodwill. CMP evaluates the carrying value of goodwill for impairment at least annually and on an interim basis if there are indications that goodwill might be impaired. Any impairments would be recognized when the fair value of goodwill is less than its carrying value. Goodwill was amortized on a straight-line basis over 40 years until December 31, 2001. (See Note 3.)

Income taxes: Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.

Notes to Consolidated Financial Statements

Central Maine Power Company

CMP computes its income tax provision on a separate return method. SEC regulations require that no Energy East subsidiary pay more income taxes than it would pay if a separate income tax return were to be filed. The determination and allocation of CMP's income tax provision and its components are outlined and agreed to in the tax sharing agreement with Energy East.

Other (Income) and Other Deductions:

Year Ended December 31	2003	2002	2001
(Thousands)
Interest income	$(678)	$(1,057)	$(1,252)
Noncash return	(1,214)	(1,201)	(1,612)
Gains from the sale of nonutility property	(160)	(117)	(1,294)
Earnings from equity investments	(1,943)	(2,778)	(2,497)
Miscellaneous	76	112	(90)
Total other (income)	$(3,919)	$(5,041)	$(6,745)
Miscellaneous	$1,428	$2,035	$3,450
Total other deductions	$1,428	$2,035	$3,450

Principles of consolidation: CMP's financial statements consolidate its majority-owned subsidiaries after eliminating intercompany transactions.

Reclassifications: Certain amounts have been reclassified on the consolidated financial statements to conform to the 2003 presentation.

Regulatory assets and liabilities: Pursuant to Statement 71, CMP capitalizes, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.

Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Unamortized loss on debt reacquisitions is amortized over the lives of the related debt issues. Nuclear plant obligations, demand-side management program costs, gain on sale of generation assets, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with CMP's current rate plans. CMP earns a return on substantially all regulatory assets for which funds have been spent.

Revenue recognition: CMP recognizes revenues upon delivery of energy and energy-related products and services to its customers.

Pursuant to Maine State Law, since March 1, 2000, CMP has been prohibited from selling power to its retail customers. CMP does not enter into any purchase and sales arrangements for power with the ISO New England, the New England Power Pool, or any other independent system operator or similar entity. All of CMP's power entitlements under its NUG and other purchase power contracts are sold to unrelated third parties under bilateral contracts for the period March 1, 2002, through February 28, 2005.

Notes to Consolidated Financial Statements

Central Maine Power Company

Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability. CMP's adoption of Statement 143 as of January 1, 2003, did not have a material effect on its financial position or results of operations. There was no effect on net income.

Statement 143 provides that if the requirements of Statement 71 are met, a regulatory liability should be recognized for the difference between removal costs collected in rates and actual costs incurred. In previous years, those amounts were included in accumulated depreciation in accordance with industry practice. Accrued removal obligations totaling approximately $80 million as of December 31, 2003, and $74 million as of December 31, 2002, that had previously been embedded within accumulated depreciation, were reclassified as a regulatory liability.

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. FIN 46R requires a business enterprise to consolidate a variable interest entity if that enterprise has a variable interest that will absorb a majority of the entity's expected losses.

CMP has independent, ongoing, long-term power purchase contracts with NUGs. (See Note 8.) In accordance with FIN 46R, CMP is evaluating if it has a variable interest in any NUG and, to the extent that CMP has a variable interest, whether it is a primary beneficiary. To the extent that CMP is a primary beneficiary of a NUG, consolidation would be required at March 31, 2004, unless CMP is unable to obtain sufficient information to do so. CMP was not involved in the formation of any NUGs, does not have ownership interests in any NUGs and may not be able to obtain sufficient information from the NUGs to determine if it is a primary beneficiary. CMP is presently unable to determine the effect on its financial statements, if any, of applying FIN 46R to its power purchase contracts with NUGs.

Utility plant: CMP charges repairs and minor replacements to operating expense accounts, and capitalizes renewals and betterments, including certain indirect costs. The original cost of utility plant retired or otherwise disposed of is charged to accumulated depreciation.

Note 2. Restructuring

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, including $5 million for CMP. The employee positions affected by the

Notes to Consolidated Financial Statements

Central Maine Power Company

restructuring were identified in the fourth quarter of 2002. The restructuring expenses reduced CMP's 2002 net income by $3 million, including $2 million for a voluntary early retirement program that will be paid from CMP's pension plan and $1 million for an involuntary severance program, primarily for salaried employees. During 2003 CMP's entire related involuntary severance liability of $1 million was paid.

The voluntary early retirement and involuntary severance programs resulted in a reduction in overall employee headcount of 79 in 2003.

Energy East has consolidated the accounting and finance functions of five of its operating companies to one location. In connection with this latest restructuring, in the fourth quarter of 2003 CMP began to recognize an expected $1 million total liability for an enhanced severance program for certain accounting and finance employees who will be employed through March 31, 2004.

Note 3. Goodwill and Other Intangible Assets

CMP no longer amortizes goodwill effective January 1, 2002, and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized (amortized intangible assets) and are reviewed for impairment. Annual impairment testing was completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for CMP at September 30, 2003.

The carrying amount of goodwill, which is included in CMP's electric delivery operating segment, was $325 million and $326 million as of December 31, 2003 and 2002, respectively. The change resulted from miscellaneous tax adjustments.

Other Intangible Assets: CMP's unamortized intangible assets had a carrying amount of $2 million at December 31, 2003 and 2002, and consisted of pension assets. CMP's amortized intangible assets had a gross carrying amount and accumulated amortization of less than $0.3 million at December 31, 2003 and 2002, and primarily consisted of technology rights. Estimated amortization expense for intangible assets is $9 thousand for each of the next five years, 2004 through 2008.

Transitional Information: Results of operations information for CMP as though goodwill had not been amortized for all years presented is:

Year Ended December 31	2003	2002	2001
(Thousands)
Reported net income	$49,832	$54,933	$54,440
Add back: Goodwill amortization	-	-	8,575
Adjusted net income	$49,832	$54,933	$63,015

Notes to Consolidated Financial Statements

Central Maine Power Company

Note 4. Income Taxes

Year Ended December 31	2003	2002	2001
(Thousands)
Current	$10,160	$14,450	$8,749
Deferred, net     Accelerated depreciation	3,290	1,951	(207)
Pension benefits	3,741	180	1,475
Asset sale gain	-	-	-
Miscellaneous	13,288	7,170	25,959
ITC	(715)	(715)	(715)
Total	$29,764	$23,036	$35,261

CMP's effective tax rate differed from the statutory rate of 35% due to the following:

Year Ended December 31	2003	2002	2001
(Thousands)
Tax expense at statutory rate	$27,859	$27,289	$31,396
Depreciation and amortization not normalized	1,469	(446)	287
ITC amortization	(715)	(715)	(715)
State taxes, net of federal benefit	3,635	3,169	5,286
Other, net	(2,484)	(6,261)	(993)
Total	$29,764	$23,036	$35,261

CMP's deferred tax assets and liabilities consisted of the following:

December 31	2003	2002
(Thousands)
Current Deferred Tax Assets	$1,232	$1,902
Noncurrent Deferred Tax Liabilities
Depreciation	$176,447	$170,512
Unfunded future income taxes	42,549	41,535
Accumulated deferred ITC	7,669	8,384
Deferred gain on generation plant sale	(31,194)	(44,745)
Other	(52,067)	(58,962)
Total Noncurrent Deferred Tax Liabilities	143,404	116,724
Less amounts classified as regulatory liabilities
Deferred income taxes	77,849	81,981
Noncurrent Deferred Income Taxes	$65,555	$34,743

CMP has no federal or state tax credit or loss carryforwards, and no valuation allowances.

Notes to Consolidated Financial Statements

Central Maine Power Company

Note 5. Long-term Debt

At December 31, 2003 and 2002, CMP's consolidated long-term debt was:

			Amount
	Maturity Dates	Interest Rates	2003	2002
(Thousands)
Pollution control notes	2014	5 3/8%	$19,500	$19,500
Various medium-term notes	2005 to 2025	1.77% to 8.13%	255,700	270,000
Various long-term debt	2020	7.05% to 10.48%	19,922	31,034
Obligations under capital leases			23,741	25,666
Unamortized discount on debt			(1,353)	(1,429)
			317,510	344,771
Less debt due within one year, included in current liabilities			2,999	52,975
Total			$314,511	$291,796

CMP has no long-term debt obligations that are secured. CMP has no intercompany collateralizations and has no guarantees to affiliates or subsidiaries. CMP's debt has no guarantees from parent or affiliates or any additional credit supports.

At December 31, 2003, long-term debt, including sinking fund obligations, and capital lease payments (in thousands) that will become due during the next five years are:

2004	2005	2006	2007	2008
$2,999	$23,003	$42,751	$17,536	$7,536

Note 6. Bank Loans and Other Borrowings

CMP has a committed revolving credit facility with certain banks that provides for borrowing up to $75 million through December 2005, which is secured by CMP's accounts receivable. The interest rate on borrowings is related to the London Interbank Offered Rate on base-rate-priced loans. At December 31, 2003 and 2002, the arrangement provided for payment of fees including a facility fee of 0.15% per annum and a utilization fee of 0.125% per annum for each day the outstanding balance exceeded 50% of the total facility. CMP's uncommitted credit agreement, which expires in 2004, provides for additional borrowings of $5 million.

CMP uses short-term borrowings and drawings on its committed credit facility to finance certain refundings and for other corporate purposes. There was $15 million of such short-term debt outstanding at December 31, 2003, and none outstanding at December 31, 2002. The weighted-average interest rate on short-term debt was 1.7% at December 31, 2003.

In its committed revolving credit facility, CMP covenants that (i) its consolidated total debt shall at all times be no more than 65% of the sum of its consolidated total debt and its total stockholders equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00. Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2003, CMP's consolidated total debt ratio was 31% and its interest coverage ratio was 4.0 to 1.00.

Notes to Consolidated Financial Statements

Central Maine Power Company

Note 7. Preferred Stock

At December 31, 2003 and 2002, CMP's cumulative preferred stock was:

Series	Par Value Per Share	Redemption Price Per Share	Shares Authorized and Outstanding(1)	Amount (Thousands) 2003            2002
6% Noncallable (2)	$100	-	5,713	$571	$571
3.50%	100	$101.00	220,000	22,000	22,000
4.60%	100	101.00	30,000	3,000	3,000
4.75%	100	101.00	50,000	5,000	5,000
5.25%	100	102.00	50,000	5,000	5,000
Total				$35,571	$35,571

(1) At December 31, 2003, CMP had 2,000,000 shares of $25 par value preferred stock and 1,950,000 shares of $100 par value callable preferred stock authorized but unissued.

(2) CMP's 5,713 shares outstanding include 533 shares owned by CMP Group, which are eliminated in consolidation for Energy East.

CMP had no redemptions or purchases of preferred stock during the three years 2001 through 2003.

Voting rights: If preferred stock dividends on any series of preferred stock, other than the 6% Noncallable series, are in default in an amount equivalent to four full quarterly dividends, the holders of the preferred stock are entitled to elect a majority of the directors and their privilege continues until all dividends in default have been paid. The holders of preferred stock, other than the 6% Noncallable series, are not entitled to vote in respect of any other matters except those, if any, in respect of which voting rights cannot be denied or waived under some mandatory provision of law, and except that the charter contains provisions to the effect that such holders shall be entitled to vote on certain matters affecting the rights and preferences of the preferred stock.

Holders of the 6% Noncallable series are entitled to one vote per share and have full voting rights on all matters.

Whenever holders of preferred stock shall be entitled to vote, they shall be entitled to cast one vote for each share of preferred stock held by them. Holders of CMP common stock are entitled to one-tenth of one vote per share on all matters.

Note 8. Commitments

Capital spending: CMP has commitments in connection with its capital spending program. Capital spending is projected to be $50 million in 2004 and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. CMP's capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

Notes to Consolidated Financial Statements

Central Maine Power Company

Nonutility generator power purchase contracts: CMP expensed approximately $210 million for NUG power in 2003, $211 million in 2002 and $225 million in 2001. CMP estimates that NUG power purchases will total $215 million in 2004, $219 million in 2005, $166 million in 2006, $153 million in 2007 and $129 million in 2008.

Note 9. Jointly-Owned Generation Assets and Nuclear Generation Insurance and Decommissioning

CMP has ownership interests in three nuclear generating facilities in New England, which are accounted for under the equity method. All three facilities have been permanently shut down, and are in the process of being decommissioned.

($ in Millions)	Maine Yankee	Yankee Atomic	Connecticut Yankee
Ownership Share	38%	9.5%	6%
Operating Status	Permanently shut down August 6, 1997	Permanently shut down February 26, 1992	Permanently shut down December 4, 1996
Location	Wiscasset, Maine	Rowe, Massachusetts	Haddam, Connecticut
2003 Decommissioning and Other Costs	$20.2	$2.4	$3.5
Share of Remaining Decommissioning Costs (in 2003 dollars)	$83	$21	$30
Equity Interest at December 31, 2003	$16.5	-	$2.8

Maine Yankee: In August 1997 the Board of Directors of Maine Yankee Atomic Power Company voted to permanently shut down and decommission the Maine Yankee plant. FERC approved a settlement agreement in 1998 regarding recovery of decommissioning costs and plant investment, and all issues with respect to the prudence of the decision to discontinue operation of the Maine Yankee plant. Consistent with the 1998 settlement, in October 2003 Maine Yankee filed with FERC a rate case to collect the remaining decommissioning and fuel storage costs between 2004 and 2010. Physical decommissioning began in 1998 and is expected to be completed in 2005. The estimated remaining decommissioning and fuel storage costs as of December 31, 2003, are approximately $219 million in 2003 dollars.

Yankee Atomic: In 1993 the FERC approved a settlement agreement regarding recovery of decommissioning costs and plant investment, and all issues with respect to the prudence of the decision to discontinue operation of the Yankee Atomic plant. In 2003 FERC approved a settlement agreement regarding the recovery of the remaining decommissioning and fuel storage costs. This included an approximately $200 million increase over the 1993 FERC settlement related to escalations in the projected costs of spent fuel storage, security and

Notes to Consolidated Financial Statements

Central Maine Power Company

liability and property insurance. Physical decommissioning began in 1993 and is expected to be completed in 2005. The estimated remaining decommissioning and long-term spent fuel storage costs as of December 31, 2003, are approximately $218 million in 2003 dollars.

Connecticut Yankee: In December 1996 the Board of Directors of Connecticut Yankee Atomic Power Company voted to permanently shut down and decommission the Connecticut Yankee plant for economic reasons. In 2000 FERC approved a settlement agreement regarding recovery of decommissioning costs and plant investment, and all issues with respect to the prudence of the decision to discontinue operation of the Yankee Atomic plant. Physical decommissioning began in 1997 and is expected to be completed in 2006.

Estimated decommissioning and fuel storage costs for the period 2000 through 2023 have increased approximately $390 million in 2003 dollars over the April 2000 estimate of $434 million in 2003 dollars approved by the FERC in a rate case settlement. The revised estimate reflects the fact that Connecticut Yankee is now self-performing all work to complete the decommissioning of the plant and the termination of the turnkey decommissioning contractor in July 2003. In addition, the revised estimate contains increases in the projected costs of spent fuel storage, security and liability and property insurance. The estimated remaining decommissioning and fuel storage costs as of December 31, 2003, are approximately $504 million in 2003 dollars. Connecticut Yankee is seeking recovery of additional decommissioning costs and other damages from its former decommissioning contractor and, if necessary, its surety. Connecticut Yankee and the other Yankee Companies are also seeking recovery of additional decommissioning costs and other damages from the Department of Energy for failure to remove and dispose of spent nuclear fuel pursuant to contracts mandated by the U.S. Congress.

Connecticut Yankee is currently exploring options to structure an appropriate rate application to be filed with FERC for the recovery of the increased costs, and any amounts approved will be subsequently charged to its sponsors, including CMP. The timing, amount and outcome of this filing cannot be predicted at this time.

Operating expenses: CMP is obligated to pay its proportionate share of the expenses, including decommissioning, depreciation, operation and maintenance expenses, and a return on invested capital, for each of the Yankee companies referred to above. Maine's Electric Industry Restructuring Act requires the MPUC to provide a reasonable opportunity to recover stranded costs through electric distribution rates. Nuclear related costs are stranded costs and are included in CMP's stranded costs for purposes of rate recovery. Any increase in decommissioning costs not included currently in rates is deferred for future recovery.

Vermont Yankee: In July 2002, Vermont Yankee Nuclear Power Corporation sold the Vermont Yankee nuclear power plant, including CMP's 4% ownership interest, to Entergy Corporation. The book gain on the sale, of approximately $1 million, will be used to reduce CMP customers' future obligations for stranded costs. The transaction included a power purchase agreement that calls for Entergy to provide power from the plant to the sellers through 2012, the year the initial operating license for the plant expires.

Notes to Consolidated Financial Statements

Central Maine Power Company

Nuclear insurance: CMP is exempt from the provisions of the Price-Anderson Act because it no longer has an interest in a nuclear generating plant that is operating. As required by the NRC, CMP carries nuclear property damage insurance, which is obtained through Nuclear Electric Insurance Limited, for its interests in non-operating nuclear generating plants.

Note 10. Environmental Liability

From time to time environmental laws, regulations and compliance programs may require changes in CMP's operations and facilities and may increase the cost of electric service.

The U.S. Environmental Protection Agency and various state environmental agencies, as appropriate, notified CMP that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at five waste sites. The five sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the five sites, four sites are included in Maine's Uncontrolled Sites Program, one is included on the Massachusetts Non-Priority Confirmed Disposal Site list and two of the sites are also included on the National Priorities list.

Any liability may be joint and several for certain of those sites. CMP has recorded an estimated liability of $1 million related to the five sites. An estimated liability of $1 million has been recorded related to three additional sites where CMP believes it is probable that it will incur remediation and/or monitoring costs, although it has not been notified that it is among the potentially responsible parties. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to CMP.

CMP has a program to investigate and perform necessary remediation at its five sites where gas was manufactured in the past. With respect to the five sites, four sites are part of Maine's Voluntary Response Action Program and three of those four sites are part of Maine's Uncontrolled Sites Program. In November 2003 an additional site was identified where CMP believes it is probable that it will incur remediation and/or monitoring costs, although it has not been notified that it is among the potentially responsible parties.

CMP's estimate for all costs related to investigation and remediation of the five sites ranges from $2 million to $5 million at December 31, 2003. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations.

The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites, reflected on CMP's consolidated balance sheets was $2 million at December 31, 2003, and 2002.

CMP's environmental liability accruals, the majority of which are expected to be paid within the next three years, have been established on an undiscounted basis. CMP received insurance settlements during the last three years, which it accounted for as reductions in its related regulatory asset.

Notes to Consolidated Financial Statements

Central Maine Power Company

Note 11. Fair Value of Financial Instruments

The carrying amounts and estimated fair values of CMP's financial instruments included on its consolidated balance sheets are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.

December 31	2003		2002
	Carrying Amount	Estimated Fair Value	Carrying Amount	Estimated Fair Value
(Thousands)
Pollution control notes - fixed	$19,500	$21,060	$19,500	$20,085
Various medium-term notes	$254,347	$272,472	$268,571	$286,935
Various long-term debt	$19,922	$28,119	$31,034	$39,122

The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values.

Note 12. Accumulated Other Comprehensive Income

(Thousands)	Minimum Pension Liability Adjustment	Accumulated Other Comprehensive Income (Loss)
Balance, January 1, 2001	-	-
Before-tax amount	$(3,629)	$(3,629)
Tax benefit	1,481	1,481
Balance, December 31, 2001	(2,148)	(2,148)
Before-tax amount	(38,213)	(38,213)
Tax benefit	15,593	15,593
Balance, December 31, 2002	(24,768)	(24,768)
Before-tax amount	12,829	12,829
Tax benefit	(5,235)	(5,235)
Balance, December 31, 2003	$(17,174)	$(17,174)

Notes to Consolidated Financial Statements

Central Maine Power Company

Note 13. Retirement Benefits

	Pension Benefits		Postretirement Benefits
	2003	2002	2003	2002
(Thousands)
Change in projected benefit obligation
Benefit obligation at January 1	$208,826	$182,495	$123,637	$101,841
Service cost	4,411	3,931	1,813	1,783
Interest cost	13,574	12,763	7,914	7,744
Plan amendments	549	-	(785)	(1,410)
Actuarial loss	9,052	16,176	7,431	19,157
Curtailments	(655)	-	-	-
Special termination benefits	-	3,679	-	-
Benefits paid	(12,475)	(10,218)	(7,457)	(5,478)
Projected benefit obligation at December 31	$223,282	$208,826	$132,553	$123,637
Change in plan assets
Fair value of plan assets at January 1	$122,470	$151,273	$13,421	$15,084
Actual return on plan assets	31,327	(18,585)	2,627	(1,663)
Employer contributions	15,000	-	7,457	5,478
Benefits paid	(12,475)	(10,218)	(7,457)	(5,478)
Fair value of plan assets at December 31	$156,322	$122,470	$16,048	$13,421
Funded status	$(66,960)	$(86,356)	$(116,505)	$(110,216)
Unrecognized net actuarial loss	94,328	107,153	49,623	45,749
Unrecognized prior service cost (benefit)	2,255	2,327	(6,299)	(6,769)
Prepaid (accrued) benefit cost	$29,623	$23,124	$(73,181)	$(71,236)
Amounts recognized on the balance sheet:
Prepaid benefit cost	$29,623	$23,124		-
Accrued benefit liability	-	-	$(73,181)	$(71,236)
Additional minimum liability	(74,680)	(87,581)	-	-
Intangible asset	2,255	2,327	-	-
Regulatory liability	43,412	43,412	-	-
Accumulated other comprehensive income	29,013	41,842	-	-
Net amount recognized	$29,623	$23,124	$(73,181)	$(71,236)

CMP uses a December 31 measurement date for its pension and postretirement benefit plans.

CMP's accumulated benefit obligation for all defined benefit pension plans was $201 million at December 31, 2003, and $187 million at December 31, 2002.

The minimum liability included in CMP's other comprehensive income for pension benefits decreased $13 million in 2003 and increased $38million in 2002. CMP recorded a minimum pension liability of $75 million at December 31, 2003, as required by Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions. The effect of the minimum pension liability is recognized in other long-term liabilities, intangible assets, regulatory liability and other comprehensive income, as appropriate, and is prescribed when the accumulated benefit obligation in the plan exceeds the fair value of the underlying pension plan assets and accrued pension liabilities. The decrease in the unfunded accumulated benefit obligation in 2003 was primarily due to a higher than estimated actual return on plan assets and employer contributions.

Notes to Consolidated Financial Statements

Central Maine Power Company

Weighted-average assumptions used to determine benefit obligations at	Pension Benefits		Postretirement Benefits
December 31	2003	2002	2003	2002
Discount rate	6.25%	6.50%	6.25%	6.50%
Rate of compensation increase	4.00%	4.00%	4.00%	4.00%

As of December 31, 2003, CMP decreased its discount rate from 6.50% to 6.25%.

	Pension Benefits			Postretirement Benefits
	2003	2002	2001	2003	2002	2001
(Thousands)
Components of net periodic   benefit cost
Service cost	$4,411	$3,931	$3,368	$1,813	$1,783	$1,475
Interest cost	13,574	12,763	12,199	7,914	7,744	5,911
Expected return on plan assets	(14,106)	(15,192)	(15,675)	(1,164)	(996)	(1,105)
Amortization of prior service cost	218	190	29	(641)	(517)	(517)
Recognized net actuarial   (gain) loss	4,000	1,392	164	2,094	1,541	-
Special termination benefits		3,679	2,551	-	-	-
Curtailment	404	-	-	(614)	-	-
Adjustment to plan	-	-	(18)	-	357	-
Net periodic benefit cost	$8,501	$6,763	$2,618	$9,402	$9,912	$5,764

Net periodic benefit cost is included in other operating expenses on the consolidated statements of income. The net periodic benefit cost for postretirement benefits represents the cost charged to expense for providing health care benefits to retirees and their eligible dependents. The amount of postretirement benefit cost deferred was $35 million as of December 31, 2003, and $38 million as of December 31, 2002. CMP expects to recover any deferred postretirement costs related to the transition obligation by 2012. The transition obligation for postretirement benefits is being amortized over a period of 20 years.

Weighted-average assumptions used    to determine net periodic benefit cost	Pension Benefits			Postretirement Benefits
Year ended December 31	2003	2002	2001	2003	2002	2001
Discount rate	6.50%	7.00%	7.25%	6.50%	7.00%	7.25%
Expected return on plan assets	8.75%	9.00%	9.00%	8.75%	9.00%	9.00%
Rate of compensation increase	4.00%	4.00%	4.00%	4.00%	4.00%	4.00%

CMP's expected rate of return on plan assets assumption was developed based on a review of historical returns for the major asset classes. This analysis also considered both current capital market conditions and projected future conditions. Given the current low interest rate environment, CMP selected an assumption of 8.75% per year, which is lower than the rate otherwise determined solely based on historical returns.

Notes to Consolidated Financial Statements

Central Maine Power Company

CMP assumed a 10.0% annual rate of increase in the per capita cost of covered health care benefits for 2004 that gradually decreases to 5.0% by the year 2007. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase	1% Decrease
Effect on total of service and interest cost components	$1 million	$(1 million)
Effect on postretirement benefit obligation	$13 million	$(11 million)

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

In accordance with FASB Staff Position No. FAS 106-1, any measures of the APBO or net periodic postretirement benefit cost in CMP's financial statements or accompanying notes do not reflect the effects of the Act on the plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the sponsor to change previously reported information. Moreover, the issues of how and when the federal subsidy should be accounted for are not yet resolved by the FASB. CMP has not yet determined the potential effects of the Act on its future postretirement costs, including the participation rates in its benefit plans, nor whether any amendments to its benefit plans are appropriate given the provisions of the Act.

CMP's weighted-average asset allocations at December 31, 2003 and 2002, by asset category are:

	Pension Benefits			Postretirement Benefits
Asset Category	Target Allocation	2003	2002	Target Allocation	2003	2002
Equity securities	60%	64%	59%	50%	53%	49%
Debt securities	30%	34%	41%	45%	45%	48%
Real estate	5%	-	-	-	-	-
Other	5%	2%	-	5%	2%	3%
Total	100%	100%	100%	100%	100%	100%

CMP's pension plan assets are held in a master trust with a trustee and are invested among and within various asset classes in order to achieve sufficient diversification in accordance with CMP's risk tolerance. This is achieved through the utilization of multiple asset managers and systematic allocation to investment management styles, providing a broad exposure to different segments of the fixed income and equity markets.

CMP's postretirement benefits are held by trustee in multiple VEBA and 401(h) arrangements and are invested among and within various asset classes in order to achieve sufficient diversification in accordance with CMP's risk tolerance. This is achieved through the utilization of multiple institutional mutual funds, which provide exposure to different segments of the fixed income and equity markets.

Notes to Consolidated Financial Statements

Central Maine Power Company

Equity securities included no Energy East common stock as of December 31, 2003 and 2002.

As of December 31, 2003 and 2002, the accumulated benefit obligation and the projected benefit obligation exceeded the fair value of pension plan assets for CMP. The following table shows the projected and accumulated benefit obligations and the fair value of plan assets for CMP as of the dates indicated.

	Accumulated and Projected Benefit Obligations Exceed Fair Value of Plan Assets
December 31	2003	2002
(Thousands)
Projected benefit obligation	$223,282	$208,826
Accumulated benefit obligation	$201,378	$186,927
Fair value of plan assets	$156,322	$122,470

CMP expects to contribute from $5 million to $10 million to its pension plans and $8 million to its other postretirement benefit plans in 2004.

Expected benefit payments, which reflect expected future service, as appropriate, are as follows:

	Pension Benefits	Postretirement Benefits
(Thousands)
2004	$12,488	$8,040
2005	$12,653	$7,947
2006	$13,091	$8,367
2007	$13,393	$8,784
2008	$13,917	$8,992
2009 - 2013	$80,384	$51,374

Notes to Consolidated Financial Statements

Central Maine Power Company

Note 14. Segment Information

Selected financial information for CMP's business segments is presented in the table below. CMP's electric delivery business, which it conducts in the State of Maine, consists of its transmission and distribution operations. All Operating Revenues; Depreciation and Amortization; Operating Income; Interest Charges, Net; Income Taxes and Earnings Available for Common Stock relate to CMP's electric delivery business. Other consists of CMP's corporate assets.

	Electric Delivery	Other	Total
(Thousands)
2003
Total Assets	$1,798,234	$8,619	$1,806,853
Capital Spending	$42,174	-	$42,174
2002
Total Assets	$1,851,586	$8,596	$1,860,182
Capital Spending	$37,985	-	$37,985
2001
Total Assets	$1,857,157	$8,643	$1,865,800
Capital Spending	$46,182	$91	$46,273

Note 15. Quarterly Financial Information (Unaudited)

Quarter Ended	March 31	June 30	September 30	December 31
(Thousands)
2003
Operating Revenues	$176,418	$135,259	$145,715	$153,198
Operating Income	$44,746	$11,036	$20,973	$26,788
Net Income	$24,103	$2,821	$9,569	$13,339
Earnings Available for   Common Stock	$23,742	$2,460	$9,208	$12,980
2002
Operating Revenues	$200,614	$139,208	$153,663	$160,036
Operating Income	$44,945	$10,048	$23,100	$25,454
Net Income	$23,283	$5,293	$11,372	$14,985
Earnings Available for   Common Stock	$22,922	$4,932	$11,011	$14,626

Report of Independent Auditors

To the Shareholder and Board of Directors,
Central Maine Power Company and Subsidiaries

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 170 present fairly, in all material respects, the financial position of Central Maine Power Company and its subsidiaries ("the Company") at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing in Item 15(a)(2) on page 170 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 1 and 3 to the consolidated financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. In addition, as discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

PricewaterhouseCoopers LLP

New York, New York
January 30, 2004

CENTRAL MAINE POWER COMPANY

SCHEDULE II - Consolidated Valuation and Qualifying Accounts

Years Ended December 31, 2003, 2002 and 2001

Classification	Beginning of Year	Additions	Write-offs (a)	Adjustments	End of Year
(Thousands)
2003   Allowance for Doubtful Accounts     - Accounts Receivable	$1,853	$2,143	$(2,248)	-	$1,748
2002   Allowance for Doubtful Accounts     - Accounts Receivable	$2,854	$2,584	$(3,585)	-	$1,853
2001   Allowance for Doubtful Accounts     - Accounts Receivable	$2,874	$3,383	$(3,629)	$226	$2,854

(a)  Uncollectible accounts charged against the allowance, net of recoveries.

Selected Financial Data

New York State Electric & Gas Corporation

	2003	2002		2001		2000		1999
(Thousands)
Operating Revenues	$1,876,169	$1,878,579		$2,037,874		$2,123,024		$2,094,040
Depreciation and amortization	$100,726	$98,342		$101,083		$109,484		$616,244	(4)
Other taxes	$117,991	$118,703		$128,186		$126,846		$166,215
Interest Charges, Net	$79,394	$93,321		$103,624		$103,279		$128,063
Net Income	$142,925	$132,718	(1)	$194,807		$219,595	(3)	$206,134	(5)
Capital Spending	$96,480	$89,641		$74,290		$78,869		$69,249
Total Assets	$3,587,565	$3,427,342		$3,014,423	(2)	$2,952,985	(2)	$2,948,150	(2)
Long-term Obligations,   Capital Leases and   Redeemable Preferred Stock	$1,065,590	$1,017,902		$1,039,135		$1,189,249		$1,210,474

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

(1) Includes NYSEG's loss from the early retirement of debt that decreased net income $10 million and restructuring expenses that decreased net income $15 million.
⁽²⁾ Does not reflect the reclassification of accrued removal costs from accumulated depreciation to a regulatory liability.
⁽³⁾ Includes the effect of the benefit from the sale of an affiliate's coal-fired generation assets that increased net income $8 million.
⁽⁴⁾ Depreciation and amortization includes accelerated amortization of NMP2 related to the sale of an affiliate's coal-fired generation assets, authorized by the NYPSC.
⁽⁵⁾ Includes the effect of the loss from the early retirement of debt that decreased net income $18 million and the writeoff of NMP2 net of the benefit from the sale of an affiliate's coal-fired generation assets that decreased net income $5 million.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Liquidity and Capital Resources

Restructuring

See Energy East's Item 7 - Restructuring, for this discussion.

Electric Delivery Business

NYSEG's principal electric business is transmitting and distributing electricity. It also generates electricity primarily from its several hydroelectric stations.

NYSEG Electric Rate Plan: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Nonutility Generation: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

NYSEG expensed approximately $398 million for NUG power in 2003. It estimates that its purchases will total $427 million in 2004, $464 million in 2005, $444 million in 2006, $421 million in 2007 and $237 million in 2008. NYSEG continues to seek ways to provide relief to its customers from above-market NUG contracts that state regulators ordered it to sign, and which, in 2003, averaged 8.7 cents per kilowatt-hour. Recovery of these NUG costs is provided for in NYSEG's current regulatory plan. (See Note 8 to NYSEG's Financial Statements.)

NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

FERC Standard Market Design: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Transmission Planning and Expansion and Generation Interconnection: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Manufactured Gas Plant Remediation Recovery: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Natural Gas Delivery Business

NYSEG's natural gas delivery business consists of transporting, storing and distributing natural gas.

Natural Gas Supply Agreements: See Energy East's Item 7 - Natural Gas Delivery Business, for this discussion.

NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

NYSEG Natural Gas Rate Plan: See Energy East's Item 7 - Natural Gas Delivery Business, for this discussion.

Other Matters

Accounting Issues

FIN 46R: See Energy East's Item 7 - Other Matters, for this discussion. (See Note 1 to NYSEG's Financial Statements.)

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Contractual Obligations and Commercial Commitments

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

	Total	2004	2005	2006	2007	2008	After 2008
(Thousands)
Contractual Obligations
Long-term debt	$1,058,221	-	-	$37,000	$150,000	-	$871,221
Capital lease  obligations	8,079	$710	$559	626	700	$767	4,717
Operating leases	3,911	2,472	1,439	-	-	-	-
Nonutility  generator  purchase  power obligations	2,329,986	426,955	463,896	443,655	420,836	237,226	337,418
NYPA purchase  power contracts	172,555	48,018	41,535	33,348	27,302	3,913	18,439
NMP2 power  purchase  agreement	413,653	49,510	53,902	48,902	53,404	54,499	153,436
Capacity contracts  - electric	27,476	27,166	310	-	-	-	-
Capacity contracts  - natural gas	243,703	47,122	36,810	14,282	8,202	7,239	130,048
Pension and  other  postretirement  benefits(1)	1,075,856	85,728	90,640	95,606	100,888	105,847	597,147
Total Contractual  Obligations	$5,333,440	$687,681	$689,091	$673,419	$761,332	$409,491	$2,112,426
Other Commercial Commitments
Committed lines  of credit	$150,000	$150,000	-	-	-	-	-
Total Commercial  Commitments	$150,000	$150,000	-	-	-	-	-

(1) Amounts are through 2013 only.

NYSEG and RG&E have a joint revolving credit agreement in which they each covenant to maintain certain debt and earnings ratios. NYSEG has a letter of credit and reimbursement agreement in which it covenants to maintain certain debt ratios (See Note 6 to NYSEG's Financial Statements).

Critical Accounting Estimates

See Energy East's Item 7 - Critical Accounting Estimates for this discussion.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Investing and Financing Activities

Investing Activities: Capital spending, including nuclear fuel, totaled $96 million in 2003, $90 million in 2002, and $74 million in 2001. Capital spending in all three years was financed with internally generated funds and was primarily for necessary improvements to existing facilities, the extension of energy delivery service and compliance with environmental requirements and governmental mandates and merger integration in 2003.

Capital spending is projected to be $113 million in 2004. It is expected to be paid for with internally generated funds and will be primarily for the same purposes described above. (See Note 8 to NYSEG's Financial Statements.)

NYSEG's pension plans generated pretax noncash pension income (net of amounts capitalized) of $50 million in 2003, compared to $68 million in 2002 and $72 million in 2001. The decrease in 2003 was due to the significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute NYSEG's pension liability (reduced from 7.0% to 6.5% as of December 31, 2002), and return on assets (reduced from 9% to 8.75% effective January 1, 2003). NYSEG anticipates no funding requirements in 2004 and had no funding requirements in 2003 as total plan assets exceeded the projected benefit obligation. (See Note 13 to NYSEG's Financial Statements.)

Financing Activities: In December 2003 NYSEG and RG&E renewed their joint $200 million 364-day revolving credit facility with certain banks. NYSEG is permitted to borrow up to $150 million and RG&E is permitted to borrow up to $75 million under the facility. NYSEG had no amounts outstanding under this agreement during 2003 or 2002.

NYSEG uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. NYSEG had $41 million of such short-term debt outstanding at December 31, 2003, at a weighted-average interest rate of 1.16%, and $64 million outstanding at December 31, 2002, at a weighted-average interest rate of 1.82%.

See Energy East's Item 7 - NYSEG Financing Activities, for more discussion.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Results of Operations

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Operating Revenues	$1,876,169	$1,878,579	$2,037,874	-	(8%)
Operating Income	$302,900	$328,739	$448,525	(8%)	(27%)
Earnings Available for   Common Stock	$142,529	$132,322	$194,411	8%	(32%)

Earnings

Earnings for 2003 increased $10 million primarily due to increases of $15 million due to higher electric and natural gas retail deliveries primarily because of colder winter weather in the first quarter of 2003, $15 million of restructuring expenses in 2002, $10 million due to the effect of a loss from the early retirement of debt in 2002, $9 million for integration savings and cost control efforts and $8 million due to lower interest charges as a result of refinancings and repayments of first mortgage bonds. Those increases were partially offset by earnings reductions of $18 million caused by an electric price reduction effective March 1, 2002, $6 million due to lower transmission revenues, $11 million because of lower noncash pension income and $9 million from several major storms.

Earnings for 2002 decreased $62 million. The decrease was primarily due to $68 million for an electric price reduction, effective March 1, 2002; lower wholesale deliveries that resulted in higher net purchased power costs of $28 million; $15 million of restructuring expenses; a $10 million loss from the early retirement of debt (see Financing Activities); and $7 million for merger integration costs. Those decreases were partially offset by increases of $31 million for lower natural gas costs, $17 million for higher electric and natural gas retail deliveries due to colder winter weather and warmer summer weather, $8 million for cost control efforts, and $6 million of interest savings due to the early retirement of debt.

Other Items: Other operating expense includes net periodic pension benefit income of $50 million in 2003 after reflecting the effects of regulatory deferrals, $68 million in 2002 and $72 million in 2001. Other operating expenses would have been $18 million lower for 2003 and $4 million lower for 2002 without those decreases in net periodic pension benefit income. Net periodic pension benefit income represented 21% of net income for 2003, 31% for 2002 and 24% for 2001.

Other deductions increased $15 million in 2002 primarily due to a loss on the early retirement of debt. Fees related to the sale of accounts receivable were included in other deductions in the first quarter of 2001. (See Note 1 to NYSEG's Financial Statements.)

Interest charges decreased $14 million in 2003 and $10 million in 2002, primarily as a result of refinancings and repayments of first mortgage bonds.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Operating Results for the Electric Delivery Business

	2003	2002	2001		2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Deliveries - Megawatt-hours   Retail   Wholesale	14,688 1,449	14,379 1,832		13,955 2,714	2%  (21%)	3%  (32%)
Operating Revenues	$1,471,321	$1,545,107		$1,689,464	(5%)	(9%)
Operating Expenses	$1,234,770	$1,277,752		$1,249,775	(3%)	2%
Operating Income	$236,551	$267,355		$439,689	(12%)	(39%)

Operating Revenues: Operating revenues decreased $74 million in 2003 primarily due to a $53 million decrease because of the combined effects of a price reduction, effective March 1, 2002, and the net effect of customers choosing alternate suppliers and customers choosing the bundled rate option, a $46 million decrease due to the elimination in 2002 of the partial amortization of an asset sale gain account that was used to fund a portion of the price reduction effective in March 2002 and a $10 million reduction in transmission revenues. Those decreases were partially offset by higher retail deliveries of $30 million, primarily because of colder winter weather.

The $144 million decrease in operating revenues for 2002 is primarily due to a price reduction, effective March 1, 2002, that decreased revenues $114 million and lower wholesale revenues of $64 million due to lower market prices and lower deliveries. Those decreases were partially offset by increased retail deliveries of $41 million primarily due to warmer summer weather and colder winter weather.

Operating Expenses: The $43 million decrease in operating expenses in 2003 was primarily the result of a $36 million decrease in purchased power resulting from customers choosing alternate suppliers, partially offset by increases due to both higher market prices and higher retail deliveries because of colder winter weather in the first quarter of 2003, a $20 million increase in 2002 due to restructuring expenses and a $12 million decrease due to integration savings and cost control efforts. Those decreases were partially offset by a $17 million increase because of lower noncash pension income and a $15 million increase in expense due to several major storms.

Operating expenses increased $28 million for 2002, primarily due to increases of $20 million for restructuring expenses, $12 million for the effect of the sale of NYSEG's share of NMP2 in 2001, $15 million for purchased power costs for higher retail deliveries due to warmer summer weather and colder winter weather, $9 million for merger integration costs and $6 million for electricity purchased that was deferred in accordance with the electric rate plan. A $44 million increase for purchased power costs to replace energy previously provided by NMP2 was partially offset by a $35 million decrease in certain operating expenses due to the sale of NMP2. Those increases were partially offset by decreases of $32 million for lower market prices for electricity and $20 million due to the elimination of a regulatory amortization of demand-side management program costs.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Operating Results for the Natural Gas Delivery Business

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Deliveries - Dekatherms   Retail   Wholesale	61,786 4,537	58,104 6,381	56,503 6,134	6%  (29%)	3%  4%
Operating Revenues	$404,848	$333,472	$348,410	21%	(4%)
Operating Expenses	$338,499	$272,088	$339,573	24%	(20%)
Operating Income	$66,349	$61,384	$8,837	8%	595%

Operating Revenues: Operating revenues for 2003 increased $71 million primarily due to gas cost recovery of $50 million resulting from a natural gas supply charge and higher retail deliveries of $27 million, primarily because of colder winter weather in the first quarter of 2003.

The $15 million decrease in operating revenues for 2002 is primarily due to lower market prices of natural gas of $20 million that were passed on to nonresidential and wholesale customers, partially offset by $5 million for increased deliveries due to colder winter weather.

Operating Expenses: Operating expenses for 2003 increased $66 million primarily due to a $52 million increase in the cost of natural gas purchased, after various gas cost deferrals and recoveries, and a $14 million increase in natural gas purchased for higher retail deliveries because of colder winter weather in the first quarter of 2003. The increase in operating expense was partially offset by $6 million of restructuring expenses in 2002.

Operating expenses decreased $67 million for 2002 primarily due to an $81 million decrease in natural gas purchased as a result of lower natural gas prices due to market conditions and the deferral of gas costs for future recovery. That decrease was partially offset by increases of $6 million for restructuring expenses and $4 million of gas purchases for higher deliveries due to colder winter weather.

New York State Electric & Gas Corporation
Balance Sheets

December 31	2003	2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$14,458	$11,490
Special deposits	30,353	44,205
Accounts receivable, net	290,166	260,189
Fuel, at average cost	43,207	29,000
Materials and supplies, at average cost	5,893	5,573
Accumulated deferred income tax benefits, net	5,500	4,232
Prepayments	28,917	26,571
Total Current Assets	418,494	381,260
Utility Plant, at Original Cost
Electric	2,593,090	2,551,775
Natural gas	688,705	671,321
Common	120,584	121,661
	3,402,379	3,344,757
Less accumulated depreciation	1,144,385	1,085,840
Net Utility Plant in Service	2,257,994	2,258,917
Construction work in progress	55,638	40,166
Total Utility Plant	2,313,632	2,299,083
Other Property and Investments, Net	37,872	41,365
Regulatory and Other Assets
Regulatory assets
Unfunded future income taxes	42,366	20,467
Unamortized loss on debt reacquisitions	38,863	35,631
Environmental remediation costs	74,734	52,434
Deferred income taxes	71,095	87,864
Other	53,238	23,563
Total regulatory assets	280,296	219,959
Other assets
Goodwill, net	11,199	11,199
Prepaid pension benefits	450,817	395,586
Other	75,255	78,890
Total other assets	537,271	485,675
Total Regulatory and Other Assets	817,567	705,634
Total Assets	$3,587,565	$3,427,342

The notes on pages 119 through 136 are an integral part of the financial statements.

New York State Electric & Gas Corporation
Balance Sheets

December 31	2003	2002
(Thousands)
Liabilities
Current Liabilities
Current portion of long-term debt	$710	$702
Notes payable	41,400	64,000
Accounts payable and accrued liabilities	148,918	169,884
Interest accrued	10,068	12,289
Taxes accrued	15,367	11,091
Other	74,819	58,577
Total Current Liabilities	291,282	316,543
Regulatory and Other Liabilities
Regulatory liabilities	`
Gain on sale of generation assets	52,642	40,638
Accrued removal obligation	304,065	286,052
Other	21,571	25,036
Total regulatory liabilities	378,278	351,726
Other liabilities
Deferred income taxes	522,919	461,418
Other postretirement benefits	208,393	197,193
Asset retirement obligation	377	-
Environmental remediation costs	97,400	75,100
Other	50,840	56,683
Total other liabilities	879,929	790,394
Total Regulatory and Other Liabilities	1,258,207	1,142,120
Long-term debt	1,065,590	1,017,902
Total Liabilities	2,615,079	2,476,565
Commitments	-	-
Preferred Stock  Redeemable solely at NYSEG's option	10,159	10,159
Common Stock Equity  Common stock ($6.66 2/3 par value, 90,000 shares authorized    and 64,508 shares outstanding at December 31, 2003 and 2002)	430,057	430,057
Capital in excess of par value	277,462	277,297
Retained earnings	229,048	206,519
Accumulated other comprehensive income	25,760	26,745
Total Common Stock Equity	962,327	940,618
Total Liabilities and Stockholder's Equity	$3,587,565	$3,427,342

The notes on pages 119 through 136 are an integral part of the financial statements.

New York State Electric & Gas Corporation
Statements of Income

Year Ended December 31	2003	2002	2001
(Thousands)
Operating Revenues
Electric	$1,471,321	$1,545,107	$1,689,464
Natural gas	404,848	333,472	348,410
Total Operating Revenues	1,876,169	1,878,579	2,037,874
Operating Expenses
Electricity purchased	799,664	836,027	801,877
Natural gas purchased	241,746	170,726	247,156
Other operating expenses	215,996	215,278	237,513
Maintenance	97,146	85,013	85,814
Depreciation and amortization	100,726	98,342	101,083
Other taxes	117,991	118,703	128,186
Restructuring expenses	-	25,751	-
Gain on sale of generation assets	-	-	(84,083)
Deferral of asset sale gain	-	-	71,803
Total Operating Expenses	1,573,269	1,549,840	1,589,349
Operating Income	302,900	328,739	448,525
Other (Income)	(8,578)	(6,941)	(10,033)
Other Deductions	1,139	19,248	4,431
Interest Charges, Net	79,394	93,321	103,624
Income Before Income Taxes	230,945	223,111	350,503
Income Taxes	88,020	90,393	155,696
Net Income	142,925	132,718	194,807
Preferred Stock Dividends	396	396	396
Earnings Available for Common Stock	$142,529	$132,322	$194,411

The notes on pages 119 through 136 are an integral part of the financial statements.

New York State Electric & Gas Corporation
Statements of Cash Flows

Year Ended December 31	2003	2002	2001
(Thousands)
Operating Activities
Net income	$142,925	$132,718	$194,807
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	143,925	76,476	149,611
Income taxes and investment tax credits deferred, net	56,330	38,053	14,933
Restructuring expenses	-	25,751	-
Gain on sale of generation assets	-	-	(84,083)
Deferral of asset sale gain	-	-	71,803
Pension income	(44,061)	(67,569)	(71,855)
Changes in current operating assets and liabilities
Accounts receivable, net	(29,977)	32,498	60,159
Sale of accounts receivable program	-	-	(152,000)
Note receivable, current	-	-	(12,126)
Inventory	(14,527)	4,548	(3,049)
Accounts payable and accrued liabilities	(20,966)	25,230	(57,272)
Other current liabilities	16,242	(6,690)	(6,242)
Other assets	(57,105)	(35,311)	(15,019)
Other liabilities	(6,007)	817	(1,215)
Net Cash Provided by Operating Activities	186,779	226,521	88,452
Investing Activities
Utility plant additions	(96,480)	(89,466)	(79,885)
Sale of generation assets	-	59,442	59,441
Proceeds from sale of utility plant	534	6,536	546
Special deposits	6,327	(5,166)	19,909
Other	5,903	1,050	4,475
Net Cash (Used in) Provided by Investing Activities	(83,716)	(27,604)	4,486
Financing Activities
Equity contribution from parent	-	-	100,000
Repayments of first mortgage bonds and preferred    stock, including net premiums	(154,085)	(430,455)	-
Long-term note issuances	196,986	247,807	-
Notes payable three months or less, net	(22,600)	64,000	(123,000)
Dividends on common and preferred stock	(120,396)	(90,396)	(65,939)
Net Cash Used in Financing Activities	(100,095)	(209,044)	(88,939)
Net Increase (Decrease) in Cash and   Cash Equivalents	2,968	(10,127)	3,999
Cash and Cash Equivalents, Beginning of Year	11,490	21,617	17,618
Cash and Cash Equivalents, End of Year	$14,458	$11,490	$21,617

The notes on pages 119 through 136 are an integral part of the financial statements.

New York State Electric & Gas Corporation
Statements of Changes in Common Stock Equity

(Thousands)	Common Stock     Outstanding      $6.66 2/3 Par Value  Shares         Amount		Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total
Balance, January 1, 2001	64,508	$430,057	$170,678	$35,329	$1,327	$637,391
Net income				194,807		194,807
Other comprehensive income (loss),     net of tax					(17,562)	(17,562)
Comprehensive income						177,245
Equity contribution from parent			100,000			100,000
Cash dividends declared
Preferred stock (at serial rates)
Redeemable - optional				(396)		(396)
Common Stock				(65,543)		(65,543)
Amortization of capital stock issue expense			157			157
Balance, December 31, 2001	64,508	430,057	270,835	164,197	(16,235)	848,854
Net income				132,718		132,718
Other comprehensive income, net of tax					42,980	42,980
Comprehensive income						175,698
Equity contribution from parent			6,462			6,462
Cash dividends declared
Preferred stock (at serial rates)
Redeemable - optional				(396)		(396)
Common Stock				(90,000)		(90,000)
Balance, December 31, 2002	64,508	430,057	277,297	206,519	26,745	940,618
Net income				142,925		142,925
Other comprehensive income (loss), net of tax					(985)	(985)
Comprehensive income						141,940
Equity contribution from parent			165			165
Cash dividends declared
Preferred stock (at serial rates)
Redeemable - optional				(396)		(396)
Common Stock				(120,000)		(120,000)
Balance, December 31, 2003	64,508	$430,057	$277,462	$229,048	$25,760	$962,327

The notes on pages 119 through 136 are an integral part of the financial statements.

Notes to Financial Statements

New York State Electric & Gas Corporation

Note 1. Significant Accounting Policies

Background: New York State Electric & Gas Corporation (NYSEG) is primarily engaged in electricity transmission and distribution operations and natural gas transportation, storage and distribution operations in upstate New York. In connection with Energy East Corporation's merger with RGS Energy Group, Inc. (RGS Energy) on June 28, 2002, NYSEG became a wholly-owned subsidiary of RGS Energy.

Accounts receivable: Accounts receivable include unbilled revenues of $72 million at December 31, 2003, and $79 million at December 31, 2002, and are shown net of an allowance for doubtful accounts of $10 million at December 31, 2003 and 2002. Bad debt expense was $15 million in 2003, $18 million in 2002, and $14 million in 2001.

In August 2001 NYSEG terminated its agreement to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allowed NYSEG to receive up to $152 million from the sale of such interests. All fees related to the agreement beginning April 1, 2001, are included in interest expense and were approximately $3 million. Fees related to the sale of accounts receivable through March 31, 2001, are included in other deductions and were approximately $2 million in 2001. NYSEG's sale of accounts receivable before the agreement was terminated did not constitute a securitization transaction because the accounts receivable were not transferred to a special purpose entity, and therefore, were not transformed into securities.

Statements of cash flows: NYSEG considers all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and those investments are included in cash and cash equivalents.

Supplemental Disclosure of Cash Flows Information	2003	2002	2001
(Thousands)
Cash paid during the year ended December 31:
Interest, net of amounts capitalized	$57,359	$70,221	$83,123
Income taxes, net of benefits received	$26,159	$58,844	$132,942

Depreciation and amortization: NYSEG determines depreciation expense using straight-line rates, based on the average service lives of groups of depreciable property, which includes estimated cost of removal, in service. The average service lives of certain classifications of property are: transmission property - 55 years, distribution property - 44 years, generation property - 50 years, gas storage property - 20 years and other property - 40 years. NYSEG's depreciation accruals were equivalent to 3.2% of average depreciable property for 2003 and 2002 and 2.9% for 2001.

Estimates: Preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Notes to Financial Statements

New York State Electric & Gas Corporation

Goodwill: The excess of the cost over fair value of net assets of purchased businesses is recorded as goodwill. NYSEG evaluates the carrying value of goodwill for impairment at least annually and on an interim basis if there are indications that goodwill might be impaired. Any impairments would be recognized when the fair value of goodwill is less than its carrying value. Goodwill was amortized on a straight-line basis over 40 years until December 31, 2001. (See Note 3.)

Income taxes: Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.

NYSEG computes its income tax provision on a separate return method. SEC regulations require that no Energy East subsidiary pay more income taxes than it would pay if a separate income tax return were to be filed. The determination and allocation of NYSEG's income tax provision and its components are outlined and agreed to in the tax sharing agreement with Energy East.

Other (Income) and Other Deductions:

Year Ended December 31	2003	2002	2001
(Thousands)
Dividends	-	$(92)	$(1,844)
Interest income	$(1,126)	(4,617)	(3,852)
Noncash return	(1,024)	(1,313)	(792)
Sale of securities	(2,883)	-	-
Miscellaneous	(3,545)	(919)	(3,545)
Total other (income)	$(8,578)	$(6,941)	$(10,033)
NYSEG early retirement of debt	-	$16,145	-
Fees on sale of accounts receivable	-	-	$2,495
Miscellaneous	$1,139	3,103	1,936
Total other deductions	$1,139	$19,248	$4,431

Reclassifications: Certain amounts have been reclassified on the financial statements to conform to the 2003 presentation.

Regulatory assets and liabilities: Pursuant to Statement 71, NYSEG capitalizes, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.

Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Unamortized loss on debt reacquisitions is amortized over the lives of the related debt issues. Other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with NYSEG's current rate plans. NYSEG earns a return on all regulatory assets for which funds have been spent.

Notes to Financial Statements

New York State Electric & Gas Corporation

Revenue recognition: NYSEG recognizes revenues upon delivery of energy and energy-related products and services to its customers.

NYSEG enters into power purchase and sales transactions with the NYISO. When electricity from owned generation is sold to the NYISO, and subsequently repurchased from the NYISO to serve its customers, the transactions are recorded on a net basis in the statements of income.

Risk management: NYSEG has a gas supply charge that allows it to recover through rates any changes in the market price of purchased natural gas, substantially eliminating its exposure to natural gas price risk. NYSEG uses 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.

NYSEG uses 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 uses interest rate swap agreements to manage the risk of increases in variable interest rates and to maintain desired fixed-to-floating rate ratios. It records amounts paid and received under the agreements as adjustments to the interest expense of the specific debt issues.

NYSEG does not hold or issue financial instruments for trading or speculative purposes.

NYSEG recognizes the fair value of its natural gas futures and forwards, financial electricity contracts and interest rate agreements as assets or liabilities. NYSEG's derivative asset was $49 million at December 31, 2003, and $55 million at December 31, 2002, and its derivative liability was $3 million at December 31, 2003, and $5 million at December 31, 2002. All of the arrangements are designated as cash flow hedging instruments. Changes in the fair value of the cash flow hedging instruments are recognized in other comprehensive income until the underlying transaction occurs. When the underlying transaction occurs, the amounts in accumulated other comprehensive income are reported in the statements of income.

NYSEG uses quoted market prices to fair value derivatives and adjust for volatility and inflation when the period of the derivative exceeds the period for which market prices are readily available.

As of December 31, 2003, the maximum length of time over which NYSEG is hedging its exposure to the variability in future cash flows for forecasted transactions is 72 months. NYSEG estimates that gains of $19 million will be reclassified from accumulated other comprehensive income into earnings in 2004, as the underlying transactions occur.

NYSEG has commodity purchase and sales contracts for both capacity and energy that have been designated and qualify for the normal purchases and normal sales exception in Statement 133, as amended.

Notes to Financial Statements

New York State Electric & Gas Corporation

Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability.

NYSEG's adoption of Statement 143 as of January 1, 2003, did not have a material effect on its financial position or results of operations. There was no effect on net income. NYSEG recognized various amounts on its balance sheets. Changes in the assumptions underlying the items shown in the following table could affect the balance sheet amounts and future costs related to the obligations.

As of January 1, 2003
(Thousands)
Asset retirement obligation	$(539)
Regulatory asset	$350
Regulatory liability	$(3,689)
Increase in utility plant	$30
Decrease in accumulated depreciation	$3,848

Statement 143 provides that if the requirements of Statement 71 are met, a regulatory liability should be recognized for the difference between removal costs collected in rates and actual costs incurred. In previous years, those amounts were included in accumulated depreciation in accordance with industry practice. Accrued removal obligations totaling approximately $304 million for NYSEG as of December 31, 2003, and $286 million as of December 31, 2002, that had previously been embedded within accumulated depreciation, were reclassified as a regulatory liability.

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. FIN 46R requires a business enterprise to consolidate a variable interest entity if that enterprise has a variable interest that will absorb a majority of the entity's expected losses.

NYSEG has independent, ongoing, long-term power purchase contracts with NUGs. (See Note 8.) In accordance with FIN 46R, NYSEG is evaluating if it has a variable interest in any NUG and, to the extent that NYSEG has a variable interest, whether it is a primary beneficiary. To the extent that NYSEG is a primary beneficiary of a NUG, consolidation would be required at March 31, 2004, unless NYSEG is unable to obtain sufficient information to do so. NYSEG was not involved in the formation of any NUGs, does not have ownership interests in any NUGs and may not be able to obtain sufficient information from the NUGs to determine if it is a primary

Notes to Financial Statements

New York State Electric & Gas Corporation

beneficiary. NYSEG is presently unable to determine the effect on its financial statements, if any, of applying FIN 46R to its power purchase contracts with NUGs.

Utility plant: NYSEG charges repairs and minor replacements to operating expense accounts, and capitalizes renewals and betterments, including certain indirect costs. The original cost of utility plant retired or otherwise disposed of is charged to accumulated depreciation.

Note 2. Restructuring

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, including $26 million for NYSEG. The employee positions affected by the restructuring were identified in the fourth quarter of 2002. The restructuring expenses reduced NYSEG's 2002 net income by $15 million, including $13 million for a voluntary early retirement program that will be paid from NYSEG's pension plan and $2 million for an involuntary severance program for salaried employees. During 2003 NYSEG's entire related involuntary severance liability of $3 million was paid.

The voluntary early retirement and involuntary severance programs resulted in a reduction in overall employee headcount of 255 in 2003.

Energy East has consolidated the accounting and finance functions of five of its operating companies to one location. In connection with this latest restructuring, in the fourth quarter of 2003 NYSEG began to recognize an expected total liability of less than $1 million for an enhanced severance program for certain accounting and finance employees who will be employed through March 31, 2004.

Note 3. Goodwill and Other Intangible Assets

NYSEG no longer amortizes goodwill effective January 1, 2002, and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized (amortized intangible assets) and are reviewed for impairment. Annual impairment testing was completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for NYSEG at September 30, 2003.

The carrying amount of goodwill, which is included in NYSEG's natural gas delivery operating segment, was $11 million as of December 31, 2003 and 2002.

Other Intangible Assets: NYSEG's unamortized intangible assets had a carrying amount of $1.4 million at December 31, 2003, and $1.6 million at December 31, 2002, and primarily consisted of pension assets, franchises and consents. NYSEG's amortized intangible assets had a gross carrying amount of $1.5 million and accumulated amortization of $1 million at December 31, 2003 and 2002, and consisted of hydroelectric licenses. Estimated amortization expense for intangible assets for the next five years is $40 thousand each year for 2004 and 2005, $24 thousand for 2006 and $21 thousand each year for 2007 and 2008.

Notes to Financial Statements

New York State Electric & Gas Corporation

Transitional Information: Results of operations information for NYSEG as though goodwill had not been amortized for all years presented is:

Year Ended December 31	2003	2002	2001
(Thousands)
Reported net income	$142,925	$132,718	$194,807
Add back: Goodwill amortization	-	-	383
Adjusted net income	$142,925	$132,718	$195,190

Note 4. Income Taxes

Year Ended December 31	2003	2002	2001
(Thousands)
Current	$31,690	$52,420	$140,764
Deferred, net     Accelerated depreciation	25,899	8,229	10,036
Pension benefits	24,813	31,847	28,917
Statement 106 postretirement benefits	(2,693)	605	(3,479)
Demand-side management	-	(1,429)	(8,499)
Asset sale gain account amortization	(52)	19,465	-
Deferred gas costs	(457)	5,313	-
Restructuring expenses	1,424	(10,268)	-
Gas supply deferral	8,175	5,813	-
Miscellaneous	(99)	(21,237)	(11,221)
ITC	(680)	(365)	(822)
Total	$88,020	$90,393	$155,696

NYSEG's effective tax rate differed from the statutory rate of 35% due to the following:

Year Ended December 31	2003	2002	2001
(Thousands)
Tax expense at statutory rate	$80,831	$78,089	$122,676
Depreciation and amortization not normalized	2,527	2,566	15,182
ITC amortization	(680)	(365)	(822)
State taxes, net of federal benefit	10,762	10,716	16,526
Other, net	(5,420)	(613)	2,134
Total	$88,020	$90,393	$155,696

Notes to Financial Statements

New York State Electric & Gas Corporation

NYSEG's deferred tax assets and liabilities consisted of the following:

December 31	2003	2002
(Thousands)
Current Deferred Tax Assets	$5,500	$4,232
Noncurrent Deferred Tax Liabilities
Depreciation	$342,768	$297,978
Unfunded future income taxes	17,734	902
Accumulated deferred ITC	14,972	15,548
Deferred gain on generation plant sale	(18,247)	(14,766)
Pension benefits	151,640	129,940
Statement 106 retirement benefits	(55,543)	(52,849)
Other	(1,500)	(3,199)
Total Noncurrent Deferred Tax Liabilities	451,824	373,554
Less amounts classified as regulatory assets
Deferred income taxes	(71,095)	(87,864)
Noncurrent Deferred Income Taxes	$522,919	$461,418

NYSEG has no federal or state tax credit or loss carryforwards, and no valuation allowances.

Note 5. Long-term Debt

At December 31, 2003 and 2002, NYSEG's long-term debt was:

			Amount
	Maturity Dates	Interest Rates	2003	2002
(Thousands)
First mortgage bonds	-	-	-	$150,000
Pollution control notes - fixed	2006 to 2034	5.70% to 6.15%	$306,000	306,000
Pollution control notes - variable	2015 to 2029	1.08% to 4.30%	307,000	307,000
Long-term notes	2007 to 2023	4 3/8% to 5 3/4%	450,000	250,000
Obligations under capital leases			8,079	8,781
Unamortized premium and discount on debt, net			(4,779)	(3,177)
			1,066,300	1,018,604
Less debt due within one year, included in current liabilities			710	702
Total			$1,065,590	$1,017,902

NYSEG has no secured indebtedness. None of NYSEG's debt obligations are guaranteed or secured by any of its affiliates.

At December 31, 2003, long-term debt and capital lease payments (in thousands) that will become due during the next five years are:

2004	2005	2006	2007	2008
$710	$559	$37,626	$150,700	$767

Cross-default Provisions: NYSEG has provisions in its unsecured indenture and the reimbursement agreements relating to certain series of pollution control bonds, which provide that default by NYSEG with respect to any other debt in excess of $40 million in the case of the

Notes to Financial Statements

New York State Electric & Gas Corporation

unsecured indenture and $5 million in the case of the reimbursement agreements will be considered a default under those respective documents.

Note 6. Bank Loans and Other Borrowings

NYSEG uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. NYSEG had $41 million of such short-term debt outstanding at December 31, 2003, at a weighted-average interest rate of 1.16%, and $64 million at December 31, 2002, at a weighted-average interest rate of 1.82%.

NYSEG and RG&E have a joint $200 million 364-day revolving credit facility with certain banks, which they renewed in December 2003. NYSEG is permitted to borrow up to $150 million under the facility. At NYSEG's and RG&E's option, the interest rate on borrowings is related to the prime rate or the Eurodollar rate. The agreement provides for payment of a commitment fee, which was .15% at December 31, 2003 and 2002. NYSEG had no amounts outstanding under this agreement at December 31, 2003 and 2002.

In their joint revolving credit agreement NYSEG and RG&E each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2003, NYSEG's ratio of earnings before interest expense and income tax to interest expense was 5.2 to 1.0, and its ratio of total indebtedness to total capitalization was 0.53 to 1.00.

NYSEG has a letter of credit and reimbursement agreement in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 as of the last day of any fiscal quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2003.

Notes to Financial Statements

New York State Electric & Gas Corporation

Note 7. Preferred Stock Redeemable Solely at the Option of NYSEG

At December 31, 2003 and 2002, NYSEG's serial cumulative preferred stock was:

Series	Par Value Per Share	Redemption Price Per Share	Shares Authorized and Outstanding(1)	Amount (Thousands)     2003              2002
3.75%	$100	$104.00	78,379	$7,838	$7,838
4 1/2% (1949)	100	103.75	11,800	1,180	1,180
4.40%	100	102.00	7,093	709	709
4.15% (1954)	100	102.00	4,317	432	432
Total				$10,159	$10,159

(1) At December 31, 2003, NYSEG had 2,353,411 shares of $100 par value preferred stock, 10,800,000 shares of $25 par value preferred stock and 1,000,000 shares of $100 par value preference stock authorized but unissued.

NYSEG had no redemptions or purchases of preferred stock during the three years 2001 through 2003.

Voting rights: If preferred stock dividends on any series of preferred stock are in default in an amount equivalent to four full quarterly dividends, the holders of the preferred stock are entitled to elect a majority of the directors and their privilege continues until all dividends in default have been paid. The holders of preferred stock are not entitled to vote in respect of any other matters except those, if any, in respect of which voting rights cannot be denied or waived under some mandatory provision of law, and except that the charter contains provisions to the effect that such holders shall be entitled to vote on certain matters affecting the rights and preferences of the preferred stock.

Whenever holders of preferred stock shall be entitled to vote, they shall be entitled to cast one vote for each share of preferred stock held by them. Holders of NYSEG common stock are entitled to one vote per share on all matters, except in the election of directors with respect to which NYSEG common stock has cumulative voting rights.

Note 8. Commitments

Capital spending: NYSEG has commitments in connection with its capital spending program. Capital spending is projected to be $113 million in 2004 and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. NYSEG's capital spending will be primarily for necessary improvements to existing facilities, the extension of energy delivery service, compliance with environmental requirements and governmental mandates and merger integration.

Nonutility generator power purchase contracts: NYSEG expensed approximately $398 million for NUG power in 2003, $400 million in 2002 and $368 million in 2001. NYSEG estimates that its NUG power purchases will total $427 million in 2004, $464 million in 2005, $444 million in 2006, $421 million in 2007 and $237 million in 2008.

Notes to Financial Statements

New York State Electric & Gas Corporation

Note 9. Nuclear Generation Assets

In November 2001 NYSEG sold its 18% interest in NMP2 to Constellation Nuclear. In October 2001 the NYPSC issued an order approving the sale. NYSEG's 18% share of NMP2's operating expenses until it was sold are included in various categories on the statements of income. Upon completion of the sale of NMP2, NYSEG recorded an asset sale gain of approximately $110 million, in accordance with the NYPSC's order approving the sale, as a regulatory liability under Statement 71. The gain includes a gross up for unfunded future income taxes and is being returned to customers in accordance with NYSEG's current electric rate plan, which was approved by the NYPSC in February 2002.

NYSEG's pre-existing decommissioning funds were transferred to Constellation, which has taken responsibility for all future decommissioning funding.

The transaction included a power purchase agreement that calls for Constellation to provide electricity to NYSEG, at fixed prices, for 10 years. The power purchase agreement is a contract for physical delivery of NYSEG's 18% share of 90% of the output from NMP2. NYSEG records expenses for electricity purchased in accordance with the agreement at the time the power is physically delivered, at prices pursuant to the agreement. The contract is not required to be marked-to-market and is not considered to be a derivative instrument because it qualifies for the normal purchases and normal sales exception in Statement 133, as amended.

After the power purchase agreement is completed a revenue sharing agreement will begin. The revenue sharing agreement could provide NYSEG additional revenue through 2021, which would mitigate increases in electricity prices. Both agreements are based on plant output. No amounts are recorded under the revenue sharing agreement because any benefit that may occur between 2011 and 2021 cannot be estimated. Any benefits from the revenue sharing agreement will be deferred for customers.

Note 10. Environmental Liability

From time to time environmental laws, regulations and compliance programs may require changes in NYSEG's operations and facilities and may increase the cost of electric and natural gas service.

The U.S. Environmental Protection Agency and the New York State Department of Environmental Conservation (NYSDEC), as appropriate, notified NYSEG that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at nine waste sites, not including its sites where gas was manufactured in the past, which are discussed below. With respect to the nine sites, seven sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites and three of the sites are also included on the National Priorities list.

Any liability may be joint and several for certain of those sites. NYSEG has recorded an estimated liability of $0.4 million related to five of the nine sites. Remediation costs have been paid at the remaining four sites, and NYSEG expects no additional liability to be incurred. The ultimate cost to remediate the sites may be significantly more than the estimated amount.

Notes to Financial Statements

New York State Electric & Gas Corporation

Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to NYSEG.

NYSEG has a program to investigate and perform necessary remediation at its sites where gas was manufactured in the past. In 1994 and 1996 NYSEG entered into Orders on Consent with the NYSDEC. These Orders require NYSEG to investigate and, where necessary, remediate 34 of its 38 sites. Eight sites are included in the New York State Registry.

NYSEG's estimate for all costs related to investigation and remediation of the 38 sites ranges from $97 million to $192 million at December 31, 2003. That estimate is based on both known and potential site conditions and multiple remediation alternatives for each of the sites. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations.

The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites, reflected on NYSEG's balance sheets was $97 million at December 31, 2003, and $75 million at December 31, 2002. NYSEG recorded a corresponding regulatory asset, net of insurance recoveries, since it expects to recover the net costs in rates.

NYSEG's environmental liability accruals, which are expected to be paid through the year 2017, have been established on an undiscounted basis. NYSEG received insurance settlements during the last three years, which it accounted for as reductions in its related regulatory asset.

Notes to Financial Statements

New York State Electric & Gas Corporation

Note 11. Accumulated Other Comprehensive Income

(Thousands)	Balance January 1, 2001	2001 Change	Balance December 31, 2001	2002 Change	Balance December 31, 2002	2003 Change	Balance December 31, 2003
Unrealized gains (losses) on investments:  Unrealized holding gains   (losses) during period, net of   income tax (expense) benefit   of $(380) for 2001, $784 for   2002 and $650 for 2003		$176		$(1,183)		$(950)
Net unrealized gains (losses) on investments	1,957	176	2,133	(1,183)	950	(950)	-
Minimum pension liability adjustment, net of income tax benefit (expense) of $(67) for 2001, $6 for 2002 and $(73) for 2003	(630)	26	(604)	(8)	(612)	110	$(502)
Unrealized gains (losses) on derivatives qualified as hedges:  Unrealized gains on derivatives   qualified as hedges arising   during the period due to   cumulative effect of a change   in accounting principle, net of   income tax expense of   $(36,706) for 2001  Unrealized (losses) gains   during period on derivatives   qualified as hedges, net of   income tax benefit (expense)   of $55,271 for 2001, $(23,224)   for 2002 and $(14,070) for 2003  Reclassification adjustment for   losses (gains) included in net   Income, net of income tax   (benefit) expense of  $6,624   for 2001, $6,069 for 2002 and   $(14,166) for 2003		54,602  (82,219) 9,853		-      35,019  9,152		-      21,215  (21,360)
Net unrealized (losses) gains on derivatives qualified as hedges	-	(17,764)	(17,764)	44,171	26,407	(145)	26,262
Accumulated Other Comprehensive Income (Loss)	$1,327	$(17,562)	$(16,235)	$42,980	$26,745	$(985)	$25,760

(See Risk management in Note 1.)

Notes to Financial Statements

New York State Electric & Gas Corporation

Note 12. Fair Value of Financial Instruments

The carrying amounts and estimated fair values of NYSEG's financial instruments included on its balance sheets are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.

December 31	2003	2003	2002	2002
	Carrying Amount	Estimated Fair Value	Carrying Amount	Estimated Fair Value
(Thousands)
Investments - classified as  available-for-sale	$32,550	$32,552	$36,374	$36,400
First mortgage bonds	-	-	$149,016	$167,817
Pollution control notes - fixed	$306,000	$318,785	$306,000	$319,790
Pollution control notes - variable	$307,000	$307,000	$307,000	$307,000
Long-term notes	$445,221	$450,855	$247,807	$257,805

The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values. Special deposits may include restricted funds set aside as collateral for first mortgage bonds and collateral received from counterparties. The carrying amount approximates fair value because the special deposits have been invested in securities that mature within one year.

Note 13. Retirement Benefits

	Pension Benefits		Postretirement Benefits
	2003	2002	2003	2002
(Thousands)
Change in projected benefit obligation
Benefit obligation at January 1	$1,060,428	$954,532	$274,930	$244,667
Service cost	16,868	17,418	3,233	2,942
Interest cost	67,856	65,884	18,825	17,625
Plan amendments	84	-	-	(10,597)
Actuarial loss	36,185	56,044	35,944	34,017
Special termination benefits	-	21,917	-	-
Benefits paid	(79,234)	(55,367)	(16,536)	(13,724)
Projected benefit obligation at December 31	$1,102,187	$1,060,428	$316,396	$274,930
Change in plan assets
Fair value of plan assets at January 1	$1,213,892	$1,424,135	-	-
Actual return on plan assets	281,572	(154,876)	-	-
Employer contributions	-	-	$16,536	$13,724
Benefits paid	(79,234)	(55,367)	(16,536)	(13,724)
Fair value of plan assets at December 31	$1,416,230	$1,213,892	-	-
Funded status	$314,043	$153,464	$(316,396)	$(274,930)
Unrecognized net actuarial loss (gain)	96,026	204,038	76,750	44,576
Unrecognized prior service cost (benefit)	41,979	46,552	(41,342)	(47,500)
Unrecognized net transition (asset) obligation	(1,231)	(8,468)	72,595	80,661
Prepaid (accrued) benefit cost	$450,817	$395,586	$(208,393)	$(197,193)

Notes to Financial Statements

New York State Electric & Gas Corporation

NYSEG uses a December 31 measurement date for its pension and postretirement benefit plans.

NYSEG's accumulated benefit obligation for all defined benefit pension plans was $1,017 million at December 31, 2003, and $976 million at December 31, 2002.

NYSEG's postretirement benefits were unfunded as of December 31, 2003 and 2002.

Weighted-average assumptions used to determine benefit obligations at	Pension Benefits		Postretirement Benefits
December 31	2003	2002	2003	2002
Discount rate	6.25%	6.50%	6.25%	6.50%
Rate of compensation increase	4.00%	4.00%	N/A	N/A

As of December 31, 2003, NYSEG decreased its discount rate from 6.5% to 6.25%.

	Pension Benefits			Postretirement Benefits
	2003	2002	2001	2003	2002	2001
(Thousands)
Components of net periodic benefit cost
Service cost	$16,868	$17,418	$16,416	$3,233	$2,942	$2,901
Interest cost	67,856	65,884	63,109	18,825	17,625	15,145
Expected return   on plan assets	(120,665)	(127,659)	(122,043)	-	-	-
Amortization of prior   service cost	4,658	7,697	7,715	(6,157)	(6,157)	(6,157)
Recognized net   actuarial gain	(16,710)	(38,836)	(41,902)	3,769	(535)	(4,341)
Amortization of transition   (asset) obligation	(7,238)	(7,238)	(7,238)	8,066	9,126	9,126
Special termination benefits	-	21,917	-	-	-	-
Net periodic benefit cost	$(55,231)	$(60,817)	$(83,943)	$27,736	$23,001	$16,674

Net periodic benefit cost is included in other operating expenses. The net periodic benefit cost for postretirement benefits represents the cost NYSEG charged to expense for providing health care benefits to retirees and their eligible dependents. There were no postretirement benefit costs deferred as of December 31, 2003, and $0.4 million was deferred as of December 31, 2002. NYSEG recovered deferred postretirement costs as of March 2003. The transition obligation for postretirement benefits is being amortized over a period of 20 years.

Weighted-average assumptions used    to determine net periodic benefit cost	Pension Benefits			Postretirement Benefits
Year ended December 31	2003	2002	2001	2003	2002	2001
Discount rate	6.50%	7.00%	7.25%	6.50%	7.00%	7.25%
Expected return on plan assets	8.75%	9.00%	9.00%	N/A	N/A	N/A
Rate of compensation increase	4.00%	4.00%	4.00%	N/A	N/A	N/A

Notes to Financial Statements

New York State Electric & Gas Corporation

NYSEG's expected rate of return on plan assets assumption was developed based on a review of historical returns for the major asset classes. This analysis also considered both current capital market conditions and projected future conditions. Given the current low interest rate environment, NYSEG selected an assumption of 8.75% per year, which is lower than the rate otherwise determined solely based on historical returns.

NYSEG assumed a 10.0% annual rate of increase in the per capita cost of covered health care benefits for 2004 that gradually decreases to 5.0% by the year 2007. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase	1% Decrease
Effect on total of service and interest cost components	$1 million	$(1 million)
Effect on postretirement benefit obligation	$20 million	$(17 million)

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

In accordance with FASB Staff Position No. FAS 106-1, any measures of the APBO or net periodic postretirement benefit cost in NYSEG's financial statements or accompanying notes do not reflect the effects of the Act on its plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the sponsor to change previously reported information. Moreover, the issues of how and when the federal subsidy should be accounted for are not yet resolved by the FASB. NYSEG has not yet determined the potential effects of the Act on its future postretirement costs, including the participation rates in its benefit plans, nor whether any amendments to its benefit plans are appropriate given the provisions of the Act.

NYSEG's weighted-average asset allocations at December 31, 2003 and 2002, by asset category are:

	Pension Benefits
Asset Category	Target Allocation	2003	2002
Equity securities	60%	64%	59%
Debt securities	30%	34%	41%
Real estate	5%	-	-
Other	5%	2%	-
Total	100%	100%	100%

Notes to Financial Statements

New York State Electric & Gas Corporation

NYSEG's pension plan assets are held in a master trust with a trustee and are invested among and within various asset classes in order to achieve sufficient diversification in accordance with NYSEG's risk tolerance. This is achieved through the utilization of multiple asset managers and systematic allocation to investment management styles, providing a broad exposure to different segments of the fixed income and equity markets.

Equity securities included no Energy East common stock as of December 31, 2003 and 2002.

NYSEG does not anticipate any contributions to its pension fund in 2004.

Expected benefit payments, which reflect expected future service, as appropriate, are as follows:

	Pension Benefits	Postretirement Benefits
(Thousands)
2004	$63,798	$21,930
2005	66,213	24,427
2006	68,915	26,691
2007	71,930	28,958
2008	75,223	30,624
2009 - 2013	417,154	179,993

Notes to Financial Statements

New York State Electric & Gas Corporation

Note 14. Segment Information

Selected financial information for NYSEG's business segments is presented in the table below. NYSEG's electric delivery segment consists of its regulated transmission, distribution and generation operations. Its natural gas delivery segment consists of its regulated transportation, storage and distribution operations. Other includes NYSEG's corporate assets.

	Electric Delivery	Natural Gas Delivery	Other	Total
(Thousands)
2003
Operating Revenues	$1,471,321	$404,848	-	$1,876,169
Depreciation and Amortization	$81,222	$19,504	-	$100,726
Operating Income	$236,551	$66,349	-	$302,900
Interest Charges, Net	$61,561	$17,833	-	$79,394
Income Taxes	$68,422	$19,598	-	$88,020
Earnings Available for   Common Stock	$111,994	$30,535	-	$142,529
Total Assets	$2,664,449	$870,464	$52,652	$3,587,565
Capital Spending	$70,013	$26,467	-	$96,480
2002
Operating Revenues	$1,545,107	$333,472	-	$1,878,579
Depreciation and Amortization	$79,361	$18,981	-	$98,342
Operating Income	$267,355	$61,384	-	$328,739
Interest Charges, Net	$71,951	$21,370	-	$93,321
Income Taxes	$76,392	$14,001	-	$90,393
Earnings Available for   Common Stock	$109,919	$22,403	-	$132,322
Total Assets	$2,584,216	$783,672	$59,454	$3,427,342
Capital Spending	$64,377	$25,264	-	$89,641
2001
Operating Revenues	$1,689,464	$348,410	-	$2,037,874
Depreciation and Amortization	$82,394	$18,689	-	$101,083
Operating Income	$439,689	$8,836	-	$448,525
Interest Charges, Net	$89,138	$14,486	-	$103,624
Income Taxes	$157,916	$(2,220)	-	$155,696
Earnings Available for   Common Stock	$197,204	$(2,793)	-	$194,411
Total Assets	$2,250,852	$697,280	$66,291	$3,014,423
Capital Spending	$50,391	$23,899	-	$74,290

Notes to Financial Statements

New York State Electric & Gas Corporation

Note 15. Quarterly Financial Information (Unaudited)

Quarter Ended	March 31	June 30		September 30	December 31
(Thousands)
2003
Operating Revenues	$575,732	$413,364		$406,627	$480,446
Operating Income	$120,648	$70,119		$43,267	$68,866
Net Income	$60,617	$29,923		$20,253	$32,132
Earnings Available for   Common Stock	$60,518	$29,824		$20,154	$32,033
2002
Operating Revenues	$557,255	$425,445		$424,891	$470,988
Operating Income	$142,930	$61,519		$60,340	$63,950	(2)
Net Income	$69,621	$13,145	(1)	$23,296	$26,656	(2)
Earnings Available for   Common Stock	$69,522	$13,046	(1)	$23,197	$26,557	(2)

(1) Includes the effect of the early retirement of debt that decreased net income $10 million.
⁽²⁾ Includes the effect of restructuring expenses that decreased operating income $26 million and net income $15 million.

Report of Independent Auditors

To the Shareholder and Board of Directors,
New York State Electric & Gas Corporation

In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) on page 170 present fairly, in all material respects, the financial position of New York State Electric & Gas Corporation ("the Company") at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing in Item 15(a)(2) on page 170 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 1 and 11 to the financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative and hedging activities pursuant to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133). As discussed in Notes 1 and 3 to the financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

PricewaterhouseCoopers LLP

New York, New York
January 30, 2004

NEW YORK STATE ELECTRIC & GAS CORPORATION

SCHEDULE II - Valuation and Qualifying Accounts

Years Ended December 31, 2003, 2002 and 2001

Classification	Beginning of Year	Additions	Write-offs (a)	Adjustments	End of Year
(Thousands)
2003   Allowance for Doubtful     Accounts - Accounts     Receivable	$10,288	$15,054	$(15,054)	-	$10,288
2002   Allowance for Doubtful     Accounts - Accounts     Receivable	$6,300	$17,600	$(14,100)	$488	$10,288
2001   Allowance for Doubtful     Accounts - Accounts     Receivable	$6,300	$14,435	$(14,435)	-	$6,300	(b)

(a)  Uncollectible accounts charged against the allowance, net of recoveries.
(b)  Represents an estimate of write-offs that would not be recovered in rates.

Selected Financial Data

Rochester Gas and Electric Corporation

	2003	2002	2001		2000		1999
(Thousands)
Operating Revenues	$1,025,110	$992,940	$1,039,476		$1,044,149		$1,090,448
Depreciation and amortization	$105,901	$102,758	$112,643		$112,110		$117,289
Other taxes	$82,045	$89,370	$87,718		$90,090		$112,613
Interest Charges, Net	$75,947	$59,838	$62,416		$60,922		$56,563
Net Income	$29,640	$50,067	$73,650		$95,529		$94,488
Capital Spending	$109,947	$123,591	$147,639		$143,544		$108,245
Total Assets	$2,960,830	$2,632,396	$2,453,007	(1)	$2,454,773	(1)	$2,408,787	(1)
Long-term Obligations and   Redeemable Preferred Stock	$850,261	$777,254	$812,243		$816,835		$821,000

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

(1) Does not reflect the reclassification of accrued removal costs from accumulated depreciation to a regulatory liability.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Liquidity and Capital Resources

Restructuring

See Energy East's Item 7 - Restructuring, for this discussion.

Electric Delivery Business

RG&E's electric delivery business consists of its regulated electricity transmission and distribution operations in western New York. It also generates electricity from its one nuclear plant, one coal-fired plant, three gas turbines and several smaller hydroelectric stations.

RG&E 2002 Electric and Gas Rate Proceeding: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

RG&E Cost Deferral Petitions: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

RG&E 2003 Electric and Gas Rate Proceeding: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

RG&E Electric Rate Unbundling: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Sale of Ginna Station and Relicensing: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

RG&E Transmission Project: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

FERC Standard Market Design: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Transmission Planning and Expansion and Generation Interconnection: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Manufactured Gas Plant Remediation Recovery: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Natural Gas Delivery Business

RG&E's natural gas delivery business consists of transporting, storing and distributing natural gas.

Natural Gas Supply Agreements: See Energy East's Item 7 - Natural Gas Delivery Business, for this discussion.

RG&E 2002 Electric and Gas Rate Proceeding : See Energy East's Item 7 - Electric Delivery Business, for this discussion.

RG&E 2003 Electric and Gas Rate Proceeding: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 7 - Electric Delivery Business, for this discussion.

Other Matters

Accounting Issues

Statement 150: See Energy East's Item 7 - Other Matters, Statement 150, for this discussion.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Contractual Obligations and Commercial Commitments

At December 31, 2003, RG&E's contractual obligations and commercial commitments are:

	Total	2004	2005	2006	2007	2008	After 2008
(Thousands)
Contractual  Obligations
Long-term debt	$826,511	-	-	-	-	$50,000	$776,511
Preferred stock	25,000	$1,250	$1,250	$1,250	$1,250	1,250	18,750
Operating  leases	29,567	4,090	4,120	4,150	4,195	4,195	8,817
NMP2 power  purchase  agreement	299,853	38,438	41,794	34,357	38,175	36,497	110,592
Capacity  contracts -  electric	6,580	1,860	1,860	1,860	1,000	-	-
Nuclear plant  obligations    Capital     expenditures    Nuclear fuel    Decommissioning    costs	112,956 53,973 117,753	6,817 4,600 21,753	10,592 15,022 24,000	9,051 15,404 24,000	19,987 9,000 24,000	43,909 9,947 24,000	22,600 -      -
Capacity  contracts -  natural gas	225,559	50,030	49,499	49,316	43,351	32,484	879
Pension and  other  postretirement  benefits(1)	729,369	49,260	50,485	53,659	56,336	62,360	457,269
Total Contractual  Obligations	$2,427,121	$178,098	$198,622	$193,047	$197,294	$264,642	$1,395,418
Other Commercial  Commitments
Lines of credit	$75,000	$75,000	-	-	-	-	-
Total Commercial  Commitments	$75,000	$75,000	-	-	-	-	-

(1) Amounts are through 2013 only.

RG&E and NYSEG have a joint revolving credit agreement in which they each covenant to maintain certain debt and earnings ratios. (See Note 6 to RG&E's Financial Statements.)

Critical Accounting Estimates

See Energy East's Item 7 - Critical Accounting Estimates for this discussion.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Investing and Financing Activities

Investing Activities: Capital spending totaled $110 million in 2003, $124 million in 2002 and $148 million in 2001, including nuclear fuel. Capital spending in all three years was financed primarily with internally generated funds and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements and governmental mandates.

Capital spending is projected to be $123 million in 2004, including nuclear fuel. It is expected to be paid for primarily with internally generated funds and will be primarily for the same purposes described above and merger integration. (See Note 8 to RG&E's Financial Statements.)

RG&E's pension plans generated pretax noncash pension income (net of amounts capitalized) of $18 million in 2003, compared to $21 million in 2002 and $23 million in 2001. The $3 million decrease in 2003 was due to significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute its pension liability (reduced from 7% to 6.5% as of December 31, 2002), and return on assets (reduced from 9% to 8.75% effective January 1, 2003). RG&E anticipates no funding requirements in 2004 and had no funding requirements in 2003 as total plan assets exceeded the projected benefit obligation. (See Note 12 to RG&E's Financial Statements.)

RG&E Financing Activities: In December 2003 RG&E and NYSEG renewed their joint $200 million 364-day revolving credit facility with certain banks. RG&E is permitted to borrow up to $75 million and NYSEG is permitted to borrow up to $150 million under the facility. RG&E had no amounts outstanding under this agreement during 2003 or 2002.

RG&E uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. RG&E had no such short-term debt outstanding at December 31, 2003 and 2002.

See Energy East's Item 7 - RG&E's Financing Activities, for more discussion.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Results of Operations

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Operating Revenues	$1,025,110	$992,940	$1,039,476	3%	(4%)
Operating Income	$120,826	$131,759	$169,749	(8%)	(22%)
Earnings Available for   Common Stock	$26,765	$46,367	$69,950	(42%)	(34%)

Earnings

Earnings for 2003 decreased $20 million. The recognition of the terms and conditions of the NYPSC rate order for RG&E, which became effective January 15, 2003, reduced earnings $30 million. That amount includes $26 million for excess electric earnings and related interest. (See RG&E 2002 Electric and Gas Rate Proceeding.) That decrease was partially offset by increases of $6 million primarily for higher natural gas deliveries because of colder winter weather in 2003 and $9 million due to a writedown of software development costs that reduced earnings in 2002.

Earnings for 2002 decreased $24 million primarily due to lower wholesale electric revenues of $16 million largely due to lower wholesale market prices, a $9 million writedown of software development costs that management determined to have no future economic value, an electric price reduction, effective July 1, 2001, that decreased earnings $8 million, and higher replacement power costs of $7 million due to a scheduled refueling outage at the Ginna nuclear plant. There was no refueling outage in 2001. Lower merger-related costs of $8 million and higher electric and natural gas deliveries of about $6 million due to warmer summer weather and a colder heating season increased earnings for 2002.

Other Items: Other operating expenses includes net periodic pension benefit income of $18 million in 2003, $21 million in 2002 and $23 million in 2001. Other operating expenses would have been $3 million lower for 2003 and $2 million lower for 2002 without those decreases in net periodic pension benefit income. Net periodic pension benefit income represented 60% of net income for 2003, 42% for 2002 and 32% for 2001.

Other deductions decreased $13 million in 2002 compared to 2001 primarily due to lower merger costs of $10 million. Other deductions increased $17 million in 2001 primarily due to higher merger costs of $14 million. (See Other (Income) and Other Deductions in Note 1 to RG&E's Financial Statements.)

Interest charges, net, increased $16 million in 2003 compared to 2002 primarily due to the effect of $21 million of interest expense related to the recognition of the terms and conditions of the NYPSC rate order for RG&E as discussed above.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Operating Results for the Electric Delivery Business

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Deliveries - Megawatt-hours   Retail   Wholesale	6,979 1,885	7,218 1,941	6,986 2,219	(3%) (3%)	3%  (13%)
Operating Revenues	$676,678	$705,982	$728,099	(4%)	(3%)
Operating Expenses	$596,501	$604,768	$594,419	(1%)	2%
Operating Income	$80,177	$101,214	$133,680	(21%)	(24%)

Operating Revenues: Operating revenues for 2003 decreased $29 million primarily due to lower deliveries because of cooler summer weather in 2003.

The $22 million decrease in operating revenues for 2002 was primarily due to lower wholesale revenues of $24 million largely due to lower market prices and a price reduction, effective July 1, 2001, that reduced revenues $12 million. Those decreases were partially offset by increased retail deliveries of $12 million due to warmer summer weather.

RG&E's electric revenues included $132 million in 2003, $120 million in 2002 and $107 million in 2001 related to energy sales to Energetix.

Operating Expenses: The $8million decrease in operating expenses for 2003 was primarily due to lower fuel costs as a result of decreased purchases of $30 million and a scheduled refueling at the Ginna nuclear plant that added $10 million to operating costs in 2002 and $10 million due to a writedown of software development costs that also increased operating costs in 2002. Those decreases were partially offset by the recognition of terms and conditions of the NYPSC rate order for RG&E, which became effective January 15, 2003, and increased operating expenses of $30 million, primarily for excess electric earnings. (See RG&E 2002 Electric and Gas Rate Proceeding.)

The $10 million increase in operating expenses for 2002 was primarily due to higher purchased power costs of $46 million as a result of electricity being purchased instead of generated due to the sale of NMP2 in November 2001 and replacement power that was needed during the scheduled refueling of the Ginna nuclear plant in 2002. There was no refueling outage in 2001. A $10 million writedown of software development costs that management determined to have no future economic value also contributed to the increase. Those increases were partially offset by a $20 million decrease in accelerated amortization associated with a NMP2 regulatory asset and a $21 million decrease in other operating expenses due to the sale of NMP2.

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Operating Results for the Natural Gas Delivery Business

	2003	2002	2001	2003 over 2002 Change	2002 over 2001 Change
(Thousands)
Retail Deliveries - Dekatherms	55,207	52,012	49,903	6%	4%
Operating Revenues	$348,432	$286,958	$311,377	21%	(8%)
Operating Expenses	$307,783	$256,413	$275,308	20%	(7%)
Operating Income	$40,649	$30,545	$36,069	33%	(15%)

Operating Revenues: The $61 million increase in operating revenues for 2003 was primarily due to higher retail deliveries of $22 million because of colder winter weather in 2003, gas cost recovery of $37 million associated with higher commodity market prices and a $5 million increase due to higher delivery prices collected from customers effective in March 2003.

The $24 million decrease in operating revenues for 2002 was primarily due to a $33 million decrease because of lower market prices of gas that are passed on to customers, partially offset by $9 million for higher retail deliveries primarily because of colder winter weather in the fourth quarter of 2002.

RG&E's natural gas revenues include $24 million in 2003, $19 million in 2002 and $22 million in 2001 for sales of natural gas to Energetix.

Operating Expenses: Operating expenses for 2003 increased $51 million primarily due to higher natural gas purchases including $15 million for higher retail deliveries because of colder weather this year and a $36 million increase in the cost of natural gas due to market conditions.

Operating expenses for 2002 decreased $19 million primarily due to a decrease in purchased natural gas of $26 million mainly due to lower natural gas prices, which was partially offset by a $4 million writedown of software development costs that management determined to have no future economic value.

Rochester Gas and Electric Corporation
Balance Sheets

December 31	2003	2002
(Thousands)
Assets
Current Assets
Cash and cash equivalents	$13,596	$86,385
Special deposits	3,706	2,841
Accounts receivable, net	131,514	126,227
Affiliate receivable	24,524	20,330
Fuel, at average cost	29,310	20,555
Materials and supplies, at average cost	7,016	6,467
Accumulated deferred income tax benefits, net	12,154	11,454
Prepayments and other current assets	13,232	35,324
Total Current Assets	235,052	309,583
Utility Plant, at Original Cost
Electric	2,060,980	1,935,778
Natural gas	522,409	515,829
Common	158,804	157,416
	2,742,193	2,609,023
Less accumulated depreciation	1,271,462	1,361,884
Net Utility Plant in Service	1,470,731	1,247,139
Construction work in progress	160,595	133,195
Total Utility Plant	1,631,326	1,380,334
Other Property and Investments, Net	274,619	226,373
Regulatory and Other Assets
Regulatory assets
Nuclear plant obligations	240,884	313,412
Unfunded future income taxes	50,265	52,058
Environmental remediation costs	11,475	11,290
Nonutility generator termination agreement	100,687	109,587
Asset retirement obligation	163,530	-
Other	174,998	163,655
Total regulatory assets	741,839	650,002
Other assets
Prepaid pension benefits	16,524	-
Other	61,470	66,104
Total other assets	77,994	66,104
Total Regulatory and Other Assets	819,833	716,106
Total Assets	$2,960,830	$2,632,396

The notes on pages 151 through 166 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Balance Sheets

December 31	2003	2002
(Thousands)
Liabilities
Current Liabilities
Current portion of preferred stock subject to mandatory    redemption requirements	$1,250	-
Current portion of long-term debt	-	$159,935
Accounts payable and accrued liabilities	70,560	67,787
Affiliate payable	6,916	7,365
Interest accrued	11,540	10,509
Taxes accrued	24,130	3,451
Other	29,642	40,523
Total Current Liabilities	144,038	289,570
Regulatory and Other Liabilities
Regulatory liabilities
Accrued removal obligation	185,472	168,845
Deferred income taxes	186,571	164,204
Other	46,173	56,617
Total regulatory liabilities	418,216	389,666
Other liabilities
Deferred income taxes	72,568	90,754
Nuclear waste disposal	104,095	102,745
Other postretirement benefits	71,956	65,983
Environmental remediation costs	22,356	22,356
Asset retirement obligation	436,096	-
Other	39,831	59,721
Total other liabilities	746,902	341,559
Total Regulatory and Other Liabilities	1,165,118	731,225
Preferred stock subject to mandatory redemption requirements	23,750	-
Other long-term debt	826,511	752,254
Total long-term debt	850,261	752,254
Total Liabilities	2,159,417	1,773,049
Commitments	-	-
Preferred Stock  Redeemable solely at the option of RG&E  Subject to mandatory redemption requirements	47,000  -	47,000  25,000
Common Stock Equity  Common stock ($5 par value, 50,000 shares authorized,    38,886 shares outstanding at December 31, 2003 and 2002)	194,429	194,429
Capital in excess of par value	556,190	555,889
Retained earnings	121,032	154,267
Treasury stock, at cost (4,379 shares at December 31, 2003    and 2002)	(117,238)	(117,238)
Total Common Stock Equity	754,413	787,347
Total Liabilities and Stockholder's Equity	$2,960,830	$2,632,396

The notes on pages 151 through 166 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Statements of Income

Year Ended December 31	2003	2002	2001
(Thousands)
Operating Revenues
Electric	$676,678	$705,982	$728,099
Natural Gas	348,432	286,958	311,377
Total Operating Revenues	1,025,110	992,940	1,039,476
Operating Expenses
Electricity purchased and fuel used     in generation	152,131	188,196	149,177
Natural gas purchased	210,605	159,170	184,690
Other operating expenses	293,948	264,930	279,549
Maintenance	59,654	56,757	55,950
Depreciation and amortization	105,901	102,758	112,643
Other taxes	82,045	89,370	87,718
Total Operating Expenses	904,284	861,181	869,727
Operating Income	120,826	131,759	169,749
Other (Income)	(5,267)	(15,950)	(14,808)
Other Deductions	2,441	6,184	19,572
Interest Charges, Net	75,947	59,838	62,416
Income Before Income Taxes	47,705	81,687	102,569
Income Taxes	18,065	31,620	28,919
Net Income	29,640	50,067	73,650
Preferred Stock Dividends	2,875	3,700	3,700
Earnings Available for Common Stock	$26,765	$46,367	$69,950

The notes on pages 151 through 166 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Statements of Cash Flows

Year Ended December 31	2003	2002	2001
(Thousands)
Operating Activities
Net income	$29,640	$50,067	$73,650
Adjustments to reconcile net income to net cash   provided by operating activities
Depreciation and amortization	178,589	164,833	165,248
Income taxes and investment tax credits deferred, net	2,502	(12,838)	(38,417)
Pension income	(17,616)	(21,025)	(23,332)
Writedown of investments	-	13,718	-
Accelerated amortization of NMP2 regulatory asset	-	-	20,000
Regulatory disallowance for excess earnings	44,051	-	-
Changes in current operating assets and liabilities
Accounts receivable, net	(6,364)	(3,410)	17,457
Inventory	(9,304)	5,227	9,834
Prepayments	13,643	(14,842)	(10,724)
Accounts payable and accrued liabilities	2,324	820	16,971
Interest accrued	1,031	(1,830)	-
Taxes accrued	20,679	(930)	(7,545)
Other current liabilities	(13,320)	(8,212)	(16,676)
Other assets	(60,551)	(39,561)	(18,097)
Other liabilities	15,214	18,622	26,894
Net Cash Provided by Operating Activities	200,518	150,639	215,263
Investing Activities
Utility plant additions	(101,453)	(122,788)	(152,292)
Sale of generation assets	-	50,484	52,416
Nuclear generating plant decommissioning fund	(17,362)	(17,362)	(20,736)
Other	(5,443)	(5,661)	(6,948)
Net Cash Used in Investing Activities	(124,258)	(95,327)	(127,560)
Financing Activities
Equity contribution from parent	-	50,000	-
Repayments of first mortgage bonds, including net premiums	(80,000)	(100,000)	(104,470)
Long-term debt issuances, net of discount or premiums	74,174	125,000	199,534
Repayment of promissory notes	(79,935)	(4,522)	(4,073)
Notes payable three months or less, net	-	-	(98,000)
Dividends on common and preferred stock	(63,288)	(58,867)	(65,971)
Other	-	-	191
Net Cash Used in Financing Activities	(149,049)	11,611	(72,789)
Net Increase (Decrease) in Cash and Cash Equivalents	(72,789)	66,923	14,914
Cash and Cash Equivalents, Beginning of Year	86,385	19,462	4,548
Cash and Cash Equivalents, End of Year	$13,596	$86,385	$19,462

The notes on pages 151 through 166 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Statements of Changes in Common Stock Equity

(Thousands)	Common Stock     Outstanding       $5 Par Value       Shares         Amount		Capital in Excess of Par Value	Retained Earnings	Treasury Stock	Total
Balance, January 1, 2001	38,886	$194,429	$505,889	$166,184	$(117,238)	$749,264
Net income				73,650		73,650
Dividends declared
Preferred stock				(3,700)		(3,700)
Common stock				(62,271)		(62,271)
Other adjustments				191		191
Balance, December 31, 2001	38,886	194,429	505,889	174,054	(117,238)	757,134
Net income				50,067		50,067
Equity contribution from parent			50,000			50,000
Dividends declared
Preferred stock				(3,700)		(3,700)
Common stock				(66,154)		(66,154)
Balance, December 31, 2002	38,886	194,429	555,889	154,267	(117,238)	787,347
Net income				29,640		29,640
Equity contribution from parent			301			301
Dividends declared
Preferred stock				(2,875)		(2,875)
Common stock				(60,000)		(60,000)
Balance, December 31, 2003	38,886	$194,429	$556,190	$121,032	$(117,238)	$754,413

The notes on pages 151 through 166 are an integral part of the financial statements.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Note 1. Significant Accounting Policies

Background: Rochester Gas and Electric Corporation (RG&E) is primarily engaged in electricity generation, transmission and distribution operations and natural gas transportation and distribution operations in western New York. RG&E is an operating utility subsidiary of RGS Energy Group, Inc. (RGS Energy). Effective June 28, 2002, RGS Energy became a wholly-owned subsidiary of Energy East Corporation. The acquisition was accounted for under the purchase method of accounting. RGS Energy did not push goodwill down to RG&E.

Accounts receivable: Accounts receivable include unbilled revenues of $50 million at December 31, 2003, and $59 million at December 31, 2002, and are shown net of an allowance for doubtful accounts of $27 million at December 31, 2003, and $31 million at December 31, 2002. Bad debt expense was $11 million in 2003, $9 million in 2002 and $5 million in 2001.

Statements of cash flows: RG&E considers all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and those investments are included in cash and cash equivalents.

Supplemental Disclosure of Cash Flows Information	2003	2002	2001
(Thousands) Cash paid during the year ended December 31:
Interest, net of amounts capitalized	$47,805	$58,145	$61,801
Income taxes, net of benefits received (2001includes    $19,780 related to a gain on sale of generation assets)	$(28,885)	$56,949	$79,025

Decommissioning expense: Other operating expenses include nuclear decommissioning expense accruals, which result in corresponding decreases in the regulatory asset for the asset retirement obligation. Contributions are made to the decommissioning trust funds, which are included in other property and investments. Increases in the fair value of fund investments also result in decreases in the regulatory asset for the asset retirement obligation.

Depreciation and amortization: RG&E determines depreciation expense using the straight-line method. The average service lives of certain classifications of property are: transmission property - 59 years, distribution property - 54 years, and other property - 21 years. RG&E determines depreciation expense for generation property using remaining service life rates, which include estimated cost of removal, based on operating license or anticipated closing dates. The remaining service lives of generation property range from six years for nuclear facilities to 32 years for hydroelectric facilities. RG&E's depreciation accruals were equivalent to 3.6% of average depreciable property for 2003, 3.7% for 2002 and 3.5% for 2001.

Estimates: Preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Income taxes: Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.

Notes to Financial Statements

Rochester Gas and Electric Corporation

RG&E computes its income tax provision on a separate return method. SEC regulations require that no Energy East subsidiary pay more income taxes than it would pay if a separate income tax return were to be filed. The determination and allocation of RG&E's income tax provision and its components is outlined and agreed to in the tax sharing agreement with Energy East.

Other (Income) and Other Deductions:

Year Ended December 31	2003	2002	2001
(Thousands)
Interest income	$(3,830)	$(4,377)	$(4,601)
Noncash return	-	(8,513)	(8,744)
Miscellaneous	(1,437)	(3,060)	(1,463)
Total other (income)	$(5,267)	$(15,950)	$(14,808)
Merger costs	-	$4,350	$13,901
Miscellaneous	$2,441	1,834	5,671
Total other deductions	$2,441	$6,184	$19,572

Reclassifications: Certain amounts have been reclassified on the financial statements to conform to the 2003 presentation.

Regulatory assets and liabilities: Pursuant to Statement 71, RG&E capitalizes, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.

Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Nuclear plant obligations, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with RG&E 's current rate plans. RG&E earns a return on substantially all regulatory assets for which funds have been spent.

Related party transactions: RG&E conducts certain transactions with Energetix, a subsidiary of RGS Energy. Transactions between RG&E and Energetix are primarily for the purchase of commodity and delivery services for both electricity and natural gas at tariff rates, and for related administrative services. The following table provides a summary of amounts included in RG&E's revenues for sales to Energetix (in millions):

Year Ended December 31	2003	2002	2001
Electric revenue	$132	$120	$107
Natural gas revenue	$24	$19	$22

RG&E's affiliate receivable from Energetix consists primarily of electric and natural gas services provided to Energetix's customers and for related administrative services.

Revenue recognition: RG&E recognizes revenues upon delivery of energy and energy-related products and services to its customers.

RG&E enters into power purchase and sales transactions with the NYISO. When electricity from owned generation is sold to the NYISO, and subsequently repurchased from the NYISO to serve its customers, the transactions are recorded on a net basis in the statements of income.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Risk management: RG&E has a purchased gas adjustment clause that allows it to recover through rates any changes in the market price of purchased natural gas, substantially eliminating its exposure to natural gas price risk. RG&E uses 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.

RG&E uses 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.

RG&E does not hold or issue financial instruments for trading or speculative purposes.

RG&E recognizes the fair value of its natural gas futures and forwards and financial electricity contracts as assets or liabilities. RG&E's derivative asset was $8 million at December 31, 2003, and $11 million at December 31, 2002, and its derivative liability was less than $1 million at December 31, 2003, and $4 million at December 31, 2002. All of the arrangements are designated as cash flow hedging instruments. RG&E defers the fair value of the hedging instruments as regulatory assets or regulatory liabilities.

As of December 31, 2003, the maximum length of time over which RG&E is hedging its exposure to the variability in future cash flows for forecasted transactions is 16 months.

RG&E has commodity purchase and sales contracts for both capacity and energy that have been designated and qualify for the normal purchases and normal sales exception in Statement 133, as amended.

Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability.

RG&E's adoption of Statement 143 as of January 1, 2003, did not have a material effect on its financial position or results of operations. There was no effect on net income. RG&E recognized various amounts on its balance sheets. Changes in the assumptions underlying the items shown in the following table could affect the balance sheet amounts and future costs related to the obligations.

As of January 1, 2003
(Thousands)
Asset retirement obligation	$(413,988)
Regulatory asset	$139,611
Regulatory liability	$(635)
Increase in utility plant	$74,064
Decrease in accumulated depreciation	$200,948

Notes to Financial Statements

Rochester Gas and Electric Corporation

Statement 143 provides that if the requirements of Statement 71 are met, a regulatory liability should be recognized for the difference between removal costs collected in rates and actual costs incurred. In previous years, those amounts were included in accumulated depreciation in accordance with industry practice. Accrued removal obligations totaling approximately $185 million as of December 31, 2003, and $169 million as of December 31, 2002, that had previously been embedded within accumulated depreciation, were reclassified as a regulatory liability.

Statement 150: In May 2003 the 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. In accordance with Statement 150, RG&E is required to classify its mandatorily redeemable preferred stock as a liability on its statements of financial position, which it had previously classified as equity, and to recognize as interest expense distributions that it had previously recognized as dividends. RG&E has $25 million of mandatorily redeemable preferred stock. RG&E adopted Statement 150 as of July 1, 2003. The adoption of Statement 150 did not have a material effect on RG&E's financial position or results of operations.

Utility plant: RG&E charges repairs and minor replacements to operating expense accounts, and capitalizes renewals and betterments, including certain indirect costs. The original cost of utility plant retired or otherwise disposed of is charged to accumulated depreciation.

Note 2. Restructuring

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. The employee positions affected by the restructuring were identified in the fourth quarter of 2002. Included in the amounts deferred by RG&E were $32 million for the voluntary early retirement program that will be paid from RG&E's pension plan and $4 million for the involuntary severance program, primarily for salaried employees. During 2003 RG&E's entire related involuntary severance liability of $4 million was paid and deferred for recovery.

The voluntary early retirement and involuntary severance programs resulted in a reduction in overall employee headcount of 253 in 2003.

Energy East has consolidated the accounting and finance functions of five of its operating companies to one location. In connection with this latest restructuring, in the fourth quarter of 2003 RG&E began to recognize an expected $1 million total liability for an enhanced severance program for certain accounting and finance employees who will be employed through March 31, 2004.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Note 3. Other Intangible Assets

RG&E amortizes intangible assets with finite lives (amortized intangible assets) and reviews them for impairment. RG&E has no goodwill or intangible assets with indefinite lives. RG&E's amortized intangible assets consisted of water rights and had a gross carrying amount of $3 million and accumulated amortization of about $2 million at December 31, 2003 and 2002. Estimated amortization expense for intangible assets is $78 thousand for each of the next five years, 2004 through 2008.

Note 4. Income Taxes

Year Ended December 31	2003	2002	2001
(Thousands)
Current	$15,563	$44,458	$67,336
Deferred, net     Accelerated depreciation	8,794	3,734	(101,161)
Pension benefits	9,817	8,373	8,396
Asset sale gain	(26,283)	(12,391)	75,709
Nuclear decommissioning	(4,785)	(4,785)	(4,717)
Statement 106 postretirement benefits	(2,274)	(2,418)	(1,810)
Ginna outage	-	1,501	(3,041)
Excess earnings accrual	4,725	-	(1,654)
Cost to achieve	(5,100)	-	-
Nonqualified decommissioning liability	(10,596)	(425)	374
Merger accrual		-	(1,826)
Cost of removal	418	202	2,726
Kamine amortization	30,679	1,373	2,249
Deferred competition implementation	-	-	(2,349)
GCA	-	-	797
Purchased software and internal development	(566)	(5,489)	5,035
Miscellaneous	(632)	(818)	(2,217)
ITC	(1,695)	(1,695)	(14,928)
Total	$18,065	$31,620	$28,919

RG&E's effective tax rate differed from the statutory rate of 35% due to the following:

Year Ended December 31	2003	2002	2001
(Thousands)
Tax expense at statutory rate	$16,697	$28,590	$35,899
Depreciation and amortization not normalized	5,224	3,210	4,820
ITC amortization	(1,695)	(1,695)	(14,928)
State taxes, net of federal benefit	1,835	4,762	4,876
Cost of removal not normalized	(2,679)	(2,005)	(1,269)
Audit settlement/reserve for disputed items	(4,088)	(2,032)	(2,334)
Deferral to equal rate base	(732)	567	(2,246)
Other, net	3,503	223	4,101
Total	$18,065	$31,620	$28,919

Notes to Financial Statements

Rochester Gas and Electric Corporation

RG&E's deferred tax liabilities consisted of the following:

December 31	2003	2002
(Thousands)
Current Deferred Tax Assets	$12,154	$11,454
Noncurrent Deferred Tax Liabilities
Depreciation	$176,102	$148,713
Unfunded future income taxes	50,266	52,058
Accumulated deferred ITC	15,301	16,996
Deferred loss on generation plant sale	84,652	123,480
Nuclear decommissioning	(49,681)	(44,093)
Statement 106 postretirement benefits	(26,014)	(23,866)
Excess earnings accrual	(5,802)	(10,553)
Pension	17,517	6,476
Gas demand charges	(3,028)	(3,449)
Site remediation	(2,852)	(2,848)
Statement 112 postemployment benefits	(3,051)	(2,677)
NMP2 outage deferred accounting	(2,951)	(4,782)
Other	8,680	(497)
Total Noncurrent Deferred Tax Liabilities	259,139	254,958
Less amounts classified as regulatory liabilities
Deferred income taxes	186,571	164,204
Noncurrent Deferred Income Taxes	$72,568	$90,754

RG&E has no federal or state tax credit or loss carryforwards, and no valuation allowances.

Note 5. Long-term Debt

Preferred stock subject to mandatory redemption requirements: RG&E's preferred stock subject to mandatory redemption requirements is its 6.60% Series V, Par Value $100, with a redemption price per share of $100 and 250,000 shares authorized and outstanding. This series is subject to a mandatory sinking fund sufficient to redeem, at par, on March 1 of each year from 2004 through 2008, 12,500 shares, and on March 1, 2009, the balance of the shares. RG&E has the option to redeem up to an additional 12,500 shares on the same terms and dates as applicable to the mandatory sinking fund. In the event RG&E should be in arrears in the sinking fund requirement, RG&E may not redeem or pay dividends on any stock subordinate to the preferred stock.

Voting rights: If preferred stock dividends on this series of preferred stock are in default in an amount equivalent to four full quarterly dividends, the holders of the preferred stock are entitled to elect a majority of RG&E's directors and their privilege continues until all dividends in default have been paid. The holders of preferred stock are not entitled to vote in respect of any other matters except those, if any, in respect of which voting rights cannot be denied or waived under some mandatory provision of law, and except that RG&E's charter contains provisions to the effect that such holders shall be entitled to vote on certain matters affecting the rights and preferences of the preferred stock.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Whenever holders of preferred stock shall be entitled to vote, they shall be entitled to cast one vote for each share of preferred stock held by them. Holders of RG&E common stock are entitled to one vote per share on all matters.

Other long-term Debt: At December 31, 2003 and 2002, RG&E's other long-term debt was:

			Amount
	Maturity Dates	Interest Rates	2003	2002
(Thousands)
First mortgage bonds (1)	2008 to 2033	5.84% to 7.67%	$700,500	$705,500
Pollution control securities - fixed	2033	5.95%	25,500	25,500
Pollution control notes - variable	2032	0.95% to 1.00%	101,900	101,900
Various long-term debt	-	-	-	79,935
Unamortized discount on debt			(1,389)	(646)
			826,511	912,189
Less debt due within one year, included in current liabilities			-	159,935
Total			$826,511	$752,254

(1) RG&E's first mortgage bonds are secured by a first mortgage lien on substantially all of its properties. RG&E has no other secured indebtedness. None of RG&E's other debt obligations are guaranteed or secured by any of its affiliates.

At December 31, 2003, other long-term debt, including sinking fund obligations (in thousands), that will become due during the next five years are:

2004	2005	2006	2007	2008
-	-	-	-	$50,000

Cross-default Provision: RG&E has a provision in a participation agreement relating to certain series of pollution control bonds, which provides that default by RG&E with respect to bonds issued under its first mortgage indenture will be considered a default under the participation agreement.

Note 6. Bank Loans and Other Borrowings

RG&E uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. RG&E had no such short-term debt outstanding at December 31, 2003 or 2002.

RG&E and NYSEG have a joint $200 million 364-day revolving credit facility with certain banks, which they renewed in December 2003. RG&E is permitted to borrow up to $75 million under the facility. At RG&E's and NYSEG's option, the interest rate on borrowings is related to the prime rate or the Eurodollar rate. The agreement provides for payment of a commitment fee, which was .15% at December 31, 2003 and 2002. RG&E had no amounts outstanding under this agreement during 2003 or 2002.

In their joint revolving credit agreement RG&E and NYSEG each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2003, RG&E's ratio of earnings before interest expense and income tax to interest expense was 1.9 to 1.0, and its ratio of total indebtedness to total capitalization was 0.50 to 1.00.

Note 7. Preferred Stock Redeemable Solely at the Option of RG&E

At December 31, 2003 and 2002, RG&E 's serial cumulative preferred stock was:

Series	Par Value Per Share	Redemption Price Per Share	Shares Authorized and Outstanding(1)	Amount (Thousands)   2003              2002
4% F	$100	$105.00	120,000	$12,000	$12,000
4.10% H	100	101.00	80,000	8,000	8,000
4.75% I	100	101.00	60,000	6,000	6,000
4.10% J	100	102.50	50,000	5,000	5,000
4.95% K	100	102.00	60,000	6,000	6,000
4.55% M	100	101.00	100,000	10,000	10,000
Total				$47,000	$47,000

(1) At December 31, 2003, RG&E had 1,280,000 shares of $100 par value cumulative preferred stock, 4,000,000 shares of $25 par value cumulative preferred stock and 5,000,000 shares of $1 par value preference stock authorized but unissued.

RG&E had no redemptions or purchases of preferred stock during the three years 2001 through 2003.

Voting rights: If preferred stock dividends on any series of preferred stock are in default in an amount equivalent to four full quarterly dividends, the holders of the preferred stock are entitled to elect a majority of RG&E's directors and their privilege continues until all dividends in default have been paid. The holders of preferred stock are not entitled to vote in respect of any other matters except those, if any, in respect of which voting rights cannot be denied or waived under some mandatory provision of law, and except that RG&E's charter contains provisions to the effect that such holders shall be entitled to vote on certain matters affecting the rights and preferences of the preferred stock.

Whenever holders of preferred stock shall be entitled to vote, they shall be entitled to cast one vote for each share of preferred stock held by them. Holders of RG&E common stock are entitled to one vote per share on all matters.

Note 8. Commitments

Capital spending: RG&E has commitments in connection with its capital spending program. Capital spending is projected to be $123 million in 2004, including nuclear fuel, and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. RG&E 's capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Note 9. Nuclear Generation Assets, Insurance and Decommissioning

Sale of Nine Mile Point 2: In November 2001 RG&E sold its 14% interest in NMP2 to Constellation Nuclear. RG&E's 14% share of NMP2's operating expenses until it was sold is included in various categories on the statements of income.

In October 2001 the NYPSC issued an order approving the sale of NMP2, which provided for the establishment of a regulatory asset of approximately $326 million at the time of closing. RG&E agreed to a one-time $20 million pretax accelerated amortization of the regulatory asset that was recorded in the third quarter of 2001. In addition, RG&E accelerated its recognition of approximately $13 million of previously deferred investment tax credits. RG&E also agreed to amortize the regulatory asset by an additional $30 million per year during the period from the closing of the sale of NMP2 until RG&E's base electric rates are reset. The $30 million annual amortization reflects RG&E's projected savings for its share of NMP2 operating expenses compared to the estimated cost of electricity purchases to replace RG&E's presale share of the output. The terms associated with the recovery of the remaining regulatory asset will be established in future RG&E rate proceedings. The settlement further provides that it constitutes a final and irrevocable resolution of all RG&E ratemaking issues associated with the sale of NMP2 and RG&E's ability to recover through rates the costs associated with its investment in NMP2.

RG&E's pre-existing decommissioning funds for NMP2 were transferred to Constellation, which has taken responsibility for all future decommissioning funding.

The transaction included a power purchase agreement that calls for Constellation to provide electricity to RG&E, at fixed prices, for 10 years. The power purchase agreement is a contract for physical delivery of RG&E's 14% share of 90% of the output from NMP2. RG&E records expenses for electricity purchased in accordance with the agreement at the time the power is physically delivered, at prices pursuant to the agreement. The contract is not required to be marked-to-market and is not considered to be a derivative instrument because it qualifies for the normal purchases and normal sales exception in Statement 133, as amended.

After the power purchase agreement is completed a revenue sharing agreement will begin. The revenue sharing agreement could provide additional revenue to RG&E through 2021, which would mitigate increases in electricity prices. Both agreements are based on plant output. No amounts were recorded under the revenue sharing agreement in 2002 or 2003 because any benefit that may occur between 2011 and 2021 cannot be estimated. Any benefits from the revenue sharing agreement will be deferred for customers.

Sale of Ginna Station: 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 which 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. RG&E is unable to predict the outcome of this proceeding.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Nuclear insurance: The Price-Anderson Act is a federal statute providing, among other things, a limit on the maximum liability of nuclear reactor owners for damages resulting from a single nuclear incident. The public liability limit for a nuclear incident is approximately $10.9 billion and is subject to inflation and changes in the number of licensed reactors. RG&E carries the maximum available commercial insurance of $300 million and participates in the mandatory financial protection pool for the remaining $10.6 billion. Under the Price-Anderson Act, RG&E would be liable for up to $101 million per incident payable at a rate not to exceed $10 million per incident per year.

In addition to the insurance required by the Price-Anderson Act, RG&E also carries nuclear property damage insurance and accidental outage insurance through Nuclear Electric Insurance Limited. Under those insurance policies, RG&E could be subject to assessments if losses exceed the accumulated funds available to the insurers. The maximum amounts of the assessments for the current policy year are $13 million for nuclear property damage insurance and $4 million for accidental outage insurance.

Nuclear plant decommissioning costs: RG&E's estimated liability, in 2004 dollars, for decommissioning Ginna, including spent fuel storage, is $421 million. The amount currently accrued for those costs is recovered by RG&E through its electric rates.

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 NRC's 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 to ensure that RG&E's customers continue to receive the benefit of power from Ginna.

Note 10. Environmental Liability

From time to time environmental laws, regulations and compliance programs may require changes in RG&E's operations and facilities and may increase the cost of electric and natural gas service.

The U.S. Environmental Protection Agency and various state environmental agencies, as appropriate, notified RG&E that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at four waste sites. The four sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the four sites, two sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites and two of the sites are also included on the National Priorities List.

Any liability may be joint and several for certain of those sites. RG&E has recorded an estimated liability of less than $1 million related to the four sites. An estimated liability of $3 million has been recorded related to nine sites where RG&E believes it is probable that it will incur remediation costs, although it has not been notified that it is among the potentially responsible parties. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to RG&E.

Notes to Financial Statements

Rochester Gas and Electric Corporation

RG&E has a program to investigate and perform necessary remediation at its eight sites where gas was manufactured in the past. All eight sites are included in the New York Voluntary Clean-up Program.

RG&E's estimate for all costs related to investigation and remediation of six of the eight sites ranges from $14 million to $32 million at December 31, 2003. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations. No estimate has yet been made for the two remaining sites, which are not owned by RG&E, because sufficient information upon which to base an estimate is not available.

The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites was $19 million at December 31, 2003 and 2002.

RG&E's environmental liability accruals, which are expected to be paid within the next 14 years, have been established on an undiscounted basis. RG&E received insurance settlements during the last three years, which it accounted for as reductions in its related regulatory asset.

Note 11. Fair Value of Financial Instruments

The carrying amounts and estimated fair values of RG&E 's financial instruments included on its balance sheets are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.

December 31	2003		2002
	Carrying Amount	Estimated Fair Value	Carrying Amount	Estimated Fair Value
(Thousands)
Investments - classified as   available-for-sale	$287,118	$287,118	$239,570	$239,570
Preferred stock subject to mandatory   redemption requirements	$25,000	$25,000	-	-
First mortgage bonds	$699,111	$764,135	$704,854	$761,839
Pollution control notes - fixed	$25,500	$27,540	$25,500	$24,990
Pollution control notes - variable	$101,900	$101,900	$101,900	$101,900
Long-term notes	-	-	$79,935	$91,166

The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values. Substantially all of the investments classified as held for sale represent decommissioning trust funds for Ginna. In December 2003 these funds were converted to short-term, highly liquid investments in preparation for the sale of Ginna.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Note 12. Retirement Benefits

	Pension Benefits		Postretirement Benefits
	2003	2002	2003	2002
(Thousands)
Change in benefit obligation
Benefit obligation at January 1	$553,301	$494,433	$99,857	$91,988
Service cost	6,285	7,161	1,168	1,152
Interest cost	32,345	33,769	6,247	6,200
Plan amendments	(638)	2,089	-	2,940
Actuarial loss	3,167	24,997	(139)	2,738
Special termination benefits	-	32,086	-	-
Benefits paid	(46,838)	(41,234)	(4,990)	(5,161)
Benefit obligation at December 31	$547,622	$553,301	$102,143	$99,857
Change in plan assets
Fair value of plan assets at January 1	526,324	$645,375	-	-
Actual return on plan assets	128,338	(77,817)	-	-
Employer contributions	-	-	$4,991	$5,161
Benefits paid	(46,838)	(41,234)	(4,991)	(5,161)
Fair value of plan assets at December 31	$607,824	$526,324	-	-
Funded status	$60,202	$(26,977)	$(102,143)	$(99,857)
Unrecognized net actuarial loss (gain)	(59,100)	6,531	(660)	(797)
Unrecognized prior service cost	15,422	17,522	10,965	12,304
Unrecognized net transition obligation	-	-	19,882	22,367
Prepaid (accrued) benefit cost	$16,524	$(2,924)	$(71,956)	$(65,983)

RG&E uses a December 31 measurement date for its pension and postretirement benefit plans.

RG&E's accumulated benefit obligation for all defined benefit pension plans was $468 million at December 31, 2003, and $493 million at December 31, 2002.

RG&E's postretirement benefits were unfunded as of December 31, 2003 and 2002.

Weighted-average assumptions used to determine benefit obligations at	Pension Benefits		Postretirement Benefits
December 31	2003	2002	2003	2002
Discount rate	6.25%	6.50%	6.25%	6.50%
Rate of compensation increase	4.00%	4.00%	N/A	N/A

As of December 31, 2003, RG&E decreased its discount rate from 6.5% to 6.25%.

Notes to Financial Statements

Rochester Gas and Electric Corporation

	Pension Benefits			Postretirement Benefits
	2003	2002	2001	2003	2002	2001
(Thousands)
Components of net periodic benefit cost
Service cost	$6,285	$7,161	$6,652	$1,168	$1,153	$1,019
Interest cost	32,345	33,769	33,717	6,248	6,200	6,145
Expected return on plan assets	(51,292)	(56,589)	(55,985)	-	-	-
Unrecognized transition obligation	-	-	-	2,485	2,485	2,485
Amortization of prior service cost	1,462	1,548	1,406	1,339	1,068	1,068
Recognized net actuarial gain	(8,248)	(8,704)	(10,768)	(276)	-	-
Special termination benefits	-	-	-	-	-	-
Deferral for future recovery	-	-	-	-	-	-
Net periodic benefit cost	$(19,448)	$(22,815)	$(24,978)	$10,964	$10,906	$10,717

Net periodic benefit cost is included in other operating expenses. The net periodic benefit cost for postretirement benefits represents the cost RG&E charged to expense for providing health care benefits to retirees and their eligible dependents. RG&E expects to recover any costs related to the transition obligation by 2011. The transition obligation for postretirement benefits is being recognized over a period of 20 years.

Weighted-average assumptions used    to determine net periodic benefit cost	Pension Benefits			Postretirement Benefits
Year ended December 31	2003	2002	2001	2003	2002	2001
Discount rate	6.50%	7.00%	7.25%	6.50%	7.00%	7.25%
Expected return on plan assets	8.75%	8.50%	9.00%	N/A	N/A	N/A
Rate of compensation increase	4.00%	5.00%	4.00%	N/A	N/A	N/A

RG&E's expected rate of return on plan assets assumption was developed based on a review of historical returns for the major asset classes. This analysis also considered both current capital market conditions and projected future conditions. Given the current low interest rate environment, RG&E selected an assumption of 8.75% per year, which is lower than the rate otherwise determined solely based on historical returns.

RG&E assumed a 10.0% annual rate of increase in the per capita cost of covered health care benefits for 2004 that gradually decreases to 5.0% by the year 2007. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase	1% Decrease
Effect on total of service and interest cost components	$3 thousand	$(5 thousand)
Effect on postretirement benefit obligation	$32 thousand	$(47 thousand)

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

Notes to Financial Statements

Rochester Gas and Electric Corporation

In accordance with FASB Staff Position No. FAS 106-1, any measures of the APBO or net periodic postretirement benefit cost in the financial statements or accompanying notes do not reflect the effects of the Act on the plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the sponsor to change previously reported information. Moreover, the issues of how and when the federal subsidy should be accounted for are not yet resolved by the FASB. Energy East has not yet determined the potential effects of the Act on its future postretirement costs, including the participation rates in its benefit plans, nor whether any amendments to its benefit plans are appropriate given the Act.

RG&E's weighted-average asset allocations at December 31, 2003 and 2002, by asset category are:

	Pension Benefits
Asset Category	Target Allocation	2003	2002
Equity securities	60%	64%	59%
Debt securities	30%	34%	41%
Real estate	5%	-	-
Other	5%	2%	-
Total	100%	100%	100%

RG&E's pension plan assets are held in a master trust with a trustee and are invested among and within various asset classes in order to achieve sufficient diversification in accordance with RG&E's risk tolerance. This is achieved through the utilization of multiple asset managers and systematic allocation to investment management styles, providing a broad exposure to different segments of the fixed income and equity markets.

Equity securities included no Energy East common stock as of December 31, 2003 and 2002.

As of December 31, 2002, the projected benefit obligation exceeded the fair value of pension plan assets for RG&E. The following table shows the projected and accumulated benefit obligations and the fair value of plan assets for RG&E as of that date.

	Projected Benefit Obligation Exceeds Fair Value of Plan Assets
December 31	2002
(Thousands)
Projected benefit obligation	$553,301
Accumulated benefit obligation	493,098
Fair value of plan assets	526,324

RG&E does not anticipate any contributions to its pension plans in 2004.

Notes to Financial Statements

Rochester Gas and Electric Corporation

Expected benefit payments, which reflect expected future service, as appropriate, are as follows:

	Pension Benefits	Postretirement Benefits
(Thousands)
2004	$40,192	$9,068
2005	40,833	9,652
2006	43,476	10,183
2007	45,605	10,731
2008	51,078	11,282
2009 - 2013	390,783	66,486

Note 13. Segment Information

Selected financial information for RG&E's business segments is presented in the table below. RG&E's electric delivery segment consists of its regulated transmission, distribution and generation operations. Its natural gas delivery segment consists of its regulated transportation, storage and distribution operations. Other includes RG&E's corporate assets.

	Electric Delivery	Natural Gas Delivery	Other	Total
(Thousands)
2003
Operating Revenues	$676,678	$348,432	-	$1,025,110
Depreciation and Amortization	$88,822	$17,079	-	$105,901
Operating Income	$80,177	$40,649	-	$120,826
Interest Charges, Net	$65,011	$10,936	-	$75,947
Income Taxes	$3,206	$14,859	-	$18,065
Earnings Available for Common Stock	$12,138	$14,627	-	$26,765
Total Assets	$2,288,175	$590,555	$82,100	$2,960,830
Capital Spending	$80,222	$29,725	-	$109,947
2002
Operating Revenues	$705,982	$286,958	-	$992,940
Depreciation and Amortization	$87,817	$14,941	-	$102,758
Operating Income	$101,214	$30,545	-	$131,759
Interest Charges, Net	$49,459	$10,379	-	$59,838
Income Taxes	$24,169	$7,451	-	$31,620
Earnings Available for   Common Stock	$34,656	$11,711	-	$46,367
Total Assets	$1,925,473	$556,823	$150,100	$2,632,396
Capital Spending	$91,700	$31,891	-	$123,591
2001
Operating Revenues	$728,099	$311,377	-	$1,039,476
Depreciation and Amortization	$99,979	$12,664	-	$112,643
Operating Income	$133,680	$36,069	-	$169,749
Interest Charges, Net	$51,102	$11,314	-	$62,416
Income Taxes	$20,501	$8,418	-	$28,919
Earnings Available for   Common Stock	$57,338	$12,612	-	$69,950
Total Assets	$1,846,641	$475,681	$130,685	$2,453,007
Capital Spending	$103,801	$43,838	-	$147,639

Notes to Financial Statements

Rochester Gas and Electric Corporation

Note 14. Quarterly Financial Information (Unaudited)

Quarter Ended	March 31	June 30	September 30	December 31
(Thousands)
2003
Operating Revenues	$326,694	$228,612	$203,638	$266,166
Operating Income (Loss)	$31,081	$37,034	$15,172	$37,539
Net Income (Loss)	$1,490	$14,673	$(2,861)	$16,338
Earnings (Loss) Available for   Common Stock	$565	$13,748	$(3,374)	$15,826
2002
Operating Revenues	$278,290	$218,807	$231,368	$264,475
Operating Income (Loss)	$45,241	$(2,865)	$35,422	$53,961
Net Income (Loss)	$20,728	$(17,009)	$17,287	$29,061
Earnings (Loss) Available for   Common Stock	$19,803	$(17,934)	$16,362	$28,136

Report of Independent Auditors

To the Shareholder and Board of Directors,
Rochester Gas and Electric Corporation

In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) on page 170 present fairly, in all material respects, the financial position of Rochester Gas and Electric Corporation ("the Company") at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing in Item 15(a)(2) on page 170presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, and effective July 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.

PricewaterhouseCoopers LLP

New York, New York
January 30, 2004

ROCHESTER GAS AND ELECTRIC CORPORATION

SCHEDULE II - Valuation and Qualifying Accounts

Years Ended December 31, 2003, 2002 and 2001

Classification	Beginning of Year	Additions	Write-offs	Adjustments	End of Year
(Thousands)
2003   Allowance for Doubtful     Accounts - Accounts     Receivable	$31,182	$11,310	$(11,310)	$(4,000)	$27,182
2002   Allowance for Doubtful     Accounts - Accounts     Receivable	$29,482	$8,803	$(8,803)	$1,700	$31,182
2001   Allowance for Doubtful     Accounts - Accounts     Receivable	$33,482	$5,476	$(9,476)	-	$29,482

PART III

Item 10.  Directors and executive officers of the Registrants

Incorporated herein by reference to the information under the captions "Corporate Governance," "Committees," "Election of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in Energy East's Proxy Statement, which will be filed with the Commission on or before April 29, 2004.

Information regarding Directors and compliance with Section 16(a) of the Securities Exchange Act of 1934 for CMP is set forth in CMP's Exhibit 99-1, for NYSEG is set forth in NYSEG's Exhibit 99-1 and for RG&E is set forth in RG&E's Exhibit 99-1.

Information regarding executive officers of the registrants is on pages 12 and 13 of this report.

Item 11.  Executive compensation

Incorporated herein by reference to the information under the captions "Stock Performance Graph," "Executive Compensation," "Pension Plan Table," "Employment, Change in Control and Other Arrangements," "Directors' Compensation" and "Report of Compensation and Management Succession Committee" in Energy East's Proxy Statement, which will be filed with the Commission on or before April 29, 2004.

Information regarding executive compensation for CMP is set forth in CMP's Exhibit 99-1, for NYSEG is set forth in NYSEG's Exhibit 99 -1and for RG&E is set forth in RG&E's Exhibit 99-1.

Item 12.  Security ownership of certain beneficial owners and management

Incorporated herein by reference to the information under the captions "Security Ownership of Certain Beneficial Owners and Management" and "Equity Compensation Plan Information" in Energy East's Proxy Statement, which will be filed with the Commission on or before April 29, 2004.

CMP Group, a wholly-owned subsidiary of Energy East, is the beneficial owner of 100% of CMP's common stock. Information regarding ownership of equity securities of Energy East is set forth in CMP's Exhibit 99-1.

RGS Energy, a wholly-owned subsidiary of Energy East, is the beneficial owner of 100% of NYSEG's common stock and 100% of RG&E's common stock. Information regarding ownership of equity securities of Energy East is set forth in NYSEG's Exhibit 99-1 and in RG&E's Exhibit 99-1.

Item 13.  Certain relationships and related transactions

Incorporated herein by reference to the information under the caption "Election of Directors"
in Energy East's Proxy Statement, which will be filed with the Commission on or before April 29, 2004.

None for CMP, NYSEG or RG&E.

Item 14.  Principal accountant fees and services

Incorporated herein by reference to the information under the captions "Independent Accountants," "Audit Fees," "Audit Related Fees," "Tax Fees" and "All Other Fees" in Energy East's Proxy Statement, which will be filed with the Commission on or before April 29, 2004. Information regarding "Audit Fees", "Audit Related Fees", "Tax Fees" and "All Other Fees" for CMP is set forth in CMP's Exhibit 99-1, for NYSEG in NYSEG's Exhibit 99-1 and for RG&E in RG&E's Exhibit 99-1.

PART IV

Item 15.  Exhibits, financial statement schedule, and reports on Form 8-K
(a)  The following documents are filed as part of this report for Energy East and CMP:

(1) Financial statements      Included in Part II of this report:
a)	Consolidated Balance Sheets as of December 31, 2003 and 2002
b)	For the three years ended December 31, 2003:
	Consolidated Statements of Income
	Consolidated Statements of Cash Flows
	Consolidated Statements of Changes in Common Stock Equity
c)	Notes to Consolidated Financial Statements
d)	Report of Independent Auditors
(2) Financial statement schedule      Included in Part II of this report:
For the three years ended December 31, 2003
	II. Consolidated Valuation and Qualifying Accounts

(a)  The following documents are filed as part of this report for NYSEG and RG&E:

(1) Financial statements      Included in Part II of this report:
a)	Balance Sheets as of December 31, 2003 and 2002
b)	For the three years ended December 31, 2003:
	Statements of Income
	Statements of Cash Flows
	Statements of Changes in Common Stock Equity
c)	Notes to Financial Statements
d)	Report of Independent Auditors
(2) Financial statement schedule      Included in Part II of this report:
For the three years ended December 31, 2003
	II. Valuation and Qualifying Accounts

Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the Consolidated Financial Statements, Financial Statements or notes thereto.

Exhibits

(a)(1)   The following exhibits are delivered with this report:

Registrant	Exhibit No.	Description
Energy East Corporation	(A)10-9 -	Deferred Compensation Plan for Eligible Employees, effective January 1, 2004.
	12-1 -	Computation of Ratio of Earnings to Fixed Charges.
	12-2 -	Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends.
	21 -	Subsidiaries.
	23 -	Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32 -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Central Maine Power Company	21 -	Subsidiaries.
	23 -	Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32 -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
	99-1 -	Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, security ownership of management, code of ethics and audit fees.
New York State Electric   & Gas Corporation	23 -	Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32 -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
	99-1 -	Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, security ownership of management, code of ethics and audit fees.
Rochester Gas and Electric   Corporation	10-7 -	Asset Purchase Agreement by and among Rochester Gas and Electric Corporation, Constellation Generation Group, LLC and Constellation Energy Group, Inc. dated as of November 24, 2003.
	23 -	Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32 -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Registrant	Exhibit No.	Description
Rochester Gas and Electric   Corporation	99-1 -	Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, security ownership of management, code of ethics and audit fees.

(a)(2)    The following exhibits are incorporated herein by reference:

Registrant	Exhibit No.	Filed in	As Exhibit No.
Energy East Corporation	3-1 -	Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on April 23, 1998 - Post-effective Amendment No.1 to Registration No. 033-54155	4-1
	3-2 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on April 26, 1999 - Company's 10-Q for the quarter ended March 31, 1999 - File No. 1-14766	3-3
	3-3 -	By-Laws of the Company as amended April 12, 2001 - Company's 10-Q for the quarter ended March 31, 2001 - File No. 1-14766	3-4
	4-1 -	Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of August 31, 2000 - Company's 10-Q for the quarter ended September 30, 2000 - File No. 1-14766	4-1
	4-2 -	Third Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of November 14, 2000 related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000 - Company's 10-K for the year ended December 31, 2000 - File No. 1-14766	4-3
	4-3 -	Fourth Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of November 14, 2001, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000 - Company's 10-K for the year ended December 31, 2001 - File No. 1-14766	4-4

Registrant	Exhibit No.	Filed in	As Exhibit No.
Energy East Corporation	4-4 -	Sixth Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of June 14, 2002, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-14766	4-6
	4-5 -	Seventh Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of September 9, 2003, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000 - Company's 10-Q for the quarter ended September 30, 2003 - File No. 1-14766	4-9
	4-6 -	Subordinated Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of July 24, 2001 - Company's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766	4-4
	4-7 -	First Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of July 24, 2001, related to the Subordinated Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of July 24, 2001 - Company's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766	4-5
	(A)10-1 -	Deferred Compensation Plan for Directors - Company's 10-Q for the quarter ended September 30, 2000 - File No. 1-14766	10-40
	(A)10-2 -	Amended and Restated Director Share Plan - Company's 10-Q for the quarter ended September 30, 2000 - File No. 1-14766	10-38
	(A)10-3 -	Deferred Compensation Plan - Director Share Plan - Company's 10-Q for the quarter ended September 30, 2000 - File No. 1-14766	10-39
	(A)10-4 -	Supplemental Executive Retirement Plan - Company's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766	10-33
	(A)10-5 -	Supplemental Executive Retirement Plan Amendment No. 1 - Company's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-5
	(A)10-6 -	Annual Executive Incentive Plan - Company's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-8

Registrant	Exhibit No.	Filed in	As Exhibit No.
Energy East Corporation	(A)10-7 -	Annual Executive Incentive Plan Amendment No. 1 - Company's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-9
	(A)10-8 -	Annual Executive Incentive Plan Amendment No. 2 - Company's 10-Q for the quarter ended June 30, 2001 - File No. 1-14766	10-28
	(A)10-10 -	Employment Agreement dated February 8, 2002, for W. W. von Schack - Company's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-14
	(A)10-11 -	Employment Agreement dated February 8, 2002, for K. M. Jasinski - Company's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-15
	(A)10-12 -	Restricted Stock Plan - Company's 10-K for the year ended December 31, 1998 - File No. 1-14766	10-36
	(A)10-13 -	Restricted Stock Plan Amendment No. 1 - Company's 10-K for the year ended December 31, 2002 - File No. 1-14766	10-16
	(A)10-14 -	Form of Restricted Stock Award Grant - Company's 10-K for the year ended December 31, 2002 - File No. 1-14766	10-17
	(A)10-15 -	Amended and Restated 2000 Stock Option Plan, effective October 15, 2003 - Company's 10-Q for the quarter ended September 30, 2003 - File No. 1-14766	10-27
	(A)10-16 -	Award Agreement under the 2000 Stock Option Plan - Company's 10-Q for the quarter ended June 30, 2000 - File No. 1-14766	10-37
	(A)10-17 -	Award Agreement (February 2001) under the 2000 Stock Option Plan - Company's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-27
	(A)10-18 -	Director's Charitable Giving Program - Company's 10-Q for the quarter ended June 30, 2003 - File No. 1-14766	10-25
	(A)10-19 -	Energy East Management Corporation Form of Change In Control Agreement - Company's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-23
	(A)10-20 -	Energy East Management Corporation Form of Employee Invention and Confidentiality Agreement - Company's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-24
Central Maine Power Company	3-1 -	Articles of Incorporation, as amended - Company's 10-K for the year ended December 31, 1992 - File No. 1-5139	3-1
	3-2 -	Articles of Amendment to the Articles of Incorporation - Company's 10-K for the year ended December 31, 2000 - File No. 1-5139	3-1.2
	3-3 -	Amended and Restated By-Laws - Company's 10-Q for the quarter ended June 30, 2001 - File No. 1-5139	3-2

Registrant	Exhibit No.	Filed in	As Exhibit No.
Central Maine Power Company	4-1 -	Indenture, dated as of August 1, 1989, between the Company and The Bank of New York, as Trustee, relating to the Medium- Term Notes - Registration No. 33-29626	4.1
	4-2 -	Fifth Supplemental Indenture dated as of May 18, 2000, relating to the Medium-Term Notes, Series E, and supplementing the Indenture dated as of August 1, 1989, between the Company and The Bank of New York, as Trustee - Registration No. 333-36456	4-6
	10-1 -	Stockholder Agreement dated as of May 20, 1968 among the Company and the other stockholders of Maine Yankee Atomic Power Company - Registration No. 2-32333	4.30
	10-2 -	Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Registration No. 2-32333	4.31
	10-3 -	Amendment No. 1 dated as of March 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554	10-1.1
	10-4 -	Amendment No. 2 dated as of January 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554	10-1.2
	10-5 -	Amendment No. 3 dated as of October 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554	10-1.3
	10-6 -	Additional Power Contract between the Company and Maine Yankee Atomic Power Company dated as of February 1, 1984 - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554	10-1.4
	10-7 -	Capital Funds Agreement dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Registration No. 2-32333	4.32
	10-8 -	Amendment No. 1 dated as of August 1, 1985 to Capital Funds Agreement dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554	10-2.1

Registrant	Exhibit No.	Filed in	As Exhibit No.
Central Maine Power Company	10-9 -	Amendatory Agreement between the Company and Maine Yankee Atomic Power Company dated as of August 6, 1997, amending Company Exhibits 10-2 and 10-6 - Company's 10-K for the year ended December 31, 2001 - File No. 1-5139	10-9
	(A)10-10 -	Energy East Corporation's Supplemental Executive Retirement Plan - Energy East Corporation's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766	10-33
	(A)10-11 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-5
	(A)10-12 -	Energy East Corporation's Annual Executive Incentive Plan - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-8
	(A)10-13 -	Energy East Corporation's Annual Executive Incentive Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-9
	(A)10-14 -	Energy East Corporation's Annual Executive Incentive Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2001 - File No. 1-14766	10-28
	(A)10-15 -	Energy East Corporation's Restricted Stock Plan - Energy East Corporation's 10-K for the year ended December 31, 1998 - File No. 1-14766	10-36
	(A)10-16 -	Energy East Corporation's Restricted Stock Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766	10-16
	(A)10-17 -	Energy East Corporation's Form of Restricted Stock Award Grant - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766	10-17
	(A)10-18 -	Energy East Corporation's Amended and Restated 2000 Stock Option Plan, effective October 15, 2003 - Energy East Corporation's 10-Q for the quarter ended September 30, 2003 - File No. 1-14766	10-27
	(A)10-19 -	Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-27
	(A)10-20 -	Amended and Restated Employment Agreement between the Company, Energy East Corporation and Sara J. Burns dated June 14, 1999 - Company's 10-K for the year ended December 31, 2000 - File No. 1-5139	10-104

Registrant	Exhibit No.	Filed in	As Exhibit No.
Central Maine Power Company	(A)10-21 -	Employment Agreement between the Company and Curtis I. Call dated June 30, 1997 - Company's 10-K for the year ended December 31, 1998 - File No. 1-5139	10-107
	(A)10-22 -	First Amendment dated as of March 18, 1999 to the Employment Agreement between the Company and Curtis I. Call dated June 30, 1997 - Company's 10-K for the year ended December 31, 1999 - File No. 1-5139	10-107.1
	(A)10-23-	Employment Agreement between the Company and Stephen G. Robinson dated May 12, 1999 - Company's 10-K for the year ended December 31, 2001 - File No. 1-5139	10-25
	(A)10-24 -	Employment Agreement between the Company and Kathleen A. Case dated May 12, 1999 - Company's 10-K for the year ended December 31, 2002 - File No. 1-5139	10-24
	(A)10-25 -	Employment Agreement between the Company and Douglas A. Herling dated May 12, 1999 - Company's 10-K for the year ended December 31, 2001 - File No. 1-5139	10-24
	(A)10-26 -	Deferred Compensation Plan for Eligible Employees, effective January 1, 2004 - Energy East Corporation's 10-K for the year ended December 31, 2003 - File No. 1-14766	10-9
New York State Electric   & Gas Corporation	3-1 -	Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988 - Registration No. 33-50719	4-11
	3-2 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989 - Registration No. 33-50719	4-12
	3-3 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990 - Registration No. 33-50719	4-13
	3-4 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990 - Registration No. 33-50719	4-14
	3-5 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991 - Registration No. 33-50719	4-15
	3-6 -	Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991 - Registration No. 33-50719	4-20

Registrant	Exhibit No.	Filed in	As Exhibit No.
New York State Electric   & Gas Corporation	3-7 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991 - Registration No. 33-50719	4-16
	3-8 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992 - Registration No. 33-50719	4-17
	3-9 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992 - Registration No. 33-50719	4-18
	3-10 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993 - Registration No. 33-50719	4-19
	3-11 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 10, 1993 - Company's 10-K for the year ended December 31, 1993 - File No. 1-3103-2	3-11
	3-12 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993 - Company's 10-K for the year ended December 31, 1993 - File No. 1-3103-2	3-12
	3-13 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993 - Company's 10-K for the year ended December 31, 1993 - File No. 1-3103-2	3-13
	3-14 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on September 6, 2000 - Company's 10-Q for the quarter ended September 30, 2000 - File No. 1-3103-2	3-16
	3-15 -	Certificates of the Secretary of the Company concerning consents dated March 20, 1957, May 9, 1975, and April 1, 1999, of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness - Company's 10-Q for the quarter ended March 31, 1999 - File No. 1-3103-2	3-16
	3-16 -	By-Laws of the Company as amended June 28, 2002 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-3103-2	3-17
	4-1 -	Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002 - Company's 10-K for the year ended December 31, 2002 - File No. 1-3103-2	4-7

Registrant	Exhibit No.	Filed in	As Exhibit No.
New York State Electric   & Gas Corporation	4-2 -	First Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002 - Company's 10-K for the year ended December 31, 2002- File No. 1-3103-2	4-8
	4-3 -	Second Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002 - Company's 10-K for the year ended December 31, 2002 - File No. 1-3103-2	4-9
	4-4 -	Third Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of May 9, 2003, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002 - Company's 10-Q for the quarter ended June 30, 2003 - File No. 1-3103-2	4-10
	10-1 -	Agreement between New York Independent System Operator and Transmission Owners, dated as of December 2, 1999 - Company's 10-K for the year ended December 31, 1999 - File No. 1-3103-2	10-1
	10-2 -	Independent System Operator Agreement, dated as of December 2, 1999 - Company's 10-K for the year ended December 31, 1999 - File No. 1-3103-2	10-2
	(A)10-3 -	Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001 - Company's 10-Q for the quarter ended September 30, 2001 - File No. 1-3103-2	10-31
	(A)10-4 -	Amendment No. 1 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001 - Company's 10-K for the year ended December 31, 2001 - File No. 1-3103-2	10-5
	(A)10-5 -	Amendment No. 2 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001 - Company's 10-Q for the quarter ended March 31, 2002 - File No. 1-3103-2	10-31
	(A)10-6 -	Amendment No. 3 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-3103-2	10-32
	(A)10-7 -	Amendment No. 4 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001 - Company's 10-Q for the quarter ended June 30, 2003 - File No. 1-3103-2	10-35
	(A)10-8 -	Energy East Corporation's Supplemental Executive Retirement Plan - Energy East Corporation's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766	10-33

Registrant	Exhibit No.	Filed in	As Exhibit No.
New York State Electric   & Gas Corporation	(A)10-9 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-5
	(A)10-10 -	Energy East Corporation's Annual Executive Incentive Plan - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-8
	(A)10-11 -	Energy East Corporation's Annual Executive Incentive Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-9
	(A)10-12 -	Energy East Corporation's Annual Executive Incentive Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2001 - File No. 1-14766	10-28
	(A)10-13 -	Form of Severance Agreement for Senior Vice Presidents - Company's 10-K for the year ended December 31, 1993 - File No. 1-3103-2	10-47
	(A)10-14 -	Form of Severance Agreement for Senior Vice Presidents Amendment No. 1 - Company's 10-K for the year ended December 31, 1995 - File No. 1-3103-2	10-50
	(A)10-15 -	Form of Severance Agreement for Senior Vice Presidents Amendment No. 2 - Company's Schedule 14D-9, dated July 30, 1997	4
	(A)10-16 -	Form of Severance Agreement for Senior Vice Presidents Amendment No. 3 - Company's Schedule 14D-9, dated July 30, 1997	5
	(A)10-17 -	Form of Severance Agreement for Vice Presidents - Company's 10-K for the year ended December 31, 1993 - File No. 1-3103-2	10-48
	(A)10-18 -	Form of Severance Agreement for Vice Presidents Amendment No. 1 - Company's 10-K for the year ended December 31, 1995 - File No. 1-3103-2	10-52
	(A)10-19 -	Form of Severance Agreement for Vice Presidents Amendment No. 2 - Company's Schedule 14D-9, dated July 30, 1997	6
	(A)10-20 -	Form of Severance Agreement for Vice Presidents Amendment No. 3 - Company's Schedule 14D-9, dated July 30, 1997	7
	(A)10-21 -	Form of Amendment to the Company's Severance Agreements - Company's 10-Q for the quarter ended June 30, 1998 - File No. 1-3103-2	10-51
	(A)10-22 -	Employee Invention and Confidentiality Agreement (Existing Executive) - Company's Schedule 14D-9, dated July 30, 1997	9
	(A)10-23 -	Employee Invention and Confidentiality Agreement (Existing Executive) Amendment No. 1 - Company's Schedule 14D-9, dated July 30, 1997	10
Registrant	Exhibit No.	Filed in	As Exhibit No.
New York State Electric   & Gas Corporation	(A)10-24 -	Separation Agreement, General Release and Waiver dated as of April 7, 2003, by and among Ralph R. Tedesco, the Company and Energy East Management Corporation - Company's 10-Q for the quarter ended June 30, 2003 - File No. 1-3103-2	10-36
	(A)10-25 -	Energy East Corporation's Restricted Stock Plan - Energy East Corporation's 10-K for the year ended December 31, 1998 - File No. 1-14766	10-36
	(A)10-26 -	Energy East Corporation's Restricted Stock Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766	10-16
	(A)10-27 -	Energy East Corporation's Form of Restricted Stock Award Grant - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766	10-17
	(A)10-28 -	Energy East Corporation's Amended and Restated 2000 Stock Option Plan, effective October 15, 2003 - Energy East Corporation's 10-Q for the quarter ended September 30, 2003 - File No. 1-14766	10-27
	(A)10-29 -	Energy East Corporation's Award Agreement under the 2000 Stock Option Plan - Energy East Corporation's 10-Q for the quarter ended June 30, 2000 - File No. 1-14766	10-37
	(A)10-30 -	Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-27
	(A)10-31 -	Energy East Management Corporation Form of Change in Control Agreement - Energy East Corporation's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-23
	(A)10-32 -	Deferred Compensation Plan for Eligible Employees, effective January 1, 2004 - Energy East Corporation's 10-K for the year ended December 31, 2003 - File No. 1-14766	10-9
Rochester Gas and Electric   Corporation	3-1 -	Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on June 23, 1992 - Registration No. 33-49805	4-5
	3-2 -	Certificate of Amendment of the Certificate of Incorporation of the Company under Section 805 of the Business Corporation Law filed with the Secretary of State of the State of New York on March 18, 1994 - Company's 10-Q for the quarter ended March 31, 1994 - File No. 1-672	4

Registrant	Exhibit No.	Filed in	As Exhibit No.
Rochester Gas and Electric   Corporation	3-3 -	By-Laws of Company as amended June 28, 2002 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-672	3-3
	4-1 -	General Mortgage to Bankers Trust Company, as Trustee, dated September 1, 1918, and supplements thereto, dated March 1, 1921, October 23, 1928, August 1, 1932 and May 1, 1940 - Company's 10-K for the year ended December 31, 1990 - File No. 1-672	4-2
	4-2 -	Supplemental Indenture, dated as of March 1, 1983, between the Company and Bankers Trust Company, as Trustee - Company's 8-K dated July 15, 1993 - File No. 1-672	4-1
	10-1 -	Agreement dated February 5, 1980 between the Company and the Power Authority of the State of New York - Company's 10-K for the year ended December 31, 1989 - File No. 1-672	10-10
	10-2 -	Agreement dated March 9, 1990 between the Company and Mellon Bank, N.A. - Company's 10-Q for the quarter ended March 31, 1990 - File No. 1-672	10-1
	10-3 -	Agreement between New York Independent System Operator and Transmission Owners, dated as of December 2, 1999 - New York State Electric & Gas Corporation's 10-K for the year ended December 31, 1999 - File No. 1-3103-2	10-1
	10-4 -	Independent System Operator Agreement, dated as of December 2, 1999 - New York State Electric & Gas Corporation's 10-K for the year ended December 31, 1999 - File No. 1-3103-2	10-2
	10-5 -	Revenue Sharing Agreement regarding the sale of the Company's interest in Nine Mile Point 2 Nuclear Plant to Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000 - Company's 10-K for the year ended December 31, 2000 - File No. 1-672	10-21
	10-6 -	Power Purchase Agreement regarding the sale of the Company's interest in Nine Mile Point 2 Nuclear Plant to Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000 - Company's 10-K for the year ended December 31, 2000 - File No. 1-672	10-22
	(A)10-8 -	Employment Agreement, dated June 28, 2002, for Paul C. Wilkens - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-672	10-26
	(A)10-9 -	Supplemental Executive Retirement Program effective January 1, 1999 - Company's 10-Q for the quarter ended March 31, 2000 - File No. 1-672	10-1

Registrant	Exhibit No.	Filed in	As Exhibit No.
Rochester Gas and Electric   Corporation	(A)10-10 -	Supplemental Executive Retirement Program Amendment No. 1, effective November 1, 2001 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-672	10-30
	(A)10-11 -	Supplemental Executive Retirement Program Amendment No. 2, effective May 1, 2002 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-672	10-31
	(A)10-12 -	Supplemental Executive Retirement Program Amendment No. 3, effective as of January 1, 2003 - Company's 10-Q for the quarter ended September 30, 2003 - File No. 1-672	10-23
	(A)10-13 -	Supplemental Retirement Benefit Program effective July 1, 1999 - Company's 10-Q for the quarter ended March 31, 2000 - File No. 1-672	10-2
	(A)10-14 -	Supplemental Retirement Benefit Program Amendment No. 1, effective November 1, 2001 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-672	10-28
	(A)10-15 -	Supplemental Retirement Benefit Program Amendment No. 2, effective May 1, 2002 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-672	10-29
	(A)10-16 -	Supplemental Retirement Benefit Program Amendment No. 3, effective as of January 1, 2003 - Company's 10-Q for the quarter ended September 30, 2003 - File No. 1-672	10-24
	(A)10-17 -	Energy East Corporation's Restricted Stock Plan - Energy East Corporation's 10-K for the year ended December 31, 1998 - File No. 1-14766	10-36
	(A)10-18 -	Energy East Corporation's Restricted Stock Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766	10-16
	(A)10-19 -	Energy East Corporation's Form of Restricted Stock Award Grant - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766	10-17
	(A)10-20 -	Energy East Corporation's Amended and Restated 2000 Stock Option Plan, effective October 15, 2003 - Energy East Corporation's 10-Q for the quarter ended September 30, 2003 - File No. 1-14766	10-27
	(A)10-21 -	Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766	10-27
	(A)10-22 -	Form of Severance Agreement, as amended - Company's 10-K for the year ended December 31, 2002 - File No. 1-672	10-21

Registrant	Exhibit No.	Filed in	As Exhibit No.
Rochester Gas and Electric   Corporation	(A)10-23 -	Energy East Management Corporation Form of Change in Control Agreement - Energy East Corporation's 10-K for the year ended December 31, 2001 - File No. 1-14766	10-23
	(A)10-24 -	Deferred Compensation Plan for Eligible Employees, effective January 1, 2004 - Energy East Corporation's 10-K for the year ended December 31, 2003 - File No. 1-14766	10-9

_____________________________
(A)  Management contract or compensatory plan or arrangement.

Energy East agrees to furnish to the Commission, upon request, a copy of the following documents. The total amount of securities authorized under each of such documents does not exceed 10% of the total assets of Energy East:

A.	Three-Year Revolving Credit Agreement among Energy East, certain lenders, Bank One, N.A. and Bayerische Landesbank Girozentrale, as Co-Syndication Agents, Citibank, N.A. and Fleet National Bank, as Co-Documentation Agents, and JPMorgan Chase Bank, as Administrative Agent, dated as of July 24, 2002.
B.	The Southern Connecticut Gas Company's Indenture, dated as of March 1, 1948, with The Bridgeport City Trust Company (now US Bank), as Trustee, and Supplemental Indentures related thereto.
C.	Connecticut Natural Gas Corporation's Issuing and Paying Agency Agreement with The Connecticut National Bank (now US Bank) for Medium Term Notes, Series A, dated November 1, 1991.
D.	Connecticut Natural Gas Corporation's Issuing and Paying Agency Agreement with Shawmut Bank Connecticut, National Association (now US Bank) for Medium Term Notes, Series B, dated June 14, 1994, and an Amendment related thereto.
E.	The Berkshire Gas Company's First Mortgage Indenture and Deed of Trust, dated as of July 1, 1954, with Chemical Corn Exchange Bank (now JPMorgan Chase Bank), and the Supplemental Indenture related thereto.
F.	The Berkshire Gas Company's Term Loan Agreement, dated as of December 14, 1993, with Fleet National Bank, and Amendments related thereto.
G.	Senior Note Agreement dated as of July 1, 1990 between The Berkshire Gas Company and Allstate Life Insurance Company.
H.	Senior Note Agreement dated as of November 1, 1996 between The Berkshire Gas Company and First Colony Life Insurance Company, and Amendments related thereto.

CMP agrees to furnish to the Commission, upon request, a copy of the Loan and Trust Agreement dated as of December 1, 2001, among The Business Finance Authority of the State of New Hampshire and CMP and State Street Bank and Trust Company, as Trustee, relating to Pollution Control Revenue Refunding Bonds (Series 2001); and a copy of the Credit Agreement dated as of December 18, 2002 among CMP, Fleet National Bank, as Syndication Agent, certain lenders and the Bank of New York, as Administrative Agent. The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of CMP.

NYSEG agrees to furnish to the Commission, upon request, a copy of the Participation Agreements dated as of June 1, 1987, and December 1, 1988, between NYSEG and New York State Energy Research and Development Authority (NYSERDA) relating to Adjustable Rate Pollution Control Revenue Bonds (1987 Series A), and (1988 Series A), respectively; a copy of the Participation Agreements dated as of March 1, 1985, October 15, 1985, and December 1, 1985, between NYSEG and NYSERDA relating to Annual Tender Pollution Control Revenue Bonds (1985 Series A), (1985 Series B), and (1985 Series D), respectively, a copy of the Participation Agreements dated as of February 1, 1993, February 1, 1994, June 1, 1994, October 1, 1994, and December 1, 1994, between NYSEG and NYSERDA relating to Pollution Control Refunding Revenue Bonds (1994 Series A), (1994 Series B), (1994 Series C), (1994 Series D), and (1994 Series E), respectively; a copy of the Participation Agreement dated as of December 1, 1993, between NYSEG and NYSERDA relating to Solid Waste Disposal Revenue Bonds (1993 Series A); and a copy of the Participation Agreement dated as of December 1, 1994, between NYSEG and the Indiana County Industrial Development Authority relating to Pollution Control Refunding Revenue Bonds (1994 Series A). The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of NYSEG.

RG&E agrees to furnish to the Commission, upon request, a copy of the Participation Agreement dated as of May 1, 1992, between RG&E and NYSERDA relating to Pollution Control Refunding Revenue Bonds (1992 Series A), and (1992 Series B); a copy of the Participation Agreement dated as of August 1, 1997, between RG&E and New York State Energy Research and Development Authority (NYSERDA) relating to Pollution Control Revenue Bonds, Rochester Gas and Electric Corporation Project (1997 Series A) (1997 Series B), (1997 Series C) and (1998 Series A); and a copy of certain supplemental indentures to the General Mortgage dated September 1, 1918, as supplemented. The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of RG&E.

(b)  Reports on Form 8-K

Energy East filed four reports on Form 8-K. One, dated October 24, 2003, was filed to report certain information under Item 9, "Regulation FD Disclosure" and Item 12, "Disclosure of Results of Operations and Financial Condition." Three other reports, dated November 13, 2003, November 25, 2003, and December 18, 2003, were filed to report certain information under Item 5, "Other Events."

RG&E filed three reports on Form 8-K. The reports were dated November 13, 2003, November 25, 2003, and December 18, 2003, and were filed to report certain information under Item 5, "Other Events."

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:  March 8, 2004	ENERGY EAST CORPORATION By   /s/Kenneth M. Jasinski                                Kenneth M. Jasinski         Executive Vice President and         Chief Financial Officer
Date:  March 8, 2004	CENTRAL MAINE POWER COMPANY By     /s/Curtis I. Call                                                Curtis I. Call         Vice President, Controller & Treasurer
Date:  March 8, 2004	NEW YORK STATE ELECTRIC & GAS CORPORATION By    /s/Joseph J. Syta                                         Joseph J. Syta         Controller and Treasurer
Date:  March 8, 2004	ROCHESTER GAS AND ELECTRIC CORPORATION By    /s/Joseph J. Syta                                        Joseph J. Syta         Controller and Treasurer

Signatures (Cont'd)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each Registrant and in the capacities and on the dates indicated.

	ENERGY EAST CORPORATION
Date:  March 8, 2004	PRINCIPAL EXECUTIVE OFFICER By    /s/Wesley W. von Schack                         Wesley W. von Schack         Chairman, President, Chief         Executive Officer & Director
Date:  March 8, 2004	PRINCIPAL FINANCIAL OFFICER By    /s/Kenneth M. Jasinski                                Kenneth M. Jasinski         Executive Vice President and         Chief Financial Officer
Date:  March 4, 2004	PRINCIPAL ACCOUNTING OFFICER By    /s/Robert E. Rude                                      Robert E. Rude         Vice President and Controller

Signatures (Cont'd)

	ENERGY EAST CORPORATION, cont'd
Date:  March 8, 2004	By     /s/Richard Aurelio                                       Richard Aurelio, Director
Date:  March 8, 2004	By    /s/James A. Carrigg                                    James A. Carrigg, Director
Date:  March 8, 2004	By    /s/Joseph J. Castiglia                                Joseph J. Castiglia, Director
Date:  March 8, 2004	By    /s/Lois B. DeFleur                                      Lois B. DeFleur, Director
Date:  February 26, 2004	By    /s/G. Jean Howard                                     G. Jean Howard, Director
Date:  February 26, 2004	By    /s/David M. Jagger                                     David M. Jagger, Director
Date:  February 26, 2004	By    /s/John M. Keeler                                       John M. Keeler, Director
Date:  March 8, 2004	By    /s/Ben E. Lynch                                         Ben E. Lynch, Director
Date:  March 8, 2004	By    /s/Peter J. Moynihan                                  Peter J. Moynihan, Director
Date:  March 8, 2004	By    /s/Walter G. Rich                                       Walter G. Rich, Director

Signatures (Cont'd)

	CENTRAL MAINE POWER COMPANY
Date:  March 8, 2004	PRINCIPAL EXECUTIVE OFFICER By     /s/Sara J. Burns                                        Sara J. Burns         President and Director
Date:  March 8, 2004	PRINCIPAL FINANCIAL OFFICER AND PRINCIPAL ACCOUNTING OFFICER By    /s/Curtis I. Call                                           Curtis I. Call         Vice President, Controller & Treasurer
Date:  March 8, 2004	By    /s/Kenneth M. Jasinski                               Kenneth M. Jasinski, Director
Date:  March 8, 2004	By    /s/Wesley W. von Schack                         Wesley W. von Schack, Director

Signatures (Cont'd)

	NEW YORK STATE ELECTRIC & GAS CORPORATION
Date:  March 8, 2004	PRINCIPAL EXECUTIVE OFFICER By    /s/James P. Laurito                                    James P. Laurito         President and Director
Date:  March 8, 2004	PRINCIPAL FINANCIAL OFFICER AND PRINCIPAL ACCOUNTING OFFICER By    /s/Joseph J. Syta                                       Joseph J. Syta         Controller and Treasurer
Date:  March 8, 2004	By    /s/Kenneth M. Jasinski                               Kenneth M. Jasinski, Director
Date:  March 8, 2004	By    /s/Wesley W. von Schack                           Wesley W. von Schack, Director

Signatures (Cont'd)

	ROCHESTER GAS AND ELECTRIC CORPORATION
Date:  March 8, 2004	PRINCIPAL EXECUTIVE OFFICER By    /s/James P. Laurito                                    James P. Laurito         President and Director
Date:  March 8, 2004	PRINCIPAL FINANCIAL OFFICER AND PRINCIPAL ACCOUNTING OFFICER By    /s/Joseph J. Syta                                       Joseph J. Syta         Controller and Treasurer
Date:  March 8, 2004	By    /s/Kenneth M. Jasinski                               Kenneth M. Jasinski, Director
Date:  March 8, 2004	By    /s/Wesley W. von Schack                          Wesley W. von Schack, Director

EXHIBIT INDEX

Registrant	Exhibit No.	Description
Energy East Corporation	*3-1 -	Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on April 23, 1998.
	*3-2 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on April 26, 1999.
	*3-3 -	By-Laws of the Company as amended April 12, 2001.
	*4-1 -	Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of August 31, 2000.
	*4-2 -	Third Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of November 14, 2000 related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000.
	*4-3 -	Fourth Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of November 14, 2001, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000.
	*4-4 -	Sixth Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of June 14, 2002, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000.
	*4-5 -	Seventh Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of September 9, 2003, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000.
	*4-6 -	Subordinated Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of July 24, 2001.
	*4-7 -	First Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of July 24, 2001, related to the Subordinated Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of July 24, 2001.
	*(A)10-1 -	Deferred Compensation Plan for Directors.
	*(A)10-2 -	Amended and Restated Director Share Plan.
	*(A)10-3 -	Deferred Compensation Plan - Director Share Plan.
	*(A)10-4 -	Supplemental Executive Retirement Plan.
	*(A)10-5 -	Supplemental Executive Retirement Plan Amendment No. 1.
	*(A)10-6 -	Annual Executive Incentive Plan.
	*(A)10-7 -	Annual Executive Incentive Plan Amendment No. 1.
	*(A)10-8 -	Annual Executive Incentive Plan Amendment No. 2.
	(A)10-9 -	Deferred compensation Plan for Eligible Employees, effective January 1, 2004.
	*(A)10-10 -	Employment Agreement dated February 8, 2002, for W. W. von Schack.
	*(A)10-11 -	Employment Agreement dated February 8, 2002, for K. M. Jasinski.
	*(A)10-12 -	Restricted Stock Plan.
	*(A)10-13 -	Restricted Stock Plan Amendment No. 1.
	*(A)10-14 -	Form of Restricted Stock Award Grant.

EXHIBIT INDEX (Cont'd)

Registrant	Exhibit No.	Description
Energy East Corporation	*(A)10-15 -	Amended and Restated 2000 Stock Option Plan, effective October 15, 2003.
	*(A)10-16 -	Award Agreement under the 2000 Stock Option Plan.
	*(A)10-17 -	Award Agreement (February 2001) under the 2000 Stock Option Plan.
	*(A)10-18 -	Director's Charitable Giving Program.
	*(A)10-19 -	Energy East Management Corporation Form of Change In Control Agreement.
	*(A)10-20 -	Energy East Management Corporation Form of Employee Invention and Confidentiality Agreement.
	12-1 -	Computation of Ratio of Earnings to Fixed Charges.
	12-2 -	Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends.
	21 -	Subsidiaries.
	23 -	Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32 -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
Central Maine Power Company	*3-1 -	Articles of Incorporation, as amended.
	*3-2 -	Articles of Amendment to the Articles of Incorporation.
	*3-3 -	Amended and Restated By-Laws.
	*4-1 -	Indenture, dated as of August 1, 1989, between the Company and The Bank of New York, as Trustee, relating to the Medium-Term Notes.
	*4-2 -	Fifth Supplemental Indenture dated as of May 18, 2000, relating to the Medium-Term Notes, Series E, and supplementing the Indenture dated as of August 1, 1989, between the Company and The Bank of New York, as Trustee.
	*10-1 -	Stockholder Agreement dated as of May 20, 1968 among the Company and the other stockholders of Maine Yankee Atomic Power Company.
	*10-2 -	Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company.
	*10-3 -	Amendment No. 1 dated as of March 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company.
	*10-4 -	Amendment No. 2 dated as of January 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company.
	*10-5 -	Amendment No. 3 dated as of October 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company.
	*10-6 -	Additional Power Contract between the Company and Maine Yankee Atomic Power Company dated as of February 1, 1984.
	*10-7 -	Capital Funds Agreement dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company.
	*10-8 -	Amendment No. 1 dated as of August 1, 1985 to Capital Funds Agreement dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company.

EXHIBIT INDEX (Cont'd)

Registrant	Exhibit No.	Description
Central Maine Power Company	*10-9 -	Amendatory Agreement between the Company and Maine Yankee Atomic Power Company dated as of August 6, 1997, amending Company Exhibits 10-2 and 10-6.
	*(A)10-10 -	Energy East Corporation's Supplemental Executive Retirement Plan.
	*(A)10-11 -	Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1.
	*(A)10-12 -	Energy East Corporation's Annual Executive Incentive Plan.
	*(A)10-13 -	Energy East Corporation's Annual Executive Incentive Plan Amendment No. 1.
	*(A)10-14 -	Energy East Corporation's Annual Executive Incentive Plan Amendment No. 2.
	*(A)10-15 -	Energy East Corporation's Restricted Stock Plan.
	*(A)10-16 -	Energy East Corporation's Restricted Stock Plan Amendment No. 1.
	*(A)10-17 -	Energy East Corporation's Form of Restricted Stock Award Grant.
	*(A)10-18 -	Energy East Corporation's Amended and Restated 2000 Stock Option Plan, effective October 15, 2003.
	*(A)10-19 -	Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan.
	*(A)10-20 -	Amended and Restated Employment Agreement between the Company, Energy East Corporation and Sara J. Burns dated June 14, 1999.
	*(A)10-21 -	Employment Agreement between the Company and Curtis I. Call dated June 30, 1997.
	*(A)10-22 -	First Amendment dated as of March 18, 1999 to the Employment Agreement between the Company and Curtis I. Call dated June 30, 1997.
	*(A)10-23 -	Employment Agreement between the Company and Stephen G. Robinson dated May 12, 1999.
	*(A)10-24 -	Employment Agreement between the Company and Kathleen A. Case dated May 12, 1999.
	*(A)10-25 -	Employment Agreement between the Company and Douglas A. Herling dated May 12, 1999.
	*(A)10-26 -	Deferred Compensation Plan for Eligible Employees, effective January 1, 2004.
	21 -	Subsidiaries.
	23 -	Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32 -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
	99-1 -	Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, security ownership of management, code of ethics and audit fees.

EXHIBIT INDEX (Cont'd)

Registrant	Exhibit No.	Description
New York State Electric   & Gas Corporation	*3-1 -	Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988.
	*3-2 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989.
	*3-3 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990.
	*3-4 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990.
	*3-5 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991.
	*3-6 -	Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991.
	*3-7 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991.
	*3-8 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992.
	*3-9 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992.
	*3-10 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993.
	*3-11 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 10, 1993.
	*3-12 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993.
	*3-13 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993.
	*3-14 -	Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on September 6, 2000.
	*3-15 -	Certificates of the Secretary of the Company concerning consents dated March 20, 1957, May 9, 1975, and April 1, 1999, of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness.
	*3-16 -	By-Laws of the Company as amended June 28, 2002.
	*4-1 -	Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002.
	*4-2 -	First Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002.
	*4-3 -	Second Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002.

EXHIBIT INDEX (Cont'd)

Registrant	Exhibit No.			Description
New York State Electric   & Gas Corporation	*4-4 -			Third Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of May 9, 2003, related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002.
	*10-1 -			Agreement between New York Independent System Operator and Transmission Owners, dated as of December 2, 1999.
	*10-2 -			Independent System Operator Agreement, dated as of December 2, 1999.
	*(A)10-3 -			Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001.
	*(A)10-4 -			Amendment No. 1 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001.
	*(A)10-5 -			Amendment No. 2 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001.
	*(A)10-6 -			Amendment No. 3 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001.
	*(A)10-7 -			Amendment No. 4 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001.
	*(A)10-8 -		Energy East Corporation's Supplemental Executive Retirement Plan.
	*(A)10-9 -		Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1.
	*(A)10-10 -		Energy East Corporation's Annual Executive Incentive Plan.
	*(A)10-11 -		Energy East Corporation's Annual Executive Incentive Plan Amendment No. 1.
	*(A)10-12 -		Energy East Corporation's Annual Executive Incentive Plan Amendment No. 2.
	*(A)10-13 -		Form of Severance Agreement for Senior Vice Presidents.
	*(A)10-14 -		Form of Severance Agreement for Senior Vice Presidents Amendment No. 1.
	*(A)10-15 -		Form of Severance Agreement for Senior Vice Presidents Amendment No. 2.
	*(A)10-16 -		Form of Severance Agreement for Senior Vice Presidents Amendment No. 3.
	*(A)10-17 -		Form of Severance Agreement for Vice Presidents.
	*(A)10-18 -	Form of Severance Agreement for Vice Presidents Amendment No. 1.
	*(A)10-19 -	Form of Severance Agreement for Vice Presidents Amendment No. 2.
	*(A)10-20 -	Form of Severance Agreement for Vice Presidents Amendment No. 3.
	*(A)10-21 -	Form of Amendment to the Company's Severance Agreements.
	*(A)10-22 -	Employee Invention and Confidentiality Agreement (Existing Executive).
	*(A)10-23 -		Employee Invention and Confidentiality Agreement (Existing Executive) Amendment No. 1.
	*(A)10-24 -		Separation Agreement, General Release and Waiver dated as of April 7, 2003, by and among Ralph R. Tedesco, the Company and Energy East Management Corporation.
	*(A)10-25 -		Energy East Corporation's Restricted Stock Plan.
	*(A)10-26 -		Energy East Corporation's Restricted Stock Plan Amendment No. 1.
	*(A)10-27 -		Energy East Corporation's Form of Restricted Stock Award Grant.
	*(A)10-28 -		Energy East Corporation's Amended and Restated 2000 Stock Option Plan, effective October 15, 2003.

EXHIBIT INDEX (Cont'd)

Registrant	Exhibit No.		Description
New York State Electric   & Gas Corporation	*(A)10-29 -	Energy East Corporation's Award Agreement under the 2000 Stock Option Plan.
	*(A)10-30 -	Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan.
	*(A)10-31 -	Energy East Management Corporation Form of Change in Control Agreement.
	*(A)10-32 -		Deferred Compensation Plan for Eligible Employees, effective January 1, 2004.
	23 -	Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32 -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
	99-1 -	Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, security ownership of management, code of ethics and audit fees.
Rochester Gas and Electric   Corporation	*3-1 -	Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on June 23, 1992.
	*3-2 -	Certificate of Amendment of the Certificate of Incorporation of the Company under Section 805 of the Business Corporation Law filed with the Secretary of State of the State of New York on March 18, 1994.
	*3-3 -	By-Laws of the Company as amended June 28, 2002.
	*4-1 -	General Mortgage to Bankers Trust Company, as Trustee, dated September 11, 1918, and supplements thereto, dated March 1, 1921, October 23, 1928, August 1, 1932 and May 1, 1940.
	*4-2 -	Supplemental Indenture, dated as of March 1, 1983, between the Company and Bankers Trust Company, as Trustee.
	*10-1 -	Agreement dated February 5, 1980 between the Company and the Power Authority of the State of New York.
	*10-2 -	Agreement dated March 9, 1990 between the Company and Mellon Bank, N.A.
	*10-3 -	Agreement between New York Independent System Operator and Transmission Owners, dated as of December 2, 1999.
	*10-4 -	Independent System Operator Agreement, dated as of December 2, 1999.
	*10-5 -	Revenue Sharing Agreement regarding the sale of the Company's interest in Nine Mile Point 2 Nuclear Plant to Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000.
	*10-6 -	Power Purchase Agreement regarding the sale of the Company's interest in Nine Mile Point 2 Nuclear Plant to Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000.
	10-7 -	Asset Purchase Agreement by and among Rochester Gas and Electric Corporation, Constellation Generation Group, LLC and Constellation Energy Group, Inc. dated as of November 24, 2003.

EXHIBIT INDEX (Cont'd)

Registrant	Exhibit No.			Description
Rochester Gas and Electric   Corporation	*(A)10-8 -		Employment Agreement, dated June 28, 2002, for Paul C. Wilkens.
	*(A)10-9 -		Supplemental Executive Retirement Program effective January 1, 1999.
	*(A)10-10 -		Supplemental Executive Retirement Program Amendment No. 1, effective November 1, 2001.
	*(A)10-11 -		Supplemental Executive Retirement Program Amendment No. 2, effective May 1, 2002.
	*(A)10-12 -		Supplemental Executive Retirement Program Amendment No. 3, effective as of January 1, 2003.
	*(A)10-13 -		Supplemental Retirement Benefit Program effective July 1, 1999.
	*(A)10-14 -		Supplemental Retirement Benefit Program Amendment No. 1, effective November 1, 2001.
	*(A)10-15 -		Supplemental Retirement Benefit Program Amendment No. 2, effective May 1, 2002.
	*(A)10-16 -		Supplemental Retirement Benefit Program Amendment No. 3, effective as of January 1, 2003.
	*(A)10-17 -		Energy East Corporation's Restricted Stock Plan.
	*(A)10-18 -		Energy East Corporation's Restricted Stock Plan Amendment No. 1.
	*(A)10-19 -		Energy East Corporation's Form of Restricted Stock Award Grant.
	*(A)10-20 -		Energy East Corporation's Amended and Restated 2000 Stock Option Plan, effective October 15, 2003.
	*(A)10-21 -	Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan.
	*(A)10-22 -	Form of Severance Agreement, as amended.
	*(A)10-23 -	Energy East Management Corporation Form of Change in Control Agreement.
	*(A)10-24 -			Deferred Compensation Plan for Eligible Employees, effective January 1, 2004.
	23 -	Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements.
	31-1 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	31-2 -	Certification under Section 302 of the Sarbanes-Oxley Act of 2002.
	32 -	Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.
	99-1 -	Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, security ownership of management, code of ethics and audit fees.

____________________________
 *   Incorporated by reference.

(A)  Management contract or compensatory plan or arrangement.