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 electricity for 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 $4 million 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.
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:
(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
7,706
RG&E
New York State
4,556
SCG
Connecticut
-
3,634
CNG
Connecticut
-
3,547
Berkshire Gas
Massachusetts
-
Maine Natural Gas
Maine
New Hampshire Gas
(Propane air)
New Hampshire
-
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.
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.
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
Chairman, President & Chief Executive Officer to date; Chairman, President & Chief Executive Officer of NYSEG to April 1999.
Kenneth M. Jasinski
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
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
Vice President and Controller, November 1999 to date; Controller to November 1999; Executive Director, Corporate Planning of NYSEG to October 2000.
Robert M. Allessio
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
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
President of CMP to date.
Michael I. German
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
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
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
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
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
President to date.
New York State Electric & Gas Corporation
and
Rochester Gas and Electric Corporation
James P. Laurito
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.
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.
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.
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.
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
Item 8. Financial statements and supplementary data
Index to 2003 Financial Statements
Page
Energy East Corporation
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Common Stock Equity
Notes to Consolidated Financial Statements
Report of Independent Auditors
Financial Statement Schedule
II. Consolidated Valuation and Qualifying Accounts
Central Maine Power Company
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Common Stock Equity
Notes to Consolidated Financial Statements
Report of Independent Auditors
Financial Statement Schedule
II. Consolidated Valuation and Qualifying Accounts
New York State Electric & Gas Corporation
Balance Sheets
Statements of Income
Statements of Cash Flows
Statements of Changes in Common Stock Equity
Notes to Financial Statements
Report of Independent Auditors
Financial Statement Schedule
II. Valuation and Qualifying Accounts
Rochester Gas and Electric Corporation
Balance Sheets
Statements of Income
Statements of Cash Flows
Statements of Changes in Common Stock Equity
Notes to Financial Statements
Report of Independent Auditors
Financial Statement Schedule
II. Valuation and Qualifying Accounts
Item 9.
Item 9.
Changes in and disagreements with accountants on accounting and
financial disclosure
None for Energy East, CMP, NYSEG or RG&E.
Item 9A.
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
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:
(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.
Earnings Per Share 	
Earnings per share for 2003 increased
1 cent 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
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 $193
million 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
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
The notes on pages 47 through 76 are an integral part of the financial statements.
Energy East Corporation
Consolidated Balance Sheets
The
notes on pages 47 through 76 are an integral part of the financial statements.
Energy East Corporation
Consolidated Statements of Income
The notes on pages 47 through 76 are an integral part of the financial statements.
Energy East Corporation
Consolidated Statements of Cash Flows
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
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:
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.
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:
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
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:
The major classes of assets and liabilities at the date of sale of the businesses were:
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.
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.
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:
Note 6. Income Taxes
The company's effective tax rate differed from the statutory rate of 35% due to the following:
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:
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:
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:
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:
(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:
* 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.
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
(See Risk management in Note 1.)
Notes to Consolidated Financial Statements
Energy East Corporation
Note 16. Retirement Benefits
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.
As of December 31, 2003, the company decreased its discount rate from 6.5% to 6.25%.
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
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:
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:
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.
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:
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.
Notes to Consolidated Financial Statements
Energy East Corporation
Note 18. Quarterly Financial Information (Unaudited)
(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)
Allowance for Doubtful
Accounts - Accounts
Receivable
$58,640
$47,919
$(48,211)
$(5,500)
$52,848
Allowance for Doubtful
Accounts - Accounts
Receivable
$17,783
$45,782
$(36,455)
$31,530
(b)
$58,640
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
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:
(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
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
The notes on pages 89 through 104 are an integral part of the financial statements.
Central Maine Power Company
Consolidated Balance Sheets
The notes on pages 89 through 104 are an integral part of the financial statements.
Central Maine Power Company
Consolidated Statements of Income
The notes on pages 89 through 104 are an integral part of the financial statements.
Central Maine Power Company
Consolidated Statements of Cash Flows
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
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.
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:
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:
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 4. Income Taxes
CMP's effective tax rate differed from the statutory rate of 35% due to the following:
CMP's deferred tax assets and liabilities consisted of the following:
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:
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:
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:
(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.
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.
The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values.
Note 12. Accumulated Other Comprehensive Income
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 13. Retirement Benefits
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 $38
million 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
As of December 31, 2003, CMP decreased its discount rate from 6.50% to 6.25%.
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.
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:
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:
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.
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:
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.
Note 15. Quarterly Financial Information (Unaudited)
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)
Allowance for Doubtful Accounts
- Accounts Receivable
$1,853
$2,143
$(2,248)
-
$1,748
Allowance for Doubtful Accounts
- Accounts Receivable
$2,854
$2,584
$(3,585)
-
$1,853
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
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:
(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
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
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
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
The notes on pages 119 through 136 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Balance Sheets
The notes on pages 119 through 136 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Statements of Income
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
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
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.
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:
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:
Note 4. Income Taxes
NYSEG's effective tax rate differed from the statutory rate of 35% due to the following:
Notes to Financial Statements
New York State Electric & Gas Corporation
NYSEG's deferred tax assets and liabilities consisted of the following:
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:
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:
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:
(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
(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.
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
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.
As of December 31, 2003, NYSEG decreased its discount rate from 6.5% to 6.25%.
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.
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:
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:
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:
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.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 15. Quarterly Financial Information (Unaudited)
(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)
Allowance for Doubtful
Accounts - Accounts
Receivable
$10,288
$15,054
$(15,054)
-
$10,288
Allowance for Doubtful
Accounts - Accounts
Receivable
$6,300
$17,600
$(14,100)
$488
$10,288
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
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:
(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
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
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 $8
million 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
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
The notes on pages 151 through 166 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Balance Sheets
The notes on pages 151 through 166 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Statements of Income
The notes on pages 151 through 166 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Statements of Cash Flows
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
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.
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:
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):
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
RG&E's effective tax rate differed from the statutory rate of 35% due to the following:
Notes to Financial Statements
Rochester Gas and Electric Corporation
RG&E's deferred tax liabilities consisted of the following:
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:
(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:
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:
(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.
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
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.
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
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.
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:
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:
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.
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:
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.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 14. Quarterly Financial Information (Unaudited)
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 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 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)
Allowance for Doubtful
Accounts - Accounts
Receivable
$31,182
$11,310
$(11,310)
$(4,000)
$27,182
Allowance for Doubtful
Accounts - Accounts
Receivable
$29,482
$8,803
$(8,803)
$1,700
$31,182
Allowance for Doubtful
Accounts - Accounts
Receivable
$33,482
$5,476
$(9,476)
-
$29,482
PART III
Item 10.
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.
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.
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.
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.
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.
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:
(a) The following documents are filed as part of this report for NYSEG and RG&E:
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
(A)10-16 -
Form of Severance Agreement for Senior
Vice Presidents Amendment No. 3 - Company's Schedule 14D-9, dated July
30, 1997
(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
(A)10-20 -
Form of Severance Agreement for Vice Presidents Amendment No. 3 - Company's Schedule 14D-9, dated July 30, 1997
(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
(A)10-23 -
Employee Invention and Confidentiality Agreement (Existing Executive) Amendment No. 1 - Company's Schedule 14D-9, dated July 30, 1997
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
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)
EXHIBIT INDEX
(Cont'd)
EXHIBIT INDEX
(Cont'd)
____________________________
* Incorporated by reference.
(A) Management contract or compensatory plan or arrangement.