Item 1. Business
General development of business
Energy East Corporation: 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 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. The company's corporate offices are located in New York and Maine.
The company's mergers within the last five years are: CNE in February 2000, CMP Group, CTG Resources and Berkshire Energy in September 2000, and 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. CMP Group's principal operating subsidiary, Central Maine Power Company, 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, a regulated natural gas distribution company in Connecticut. Berkshire Energy's wholly-owned subsidiary, The Berkshire Gas Company, is a regulated natural gas distribution company that operates in western Massachusetts. RGS Energy's principal operating subsidiaries are New York State Electric & Gas Corporation and Rochester Gas and Electric Corporation. 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. Financial information for RGS Energy for periods prior to July 1, 2002, does not include NYSEG.
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, 2004:
Regulatory and Rate Matters
See Item 7 - Electric Delivery Business and Natural Gas Delivery Business.
Financial information about segments
See Item 8 - Note 17 to the company's and Note 14 to CMP's Consolidated Financial Statements, and Note 13 to NYSEG's and RG&E's Financial Statements.
Narrative description of business
See Item 7 - Electric Delivery Business, Natural Gas Delivery Business and Other Businesses.
Principal business
The company's principal business consists of its regulated electricity transmission and distribution 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 the company's operating revenues derived from electricity sales was 58% in 2004, 61% in 2003 and 68% in 2002. The percentage of its operating revenues derived from natural gas sales was 33% in 2004, 32% in 2003 and 27% in 2002. 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 580,000 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 2004, 2003 and 2002 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 854,000 electricity and 254,000 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 2004 and 2003 and 82% for 2002 were derived from electricity sales, with the balance each year derived from natural gas sales. 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 coal-fired plant, three gas turbine plants and several smaller hydroelectric stations. RG&E serves approximately 358,000 electricity and 295,000 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 64% of RG&E's operating revenues for 2004, 66% for 2003 and 70% for 2002 were derived from electricity sales, with the balance each year derived from natural gas sales. 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 173,000 customers in its service territory of approximately 560 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 154,000 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. In 2004 CNG expanded its service territory into the towns of East Granby and Granby. Berkshire Gas serves approximately 36,000 customers in its service territory of approximately 520 square miles with a population of approximately 220,000. Berkshire Gas' service territory includes the cities of Pittsfield and North Adams.
Other businesses
The company's other businesses include a nonutility generating company, a FERC regulated liquefied natural gas peaking plant, retail energy marketing companies, a natural gas delivery company, a propane air delivery company, telecommunications assets, a district heating and cooling system, and an energy services company.
Cayuga Energy, Inc. owns electric generation facilities that sell power in the NYISO and PJM Interconnection, LLC wholesale markets at times of high demand.
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.
Energetix, Inc. and NYSEG Solutions, Inc. market electricity and natural gas services throughout upstate and central New York.
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.
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.
TEN Companies, Inc. owns and manages a district heating and cooling network in Hartford, Connecticut and owns an interest in the Iroquois Gas Transmission System.
The Union Water Power Company owns and manages real estate in Maine and New Hampshire and provides energy services throughout New England.
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. CMP no longer owns generating assets but retains its power entitlements under long-term contracts with NUGs and a power purchase contract with Vermont Yankee. In December 2004 the MPUC approved CMP's sale of those entitlements for various periods ranging from one to three years, through February 29, 2008. CMP's retail electricity prices are set to provide recovery of the costs associated with its ongoing power entitlement obligations. CMP's revenues and purchased power costs would fluctuate if it were required to be the standard-offer provider of electricity supply for retail customers. There is no effect on CMP's net income in such event, 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 2004 through purchases under long-term contracts with NUGs, the New York Power Authority and Constellation Nuclear and through 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 2004 through generation from its facilities (25% through nuclear, 22% through coal and natural gas and 3% through hydroelectric and peaking) and purchases under long-term contracts with the New York Power Authority, Constellation Nuclear and CGG. RG&E managed fluctuations in the cost of electricity for its remaining power requirements through the use of electricity contracts, both physical and financial.
Nuclear - RG&E sold Ginna to CGG in June 2004, but retains a power entitlement to 90% of Ginna's output under a 10-year contract with CGG. (See Item 7 - Sale of Ginna.)
Coal - RG&E's 2005 coal requirements are expected to be approximately 350,000 tons. RG&E's coal supply portfolio contains both spot and term agreements with multiple suppliers. In 2004, 90% of RG&E's coal requirements were purchased under contract and 10% were purchased on the spot market. RG&E maintains a reserve supply of coal ranging from 30 to 60 days' supply.
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, Berkshire Gas and Maine Natural Gas satisfy their gas supply requirements through gas supply purchases from BP Energy Company and other gas suppliers, 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 using 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 Energy East, NYSEG and RG&E, and are attached to the distribution system, or contracted for under long-term arrangements.
Franchises
The company's operating utilities, including CMP, NYSEG and RG&E, have valid franchises, with minor exceptions, from the municipalities in which they render service to the public.
Seasonal business
Winter peaking loads of electricity are primarily due to space heating usage and fewer daylight hours. Summer peak loads of electricity 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.
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. Energy East's major working capital requirements include gas inventories which are increased during the summer and fall for winter sales, accounts receivable which are highest during periods of peak sales, and cash requirements to pay for utility construction and operating expenses.
Competitive conditions
See Item 7 - Electric Delivery Business, Natural Gas Delivery Business, Other Businesses and Critical Accounting Estimates.
Research and development
The company's expenditures on research and development were $5 million each year in 2004, 2003 and 2002 (including $1 million for RG&E from July 2002), principally by NYSEG. RG&E's expenditures were $2 million for each year in 2004, 2003 and 2002. These expenditures were for internal research programs and for contributions to research administered by the NYSERDA, 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.
Environmental matters
See Item 3 - Legal proceedings, Item 7 - Electric Delivery Business, and Item 8 - Note 12 to the company's and Note10 to CMP's Consolidated Financial Statements, and Note 9 to NYSEG's Financial Statements and Note10 to 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, 2004, were approximately $17 million for Energy East, including $4 million for CMP, $3 million for NYSEG and $10 million for RG&E. For the period January 1, 2002, to June 30, 2002, RG&E had an additional $1 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 SPDES permits, which reflect water quality considerations for the protection of the environment. RG&E has SPDES permits for two of its generating stations in New York. The Energy Network owns interests in three natural gas-fired peaking generating stations and TEN Companies, Inc. owns and operates two steam plants, all of which have the required federal or state operating 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 (SPCC) regulations. Such regulations were recently revised and require that the company, CMP, NYSEG and RG&E update current oil SPCC plans and prepare new SPCC plans for locations that are covered under the regulations. These SPCC locations include electric operations service centers and substations.
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 generating stations have the required federal or state operating permits. Stack tests and continuous emissions monitoring indicate that the generating 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 1990 Amendments limit emissions of sulfur dioxide and nitrogen oxides and require emissions monitoring. The EPA allocates annual emissions allowances to RG&E's coal-fired generating station 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, the EPA has not finalized specific control requirements.
Regulations adopted 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, became effective on October 1, 2004 for nitrogen oxide and January 1, 2005 for sulfur dioxide. The current federal summertime limits for nitrogen oxides are now applied year round. Emissions reduction targets are set 50% below the current federal limits for sulfur dioxide and will be phased in between 2005 and 2008. Emissions reductions will be achieved through a New York State only market-based allowance trading system similar to those under the 1990 Amendments. Beyond those allocated to RG&E, there are few economically viable allowances available for trade.
RG&E purchases emission allowances as necessary in order to comply with the Clean Air Act, and estimates its cost for allowances will be approximately $4 million for 2005. 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: As a result of the Sale of Ginna, RG&E no longer has any responsibility to handle interim storage of Ginna's low level radioactive waste nor to dispose of high level radioactive waste including spent fuel. (See Item 7 - Sale of Ginna.)
Number of employees
As of January 31, 2005, Energy East had 6,092 employees, which includes 1,148 CMP employees, 2,540 NYSEG employees and 1,074 RG&E employees.
Financial information about geographic areas
Energy East, CMP, NYSEG and RG&E have no foreign operations.
Available information
Energy East Corporation 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 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 and the charters of the Audit, Compensation and Management Succession, and Nominating and Corporate Governance Committees are also available on its Internet Web site. Waivers of the Code of Conduct are not contemplated. However, in the unlikely event of an amendment to, or waiver from, the Code of Conduct applicable to the company's principal executive, financial and accounting officers, the company will post such information on its Web site. Access to these documents is available from the main page of Energy East's Internet Web site through "Financial Information" and then "Corporate Governance." Printed copies of these documents are also available upon request by contacting Investor Relations at (207) 688-4336.
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 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 located in the State of New York and operated by Cayuga Energy, a wholly-owned subsidiary; and one located in Pennsylvania for which Cayuga Energy manages fuel procurement and electricity sales.
The operating companies' generating facilities consist of:
(1)
Cayuga Energy's 85% share of the generating capability.
(2) 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 308 substations in Maine having an aggregate transformer capacity of 6,628,317 kilovolt-amperes. The transmission system consists of 2,565 circuit miles of line. The distribution system consists of 20,979 pole miles of overhead lines and 2,064 miles of direct bury and network underground lines.
NYSEG owns 430 substations in New York having an aggregate transformer capacity of 12,710,587 kilovolt-amperes. The transmission system consists of 4,391 circuit miles of line. The distribution system consists of 30,382 pole miles of overhead lines and 2,910 miles of direct bury and network underground lines.
RG&E owns 162 substations in New York having an aggregate transformer capacity of 6,451,000 kilovolt-amperes. 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:
Operating Company
Location
Miles of
Transmission
Pipeline
Miles of
Distribution
Pipeline
NYSEG
New York State
7,750
RG&E
New York State
8,409
SCG
Connecticut
-
3,664
CNG
Connecticut
-
3,582
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, NYSEG's or CNG's utility plant is subject to liens or mortgages securing first mortgage bonds. RG&E, Berkshire Gas and SCG have first mortgage bond indentures that constitute a direct first mortgage lien on substantially all of their respective 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 Note 6 to 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 9 to NYSEG's and Note 10 to RG&E's Financial Statements.
Since the NYPSC, DPUC, MPUC and 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 9 to NYSEG's and Note 10 to 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, financial position or cash flows.
(a) 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 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 generating stations were also sold to AES in May 1999. NYSEG furnished documents pursuant to the Attorney General's, the NYSDEC's and the 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 the EPA notified NYSEG by telephone that the 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, AES, NYSDEC and the New York Attorney General's office signed a consent decree on January 11, 2005, settling charges involving the Goudey, Greenidge, Hickling and Jennison generating stations. Under the terms of the decree, (i) NYSEG was assessed a $700 thousand penalty which AES will pay under the indemnity provisions of the Asset Purchase Agreement, and (ii) AES will install clean coal technology at Greenidge and pollution controls at Goudey, Hickling and Jennison to achieve the emission targets specified in the decree. Upon entry of the decree, which is expected to occur shortly, NYSEG is released by NYSDEC from all new source review liability for past operation of those four generating stations, and NYSEG will have no continuing liability or obligation with respect to future Clean Air Act compliance at these plants.
(b) In October 2000 NYSEG and Penelec received a new source review letter from EME Homer City Generation, L.P., a subsidiary of the purchaser of the Homer City generating 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 Homer City Generation, L.P. 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.
(c) 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 the 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 2000 to date
Energy East Corporation
Wesley W. von Schack
Chairman, President & Chief Executive Officer to date.
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 to August 2000.
Robert D. Kump
Vice President, Treasurer & Secretary, February 2002 to date; Vice President and Treasurer to February 2002; Treasurer of NYSEG to August 2000.
Robert E. Rude
Vice President and Controller to date; Executive Director, Corporate Planning of NYSEG to October 2000.
Robert M. Allessio
Executive Vice President and Chief Operating Officer of Connecticut Natural Gas Corporation and The Southern Connecticut Gas Company, May 2004 to date; Chief Executive Officer and President of Berkshire Energy Resources, September 2000 to date; Chairman and Chief Executive Officer of The Berkshire Gas Company, May 2004 to date; President of Berkshire Energy Resources and The Berkshire Gas Company, September 2000 to May 2004; Senior Vice President, Operating Services of Connecticut Natural Gas Corporation and The Southern Connecticut Gas Company, May 2003 to April 2004; President and Chief Operating Officer of The Berkshire Gas Company to September 2000.
Richard R. Benson
Vice President - Administrative Services of Energy East Management Corporation, June 2004 to date; Vice President, Human Resources of Energy East Management Corporation, October 2000 to June 2004; 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 to October 2000.
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. to October 2000.
Name
Age
Positions, offices and business
experience - January 2000 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 to January 2001.
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. to October 2000.
Wesley W. von Schack has an employment agreement for a term ending June 30, 2007, and Kenneth M. Jasinski has 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 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, Related Stockholder Matters and Issuer Purchases of Equity Securities
The company's common stock is listed on the New York Stock Exchange. The number of shareholders of record was 35,719 at January 31, 2005. See Item 8 - Note 18 to the company's Consolidated Financial Statements for information regarding high and low stock prices and dividends declared.
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.
Equity Compensation Plan Information
The following table provides information as of December 31, 2004, with respect to shares of common stock that may be issued under Energy East's 2000 Stock Option Plan and its Restricted Stock Plan.
(1)
See Item 8 - Note 14 to the company's Consolidated Financial Statements for information regarding the Restricted Stock Plan.
Issuer Purchases of Equity Securities
(1)
Represents shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan.
CMP, NYSEG and RG&E had no issuer purchases of equity securities during the quarter ended December 31, 2004.
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 84
NYSEG - page 111
RG&E - page 142
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 46
CMP - pages 84 to 88
NYSEG - pages 111 to 118
RG&E - pages 142 to 149
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 offsetting, nonspeculative derivative transactions. (See Item 8
Item 8. Financial Statements and Supplementary Data
Index to 2004 Financial Statements
Page
Energy East Corporation
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Common Stock Equity
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Financial Statement Schedule
II. Consolidated Valuation and Qualifying Accounts
Central Maine Power Company
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Common Stock Equity
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Financial Statement Schedule
II. Consolidated Valuation and Qualifying Accounts
New York State Electric & Gas Corporation
Statements of Income
Balance Sheets
Statements of Cash Flows
Statements of Changes in Common Stock Equity
Notes to Financial Statements
Report of Independent Registered Public Accounting Firm
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 Registered Public Accounting Firm
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
Management's Annual Report on Disclosure 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 SEC's rules and forms, is recorded, processed, summarized and reported, and is accumulated and communicated to the company's management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that their respective company's disclosure controls and procedures are effective.
Energy East Management's Annual Report on Internal Control Over Financial Reporting
Energy East's management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, an evaluation was conducted of the effectiveness of the internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by The Committee of Sponsoring Organizations of the Treadway Commission. Based on Energy East's evaluation under the framework in Internal Control - Integrated Framework, management concluded that Energy East's internal control over financial reporting was effective as of December 31, 2004.
Energy East management's assessment of the effectiveness of its internal control over financial reporting as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report on page 81.
Changes in Internal Control over Financial Reporting
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.
Item 9B.
Item 9B. Other Information
None for Energy East, CMP, NYSEG or RG&E.
Selected Financial Data
Energy East Corporation
Reclassifications: Certain amounts included in Selected Financial Data have been reclassified to conform to the 2004 presentation and to reflect discontinued operations.
(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 EPS 6 cents and the effect of restructuring expenses that decreased net income $24 million and EPS 19 cents.
(3) Includes the writedown of the company's investment in NEON Communications, Inc. that decreased net income $46 million and EPS 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.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Overview
Energy East's primary operations, its electric and natural gas utility operations, are subject to rate regulation. The approved regulatory treatment on various matters could significantly affect the company's financial position and results of operations. Energy East has long-term rate plans for NYSEG, RG&E, CMP, CNG, SCG and Berkshire Gas. The plans, which are discussed below, provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including exogenous and stranded costs, and provide stable rates for customers and revenue predictability for those six operating companies.
Energy East's management focuses its strategic efforts on those areas of the company that it believes would have the greatest effect on shareholder value. Efficient operations are a key aspect of increasing shareholder value. Management has implemented plans to achieve savings through a company-wide restructuring that was completed in early 2004 and continued consolidation of utility support services.
The continuing uncertainty in the evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings that could significantly affect operations, although the outcomes of the proceedings are difficult to predict. Those proceedings could affect the nature of the electric and natural gas utility industries in New York and New England and are described below.
The company engages in various investing and financing activities to meet its strategic objectives. The primary goal of investing activities is to maintain a reliable energy delivery infrastructure. Investing activities are funded primarily with internally generated funds. Financing activities are focused on maintaining adequate liquidity, improving credit quality and minimizing the cost of capital.
Strategy
Energy East has maintained a consistent "pipes and wires" strategy over the past several years, focusing on the transmission and distribution of electricity and natural gas rather than the more volatile generation and energy trading businesses. Achieving operating excellence and efficiencies throughout the company is central to this strategy. While Energy East has sold certain noncore businesses and the last of its substantial regulated generation assets, investment in infrastructure that supports the electric and natural gas delivery systems continued in 2004. Also, the creation of a "utility shared services" organization has improved efficiencies and achieved savings from the integration of the company's information systems, purchasing, accounting and finance functions.
The company's long-term regulatory agreements continue to be a critical component to its success. While specific provisions may vary among the company's public utility subsidiaries, the overall strategy includes creating a stable rate environment that allows the companies to earn a fair return while minimizing price increases and sharing benefits with customers.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Electric Delivery Business
The company's electric delivery business consists primarily of its regulated electricity transmission, distribution and generation operations in upstate New York and Maine.
RG&E 2004 Electric and Natural Gas Rate Agreements: In May 2003 RG&E filed a rate case with the NYPSC to recover costs that RG&E had incurred and will continue to incur in providing safe and reliable electric and natural gas service. On May 20, 2004, the NYPSC approved the Electric and Natural Gas Joint Proposals that had been negotiated with Staff of the NYPSC and other interested parties and that address RG&E's electric and natural gas rates through 2008.
Key features of the Electric Rate Agreement include:
Freezing electric delivery rates through December 2008, except for the implementation of a retail access surcharge effective May 1, 2004, that will recover $7 million annually.
Allowing RG&E to recover its actual electricity supply costs during the period May 1, 2004, through December 31, 2004, through an Electric Supply Reconciliation mechanism.
Refunding to customers over the term of the plan $110 million of the approximately $380 million net proceeds from the sale of Ginna, including refunding $60 million after the closing, and refunding the remaining $50 million over the following three years. (See Sale of Ginna and Note 2 to the company's Consolidated Financial Statements.)
Establishing an ASGA with the net proceeds from the sale of Ginna. Portions of the ASGA will be used as follows:
To compensate RG&E for incremental supply costs resulting from the sale of Ginna;
To cover $6 million of replacement purchased power costs incurred in connection with a 2003 Ginna refueling outage;
To provide RG&E with revenue equivalent to a $2 million annual increase in electric delivery rates; and
To compensate RG&E for maximizing the sale value of Ginna through a credit to RG&E of $3.3 million annually over the term of the agreement.
Establishing an earnings-sharing mechanism to allow customers and stockholders to share equally in earnings above a 12.25% ROE target. RG&E will be allowed to increase its earnings-sharing threshold to 12.50% by meeting yet-to-be-determined standards that will measure improvements in RG&E's retail access program. No sharing occurred in 2004 under this mechanism.
Ensuring that RG&E continues to maintain the high quality of service and reliability it currently provides by specifying service quality and reliability standards and capital investment objectives.
RG&E estimates that $145 million will remain in the ASGA at the end of 2008. At that time the ASGA may be used at the discretion of the NYPSC for rate moderation, among other things.
Key features of the Natural Gas Rate Agreement include:
Freezing natural gas delivery rates through December 2008, except for the implementation of a merchant function charge that will recover approximately $7 million annually beginning May 1, 2004.
Implementing a weather normalization adjustment to protect both customers and RG&E from fluctuating revenues due to swings in temperature outside a normal range.
Implementing gas cost incentive mechanisms to provide a means of sharing with customers any future gas supply cost savings that RG&E achieves.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Establishing provisions similar to those in the Electric Rate Agreement regarding earnings sharing and service quality and reliability. The level for earnings sharing is 12.00%, with the opportunity to increase it to 12.25% if certain targets are achieved. No sharing occurred in 2004 under this mechanism.
The RG&E 2004 Electric and Natural Gas Rate Agreements resolve all outstanding issues related to RG&E's requests filed with the NYPSC in 2003. Those issues include:
The deferral and recovery of costs, including interest, for restoration work resulting from a severe ice storm in April 2003.
Recovery of replacement purchased power costs incurred in 2003 in connection with a scheduled refueling outage for Ginna.
The deferral and true-up of estimated pension costs for the 16-month period through May 1, 2004, in accordance with the NYPSC's Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Post Retirement Benefits Other than Pensions.
In addition, RG&E has withdrawn its appeal of an order the NYPSC issued in March 2003 related to RG&E's February 2002 request filed with the NYPSC for new electric and natural gas rates that were to go into effect in January 2003.
Sale of Ginna: On June 10, 2004, after receiving all regulatory approvals, RG&E sold Ginna to CGG and received $429 million in cash at closing. RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna and provides for an ASGA, established at closing at approximately $357 million, and addresses the disposition of the asset sale gain. On September 9, 2004, RG&E received an additional $25 million from CGG related to certain post-closing adjustments, resulting in a $20 million increase to the ASGA. (See Note 2 to the company's Consolidated Financial Statements.)
Upon closing of the sale of Ginna, RG&E transferred $201 million of decommissioning funds to CGG. That amount fully meets the Nuclear Regulatory Commission's decommissioning funding requirements for Ginna. RG&E retained $77 million in excess decommissioning funds, which was credited to the ASGA. CGG is now responsible for all future decommissioning funding. The sale agreement included a 10-year, fixed-price power purchase agreement that calls for CGG to provide 90% of Ginna's output to RG&E.
RG&E Electric Rate Unbundling: In June 2003, as required by an NYPSC Order issued in March 2003 RG&E filed documentation with the NYPSC to unbundle commodity charges from delivery charges and to create electric commodity options for all customers. The Electric Rate Agreement provides for that unbundling and for the commodity options. Beginning January 1, 2005, customers have an opportunity to choose to purchase commodity service from RG&E at a fixed rate or at a price that varies monthly based on the market price of electricity. Alternatively, customers may continue to choose to purchase their commodity service from an ESCO. Customers enrolled in these new commodity options between October 1, 2004, and December 31, 2004. Customers who did not make a choice will be served under RG&E's variable price option. Approximately 77% of those customers who made a choice selected RG&E's fixed price option. About 25% of RG&E's load is now served under this option.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
RG&E Transmission Project: In September 2003 RG&E applied to the NYPSC for approval to upgrade its electric transmission system. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, NY area in order to assure adequate service to customers after the planned closing of RG&E's 257 megawatt coal-fired Russell Station in 2007. The estimated cost of the multi-year project is $75 million. Construction on the project is expected to begin in the spring of 2005.
On September 28, 2004, RG&E executed a Joint Proposal with Staff of the NYPSC, the NYSDEC and the New York State Department of Agriculture & Markets, requesting that the NYPSC issue a Certificate of Environmental Compatibility and Public Need for the project subject to certain terms and conditions. RG&E received the certificate from the NYPSC on December 15, 2004.
CMP Alternative Rate Plan: In September 2000 the MPUC approved CMP's ARP 2000. ARP 2000 applies only to CMP's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services. ARP 2000 began January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007. Effective July 1, 2004, CMP's distribution prices decreased by about 2% as a result of inflation being less than the productivity offset for 2004. In addition, CMP decreased its transmission rates to eliminate billings for congestion costs that have been fully recovered and, pursuant to its formula rate approved by the FERC, to reflect CMP's and the New England Power Pool's actual costs for 2003.
CMP Electricity Supply Responsibility: Under a Maine State Law adopted in 1997, CMP was mandated to sell its generation assets and relinquish its supply responsibility. CMP no longer owns any generating assets but retains its power entitlements under long-term contracts with NUGs and a power purchase contract with Vermont Yankee. In December 2004 the MPUC approved CMP's sale of those entitlements for various periods ranging from one to three years, through February 29, 2008, depending on the type of entitlement. CMP's retail electricity prices are set to provide recovery of the costs in excess of the entitlement sale associated with its ongoing power entitlement obligations.
Under Maine State Law the MPUC can mandate that CMP be a standard-offer provider of electricity supply service for retail customers if the MPUC should deem bids by competitive suppliers to be unacceptable. In January 2005 the MPUC chose suppliers of standard-offer electricity for the six months ending August 31, 2005, for the medium and large customer classes. In December 2004 the MPUC chose CEC Group as the new supplier of standard-offer electricity to CMP's residential and small commercial customers (100% for the first year, 66.6% for the second year and 33.3% for the third year) for a three-year period beginning March 1, 2005. CMP has no standard-offer obligations through August 2005 and has not had any standard-offer obligations since March 2002. If in the future CMP should have standard-offer obligations, there would be no effect on its net income because CMP is ensured cost recovery through Maine State Law for any standard-offer obligations. CMP's revenues and purchased power costs would fluctuate, however, if it were required to be a standard-offer provider. (See the company's Operating Results for the Electric Delivery Business, CMP's Results of Operations and Note 10 to the company's and Note 8 to CMP's Consolidated Financial Statements.)
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
CMP Stranded Cost Proceeding: Through its stranded cost rates, CMP recovers the above-market costs of its purchased power agreements, as well as costs incurred to decommission and dismantle the nuclear facilities in which CMP has an ownership share, pursuant to Maine statute. In January 2005 the MPUC approved new stranded cost rates for the three-year period ending February 2008.
CMP Nuclear Costs: CMP has ownership interests in three nuclear facilities in New England that have been permanently shut down, and are in the process of being decommissioned: Maine Yankee Atomic Power Company (38% ownership), Connecticut Yankee Atomic Power Company (6% ownership) and Yankee Atomic Electric Power Company (9.5% ownership). The Yankee companies commenced litigation in 1998 charging that the federal government had breached the contracts it entered into with each of the Yankee companies in 1983. The contracts provided for the federal government to begin removing spent nuclear fuel from the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear plants, which are owned by the Yankee companies, no later than January 31, 1998, in return for payments by each of the Yankee companies. Two federal courts found that the federal government did breach its contracts with the Yankee companies and other utilities. A trial to determine the monetary damages owed to the Yankee companies for the DOE's continued failure to remove spent nuclear fuel began in the U.S. Court of Federal Claims in July 2004 and final trial arguments were made in January 2005. The Yankee companies' individual damage claims are specific to each plant and include costs through 2010, the earliest year the DOE expects that it will begin removing fuel. The Yankee companies' damage claims total approximately $543 million and CMP's sponsor-weighted share is approximately $90 million. The claims also note additional costs that will be incurred for each year that fuel remains at the sites beyond 2010. If the Yankee companies prevail in these cases, any damages awarded by the Court of Federal Claims would be credited to their respective decommissioning or spent fuel trust funds. Any remaining funds would be returned to electric customers when decommissioning is complete. The Yankee companies expect a trial court decision in the second half of 2005. CMP cannot predict the outcome of this litigation.
Pursuant to the 2000 Settlement, on July 1, 2004, Connecticut Yankee filed a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of the costs of decommissioning. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars compared to the April 2000 estimate of $434 million approved in the 2000 Settlement. The revised estimate reflects the fact that Connecticut Yankee is now self-performing all work to complete the decommissioning of the plant due to the termination of Bechtel, the turnkey decommissioning contractor, in July 2003. In addition, the revised estimate reflects increases in the projected costs for spent fuel storage, security, and liability and property insurance. The estimated remaining costs for decommissioning and long-term spent fuel storage as of December 31, 2003, totaled approximately $504 million in 2003 dollars.
Connecticut Yankee is seeking recovery of incremental decommissioning costs and other damages from Bechtel and, if necessary, its surety. In response, Bechtel has filed a complaint in Connecticut Superior Court seeking damages of $93 million for wrongful termination of the decommissioning contract. Connecticut Yankee has filed counterclaims for excess completion costs and other damages. Discovery is under way and a trial is scheduled for May 2006. CMP cannot predict the outcome of this litigation.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
The revised schedule for decommissioning collections is based on the 2003 estimate. Based on the revised schedule, increased collections of $93 million annually commenced in January 2005 and extend through December 2010. Any increase in rates approved by the FERC will be charged to Connecticut Yankee's owners, including CMP, whose share of a $93 million increase would be approximately $6 million. Under regulatory settlements, CMP is allowed to defer for future recovery any increases in decommissioning costs. Pursuant to a recent stranded cost settlement, CMP will begin to collect the higher Connecticut Yankee decommissioning costs through rates in March 2005.
On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel filed a petition with the FERC asking it to determine that, if the FERC should find any of Connecticut Yankee's decommissioning costs were not prudently incurred, the owners may not recover those costs in rates that are ultimately charged to retail customers. Instead, the DPUC believes that the owners of Connecticut Yankee must bear the costs. Connecticut Yankee and its owners, including CMP, filed protests to contest this petition. On August 30, 2004, the FERC rejected the DPUC's petition; approved Connecticut Yankee's rate increase effective February 1, 2005, subject to refund; and set for hearing the remaining issues. The DPUC has requested rehearing of the FERC's August 30, 2004 Order. CMP cannot predict the outcome of these proceedings.
NYSEG Electric Rate Plan: In February 2002 the NYPSC issued an order approving a five-year NYSEG electric rate plan, which extends through December 31, 2006, and Energy East's merger with RGS Energy. NYSEG's and the company's earnings were lower in 2002 as a result of the electric rate plan because NYSEG's electric rates were adjusted to reflect the sale of generation assets completed in 1999.
The NYPSC February 2002 Order reduced annualized electric rates by $205 million for NYSEG customers effective March 1, 2002, which amounted to an overall average reduction of 13% for most customers. In the first rate year ending December 31, 2002, approximately $55 million of the annualized reduction was funded with the partial amortization of an ASGA created as a result of NYSEG's sale in 2001 of its interest in NMP2. The NYPSC February 2002 Order also requires equal sharing of earnings between NYSEG customers and shareholders of ROEs in excess of 15.5% for 2002, and equal sharing of the greater of ROEs in excess of 12.5% on electric delivery, or 15.5% on the total electric business (including supply) for each of the years 2003 through 2006. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $720 million. Earnings levels were sufficient to generate estimated sharing with customers of $17 million in 2004 and $7 million in 2003.
Nonutility Generation: CMP and NYSEG together expensed approximately $613 million for NUG power in 2004. They estimate that their combined NUG power purchases will total $674 million in 2005, $615 million in 2006, $563 million in 2007, $381 million in 2008 and $229 million in 2009. CMP and NYSEG continue to seek ways to provide relief to their customers from above-market NUG contracts that state regulators ordered the companies to sign, and which, in 2004, averaged 9.5 cents per kilowatt-hour for CMP and 10.2 cents per kilowatt-hour for NYSEG. Recovery of these NUG costs is provided for in CMP's stranded cost rates and NYSEG's current electric rate plan. (See Note 10 to the company's and Note 8 to CMP's Consolidated Financial Statements and Note 8 to NYSEG's Financial Statements.)
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive electric and natural gas markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets and providing recommendations concerning provider of last resort and related issues. In January 2004 the NYPSC issued a notice seeking additional comments in light of the passage of time and the evolution of competitive markets. In March and April 2004 NYSEG and RG&E submitted comments supporting periodic assessment of the retail competitive marketplace and opposing the adoption of any policies restricting customer choice of supplier or limiting the availability of supply options from any particular supplier. NYSEG and RG&E believe that the NYPSC should not adopt a single end-state vision for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.
On August 25, 2004, the NYPSC issued a Statement of Policy on Further Steps Toward Competition in Retail Energy Markets recommending that all potentially competitive utility functions be opened to competition. While it is not possible to determine when markets will become workably competitive, all utilities will be required to prepare plans to foster the development of retail energy markets. The plans can vary by individual utility, and NYSEG and RG&E do not expect that statement of policy to affect their commodity service options under their current rate plans.
In a separate phase of this proceeding, on August 25, 2004, the NYPSC issued a Statement of Policy on Unbundling and Order Directing Tariff Filings. Utilities are directed to file embedded cost studies and competitive rates in future rate plans or requests for extensions and to begin tracking the costs of and revenues generated by competitive energy services. The order also allows parties to file comments and replies on rate design issues discussed in the order.
NYSEG and RG&E are not able to predict what effect, if any, these latest developments will have on future operations.
New England RTO: In January 2003, in order to promote RTOs, the FERC issued a proposed policy statement on transmission pricing. The FERC proposed a 50 basis point ROE incentive adder on facilities for which transmission owners turn control over to an RTO and a 100 basis point ROE incentive adder for new transmission facilities found appropriate through an RTO planning process. In October 2003 ISO New England and the New England transmission owners, including CMP, made a joint filing with the FERC to establish ISO New England as a qualified RTO. As an RTO, ISO New England will be responsible for the independent operation of the regional transmission system and regional wholesale energy market. The transmission owners will retain ownership of their transmission facilities and control over their revenue requirements. In a related filing, in November 2003 the New England transmission owners, including CMP, requested a joint baseline ROE and the above incentives as part of the proposal for a New England RTO.
In March 2004 the FERC issued an order that accepted a six-state New England RTO as proposed by ISO New England and the New England transmission owners. The order approved the 50 basis point and the 100 basis point ROE incentive adders, but limited application of the 100 basis point adder to regional facilities, subject to suspension, hearing and application of the
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
FERC's Pricing Policy Statement, when it is issued. The order also accepted, subject to suspension and hearing, the New England transmission owners' proposed base level ROE of 12.8% applicable to rates for local and regional transmission service, to be effective, subject to refund, on the New England RTO operational commencement date, February 1, 2005. Evidentiary hearings on the final base level ROE and the incentive for new transmission investment began on January 25, 2005. A final decision from the FERC on those issues is not expected until the end of 2005. The New England transmission owners and ISO New England implemented the New England RTO effective February 1, 2005.
FERC Standard Market Design: In October 2001 FERC commenced a proceeding to consider national SMD issues, and in July 2002 issued a NOPR concerning those issues. The SMD NOPR proposes rules that would require, among other things, changes in the wholesale power markets, transmission planning, services and charges, market power monitoring and mitigation, and the organization and structure of ISOs. CMP, NYSEG and RG&E filed comments jointly with other transmission owners in November 2002 and in early 2003. In April 2003 the FERC issued a white paper on SMD in which the FERC accommodates greater regional flexibility and seeks further comments. The SMD white paper includes a preference for energy markets based on LMP, which represents a significant change for some regions of the country. The NYISO and ISO New England already operate markets based on LMP. The companies are not able to predict the SMD's ultimate effect, if any, on their results of operations or financial position. The LMP market design was incorporated into the New England RTO filing approved by the FERC, which is discussed above.
Transmission Planning and Expansion and Generation Interconnection: In July 2003 ISO New England and the NEPOOL submitted a filing to the FERC concerning transmission expansion cost allocation, which the FERC approved in December 2003. CMP, among other parties, requested rehearing of that FERC decision, arguing that it would require customers who would not benefit from new transmission projects to contribute to those project costs. On December 2, 2004, the FERC denied rehearing of its order. ISO New England and other parties filed a motion for clarification. The FERC issued an order on January 5, 2005, granting clarification and deciding that all of the pending transmission projects would be subject to the ISO New England cost allocation process.
The FERC approved the NYISO's comprehensive planning process for reliability needs on December 28, 2004, requiring several relatively minor changes to the NYISO proposal. NYSEG and RG&E support the NYISO plan. The NYISO made a related compliance filing on February 28, 2005. On February 25, 2005, the FERC issued an order giving itself more time to issue a decision on requests for rehearing related to this issue. Discussions continue among the NYISO market participants on an economic planning process.
In July 2003 the FERC issued Order 2003 regarding generation interconnection terms, conditions and cost allocation that would require modifications to the companies' interconnection processes. The FERC issued Order 2003-A in March 2004 and Order 2003-B in December 2004, reaffirming its determinations in Order 2003, clarifying certain provisions, and directing compliance. On February 18, 2005, the NYISO and the NYTOs submitted a joint compliance filing, pursuant to Order 2003-B, to modify certain sections of the Large Facility Interconnection Procedures and Large Facility Interconnection Agreement contained in the NYISO Open Access Transmission Tariff. Comments on the filing were due on March 11, 2005.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
In January and April 2004 the NEPOOL and the New England transmission owners made separate compliance filings in response to Orders 2003 and 2003-A. In November 2004 the FERC issued an order that accepted the NEPOOL filing in part and rejected the New England transmission owners' filing. On January 28, 2005, ISO New England and the New England transmission owners made a joint compliance filing, to supersede and replace their earlier separate filings, proposing a standardized agreement and single set of procedures for generators rated 5 megawatts or greater seeking interconnection service under the RTO tariff on or after February 1, 2005.
Manufactured Gas Plant Remediation Recovery: RG&E and NYSEG independently began cost contribution actions against FirstEnergy Corp. (formerly GPU, Inc.) in federal district court; RG&E in the Western District of New York in August 2000 and NYSEG in the Northern District of New York in April 2003. The actions are for both past and future costs incurred for the investigation and remediation of inactive manufactured gas plant sites. The RG&E action is also being mediated and the parties are in the final stages of discovery. RG&E and NYSEG are unable to predict the outcome of these actions at this time.
NYISO Billing Adjustment: The NYISO frequently bills transmission owners on a retroactive basis when adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission revenue or expense as appropriate when revised amounts can be estimated. On January 25, 2005, the NYISO notified NYTOs, including NYSEG and RG&E, of a revenue allocation formula error related to transmission congestion contracts for periods including May 2000 through October 2002. The NYISO has not yet provided any further details. The correction of the error may result in revised billings for NYSEG and RG&E. The companies cannot predict at this time either the magnitude or the direction of any billing adjustments.
Locational Installed Capacity Markets: In 2003 the FERC required ISO New England to file a proposed mechanism to implement by January 1, 2006, location or deliverability requirements in the installed capacity or resource adequacy market to ensure that generators that provide capacity within areas of New England are appropriately compensated for reliability. In response, in 2004 ISO New England developed and filed with the FERC a locational installed capacity (LICAP) market proposal based on an administratively set demand curve. The FERC has refused to consider alternatives to ISO New England's proposal and has set issues regarding the exact LICAP parameters and its implementation for hearing before a FERC administrative law judge. CMP and other parties representing customers who would ultimately pay the cost of the LICAP charges as a component of energy supply costs have opposed the FERC orders requiring an administratively set capacity market and ISO New England's particular proposal. Generators that supply capacity in ISO New England's market have generally supported the FERC's order and the basic design of ISO New England's proposal. A recommended decision by the FERC administrative law judge is expected by June 1, 2005. CMP cannot predict how the FERC will rule on the filing or what modifications the FERC might make to the filing.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Errant Voltage: In January 2005 the NYPSC issued an Order Instituting Safety Standards in response to a pedestrian being electrocuted from contact with an energized service box cover in New York City, which is outside the company's service territory. All New York utilities were directed to respond by February 19, 2005, with a report that provides a detailed voltage testing program, an inspection program and schedule, safety criteria applied to each program, a quality assurance program, a training program for testing and inspections and a description of current or planned research and development activities related to errant voltage and safety issues. The Order Instituting Safety Standards also denies utility requests for recovery of implementation costs and establishes criteria for utilities seeking authorization to recover costs as an incremental expense. In addition, penalties for failure to achieve annual performance targets for testing and inspections were established at 75 basis points each. NYSEG and RG&E have reviewed the NYPSC order and jointly filed in early February 2005, with two other New York State utilities, a petition for rehearing focused on several areas including the impracticability of the timetable established in the order. In addition, NYSEG and RG&E filed a separate petition for rehearing dealing with the recovery of incremental costs of complying with the order. NYSEG and RG&E do not know what actions will be taken on the petitions for rehearing. In late February 2005 NYSEG and RG&E filed a testing and inspection plan in response to the order consistent with the timetable identified in the above noted joint petition for rehearing.
CMP Union Contract: Effective April 30, 2004, the union contract expired between CMP and the local union of the International Brotherhood of Electrical Workers. On May 5, 2004, the union membership voted to accept CMP's offer for a new contract, which expires on April 30, 2009. The contract provides for wage increases of 3.25% in 2004, 3.0% in each year 2005, 2006 and 2007, and 2.75% in 2008. It also includes provisions for active employees to contribute to medical insurance plans by the end of the contract period and for employees who retire on or after July 1, 2005, to contribute toward the cost of medical insurance according to a predetermined schedule.
NYSEG Union Contract: The contract between NYSEG and the local unions of the International Brotherhood of Electrical Workers was scheduled to expire effective July 1, 2005. On October 19, 2004, the union membership voted to accept NYSEG's offer to extend the contract until June 30, 2010. The contract provides for annual 3% wage increases for 2005 through 2009. It includes provisions for active employees to contribute to medical insurance plans by the end of the contract period.
RG&E Union Contract: In April 2003 RG&E's electric and natural gas field operations personnel voted to be represented by the International Brotherhood of Electrical Workers. RG&E recognizes the employees' right to make this decision and respects the collective votes of its employees. A negotiated labor agreement is in effect for the period September 2003 through May 2008. The agreement provides for annual 3% wage increases.
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.
RG&E 2004 Electric and Natural Gas Rate Agreements: See Electric Delivery Business.
Natural Gas Supply Agreements: Energy East's natural gas companies - NYSEG, RG&E, SCG, CNG, Berkshire Gas and Maine Natural Gas - have a three-year strategic alliance with BP Energy Company, effective April 1, 2004, that provides the companies the right to acquire natural gas supply and optimizes transportation and storage services.
NYSEG Natural Gas Rate Plan: NYSEG's Natural Gas Rate Plan, which became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, implements a natural gas supply charge to collect the actual costs of natural gas and contains an earnings-sharing mechanism. The earnings-sharing mechanism requires equal sharing of earnings between NYSEG customers and shareholders of ROEs in excess of 11.5% for the 27-month period ended December 31, 2004, and in excess of 12.5% for each of the calendar years from 2005 through 2008. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $250 million. No sharing occurred in 2004 or 2003.
On June 30, 2004, NYSEG filed a Joint Proposal, executed by NYSEG and other parties, to resolve outstanding issues in NYSEG's Natural Gas Rate Plan related to its natural gas delivery rate design, natural gas economic development plan and its natural gas Affordable Energy Program. Pursuant to NYSEG's Natural Gas Rate Plan, delivery rate designs in the Joint Proposal were developed for each of the remaining years on an overall revenue neutral manner, consistent with the billing units and firm delivery revenues contained in NYSEG's Natural Gas Rate Plan. The NYPSC approved all provisions of the Joint Proposal effective September 23, 2004. The first year of a five-year phase-in of delivery rates for nonresidential customers went into effect October 1, 2004. The first of four annual changes to residential rates will become effective October 1, 2005.
NYPSC Collaborative on End State of Energy Competition: See Electric Delivery Business.
SCG Request for Recovery of Exogenous Costs: In December 2003 SCG filed an application with the DPUC to recover approximately $21 million of exogenous costs under its approved IRP. The exogenous costs to be recovered include qualified pension and other postretirement benefits expenses, taxes, uncollectible expense and the cost of SCG's Customer Hardship Arrearage Forgiveness Program. Those costs were the result of events that were unanticipated and beyond SCG's control. SCG's IRP decision from the DPUC allows SCG to petition for relief from substantial and material costs resulting from such exogenous events. The DPUC established a docket for this proceeding and hearings were held in April 2004. On October 27, 2004, the DPUC issued a final decision that denied current recovery of exogenous costs but recognized that the costs would be reviewed in SCG's next rate case. On December 9, 2004, SCG filed an appeal with the Connecticut Superior Court concerning certain aspects of the DPUC's decision.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Connecticut Regulatory Proceedings: SCG's IRP expires September 30, 2005. As a result of the DPUC's decision denying recovery of exogenous costs, SCG anticipates filing for rate relief in the second quarter of 2005. The rate filing will request, among other items, a greater level of recovery of deferred costs, similar to SCG's request for recovery of exogenous costs. CNG's IRP expires September 30, 2005, and CNG has notified the DPUC that it intends to continue to operate under an IRP for another multi-year period.
Connecticut Merger-Enabled Gas Supply Savings and Gas Cost Reduction Plan Filings: In 2001 CNG and SCG submitted filings to the DPUC regarding MEGS and a gas-cost reduction plan, which covered the initial period April 1, 2001, through September 30, 2001. CNG provided calculations for total MEGS of $1.3 million and SCG provided calculations for total MEGS of $2.2 million. In February 2003, based on its understanding of the components of the MEGS, the DPUC issued a draft decision on CNG's and SCG's filed MEGS and gas-cost reduction plan results, modifying the MEGS amounts to $134,000 for CNG and $9,000 for SCG. CNG and SCG filed comments and additional detail with regard to the draft decision. On March 26, 2004, the DPUC issued a notice that encouraged the parties to settle the MEGS issue, which resulted in the assignment of Prosecutorial Staff of the DPUC to assist in the settlement process. The docket was suspended to allow the settlement process to proceed. On September 22, 2004, Prosecutorial Staff reported that the parties had reached an agreement in principle to settle these proceedings. On December 17, 2004, a settlement between SCG, CNG, the Office of Consumer Counsel and the Prosecutorial Division of the Department was filed with the DPUC. The settlement fully resolves the companies' claims to MEGS. Hearings took place in February 2005 and the final decision on this settlement was approved on February 23, 2005.
NYSEG Union Contract: See Electric Delivery Business.
RG&E Union Contract: See Electric Delivery Business.
Berkshire Gas Union Contract: Effective April 1, 2003, the union contract expired between Berkshire Gas and the local union of the United Steelworkers of America. In 2004 the union members voted to accept Berkshire Gas' offer of a new contract that will expire on March 31, 2009. The contract provides for wage increases of 3% for each year of the contract.
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 company.
Sale of Other Businesses: The company continues to rationalize its nonutility businesses to ensure that they fit its strategic focus. On July 26, 2004, UWP, a subsidiary of CMP Group, sold all of the assets related to its utility locating and construction divisions. The after-tax loss resulting from the sale was approximately $7 million and includes a reduction in the goodwill that was assigned to UWP at the time of Energy East's purchase of CMP Group. On October 1, 2004, Energy East Solutions, Inc., a subsidiary of The Energy Network, Inc., completed the sale of its New England and Pennsylvania natural gas customer contracts and related assets. (See Note 3 to the company's Consolidated Financial Statements.)
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Other Matters
New Accounting Standard
Statement 123R: In December 2004 the FASB issued Statement 123R, which is a revision of Statement No. 123. Statement 123R requires a public entity to measure the cost of employee services that it receives in exchange for an award of equity instruments based on the grant-date fair value of the award and recognize that cost over the period during which the employee is required to provide service in exchange for the award. Statement 123R also requires a public entity to initially measure the cost of employee services received in exchange for an award of liability instruments based on the award's current fair value, subsequently remeasure the fair value of the award at each reporting date through the settlement date and recognize changes in fair value during the required service period as compensation cost over that period. The company's adoption of Statement 123R is not expected to have a material effect on its financial position or results of operations. (See Note 1 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, 2004, the company's contractual obligations and commercial commitments are:
(1)
Amounts for long-term debt and capital lease obligations include future interest payments. Future interest payments on variable-rate debt are determined using the rates at December 31, 2004.
(2) See Sale of Ginna.
(3) Amounts are through 2014 only.
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. RG&E has a credit agreement in which it covenants to maintain the same debt and earnings ratios as in its joint revolving credit agreement. (See Note 8 to the company's and Note 6 to CMP's Consolidated Financial Statements, and Note 6 to NYSEG's and Note 7 to RG&E's Financial Statements.)
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
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 perform the annual impairment analyses for goodwill and other intangible assets, to calculate pension and other postretirement benefits and to estimate unbilled revenues.
Statement 71: Statement 71 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.
Goodwill and Other Intangible Assets: The company does not amortize goodwill or intangible assets with indefinite lives. The company tests both goodwill and intangible assets with indefinite lives for impairment at least annually. The company amortizes intangible assets with finite lives and reviews them for impairment. Impairment testing includes various assumptions, primarily the discount rate and forecasted cash flows. Impairment testing was conducted using a range of discount rates representing the company's marginal, weighted-average cost of capital and 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. The company did not have any impairment in 2004 of its goodwill or intangible assets with indefinite lives. (See Note 5 to the company's and Note 3 to CMP's Consolidated Financial Statements and Note 3 to NYSEG's and Note 4 to RG&E's Financial Statements.)
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
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 87 and Statement 106, 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, 2004, the company decreased the discount rate from 6.25% to 5.75%. (See Item 7A - Quantitative and Qualitative Disclosures About Market Risk - Other Market Risk, and Note 16 to the company's and Note 13 to CMP's Consolidated Financial Statements, and Note 12 to NYSEG's and RG&E's Financial Statements.)
Unbilled Revenues: The company's unbilled revenues represent estimates of receivables for energy provided but not yet billed. The estimates are determined based on various assumptions, such as current month energy load requirements, billing rates by customer classification and loss factors. Changes in those assumptions could significantly affect the estimates of unbilled revenues.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Liquidity and Capital Resources
Cash Flows
The following table summarizes the company's consolidated cash flows for 2004, 2003 and 2002.
Due to the merger completed on June 28, 2002, the company's consolidated cash flows include RGS Energy beginning with July 2002.
The total of cash flows from operating and investing activities in 2004 was $572 million as compared to $213 million in 2003. The increase of $359 million was primarily due to proceeds from the sale of Ginna and excess decommissioning funds retained that totaled $530 million. That increase was partially offset by a decrease in net cash provided by operating activities in 2004 related to the sale of Ginna. (See Note 2 to the company's Consolidated Financial Statements.)
Operating Activities Cash Flows: Net cash provided by operating activities was $339 million in 2004 compared to $476 million in 2003 and $451 million in 2002. The $137 million decrease in 2004 primarily resulted from:
The $60 million of net proceeds from the sale of Ginna that was refunded to RG&E customers in 2004 as provided in RG&E's Electric Rate Agreement.
Increased tax payments of $74 million primarily due to the elimination of deferred tax liabilities due to the sale of Ginna.
Increased expenditures of $44 million to replenish natural gas inventories.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
The $24 million increase in net cash provided by operating activities in 2003 was primarily due to:
A full year of cash flows provided by operating activities in 2003 compared to six months in 2002, as a result of the company's acquisition of RGS Energy in June 2002.
The company's pension plans generated pretax noncash pension income (net of amounts capitalized) of $29 million in 2004, $40 million in 2003 and $70 million in 2002. The $11 million decrease in 2004 and the $30 million decrease in 2003 were primarily due to revised actuarial assumptions including the discount rate used to compute the company's pension liability (reduced from 7.0% to 6.50% as of December 31, 2002, and to 6.25% as of December 31, 2003). Pension income for 2005 is estimated at $26 million. The company estimates contributions of $54 million to its pension plans in 2005. (See Note 16 to the company's Consolidated Financial Statements.)
Investing Activities Cash Flows: Net cash provided by investing activities was $233 million in 2004 compared to net cash used in investing activities of $263 million in 2003 and $862 million in 2002. The $495 million increase in cash in 2004 primarily resulted from the sale of Ginna. The decrease in cash used of $599 million in 2003 was primarily due to the effect of $681 million of cash paid in 2002 to acquire RGS Energy, net of $59 million of cash received in 2002 related to NYSEG's sale of its interest in NMP2 in 2001.
Capital spending totaled $299 million in 2004, $303 million in 2003, and $229 million in 2002, including capital spending for RGS Energy beginning with July 2002 and nuclear fuel for RG&E from July 2002 until early June 2004. Capital spending in all three years was financed principally 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 beginning in 2003.
Capital spending is projected to be $388 million in 2005. It is expected to be paid for principally with internally generated funds and will be primarily for the same purposes described above, as well as a customer care system and an Infrastructure Replacement Program. (See Note 10 to the company's Consolidated Financial Statements.)
Financing Activities Cash Flows: Net cash used in financing activities was $472 million in 2004 compared to $363 million in 2003. The $109 million increase was primarily the result of higher net repayments of debt due in part to funds available from the sale of Ginna. For 2002, the $270 million of net cash provided by financing activities reflects the company's borrowing to fund the acquisition of RGS Energy.
The financing activities discussed below include those activities necessary for the company and its principal subsidiaries to maintain adequate liquidity, improve credit quality and ensure access to capital markets. Activities include minimal common stock issuances in connection with the company's Investor Services Program and employee stock-based compensation plans, and various medium-term and long-term debt transactions. They also include steps taken by RG&E to revise its capital structure as a result of the sale of Ginna. (See Notes 7, 8 and 9 to the company's Consolidated Financial Statements.)
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
The company's financing activities included:
Raising its common stock dividend 6% in October 2004 to a new annual rate of $1.10 per share and raising its long-term dividend payout ratio target from 65% to 75% of earnings.
During 2004 issuing 871,838 shares of company common stock, at an average price of $23.99 per share, through the company's Investor Services Program. The shares were original issue shares.
In the first quarter of 2004, awarding 242,038 shares of company common stock, issued out of treasury stock, to certain employees through the company's Restricted Stock Plan, and recording deferred compensation of $6 million based on the market price per share of common stock on the dates of the awards, which averaged $23.90.
In December 2004 repurchasing at a premium, $17 million of 5.75% notes, due November 15, 2006, with proceeds from the sale of Ginna.
NYSEG Financing Activities: In August 2004 NYSEG refunded an aggregate $204 million of fixed-rate tax-exempt pollution control notes with interest rates ranging from 5.70% to 6.05% with proceeds from the issuance of $204 million of multi-mode tax-exempt pollution control notes with due dates ranging from 2027 to 2034.
RG&E Financing Activities: RG&E used proceeds from the sale of Ginna to significantly reduce its capitalization. The following long-term debt and preferred stock redemptions were financed through available cash and RG&E's short-term credit facility. The short-term credit facility was repaid with proceeds from the sale of Ginna. Any premiums paid to refund the debt and preferred stock are being amortized over five years in accordance with RG&E's Electric and Natural Gas Rate Agreements.
In May 2004 RG&E redeemed, at a premium, the following first mortgage bonds:
$40 million of 7.45% Series due July 2023.
$33 million of 7.64% Series due March 2023.
$5 million of 7.66% Series due March 2023.
$12 million of 7.67% Series due March 2023.
In March and May 2004 RG&E redeemed the following issues of preferred stock:
$25 million of 6.60% Series V at par.*
$12 million of 4% Series F at a premium.
$8 million of 4.10% Series H at a premium.
$6 million of 4 3/4% Series I at a premium.
$5 million of 4.10% Series J at a premium.
$6 million of 4.95% Series K at a premium.
$10 million of 4.55% Series M at a premium.
*The Series V preferred stock was mandatorily redeemable and was classified as a liability as of July 1, 2003, in accordance with Statement 150.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
In August 2004 RG&E refunded an aggregate $60 million of secured fixed-rate tax-exempt pollution control notes with interest rates ranging from 6.35% to 6.5% with proceeds from the issuance of $60 million of secured multi-mode tax-exempt pollution control notes due 2032.
In September 2004 RG&E repurchased at a premium $39 million of Series TT 6.95% first mortgage bonds, due April 1, 2011, with proceeds from the sale of Ginna.
Available Sources of Funding
The company and its subsidiaries have revolving credit agreements with various expiration dates from 2005 through 2009 and pay fees in lieu of compensating balances in connection with those credit agreements. The agreements provided for maximum borrowings of $740 million at December 31, 2004, and $700 million at December 31, 2003.
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 $206 million of such short-term debt outstanding at December 31, 2004, and $308 million outstanding at December 31, 2003. The weighted-average interest rate on short-term debt was 2.8% at December 31, 2004, and 1.8% at December 31, 2003.
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 under this shelf registration, if any, for general corporate purposes, such as the repurchase or refinancing of securities. The company currently has $805 million available under the shelf registration statement.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Results of Operations
Due to the merger completed on June 28, 2002, the company's results of operations include RGS Energy beginning with July 2002.
2004 Earnings Per Share
Earnings per share from continuing operations, basic for 2004 increased 20 cents compared to 2003 primarily because of:
Additional earnings of 16 cents per share as a result of one-time and ongoing effects from RG&E's 2004 Electric and Natural Gas Rate Agreements, including ratemaking treatment for the sale of Ginna. The one-time effects, which added 7 cents per share, include the flow-through of excess deferred taxes and ITCs and the settlement of certain regulatory assets and liabilities established pending regulatory determination. Ongoing effects added 9 cents per share to earnings, and include increases as a result of RG&E's electric retail access surcharge and natural gas merchant function charge, and annual credits from the ASGA as provided in RG&E's Electric Rate Agreement.
An increase of 10 cents per share from lower financing costs and savings from integration and efficiency initiatives. Financing costs decreased principally due to redemptions and refinancings of first mortgage bonds and preferred stock of subsidiaries funded, in part, by proceeds from the sale of Ginna, as well as the sale of certain nonutility businesses in 2003 and 2004 and internally generated funds.
The effect of a loss on retirement of debt that reduced earnings 9 cents per share in 2003.
Those increases were partially offset by:
Lower income from natural gas operations, due in part to a 2% drop in retail sales, which reduced earnings 7 cents per share.
A reduction of 6 cents per share due to cumulative stock-based compensation because of changes in the market value of Energy East common stock during 2004.
A decrease of 3 cents per share because of higher depreciation expense due to electric plant additions, excluding depreciation related to Ginna.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
2003 Earnings Per Share
Earnings from continuing operations for 2003 decreased 2 cents per share compared to 2002. The per share amounts were affected by an increase in average shares outstanding as a result of the merger with RGS Energy completed in June 2002. Major factors influencing the decrease include:
A decline of 15 cents per share due to lower noncash pension income.
An electric rate reduction of $205 million ordered by the NYPSC for NYSEG, effective March 1, 2002, that reduced 2003 earnings 11 cents per share.
A higher effective tax rate due to changes in estimates of income tax accruals for both 2002 and 2003 that reduced earnings 9 cents per share.
A decrease of 4 cents per share because of lower transmission revenue.
Higher purchased energy costs that reduced earnings 3 cents per share.
A net decrease of 2 cents per share due to losses on the retirement of debt, reflecting a loss of 9 cents per share in 2003, partially offset by the effect of a loss of 7 cents per share in 2002.
Those decreases were partially offset by:
An increase of 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.
Cost control efforts and synergy efficiencies, including lower interest charges, that added 8 cents per share to earnings.
The effect of restructuring expenses that reduced earnings 19 cents per share in 2002.
The effect of a writedown of the company's investment in NEON Communications that reduced earnings 6 cents per share in 2002.
Other Items
Other Operating Expenses: Net periodic pension income is included in other operating expenses and reduces the amount of expense that would otherwise be reported. Other operating expenses would have been $11 million lower for 2004 and $30 million lower for 2003 if net periodic pension income for each of those years had not decreased compared to the prior year.
Other (Income) and Other Deductions: (See Note 1 to the company's Consolidated Financial Statements.) The changes for 2004 include:
A $14 million increase in Other (income), primarily due to higher interest income of $3 million and a $6 million increase as a result of RG&E's 2004 Electric Rate Agreement.
A $17 million decrease in Other deductions primarily due to the effect of a $23 million loss on retirement of debt in 2003.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
The changes for 2003 include:
A $3 million decrease in Other (income) as a result of lower interest income.
A $3 million increase in Other deductions primarily due to the net effects of losses on retirement of debt in 2003 and 2002.
Interest Charges, Net and Preferred Stock Dividends of Subsidiaries: Interest charges, net and preferred stock dividends of subsidiaries decreased $23 million in 2004. In July 2003 the company began to recognize as interest expense certain distributions that it had previously recognized as preferred stock dividends. The combined decrease is primarily due to:
Refinancings of long-term debt at lower interest rates.
Redemptions and repurchases of first mortgage bonds and preferred stock of subsidiaries.
Interest charges increased $29 million in 2003 due to:
A $27 million increase due to the addition of RG&E's interest expense for a full year.
A $15 million increase because the company began to recognize as interest expense effective July 1, 2003, certain distributions that it had previously recognized as preferred stock dividends. There was a corresponding decrease in preferred stock dividends of subsidiaries in 2003 because of this change.
A $14 million increase that reflects borrowings in June 2002 to finance the company's merger transaction with RGS Energy.
Those increases were partially offset by:
Savings of $26 million primarily due to refinancings and repayments of first mortgage bonds.
Income Tax Expense: The effective tax rate for continuing operations was 51% in 2004, 36% in 2003 and 31% in 2002.
The increase in the 2004 effective tax rate was primarily due to:
Regulatory treatment of RG&E's deferred gain on the sale of Ginna. RG&E recorded pretax income of $112 million and income tax expense of $112 million. (See Note 2 to the company's Consolidated Financial Statements.)
Increases due to changes in estimates of prior year taxes of $3 million.
The effective tax rate increased in 2003 primarily due to:
The recognition as interest expense effective July 1, 2003, of $15 million of distributions that the company had previously recognized as preferred stock dividends.
The effect of depreciation and amortization not normalized related to RG&E for a full year in 2003 compared to six months in 2002. (See Note 6 to the company's Consolidated Financial Statements.)
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Operating Results for the Electric Delivery Business
Operating Revenues
: The $23 million increase in 2004 operating revenues was primarily the result of:
Higher wholesale sales of $68 million primarily for NYSEG. The increase reflected higher market prices and increased activity to mitigate supply prices.
An increase of $5 million due to higher retail deliveries.
Certain provisions of RG&E's Electric Rate Agreement that added $10 million to revenues, including $4 million from a retail access surcharge and $6 million as a result of various credits from the ASGA.
Those increases were partially offset by:
A decrease of $27 million due to rate reductions for CMP reflecting lower stranded costs and lower amortization of storm and DSM costs.
A $19 million decrease due to a change in market structure for RG&E that allows ESCOs to provide electricity, resulting in lower retail revenues partially offset by higher wholesale revenues.
A $15 million decrease for NYSEG due to reductions in the amount of electricity supplied by NYSEG under its various commodity options.
Operating revenues for 2003 increased $190 million primarily as a result of:
The addition of RG&E delivery revenues of $343 million.
That increase was partially offset by:
A $35 million decrease for RG&E due to lower retail deliveries because of cooler summer weather.
A decrease of $24 million due to the combined effects of NYSEG's rate reduction, effective March 2002, and customers choosing alternate suppliers.
A reduction of $46 million due to the elimination in 2002 of the partial amortization of an ASGA that was used to fund a portion of NYSEG's rate reduction effective March 2002.
A decrease of $18 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002.
An $11 million decrease due to lower transmission revenues.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Operating Expenses: The $84 million decrease in operating expenses for 2004 was primarily the result of:
A net $112 million decrease resulting from the regulatory treatment of RG&E's gain on the sale of Ginna, which includes RG&E's recognition of a $341 million pretax gain partially offset by the after-tax deferral of the gain of $229 million.
Reduced operating costs of $73 million, including reduced depreciation and decommissioning expenses of $32 million, as a result of the sale of Ginna.
A $10 million decrease in RG&E's operating and maintenance costs because of certain deferral petitions that were resolved as part of RG&E's Electric Rate Agreement.
Lower operating costs of $5 million because CMP completed its amortization of storm and DSM costs as of the end of June 2004.
Those decreases were partially offset by:
Increased purchased power costs of $91 million for RG&E due to the purchases from Ginna beginning in June 2004.
A $42 million increase due to higher purchased power costs, primarily for increased wholesale sales.
Higher depreciation of $7 million due to significant additions to plant in service and the accelerated depreciation of legacy accounting systems that were replaced in 2004.
Operating expenses for 2003 increased $193 million primarily as a result of:
The addition of RG&E operating expenses of $282 million.
That increase was partially offset by decreases in purchased power costs, including:
A $53 million decrease due to the net effect of customers choosing alternate suppliers and increases caused by both higher market prices and higher retail deliveries because of colder winter weather.
An $18 million decrease because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002.
Lower NUG power purchases of $12 million.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy East Corporation
Operating Results for the Natural Gas Delivery Business
Operating Revenues: Operating revenues for 2004 increased $87 million primarily as a result of:
Higher market prices of natural gas of $120 million that were passed on to customers.
That increase was partially offset by:
Lower retail deliveries of $12 million due to warmer winter weather in the first quarter of 2004, partially offset by higher deliveries in the fourth quarter of 2004.
Lower transportation revenue and wholesale entitlements of $28 million.
2003 operating revenues increased $430 million primarily as a result of:
The addition of RG&E delivery revenues of $213 million.
A $50 million increase due to higher retail deliveries because of colder winter weather in the first quarter of 2003.
An increase of $158 million largely due to higher market prices of natural gas that were passed on to customers.
Operating Expenses
: The $103 million increase in 2004 operating expenses was primarily the result of:
Higher natural gas prices of $120 million because of market conditions.
That increase was partially offset by lower natural gas purchases, including:
Decreases of $6 million due to lower retail deliveries and $16 million due to lower wholesale sales.
Operating expenses for 2003 increased $380 million primarily as a result of:
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.
A $28 million increase in natural gas purchases due to higher retail deliveries because of colder winter weather in the first quarter of 2003.
Energy East Corporation
Consolidated Statements of Income
The
notes on pages 52 through 80 are an integral part of the consolidated financial statements.
Energy East Corporation
Consolidated Balance Sheets
The
notes on pages 52 through 80 are an integral part of the consolidated financial statements.
Energy East Corporation
Consolidated Balance Sheets
The
notes on pages 52 through 80 are an integral part of the consolidated financial statements.
Energy East Corporation
Consolidated Statements of Cash Flows
The
notes on pages 52 through 80 are an integral part of the consolidated financial statements.
Energy East Corporation
Consolidated Statements of Changes in Common Stock Equity
The
notes on pages 52 through 80 are an integral part of the consolidated financial statements. Notes to Consolidated Financial Statements
Energy East Corporation
Note 1. Significant Accounting Policies
Background: Energy East 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 - Berkshire Gas; CMP Group - CMP; CNE - SCG; CTG Resources - CNG; and RGS Energy - NYSEG and RG&E. Financial information for RGS Energy prior to July 1, 2002, does not include NYSEG since it was not a subsidiary of RGS Energy prior to that time.
Accounts receivable: Accounts receivable include unbilled revenues of $227 million at December 31, 2004, and $219 million at December 31, 2003, and are shown net of an allowance for doubtful accounts of $45 million at December 31, 2004, and $53 million at December 31, 2003. Accounts receivable do not bear interest, although late fees may be assessed. Bad debt expense was $45 million in 2004, $48 million in 2003 and $46 million in 2002. Bad debt expense for 2003 includes RGS Energy for a full year and for 2002 includes RGS Energy beginning July 1, 2002. The allowance for doubtful accounts is the company's best estimate of the amount of probable credit losses in its existing accounts receivable. The company determines the allowance based on experience for each region and operating segment and other economic data. Each month the company reviews its allowance for doubtful accounts and its past due accounts over 90 days and/or above a specified amount. The company reviews all other balances on a pooled basis by age and type of receivable. When the company believes that a receivable will not be recovered, it charges off the account balance against the allowance. The company does not have any off-balance-sheet credit exposure related to its customers.
Asset retirement obligation: In June 2001 the FASB issued Statement 143. 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. In accordance with Statement 143, the company records the fair value of the liability for an asset retirement obligation in the period in which it is incurred and capitalizes the cost by increasing the carrying amount of the related long-lived asset. The company adjusts the liability to its present value periodically over time, and depreciates the capitalized cost over the useful life of the related asset. Upon settlement the company will either settle the obligation at its recorded amount or incur a gain or a loss. The company's rate-regulated entities will defer any timing differences between rate recovery and book expense as either a regulatory asset or a regulatory liability. The company's asset retirement obligation was $437 million at December 31, 2003. Substantially all of that amount was related to Ginna, which was sold in June 2004 and reduced the asset retirement obligation $434 million. The remaining balance of $2 million primarily consists of obligations related to cast iron gas mains.
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. The company classifies these amounts as accrued removal obligations.
Notes to Consolidated Financial Statements
Energy East Corporation
Basic and diluted earnings per share: Basic EPS is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the period. 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 SARs. Historically, all stock options have been issued in tandem with SARs and 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 reported net income.
The reconciliation of basic and dilutive average common shares for each period follows:
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: 2.0 million in 2004, 2.9 million in 2003 and 4.7 million in 2002. See Note 14 for additional information concerning Energy East's restricted stock.
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 resulted in corresponding decreases in the regulatory asset for the asset retirement obligation. As a result of the sale of Ginna on June 10, 2004, the company no longer has a decommissioning obligation and will not incur additional decommissioning expense. (See Note 11 for information about decommissioning expenses incurred by companies that are partially owned by CMP.)
Notes to Consolidated Financial Statements
Energy East Corporation
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 - 54 years, distribution property - 47 years, generation property - 46 years, gas production property - 30 years, gas storage property - 33 years, and other property - 33 years. RG&E determines depreciation expense for the majority of its 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 4 years for its coal station to 32 years for its hydroelectric stations. The company's depreciation accruals were equivalent to 3.3% of average depreciable property for 2004; 3.4% for 2003 and 3.5% for 2002, which was weighted for the effect of the merger completed in June 2002.
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 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. An impairment may be recognized if the fair value of goodwill is less than its carrying value. (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. ITCs are amortized over the estimated lives of the related assets.
Notes to Consolidated Financial Statements
Energy East Corporation
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 in the consolidated financial statements to conform to the 2004 presentation and to reflect discontinued operations.
Regulatory assets and liabilities: Pursuant to Statement 71 the company's operating utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. They also record, 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, DSM program costs, gain on sale of generation assets, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with each company's current rate plans. The operating utilities earn 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 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.
NYSEG and RG&E enter into power purchase and sales transactions with the NYISO. When NYSEG and RG&E sell electricity from owned generation to the NYISO, and subsequently repurchase electricity from the NYISO to serve their customers, they record the transactions on a net basis in their statements of income.
Notes to Consolidated Financial Statements
Energy East Corporation
Risk management: All of Energy East's natural gas operating utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. The company uses natural gas futures and forwards to manage fluctuations in natural gas commodity prices and provide price stability to customers. The company includes the cost or benefit of natural gas futures and forwards 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 company includes the cost or benefit of those contracts 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 derivative instruments to mitigate risk resulting from interest rate changes on future financings. The company amortizes amounts paid or received under those instruments to interest expense over the life of the corresponding financing.
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 other assets or other liabilities. The company had $37 million of derivative assets at December 31, 2004, including $9 million current and $28 million long-term. The company had $19 million of derivative liabilities at December 31, 2004, including $8 million current and $11 million long-term. At December 31, 2003, the company's had $65 million of derivative assets and $3 million of derivative liabilities. All of the arrangements are designated as cash flow hedging instruments except for the company's fixed-to-floating interest rate swap agreements totaling $250 million, which are designated as fair value hedges. 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 agreements 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 determine the fair value of 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, 2004, the maximum length of time over which the company is hedging its exposure to the variability in future cash flows for forecasted energy transactions is 60 months. The company estimates that losses of $8 million will be reclassified from accumulated other comprehensive income into earnings in 2005, 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 133, as amended.
Notes to Consolidated Financial Statements
Energy East Corporation
FIN 46R: In December 2003 the FASB issued FIN 46R, which 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 Accounting Research Bulletin 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. As of March 31, 2004, the company was required to apply FIN 46R to all entities subject to the interpretation.
CMP and NYSEG have independent, ongoing, power purchase contracts with various NUGs. CMP and NYSEG were not involved in the formation of and do not have ownership interests in any NUGs. CMP and NYSEG evaluated each of their power purchase contracts with NUGs with respect to FIN 46R. Most of the power purchase contracts were determined not to be variable interests for one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUGs are either governmental organizations or individuals.
The companies are not able to apply FIN 46R to seven remaining NUGs because they are unable to obtain the information necessary to: (1) determine if the NUGs are variable interest entities, (2) determine if either CMP or NYSEG is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of the seven NUGs. CMP requested necessary information from four NUGs and NYSEG requested information from three NUGs. None of the NUGs provided the requested information. CMP and NYSEG will continue to make efforts to obtain information from the seven NUGs.
The companies purchase electricity from the seven NUGs at above-market prices. CMP and NYSEG are not exposed to any loss as a result of their involvement with NUGs because they are allowed to recover through rates the cost of their purchases. Also, they are under no obligation to a NUG if it decides not to operate for any reason. The combined contractual capacity for the four NUGs from which CMP purchases electricity is approximately 23 megawatts. CMP's purchases from the four NUGs totaled $11 million in 2004 and 2003, and $10 million in 2002. The combined contractual capacity for the three NUGs from which NYSEG purchases electricity is approximately 494 megawatts. NYSEG's purchases from the three NUGs totaled $314 million in 2004, $335 million in 2003, and $341 million in 2002.
CMP and NYSEG did not consolidate any NUGs at December 31, 2004 or 2003.
Stock-based compensation: As permitted by Statement 123, the company applies APB 25 to account for its stock-based compensation to employees and uses the intrinsic value method to determine compensation related to its stock options issued in tandem with SARs. The company's stock-based compensation plans are described in more detail in Note 14. The company incurs a liability for its stock option plan awards because employees can compel the company to settle the awards in cash rather than by issuing equity instruments. Stock-based
Notes to Consolidated Financial Statements
Energy East Corporation
employee compensation expense, net of related tax effects, included in the company's net income was $13 million in 2004, $3 million in 2003 and $7 million in 2002. Those amounts are the same as they would have been if the fair value based method had been applied to all stock-based compensation awards consistent with Statement 123. Net income and basic and diluted EPS as reported for 2004, 2003 and 2002 are also the same as they would have been if the fair value based method had been applied to all awards.
Statement 123R: In December 2004 the FASB issued Statement 123R, which is a revision of Statement 123. Statement 123R requires a public entity to measure the cost of employee services that it receives in exchange for an award of equity instruments based on the grant-date fair value of the award and recognize that cost over the period during which the employee is required to provide service in exchange for the award. Statement 123R also requires a public entity to initially measure the cost of employee services received in exchange for an award of liability instruments based on the award's current fair value, subsequently remeasure the fair value of the award at each reporting date through the settlement date and recognize changes in fair value during the required service period as compensation cost over that period. Statement 123R is effective for public entities as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The company plans to adopt Statement 123R effective July 1, 2005, and follow the modified version of prospective application. The weighted-average fair value per share of stock options awarded in 2004, 2003 and 2002 ranged between $2.93 and $3.91, and is not expected to change significantly for future awards of stock options. As required by Statement 123R, the company will no longer defer compensation cost for awards of restricted or nonvested stock and amortize the cost into compensation expense over the vesting period. Instead it will recognize the compensation cost of nonvested stock as described above for equity instruments. The company's adoption of Statement 123R is not expected to have a material effect on its financial position or results of operations.
Statement 150: In May 2003 the FASB issued Statement 150. 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, and classified RG&E's $25 million of mandatorily redeemable preferred stock as a liability in their statements of financial position, which they had previously classified as equity. They also began to recognize as interest expense distributions that they had previously recognized as preferred stock dividends. 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.
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 Ginna
On June 10, 2004, RG&E sold Ginna to CGG and received at closing $429 million in cash. On September 9, 2004, RG&E received an additional $25 million from CGG related to certain post-closing adjustments. As a result, the company's 2004 statement of income reflects a gain on the sale of Ginna of $341 million. The deferral of the asset sale gain, net of related taxes of $112 million, is $229 million.
Notes to Consolidated Financial Statements
Energy East Corporation
RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna, including providing for an ASGA of $380 million after the post-closing adjustments, and addressing the disposition of the asset sale gain. Upon closing of the sale of Ginna, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. RG&E retained $77 million in excess decommissioning funds, which were credited to customers as part of the ASGA.
A summary of the effects of the sale of Ginna and the related ASGA follows (in thousands):
The ASGA was adjusted subsequent to the sale to reflect provisions of RG&E's Electric Rate Agreement, including refunds due to customers. Adjustments to the ASGA to reconcile to the deferred regulatory liability at December 31, 2004, are as follows (in thousands):
Nuclear insurance: Because of the sale of Ginna, RG&E is no longer subject to the Price-Anderson Act, which 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. Prior to the sale, RG&E carried the maximum available commercial insurance of $300 million and participated in a mandatory financial protection pool for the remaining $10.5 billion of the approximately $10.8 billion public liability limit for a nuclear incident. Under the terms of the sale, RG&E remains liable for assessments under the mandatory financial protection pool for incidents that may have occurred prior to the sale on June 10, 2004. If an incident can be conclusively determined to have occurred prior to the sale, RG&E could be assessed up to $101 million per incident payable at a rate not to exceed $10 million per incident per year. RG&E is not aware of any incidents that would lead to such an assessment.
Notes to Consolidated Financial Statements
Energy East Corporation
In addition to the insurance required by the Price-Anderson Act, RG&E also carried nuclear property damage insurance and accidental outage insurance through NEIL. Under those insurance policies, RG&E could be subject to retrospective premium adjustments for six years following the end of the policy period if losses exceed the accumulated funds available to the insurers. The maximum amounts of the adjustments for RG&E's final policy year were $13 million for nuclear property damage insurance and $4 million for accidental outage insurance. RG&E is not aware of any events that would initiate a retrospective premium adjustment under the NEIL policies.
Note 3. Sale of Other Businesses
In keeping with its focus on regulated electric and natural gas delivery businesses, during recent years the company has been systematically exiting certain noncore businesses. All businesses sold were previously reported in the company's Other business segment. In October 2004 Energy East Solutions, Inc., a subsidiary of The Energy Network, Inc., completed the sale of its New England and Pennsylvania natural gas customer contracts and related assets at an after-tax loss of less than $1 million. In July 2004 UWP, a subsidiary of CMP Group, sold the assets associated with its utility locating and construction divisions at an after-tax loss of $7 million. In 2004 the company recognized a loss from discontinued operations of $8 million or 6 cents per share.
In 2003 Berkshire Propane, Inc., a subsidiary of Berkshire Energy, sold its assets and Energetix, Inc., a subsidiary of RGS Energy, sold its subsidiary Griffith Oil Co., Inc. In 2004 the company recorded a change in estimated taxes of $1.2 million related to the sale of Griffith Oil to reflect actual taxes in accordance with the filing of the company's 2003 federal and state income tax returns.
In 2002 Berkshire Service Solutions, Inc., an energy service provider and a subsidiary of Berkshire Energy, was sold.
Notes to Consolidated Financial Statements
Energy East Corporation
The results of discontinued operations of the businesses sold were:
Notes to Consolidated Financial Statements
Energy East Corporation
The major classes of assets and liabilities at the date of sale of the businesses discontinued in 2004 were:
Note 4. 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. The entire related involuntary severance liability of $9 million was paid during 2003, including $4 million that was deferred for recovery by RG&E.
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 2003 the company recognized a $4 million total liability for an enhanced severance program for 83 accounting and finance employees who were employed through March 31, 2004. During the fourth quarter of 2003, 40% or approximately $2 million, of the estimated liability was charged to other operating expenses and represented the company's cumulative expense and liability as of December 31, 2003. The remaining $2 million of the liability was charged to other operating expenses in the first quarter of 2004. Approximately $3 million of the total cost was incurred by the electric delivery business and $1 million by the natural gas delivery business. The liability was paid as of June 30, 2004.
Note 5. Goodwill and Other Intangible Assets
The company does not amortize goodwill or 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 company at September 30, 2004.
Notes to Consolidated Financial Statements
Energy East Corporation
Changes in the carrying amount of goodwill, by operating segment, for the year ended December 31, 2004, are shown in the following table. The decreases in goodwill relate primarily to nonutility businesses sold in 2004.
Other Intangible Assets: The company's unamortized intangible assets had a carrying amount of $10 million at December 31, 2004 and 2003, and primarily consisted of pension assets. The company's amortized intangible assets had a gross carrying amount of $31 million at December 31, 2004 and 2003, and primarily consisted of investments in pipelines and customer lists. Accumulated amortization was $15 million at December 31, 2004, and $12 million at December 31, 2003. Estimated amortization expense for intangible assets for the next five years is approximately $2 million for 2005 and approximately $1 million each year for 2006 through 2009.
Note 6. Income Taxes
The company's effective tax rate differed from the statutory rate of 35% due to the following:
Notes to Consolidated Financial Statements
Energy East Corporation
The effective tax rate for continuing operations was 51% in 2004 and 36% in 2003. The company's effective tax rate for 2004 increased compared to the prior year primarily as a result of the regulatory treatment of the deferred gain from RG&E's sale of Ginna. RG&E recorded pretax income of $112 million and income tax expense of $112 million. (See Note 2.) Other factors contributing to the increase in the effective tax rate were increases in the estimate of prior year taxes of $3 million, primarily the result of the effects of the combined New York State tax filings for 2002 and 2003. 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 of distributions that the company had previously recognized as preferred stock 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.
At December 31, 2004 and 2003, the company's consolidated deferred tax assets and liabilities consisted of:
Energy East and its subsidiaries have no federal tax credit carryforwards. A subsidiary of Energy East has a state 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 held by 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 does not consolidate the trust. 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.
Notes to Consolidated Financial Statements
Energy East Corporation
Preferred stock of subsidiary subject to mandatory redemption requirements: On March 1, 2004, RG&E redeemed, at par, as required by a mandatory sinking fund provision, $1.25 million of its 6.60% Series V preferred stock, Par Value $100. On May 5, 2004, RG&E redeemed, at par, the remaining $23.75 million of the 6.60% Series V preferred stock.
Other long-term debt: At December 31, 2004 and 2003, the company's consolidated other long-term debt was:
(1)
For Energy East, on a consolidated basis. In addition to the information provided below for RG&E, Berkshire Gas and SCG have first mortgage bonds that are secured by liens on substantially all of their respective utility properties.
As a registered holding company under the Public Utility Holding Company Act of 1935, Energy East is prohibited from obtaining 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.
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 support.
NYSEG has no secured indebtedness. None of NYSEG's debt obligations are guaranteed or secured by any of its affiliates.
RG&E's first mortgage bonds, totaling $572 million at December 31, 2004, 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, 2004, other long-term debt, including sinking fund obligations, and capital lease payments (in thousands) that will become due during the next five years are:
Notes to Consolidated Financial Statements
Energy East Corporation
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. Energy East also has a provision in its revolving credit agreements, which provides that default by the company with respect to any other debt in excess of $50 million will be considered a default under the company's revolving credit agreements.
NYSEG has provisions in its unsecured indenture 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 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 revolving credit agreements with various expiration dates in 2005 and 2009 and pay fees in lieu of compensating balances in connection with those agreements. The agreements provided for maximum borrowings of $740 million at December 31, 2004, and $700 million at December 31, 2003.
The company and its subsidiaries use short-term, unsecured notes and drawings on their credit agreements to finance working capital needs and for other corporate purposes. There was $206 million of such short-term debt outstanding at December 31, 2004, and $308 million outstanding at December 31, 2003. The weighted-average interest rate on short-term debt was 2.8% at December 31, 2004, and 1.8% at December 31, 2003.
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 any time 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 0.58 to 1.00 at December 31, 2004.
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 for the prior four fiscal quarters 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, 2004, CMP's consolidated total debt ratio was 31% and its interest coverage ratio was 3.9 to 1.00.
Notes to Consolidated Financial Statements
Energy East Corporation
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 0.65 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, 2004, the ratio of earnings before interest expense and income tax to interest expense was 5.4 to 1.0 for NYSEG and 5.6 to 1.0 for RG&E. At December 31, 2004, the ratio of total indebtedness to total capitalization was 0.54 to 1.00 for NYSEG and 0.55 to 1.00 for RG&E.
Note 9. Preferred Stock Redeemable Solely at the Option of Subsidiaries
At December 31, 2004 and 2003, the company's consolidated preferred stock was:
(1)
At December 31, 2004, the company and its subsidiaries had 16,510,957 shares of $100 par value preferred stock, 16,800,000 shares of $25 par value preferred stock, 775,609 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.
Notes to Consolidated Financial Statements
Energy East Corporation
The company's subsidiaries redeemed or purchased the following amounts of preferred stock during the three years 2002 through 2004:
*Redeemed **Purchased at a premium
Voting rights: If preferred stock dividends on any series of preferred stock of a subsidiary, other than the CMP 6% Noncallable series and the CNG 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 elect a majority of the directors of such subsidiary (and, in the case of the CNG 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 CMP 6% Noncallable series and the CNG 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 CMP 6% Noncallable series and the CNG 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 and Contingencies
Capital spending: The company has commitments in connection with its capital spending program. Capital spending is projected to be $388 million in 2005 and is expected to be paid for principally 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, merger integration, a customer care system, and an Infrastructure Replacement Program.
Notes to Consolidated Financial Statements
Energy East Corporation
Nonutility generator power purchase contracts: CMP and NYSEG together expensed approximately $613 million for NUG power in 2004, $608 million in 2003 and $611 million in 2002. CMP and NYSEG estimate that their combined NUG power purchases will be $674 million in 2005, $615 million in 2006, $563 million in 2007, $381 million in 2008 and $229 million in 2009.
NYISO billing adjustment: The NYISO frequently bills transmission owners on a retroactive basis when adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG and RG&E record transmission revenue or expense as appropriate when revised amounts can be estimated. On January 25, 2005, the NYISO notified NYTOs, including NYSEG and RG&E, of a revenue allocation formula error related to transmission congestion contracts for periods including May 2000 through October 2002. The NYISO has not yet provided any further details. The correction of the error may result in revised billings to NYSEG and RG&E. The companies cannot predict at this time either the magnitude or the direction of any billing adjustments.
Note 11. Jointly-Owned Generation Assets and Nuclear Decommissioning
CMP: 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.
Operating expenses: CMP is obligated to pay its proportionate share of the expenses, including decommissioning, depreciation, spent fuel storage, operation and maintenance expenses, and a return on invested capital, for each of the Yankee companies referred to above. These amounts are recorded as other liabilities along with a corresponding regulatory asset. 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 costs not currently included in rates is deferred for future recovery.
Notes to Consolidated Financial Statements
Energy East Corporation
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.
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 EPA 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 20 waste sites. The 20 sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the 20 sites, 10 sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites, four are 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.
Any liability may be joint and several for certain of those sites. The company has recorded an estimated liability of $2 million related to 11 of the 20 sites. Remediation costs have been paid at the remaining nine sites, and the company expects no additional liability to be incurred. An estimated liability of $3 million has been recorded related to another 11 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 accrued 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, five sites are part of Maine's Voluntary Response Action Program and four of those five 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 $140 million to $277 million at December 31, 2004. 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.
Notes to Consolidated Financial Statements
Energy East Corporation
The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites was $140 million at December 31, 2004, and $138 million at December 31, 2003. 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.
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. A majority of the investments classified as held for sale in 2003 represented decommissioning trust funds for Ginna. In June 2004 those funds were transferred to CGG or made available to RG&E for general corporate purposes. (See Note 2.)
Note 14. Stock-Based Compensation
The company has a stock option plan under which it may grant stock options and SARs in relation to its common stock to senior management and certain other key employees. The company's policy is to grant SARs in tandem with any stock options granted. Employees may choose to exercise either the SARs, which are settled in cash, or the stock options. The exercise of SARs or options results in a corresponding cancellation of options or SARs to the extent of the number of shares of company common stock as to which the SARs or options are exercised. The stock options/SARs granted in 2004, 2003 and 2002 vest over either one-year or two-year periods, subject to, with certain exceptions, continuous employment. All stock options/SARs expire 10 years after the grant date. Unoptioned shares totaled 6.6 million of the 13 million shares authorized at December 31, 2004, and 5.5 million of the 13 million shares authorized at December 31, 2003. The company recorded compensation expense for stock options/SARs of $18 million in 2004, $3 million in 2003 and $12 million in 2002.
Notes to Consolidated Financial Statements
Energy East Corporation
The following table provides a summary of changes in the number of the company's stock options/SARs outstanding, and other information, as of and for the years ended December 31, 2004, 2003 and 2002. The exercise price of stock options/SARs equals the market price of the company's common stock on the last trading date prior to the date of grant.
The following table provides certain information about the stock options/SARs outstanding at December 31, 2004:
Notes to Consolidated Financial Statements
Energy East Corporation
The company has a Restricted Stock Plan for its common stock under which an aggregate two million shares may be granted, subject to adjustment. Shares of restricted (or nonvested) stock are awarded to selected employees and are issued 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 Compensation and Management Succession Committee of the Board of Directors administers the Restricted Stock Plan. However, Energy East's Chairman has the authority to make awards to any employees who are not executive officers, subject to a fixed maximum amount for any one participant. The shares vest based on the conditions outlined in the restricted stock award grants, including the achievement of targeted shareholder returns. Shares of common stock awarded pursuant to the Restricted Stock Plan in 2004 and 2003 were issued out of the company's treasury stock. The shares awarded in 2004 vest no later than January 1, 2010, and the shares awarded in 2003 vest no later than January 1, 2009. The company recorded deferred compensation of $6 million in 2004 and $4 million in 2003, based on the market price of its common stock on the date of the restricted stock award. The company amortizes deferred compensation to compensation expense over the vesting period and reduces compensation expense for any restricted stock cancelled or forfeited in the period the event occurs. Compensation expense related to the Restricted Stock Plan was approximately $4 million in 2004 and $2 million in 2003. The following table provides a summary of information concerning shares of restricted stock as of and for the years ended December 31, 2004 and 2003.
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
Energy East sponsors defined benefit pension plans and postretirement benefit plans applicable to substantially all employees. 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 $2.0 billion at December 31, 2004, and $1.9 billion at December 31, 2003. The sale of Ginna resulted in a decrease in the projected benefit obligation of $54 million, and $51 million of pension funds were transferred as part of the sale.
Notes to Consolidated Financial Statements
Energy East Corporation
CMP Group's, CNE's and CTG Resources' postretirement benefits were partially funded as of December 31, 2004 and 2003.
The minimum liability included in other comprehensive income for pension benefits increased $16 million in 2004 and decreased $36 million in 2003. The company recorded a minimum pension liability of $166 million at December 31, 2004, as required by Statement 87. 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 increase in the unfunded accumulated benefit obligation in 2004 was primarily due to a decrease in the assumed discount rate.
As of December 31, 2004, the company decreased its discount rate from 6.25% to 5.75%.
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 $67 million as of December 31, 2004, and $80 million as of December 31, 2003. The company expects to recover any deferred postretirement costs by 2012. The transition obligation for postretirement benefits that resulted from the adoption of Statement 106 is being amortized over 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. That 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 that would otherwise be 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 2005 that gradually decreases to 5.0% by the year 2008. 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:
In December 2003 President Bush signed the Medicare Act into law. The Medicare Act introduces a federal subsidy (the subsidy) to sponsors of single-employer defined benefit postretirement health care plans that provide to some or all participants prescription drug benefits that are at least actuarially equivalent to Medicare Part D.
In May 2004 the FASB issued its FSP No. FAS 106-2, which provides guidance on accounting for the effects of the Medicare Act and requires certain disclosures regarding the effect of the subsidy. The company adopted FSP No. FAS 106-2 prospectively in the third quarter of 2004 and remeasured its plan assets and APBO as of July 1, 2004, including the effects of the Medicare Act and the subsidy. Based on information available as of the date of adoption of FSP No. FAS 106-2, the company concluded that the prescription drug benefits provided by nearly all of its postretirement health care plans are actuarially equivalent to Medicare Part D benefits to be provided under the Medicare Act. RG&E concluded that the effects of the Medicare Act and the subsidy are insignificant because of employer caps and limited employee participation in RG&E's plans that provide postretirement prescription drug benefits.
As of July 1, 2004, the reduction in the company's APBO for the subsidy related to benefits attributed to past service was $44 million. The subsidy reduced the company's measurement of its net periodic postretirement benefit cost by $3.3 million for the six months ended December 31, 2004, including the following amounts that were reduced: service cost $0.1 million, interest cost $1.4 million and amortization of unrecognized net actuarial gain $1.8 million.
Notes to Consolidated Financial Statements
Energy East Corporation
The company's weighted-average asset allocations at December 31, 2004 and 2003, by asset category are:
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 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 did not include any Energy East common stock as of December 31, 2004 and 2003.
As of December 31, 2004 and 2003, 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. The following table shows the aggregate projected and accumulated benefit obligations and the fair value of plan assets for those three companies' plans.
The company expects to contribute approximately $54 million to its pension plans and approximately $10 million to its other postretirement benefit plans in 2005.
Notes to Consolidated Financial Statements
Energy East Corporation
Expected benefit payments and expected Medicare Act subsidy receipts, which reflect expected future service, as appropriate, are as follows:
Note 17. Segment Information
Selected financial information for the company's operating 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. The company measures segment profitability based on net income. 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)
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
of Energy East Corporation:
We have completed an integrated audit of Energy East Corporation's 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the accompanying index, present fairly, in all material respects, the financial position of Energy East Corporation and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 accompanying index 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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 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 No. 51.
Internal control over financial reporting
Also, in our opinion, management's assessment, included in Energy East Management's Annual Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
New York, New York
March 14, 2005
ENERGY EAST CORPORATION
SCHEDULE II - Consolidated Valuation and Qualifying Accounts
Years Ended December 31, 2004, 2003 and 2002
Classification
Beginning
of Year
Additions
Write-offs
(a)
Adjustments
End
of Year
(Thousands)
Allowance for Doubtful
Accounts - Accounts
Receivable
$52,848
$45,334
$(46,645)
$(6,193)
$45,344
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
(a)
Uncollectible accounts charged against the allowance, net of recoveries.
(b) Includes $30,750 due to the merger with RGS Energy.
Selected Financial Data
Central Maine Power Company
(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
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.
CMP Stranded Cost Proceeding: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
CMP Nuclear Costs: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
Nonutility Generation: CMP expensed approximately $212 million for NUG power in 2004. It estimates that its NUG purchases will total $213 million in 2005, $162 million in 2006, $151 million in 2007, $130 million in 2008 and $97 million in 2009. 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 2004, 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.)
New England RTO: 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
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.
Locational Installed Capacity Markets: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
CMP Union Contract: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
Contractual Obligations and Commercial Commitments
At December 31, 2004, CMP's contractual obligations and commercial commitments are:
(1)
Amounts for long-term debt and capital lease obligations include future interest payments. Future interest payments on variable-rate debt are determined using the rates at December 31, 2004.
(2) Amounts are through 2014 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.)
Management's Discussion and Analysis of Financial Condition and Results of Operations
Central Maine Power Company
Critical Accounting Estimates
See Energy East's Item 7 -
Critical Accounting Estimates for the discussions of Statement 71, Goodwill and Other Intangible Assets, Pension and Other Postretirement Benefit Plans, and Unbilled Revenues.
Investing and Financing Activities
Investing Activities: Capital spending totaled $49 million in 2004, $42 million in 2003 and $38 million in 2002. Capital spending in all three years was financed principally 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 $55 million in 2005 and is expected to be paid for principally with internally generated funds and will be primarily for the purposes described above. (See Note 8 to CMP's Consolidated Financial Statements.)
CMP's pension plans generated pretax noncash pension expense of $8 million in 2004, $9 million in 2003 and $2 million in 2002. CMP contributed $11 million to its plans in 2004 and expects to contribute approximately $35 million to its plans in 2005 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 revolving credit facility, secured by its accounts receivable, that expires in December 2005. The facility provides for maximum borrowings of $75 million. CMP uses short-term borrowings and drawings on its credit facility to finance working capital needs and for other corporate purposes. There was $38 million of such short-term debt outstanding at December 31, 2004, and $15 million at December 31, 2003. The weighted-average interest rate on short-term debt was 2.9% at December 31, 2004, and 1.7% at December 31, 2003. CMP has an additional credit agreement, which provides for additional borrowing of $5 million, expiring in 2005.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Central Maine Power Company
Results of Operations
Earnings
CMP's earnings for 2004 decreased less than $1 million compared to 2003 primarily due to lower revenues, which were substantially offset by lower expenses. The $5 million decrease in earnings for 2003 as compared to 2002 was also due to lower revenue partially offset by lower expenses. Earnings also declined in 2003 due to the recognition of certain tax benefits in 2002.
The offsetting revenue and expense reductions in 2004 and 2003 are the result of various regulatory mechanisms that:
provide for a direct matching of standard-offer revenues and supply costs;
provide for rate reductions under ARP 2000 to reflect completed amortizations of ice storms and DSM costs; and
allow for deferral of incurred DSM and transmission congestion costs.
Operating Revenues
The $14 million decrease in 2004 operating revenues was primarily the result of:
Rate decreases pursuant to ARP 2000, effective July 1, 2003, and July 1, 2004, that reduced revenues $13 million in 2004 because it was in effect for a full year. Rate mitigation funded by the ASGA for commercial and industrial customers declined by $5 million in 2004.
A decrease in transmission rates, effective July 1, 2004, that reduced revenues $4 million. That rate decrease reflects lower transmission costs consisting primarily of congestion costs.
Those decreases were partially offset by:
Higher retail deliveries due to economic growth that added $11 million to revenues.
Operating revenues decreased $43 million in 2003 primarily as a result of:
An $18 million decrease because CMP is no longer the standard-offer provider for the supply of electricity for residential and small commercial customers, effective March 2002.
A rate decrease pursuant to ARP 2000, effective July 1, 2003, that reduced revenues $12 million.
Lower accrued revenue of $14 million, primarily reflecting lower incurred DSM and transmission congestion costs.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Central Maine Power Company
A decrease of $5 million due to lower NUG entitlement sales.
Lower other revenue and stranded cost rates of $8 million.
Those decreases were partially offset by:
Higher retail deliveries that added $14 million to revenues.
Operating Expenses:
The $6 million decrease in 2004 operating expenses was primarily the result of:
Lower amortization of ice storm and other costs of $5 million.
Operating expenses for 2003 decreased $43 million primarily as a result of:
Decreases in electricity purchases, including an $18 million decrease because CMP is no longer the standard-offer provider for the supply of electricity for residential and small commercial class customers, effective March 2002, and $7 million due to lower NUG power and other purchase costs.
Lower operating and maintenance costs reflecting decreases of $6 million because of lower amortization of ice storm costs, $6 million due to reduced transmission costs and $6 million as a result of lower DSM costs, including amortization of past expenses.
A $5 million decrease because of the effect of restructuring costs recognized in 2002.
Lower administrative costs that cut expenses $3 million.
Those decreases were partially offset by:
Higher operating and maintenance costs due to increases in tree trimming, environmental remediation, and other distribution costs that totaled $7 million.
Other Items
Other Operating Expenses: CMP's net periodic pension cost is included in other operating expenses. Other operating expenses would have been $7 million lower for 2003 if net periodic pension cost for each of those years had not increased compared to the prior year.
Central Maine Power Company
Consolidated Statements of Income
The
notes on pages 94 through 108 are an integral part of the consolidated financial statements.
Central Maine Power Company
Consolidated Balance Sheets
The
notes on pages 94 through 108 are an integral part of the consolidated financial statements.
Central Maine Power Company
Consolidated Balance Sheets
The
notes on pages 94 through 108 are an integral part of the consolidated financial statements.
Central Maine Power Company
Consolidated Statements of Cash Flows
The
notes on pages 94 through 108 are an integral part of the consolidated financial statements.
Central Maine Power Company
Consolidated Statements of Changes in Common Stock Equity
The
notes on pages 94 through 108 are an integral part of the consolidated financial statements.
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 1. Significant Accounting Policies
Background: 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 $24 million at December 31, 2004, and $25 million at December 31, 2003, and are shown net of an allowance for doubtful accounts of $2 million at December 31, 2004, and December 31, 2003. Accounts receivable balances do not bear interest although late fees may be assessed. Bad debt expense was $3 million in 2004, $2 million in 2003 and $3 million in 2002. The allowance for doubtful accounts is CMP's best estimate of the amount of probable credit losses in its existing accounts receivable. CMP determines the allowance based on experience and other economic data. Each month CMP reviews its allowance for doubtful accounts and its past due accounts over 90 days and/or above a specified amount. CMP reviews all other balances on a pooled basis by age and type of receivable. When CMP believes that a receivable will not be recovered, it charges off the account balance against the allowance. CMP does not have any off-balance sheet credit exposure related to its customers.
Accrued removal obligation: In June 2001 the FASB issued Statement 143. 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. 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. CMP classifies these amounts as accrued removal obligations.
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 - 42 years, distribution property - 39 years and other property - 25 years. CMP's depreciation accruals were equivalent to 3.0% of average depreciable property for 2004 and 2003 and 2.9% for 2002.
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
Central Maine Power Company
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. An impairment may be recognized if the fair value of goodwill is less than its carrying value. (See Note 3.)
Income taxes: CMP determines 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 CMP's tax sharing agreement with Energy East.
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. ITCs are amortized over the estimated lives of the related assets.
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 in the consolidated financial statements to conform to the 2004 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.
Notes to Consolidated Financial Statements
Central Maine Power Company
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 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 were sold to unrelated third parties under bilateral contracts.
Risk management: CMP 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. CMP also uses derivative instruments to mitigate risk resulting from interest rate changes on future financings. CMP amortizes amounts paid or received under those instruments to interest expense over the life of the corresponding financing. At December 31, 2004, CMP had $3 million of derivative liabilities, substantially all of which were long-term.
CMP does not hold or issue financial instruments for trading or speculative purposes.
FIN 46R: In December 2003 the FASB issued FIN 46R, which 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. As of March 31, 2004, CMP was required to apply FIN 46R to all entities subject to the interpretation.
CMP has independent, ongoing, power purchase contracts with various NUGs. CMP was not involved in the formation of and does not have ownership interests in any NUGs. CMP evaluated each of its power purchase contracts with NUGs with respect to FIN 46R. Most of the power purchase contracts were determined not to be variable interests for one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUG is a governmental organization or an individual.
CMP is not able to apply FIN 46R to four remaining NUGs because it is unable to obtain the information necessary to: (1) determine if the NUGs are variable interest entities, (2) determine if CMP is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of the NUGs. CMP requested necessary information from the four NUGs and none of the NUGs provided the requested information. CMP will continue to make efforts to obtain information from the four NUGs.
CMP purchases electricity from the four NUGs at above-market prices. CMP is not exposed to any loss as a result of its involvement with NUGs because it is allowed to recover through rates the cost of its purchases. Also, it is under no obligation to a NUG if the NUG decides not to operate for any reason. The combined contractual capacity for the four NUGs from which CMP purchases electricity is approximately 23 megawatts. CMP's purchases from the four NUGs totaled $11 million in 2004 and in 2003, and $10 million in 2002.
CMP did not consolidate any NUGs at December 31, 2004 and 2003.
Notes to Consolidated Financial Statements
Central Maine Power Company
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 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. CMP's entire related involuntary severance liability of $1 million was paid during 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 were employed through March 31, 2004. The liability was paid as of June 30, 2004.
Note 3. Goodwill and Other Intangible Assets
CMP does not amortize goodwill or intangible assets with indefinite lives (unamortized intangible assets). CMP tests both goodwill and unamortized intangible assets for impairment at least annually. CMP 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 CMP at September 30, 2004.
The carrying amount of goodwill, which is included in CMP's electric delivery operating segment, was $325 million at December 31, 2004 and 2003.
Other Intangible Assets: CMP's unamortized intangible assets consisted of pension assets and had a carrying amount of $2 million at December 31, 2004 and December 31, 2003. CMP's amortized intangible assets primarily consisted of technology rights and had a gross carrying amount and accumulated amortization of less than $0.3 million at December 31, 2004 and December 31, 2003. Estimated amortization expense for intangible assets for the next three years is $26 thousand in 2005 and 2006 and $8 thousand in 2007.
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 effective tax rate for 2004 differed from the expected rate due to decreases in estimates of prior years' taxes of $3 million.
At December 31, 2004 and 2003, CMP's deferred tax assets and liabilities were:
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, 2004 and 2003, 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, 2004, 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 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, 2004 and 2003, 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 has an additional credit agreement, which expires in 2005 and provides for additional borrowings of $5 million.
CMP uses short-term borrowings and drawings on its revolving credit facilities to finance working capital needs and for other corporate purposes. There was $38 million of such short-term debt outstanding at December 31, 2004, and $15 million outstanding at December 31, 2003. The weighted-average interest rate on short-term debt was 2.9% at December 31, 2004, and 1.7% at December 31, 2003.
In its 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 for the prior four fiscal quarters 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, 2004, CMP's consolidated total debt ratio was 31% and its interest coverage ratio was 3.9 to 1.00.
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 7. Preferred Stock
At December 31, 2004 and 2003, CMP's cumulative preferred stock was:
(1)
At December 31, 2004, 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 2002 through 2004.
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 $55 million in 2005 and is expected to be paid for principally 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, and compliance with environmental requirements and governmental mandates.
Notes to Consolidated Financial Statements
Central Maine Power Company
Nonutility generator power purchase contracts: CMP expensed approximately $212 million for NUG power in 2004, $210 million in 2003 and $211 million in 2002. CMP estimates that NUG power purchases will total $213 million in 2005, $162 million in 2006, $151 million in 2007, $130 million in 2008 and $97 million in 2009.
Note 9. Jointly-Owned Generation Assets and Nuclear 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.
Operating expenses: CMP is obligated to pay its proportionate share of the expenses, including decommissioning, depreciation, spent fuel storage, operation and maintenance expenses, and a return on invested capital, for each of the Yankee companies referred to above. These obligations are recorded as other liabilities along with a corresponding regulatory asset. 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 costs not currently included in rates is deferred for future recovery.
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 EPA 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.
Notes to Consolidated Financial Statements
Central Maine Power Company
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 accrued 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, five sites are part of Maine's Voluntary Response Action Program and four of those five 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, 2004. 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, 2004 and 2003.
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.
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.
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 12. Accumulated Other Comprehensive Income
(See Risk management in Note 1.)
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 13. Retirement Benefits
CMP sponsors defined benefit pension plans and postretirement benefit plans applicable to substantially all employees. CMP uses a December 31 measurement date for its pension and postretirement benefit plans.
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 $224 million at December 31, 2004, and $201 million at December 31, 2003.
Notes to Consolidated Financial Statements
Central Maine Power Company
The minimum liability included in CMP's other comprehensive income for pension benefits increased $10 million in 2004 and decreased $13
million in 2003. CMP recorded a minimum pension liability of $85 million at December 31, 2004, as required by Statement 87. 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 increase in the unfunded accumulated benefit obligation in 2004 was primarily due to a lower discount rate in 2004 compared to the previous year.
As of December 31, 2004, CMP decreased its discount rate from 6.25% to 5.75%.
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 $32 million at December 31, 2004, and $35 million at December 31, 2003. CMP expects to recover any deferred postretirement costs related to the transition obligation by 2012. The transition obligation for postretirement benefits that resulted from the adoption of Statement 106 is being amortized over 20 years.
Notes to Consolidated Financial Statements
Central Maine Power Company
CMP's expected rate of return on plan assets assumption was developed based on a review of historical returns for the major asset classes. That analysis also considered 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 that would otherwise be determined solely based on historical returns.
CMP assumed a 10.0% annual rate of increase in the per capita cost of covered health care benefits for 2005 that gradually decreases to 5.0% by the year 2008. 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:
In December 2003 President Bush signed the Medicare Act into law. The Medicare Act introduces a federal subsidy (the subsidy) to sponsors of single-employer defined benefit postretirement health care plans that provide to some or all participants prescription drug benefits that are at least actuarially equivalent to Medicare Part D.
In May 2004 the FASB issued its FSP No. FAS 106-2, which provides guidance on accounting for the effects of the Medicare Act and requires certain disclosures regarding the effect of the subsidy. CMP adopted FSP No. FAS 106-2 prospectively in the third quarter of 2004 and remeasured its plan assets and APBO as of July 1, 2004, including the effects of the Medicare Act and the subsidy. Based on information available as of the date of adoption of FSP No. FAS 106-2, CMP concluded that the prescription drug benefits provided by its postretirement health care plans are actuarially equivalent to Medicare Part D benefits to be provided under the Medicare Act.
As of July 1, 2004, the reduction in CMP's APBO for the subsidy related to benefits attributed to past service was $13 million. The subsidy reduced CMP's measurement of its net periodic postretirement benefit cost by $0.9 million for the six months ended December 31, 2004, including the following amounts that were reduced: service cost $0.1 million, interest cost $0.4 million and amortization of unrecognized net actuarial gain $0.4 million.
Notes to Consolidated Financial Statements
Central Maine Power Company
CMP's weighted-average asset allocations at December 31, 2004 and 2003, 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 plan assets are held by trustees 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.
Equity securities did not include any Energy East common stock at December 31, 2004 and 2003.
At December 31, 2004 and 2003, CMP's accumulated benefit obligation and the projected benefit obligation exceeded the fair value of its pension plan assets. The following table shows CMP's projected and accumulated benefit obligations and the fair value of plan assets.
CMP expects to contribute approximately $35 million to its pension plans in 2005.
Notes to Consolidated Financial Statements
Central Maine Power Company
Expected benefit payments and expected Medicare Act subsidy receipts, which reflect expected future service, as appropriate, are as follows:
Note 14. Segment Information
CMP's electric delivery business, which it conducts in the State of Maine, consists of its transmission and distribution operations. All operating results and capital spending relate to CMP's electric delivery business.
Note 15. Quarterly Financial Information (Unaudited)
Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of
Central Maine Power Company and Subsidiaries:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Central Maine Power Company and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 accompanying index 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards 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 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
March 14, 2005
CENTRAL MAINE POWER COMPANY
SCHEDULE II - Consolidated Valuation and Qualifying Accounts
Years Ended December 31, 2004, 2003 and 2002
Classification
Beginning
of Year
Additions
Write-offs (a)
End
of Year
(Thousands)
Allowance for Doubtful
Accounts - Accounts
Receivable
$1,748
$2,930
$(2,789)
$1,889
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
(a) Uncollectible accounts charged against the allowance, net of recoveries.
Selected Financial Data
New York State Electric & Gas Corporation
(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.
Management's Discussion and Analysis of Financial Condition and Results of Operations
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.
Nonutility Generation: NYSEG expensed approximately $401 million for NUG power in 2004. It estimates that its NUG purchases will total $461 million in 2005, $453 million in 2006, $412 million in 2007, $251 million in 2008 and $132 million in 2009. 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 2004, averaged 10.2 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.
Management's Discussion and Analysis of Financial Condition and Results of Operations
New York State Electric & Gas Corporation
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.
NYISO Billing Adjustment: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
Errant Voltage: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
NYSEG Union Contract: 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.
NYSEG Natural Gas Rate Plan: 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 Union Contract: 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
Contractual Obligations and Commercial Commitments
At December 31, 2004, NYSEG's contractual obligations and commercial commitments are:
(1)
Amounts for long-term debt and capital lease obligations include future interest payments. Future interest payments on variable-rate debt are determined using the rates at December 31, 2004. (2)
Amounts are through 2014 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).
Management's Discussion and Analysis of Financial Condition and Results of Operations
New York State Electric & Gas Corporation
Critical Accounting Estimates
See Energy East's Item 7 -
Critical Accounting Estimates for discussions of Statement 71, Goodwill and Other Intangible Assets, Pension and Other Postretirement Benefit Plans, and Unbilled Revenues.
Investing and Financing Activities
Investing Activities: Capital spending totaled $114 million in 2004, $96 million in 2003 and $90 million in 2002. Capital spending in all three years was financed principally with internally generated funds and was primarily for necessary improvements to existing facilities, the extension of energy delivery service, compliance with environmental requirements and governmental mandates, and merger integration beginning in 2003.
Capital spending is projected to be $181 million in 2005. It is expected to be paid for principally with internally generated funds and will be primarily for the purposes described above as well as a customer care system and an Infrastructure Replacement Program. (See Note 8 to NYSEG's Financial Statements.)
NYSEG's pension plans generated pretax noncash pension income of $46 million in 2004, compared to $44 million in 2003 and $68 million in 2002. NYSEG anticipates no funding requirements in 2005 and had no funding requirements in 2004 as total plan assets exceed the projected benefit obligation. (See Note 12 to NYSEG's Financial Statements.)
Financing Activities: In July 2004 NYSEG and RG&E replaced their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-year $230 million revolving credit facility with certain banks. NYSEG is permitted to borrow up to $180 million under the facility, RG&E is permitted to borrow up to $75 million, and NYSEG and RG&E are allowed to issue letters of credit totaling up to $40 million. The aggregate borrowings and letters of credit may not exceed a combined total of $230 million. NYSEG had no amounts outstanding under either agreement during 2004 or 2003.
NYSEG uses short-term, unsecured notes to finance working capital needs and for other corporate purposes. NYSEG had $58 million of such short-term debt outstanding at December 31, 2004, at a weighted-average interest rate of 2.49%, and $41 million outstanding at December 31, 2003, at a weighted-average interest rate of 1.16%.
In August 2004 NYSEG refunded an aggregate $204 million of fixed-rate tax-exempt pollution control notes with interest rates ranging from 5.70% to 6.05% through the issuance of $204 million of multi-mode tax-exempt pollution control notes with due dates ranging from 2027 to 2034.
Management's Discussion and Analysis of Financial Condition and Results of Operations
New York State Electric & Gas Corporation
Results of Operations
Earnings
NYSEG's earnings for 2004 increased $5 million primarily due to:
A reduction in the estimate of prior year taxes and tax reserves of $12 million. (See Note 4 to NYSEG's Financial Statements.)
That increase was offset partially by:
Lower earnings in the natural gas segment of $4 million as a result of a 4% decline in retail sales.
Earnings sharing of $4 million resulting from the tax adjustments mentioned above.
Earnings for 2003 increased $10 million primarily due to:
An increase of $15 million due to higher electric and natural gas retail deliveries primarily because of colder winter weather in the first quarter of 2003.
The effect of restructuring expenses that reduced earnings $15 million in 2002.
The effect of a loss from the early retirement of debt that reduced earnings $10 million in 2002.
Integration savings and cost control efforts that increased earnings $9 million.
An $8 million increase because of lower interest charges as a result of refinancings and repayments of first mortgage bonds.
Those increases were partially offset by:
An earnings decrease of $18 million as a result of an electric price reduction effective in March 2002.
A decrease of $6 million due to lower transmission revenues.
An $11 million decrease because of lower noncash pension income.
Costs related to several major storms that reduced earnings $9 million.
Management's Discussion and Analysis of Financial Condition and Results of Operations
New York State Electric & Gas Corporation
Other Items
Other Operating Expenses: Net periodic pension income is included in other operating expenses and reduces the amount of expense that would otherwise be reported. Other operating expenses would have been $2 million higher for 2004 and $18 million lower for 2003 if net periodic pension income for each of those years had not changed compared to the prior year. The effect on expense from changes in pension income reflects any regulatory deferral mechanisms approved by the NYPSC. These deferrals had the effect of increasing pension income by $6 million in 2004 and 2003.
Other Deductions: (See Note 1 to NYSEG's Financial Statements.) The $18 million decrease in Other Deductions in 2003 was primarily due to a $16 million loss on the early retirement of debt in 2002.
Interest Charges, Net: Interest charges, net decreased $6 million in 2004 and decreased $14 million in 2003, primarily as a result of refinancings and repayments of first mortgage bonds prior to 2004.
Operating Results for the Electric Delivery Business
Operating Revenues:
Operating revenues for 2004 increased $59 million primarily due to:
A $69 million increase in wholesale revenues that reflects higher market prices and increased activity to manage the cost of supply.
That increase was partially offset by:
A $7 million decrease in retail revenue primarily as a result of lower average prices.
Lower electric commodity revenues of $8 million due to customers choosing other supply options.
Management's Discussion and Analysis of Financial Condition and Results of Operations
New York State Electric & Gas Corporation
Operating revenues decreased $74 million in 2003 primarily as a result of:
A $53 million decrease due to the combined effects of a price reduction effective in March 2002, and the net effect of customers choosing other suppliers and customers choosing the bundled rate option.
A decrease of $46 million due to the elimination in 2002 of the partial amortization of an ASGA that was used to fund a portion of the price reduction effective March 2002.
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 in the first quarter of 2003.
Operating Expenses:
The $56 million increase in 2004 operating expenses was primarily the result of:
Higher purchased power costs of $69 million reflecting increased energy supply activity that resulted in higher wholesale sales.
That increase was partially offset by:
A reduction of $9 million resulting from lower purchases of electricity because the amount of electricity supplied by NYSEG to retail customers declined in 2004.
The $43 million decrease in operating expenses in 2003 was primarily due to:
A $36 million decrease in purchased power that resulted from customers choosing other suppliers, partially offset by increases due to higher market prices and higher deliveries because of colder winter weather in the first quarter of 2003.
A decrease of $20 million due to the effect of restructuring expenses incurred in 2002.
Cost control efforts and integration savings that reduced expenses $12 million in 2003.
Those decreases were partially offset by:
An increase of $18 million due to lower noncash pension income.
A $15 million increase due to several major storms that occurred in 2003.
Operating Results for the Natural Gas Delivery Business
Operating Revenues:
2004 operating revenues increased $29 million primarily as a result of:
Higher market prices of natural gas of $60 million that were passed on to customers.
Management's Discussion and Analysis of Financial Condition and Results of Operations
New York State Electric & Gas Corporation
The above increase was partially offset by:
A decrease of $13 million due to lower retail deliveries, primarily because of warmer winter weather in the first quarter of 2004.
Lower transportation revenues of $4 million.
Lower wholesale deliveries that reduced revenues $16 million.
Operating revenues for 2003 increased $71 million primarily as a result of:
A $50 million increase for gas cost recovery resulting for a natural gas supply charge.
Higher retail deliveries or $27 million primarily because of colder winter weather in the first quarter of 2003.
Operating Expenses:
The $36 million increase in 2004 operating expenses primarily resulted from:
An increase of $60 million because of higher market prices for natural gas purchased.
The increase above was partially offset by decreases in the amount of natural gas purchased including:
An $8 million decrease because of lower retail deliveries.
A decrease of $16 million due to lower purchases for wholesale deliveries.
Operating expenses for 2003 increased $66 million primarily due to:
A $52 million increase as a result of higher market prices for natural gas purchased after various gas cost deferrals and recoveries.
An increase of $14 million for natural gas purchased to meet higher retail deliveries that resulted from colder winter weather in the first quarter of 2003.
Those increases were partially offset by:
A decrease due to the effect of $6 million of restructuring expenses incurred in 2002.
New York State Electric & Gas Corporation
Statements of Income
The
notes on pages 124 through 139 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Balance Sheets
The
notes on pages 124 through 139 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Balance Sheets
The
notes on pages 124 through 139 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Statements of Cash Flows
The
notes on pages 124 through 139 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 124 through 139 are an integral part of the financial statements.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 1. Significant Accounting Policies
Background: 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 on June 28, 2002, NYSEG became a wholly-owned subsidiary of RGS Energy.
Accounts receivable: Accounts receivable include unbilled revenues of $84 million at December 31, 2004, and $72 million at December 31, 2003, and are shown net of an allowance for doubtful accounts of $7 million at December 31, 2004 and $10 million at December 31, 2003. Accounts receivable balances do not bear interest although late fees may be assessed. Bad debt expense was $15 million in 2004 and 2003 and $18 million in 2002. The allowance for doubtful accounts is NYSEG's best estimate of the amount of probable credit losses in existing accounts receivable. NYSEG determines the allowance based on experience for each operating segment and other economic data. Each month NYSEG reviews its allowance for doubtful accounts and its past due accounts over 90 days and/or above a specified amount. NYSEG reviews all other balances on a pooled basis by age and type of receivable. When NYSEG believes that a receivable will not be recovered, it charges off the account balance against the allowance. NYSEG does not have any off-balance sheet credit exposure related to its customers.
Asset retirement obligation: In June 2001 the FASB issued Statement 143. 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. In accordance with Statement 143, NYSEG records the fair value of the liability for an asset retirement obligation in the period in which it is incurred and capitalizes the cost by increasing the carrying amount of the related long-lived asset. NYSEG adjusts the liability to its present value periodically over time, and depreciates the capitalized cost over the useful life of the related asset. Upon settlement NYSEG will either settle the obligation at its recorded amount or incur a gain or a loss. NYSEG will defer any timing differences between rate recovery and book expense as either a regulatory asset or a regulatory liability.
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. NYSEG classifies these amounts as accrued removal obligations.
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.
Notes to Financial Statements
New York State Electric & Gas Corporation
Depreciation and amortization: NYSEG determines depreciation expense using straight-line rates, based on the average service lives of groups of depreciable property in service, which includes estimated cost of removal. The average service lives of certain classifications of property are: transmission property - 56 years, distribution property - 44 years and other property - 46 years. NYSEG's depreciation accruals were equivalent to 3.1% of average depreciable property for 2004 and 3.2% for 2003 and 2002.
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.
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. An impairment may be recognized if the fair value of goodwill is less than its carrying value. (See Note 3.)
Income taxes: NYSEG determines 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 NYSEG's tax sharing agreement with Energy East.
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. ITCs are amortized over the estimated lives of the related assets.
Other (Income) and Other Deductions:
Reclassifications: Certain amounts have been reclassified on the financial statements to conform to the 2004 presentation.
Notes to Financial Statements
New York State Electric & Gas Corporation
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.
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 NYSEG sells electricity from owned generation to the NYISO, and subsequently repurchases electricity from the NYISO to serve its customers, it records the transactions on a net basis in its 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 derivative 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 other assets or other liabilities. NYSEG had $32 million of derivative assets at December 31, 2004, including $5 million current and $27 million long-term. NYSEG had $11 million of derivative liabilities at December 31, 2004, including $3 million current and $8 million long-term. At December 31, 2003, NYSEG had $49 million of derivative assets and $3 million of derivative liabilities. 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 statements of income. Changes in the fair value of the interest rate swap agreements are reported on the statements of income in the same period as the offsetting change in the fair value of the underlying debt instrument.
Notes to Financial Statements
New York State Electric & Gas Corporation
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, 2004, the maximum length of time over which NYSEG is hedging its exposure to the variability in future cash flows for forecasted transactions is 60 months. NYSEG estimates that losses of $8 million will be reclassified from accumulated other comprehensive income into earnings in 2005, 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.
FIN 46R: In December 2003 the FASB issued FIN 46R, which 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. As of March 31, 2004, NYSEG was required to apply FIN 46R to all entities subject to the interpretation.
NYSEG has independent, ongoing, power purchase contracts with various NUGs. NYSEG was not involved in the formation of and does not have ownership interests in any NUGs. NYSEG evaluated each of its power purchase contracts with NUGs with respect to FIN 46R. Most of the power purchase contracts were determined not to be variable interests for one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUG is either a governmental organization or an individual.
NYSEG is not able to apply FIN 46R to three remaining NUGs because it is unable to obtain the information necessary to: (1) determine if the NUGs are variable interest entities, (2) determine if NYSEG is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of the NUGs. NYSEG requested information from the three NUGs and none of the NUGs provided the requested information. NYSEG will continue to make efforts to obtain information from the three NUGs.
NYSEG purchases electricity from the three NUGs at above-market prices. NYSEG is not exposed to any loss as a result of its involvement with NUGs because it is allowed to recover through rates the cost of its purchases. Also, it is under no obligation to a NUG if the NUG decides not to operate for any reason. The combined contractual capacity for the three NUGs from which NYSEG purchases electricity is approximately 494 megawatts. NYSEG's purchases from the three NUGs totaled $314 million in 2004, $335 million in 2003, and $341 million in 2002.
NYSEG did not consolidate any NUGs at December 31, 2004 and 2003.
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.
Notes to Financial Statements
New York State Electric & Gas Corporation
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. NYSEG's entire related involuntary severance liability of $3 million was paid during 2003.
Energy East has consolidated the accounting and finance functions of five of its operating companies to one location. In connection with that restructuring, in the fourth quarter of 2003 NYSEG began to recognize a $1 million total liability for an enhanced severance program for certain accounting and finance employees who were employed through March 31, 2004. The liability was paid as of June 30, 2004.
Note 3. Goodwill and Other Intangible Assets
NYSEG does not amortize goodwill or intangible assets with indefinite lives (unamortized intangible assets). NYSEG tests both goodwill and unamortized intangible assets for impairment at least annually. NYSEG 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 NYSEG at September 30, 2004.
The carrying amount of goodwill, which is included in NYSEG's natural gas delivery operating segment, was $11 million at December 31, 2004 and 2003.
Other Intangible Assets: NYSEG's unamortized intangible assets primarily consisted of pension assets, franchises and consents and had a carrying amount of $1.4 million at December 31, 2004 and December 31, 2003. NYSEG's amortized intangible assets consisted of hydroelectric licenses and had a gross carrying amount of $1.8 million and accumulated amortization of $1 million at December 31, 2004 and December 31, 2003. Estimated amortization expense for intangible assets for the next five years is $41 thousand for 2005 and 2006, $38 thousand for 2007 and $35 thousand for 2008 and 2009.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 4. Income Taxes
NYSEG's effective tax rate differed from the statutory rate of 35% due to the following:
NYSEG's effective tax rate for 2004 differed from the expected rate due to decreases in estimates of prior period taxes of $12 million, primarily the result of the effects of the combined New York State tax filings for 2002 and 2003. Energy East files a combined unitary income tax return in New York. It allocates the combined unitary tax to its subsidiaries on the basis of its tax sharing agreement. (See Note 1.) In 2004 Energy East revised its estimate of New York State income taxes based on its unitary filing position and allocated $13 million of benefits to NYSEG. After the federal tax effect of $5 million, the remaining benefit was included in NYSEG's earning sharing calculation and increased net income by $4 million.
Notes to Financial Statements
New York State Electric & Gas Corporation
At December 31, 2004 and 2003, NYSEG's deferred tax assets and liabilities were:
NYSEG has no federal or state tax credit or loss carryforwards, and no valuation allowances.
Note 5. Long-term Debt
At December 31, 2004 and 2003, 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, 2004, 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 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.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 6. Bank Loans and Other Borrowings
NYSEG uses short-term, unsecured notes to finance working capital needs and for other corporate purposes. NYSEG had $58 million of such short-term debt outstanding at December 31, 2004, at a weighted-average interest rate of 2.49%, and $41 million outstanding at December 31, 2003, at a weighted-average interest rate of 1.16%.
NYSEG and RG&E have a joint $230 million five-year revolving credit facility with certain banks, which in July 2004 replaced their previous 364-day facility. NYSEG is permitted to borrow up to $180 million under the facility, RG&E is permitted to borrow up to $75 million, and NYSEG and RG&E are allowed to issue letters of credit totaling up to $40 million. The aggregate borrowings and letters of credit may not exceed a combined total of $230 million. 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 .175% at December 31, 2004, and was .15% at December 31, 2003, under the previous agreement. NYSEG had no amounts outstanding under the agreements, either at December 31, 2004, or December 31, 2003.
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 0.65 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, 2004, NYSEG's ratio of earnings before interest expense and income tax to interest expense was 5.4 to 1.0, and its ratio of total indebtedness to total capitalization was 0.54 to 1.00.
Note 7. Preferred Stock Redeemable Solely at the Option of NYSEG
At December 31, 2004 and 2003, NYSEG's serial cumulative preferred stock was:
(1) At December 31, 2004, 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 2002 through 2004.
Notes to Financial Statements
New York State Electric & Gas Corporation
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 and Contingencies
Capital spending: NYSEG has commitments in connection with its capital spending program. Capital spending is projected to be $181 million in 2005 and is expected to be paid for principally with internally generated funds. The program is subject to periodic review and revision. NYSEG's capital spending will be principally for necessary improvements to existing facilities, the extension of energy delivery service, compliance with environmental requirements and governmental mandates, merger integration, a customer care system and an Infrastructure Replacement Program.
Nonutility generator power purchase contracts: NYSEG expensed approximately $401 million for NUG power in 2004, $398 million in 2003 and $400 million in 2002. NYSEG estimates that its NUG power purchases will total $461 million in 2005, $453 million in 2006, $412 million in 2007, $251 million in 2008 and $132 million in 2009.
NYISO billing adjustment: The NYISO frequently bills transmission owners on a retroactive basis when adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. NYSEG records transmission revenue or expense as appropriate when revised amounts can be estimated. On January 25, 2005, the NYISO notified NYTOs, including NYSEG, of a revenue allocation formula error related to transmission congestion contracts for periods including May 2000 through October 2002. The NYISO has not yet provided any further details. The correction of the error may result in revised billings to NYSEG. NYSEG cannot predict at this time either the magnitude or the direction of any billing adjustments.
Note 9. 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 EPA and the 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,
Notes to Financial Statements
New York State Electric & Gas Corporation
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 $0.3 million related to three of the nine sites. Remediation costs have been paid at the remaining six sites, and NYSEG expects no additional liability to be incurred. The ultimate cost to remediate the sites may be significantly more than the accrued amount. 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 $98 million to $206 million at December 31, 2004. 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 $98 million at December 31, 2004, and $97 million at December 31, 2003. 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.
Note 10. 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.
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. Retirement Benefits
NYSEG sponsors defined benefit pension plans and postretirement benefit plans applicable to substantially all employees. 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 $1,088 million at December 31, 2004, and $1,017 million at December 31, 2003.
NYSEG's postretirement benefits were unfunded as of December 31, 2004 and 2003.
Notes to Financial Statements
New York State Electric & Gas Corporation
As of December 31, 2004, NYSEG decreased its discount rate from 6.25% to 5.75%.
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, 2004, or December 31, 2003. NYSEG recovered deferred postretirement costs as of March 2003. The transition obligation for postretirement benefits that resulted from the adoption of Statement 106 is being amortized over 20 years.
NYSEG's expected rate of return on plan assets assumption was developed based on a review of historical returns for the major asset classes. That 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 that would otherwise be 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 2008. 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:
Notes to Financial Statements
New York State Electric & Gas Corporation
In December 2003 President Bush signed into law the Medicare Act. The Medicare Act introduces a federal subsidy (the subsidy) to sponsors of single-employer defined benefit postretirement health care plans that provide to some or all participants prescription drug benefits that are at least actuarially equivalent to Medicare Part D.
In May 2004 the FASB issued its FSP No. FAS 106-2, which provides guidance on accounting for the effects of the Medicare Act and requires certain disclosures regarding the effect of the subsidy. NYSEG adopted FSP No. FAS 106-2 prospectively in the third quarter of 2004 and remeasured its plan assets and APBO as of July 1, 2004, including the effects of the Medicare Act and the subsidy. Based on information available as of the date of adoption of FSP No. FAS 106-2, NYSEG concluded that the prescription drug benefits provided by its postretirement health care plans are actuarially equivalent to Medicare Part D benefits to be provided under the Medicare Act.
As of July 1, 2004, the reduction in NYSEG's APBO for the subsidy related to benefits attributed to past service was $25 million. The subsidy reduced NYSEG's measurement of its net periodic postretirement benefit cost by $2.1 million for the six months ended December 31, 2004, including the following amounts that were reduced: interest cost $0.8 million and amortization of unrecognized net actuarial gain $1.3 million.
NYSEG's weighted-average asset allocations at December 31, 2004 and 2003, by asset category are:
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 did not include any Energy East common stock at December 31, 2004 and 2003.
NYSEG does not anticipate any contributions to its pension fund in 2005.
Notes to Financial Statements
New York State Electric & Gas Corporation
Expected benefit payments and expected Medicare Act subsidy receipts, which reflect expected future service, as appropriate, are as follows:
Note 13. Segment Information
Selected financial information for NYSEG's operating 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. NYSEG measures segment profitability based on net income. Corporate assets that have previously been included in the Other segment have been reclassified to either the Electric Delivery segment or the Natural Gas Delivery segment.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 14. Quarterly Financial Information (Unaudited)
Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of
New York State Electric and Gas Corporation:
In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of New York State Electric and Gas Corporation at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 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 accompanying index 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards 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 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
March 14, 2005
NEW YORK STATE ELECTRIC & GAS CORPORATION
SCHEDULE II - Valuation and Qualifying Accounts
Years Ended December 31, 2004, 2003 and 2002
Classification
Beginning
of Year
Additions
Write-offs (a)
Adjustments
End
of Year
(Thousands)
Allowance for Doubtful
Accounts - Accounts
Receivable
$10,288
$15,250
$(15,250)
$(3,000)
$7,288
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
(a) Uncollectible accounts charged against the allowance, net of recoveries.
Selected Financial Data
Rochester Gas and Electric Corporation
(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
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 coal-fired plant, three gas turbines and several smaller hydroelectric stations.
RG&E 2004 Electric and Natural Gas Rate Agreements: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
Sale of Ginna: 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.
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.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Rochester Gas and Electric Corporation
Manufactured Gas Plant Remediation Recovery: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
NYISO Billing Adjustment: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
Errant Voltage: See Energy East's Item 7 - Electric Delivery Business, for this discussion.
RG&E Union Contract: 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.
RG&E 2004 Electric and Natural Gas Rate Agreements : See Energy East's Item 7 - Electric Delivery Business, for this discussion.
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.
RG&E Union Contract: 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
Contractual Obligations and Commercial Commitments
At December 31, 2004, RG&E's contractual obligations and commercial commitments are:
(1)
Amounts for long-term debt include future interest payments. Future interest payments on variable-rate debt are determined using the rates at December 31, 2004. (2)
Amounts are through 2014 only.
RG&E and NYSEG have a joint revolving credit agreement in which they each covenant to maintain certain debt and earnings ratios. RG&E has a credit agreement in which it covenants to maintain the same debt and earnings ratios as in its joint revolving credit agreement. (See Note 7 to RG&E's Financial Statements.)
Critical Accounting Estimates
See Energy East's Item 7 -
Critical Accounting Estimates for discussions of Statement 71, Goodwill and Other Intangible Assets, Pension and Other Postretirement Benefit Plans, and Unbilled Revenues.
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 $82 million in 2004, $110 million in 2003 and $124 million in 2002, including nuclear fuel. Capital spending in all three years was financed principally 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.
Capital spending is projected to be $91 million in 2005. It is expected to be paid for principally with internally generated funds and will be primarily for the same purposes described above. (See Note 9 to RG&E's Financial Statements.)
RG&E's pension plans generated pretax noncash pension income of $21 million in 2004, compared to $18 million in 2003 and $21 million in 2002. RG&E anticipates no funding requirements in 2005 and had no funding requirements in 2004 as total plan assets exceeded the projected benefit obligation. (See Note 12 to RG&E's Financial Statements.)
Financing Activities: In July 2004 RG&E and NYSEG replaced their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-year $230 million revolving credit facility with certain banks. RG&E is permitted to borrow up to $75 million under the facility, NYSEG is permitted to borrow up to $180 million, and RG&E and NYSEG are allowed to issue letters of credit totaling up to $40 million. The aggregate borrowings and letters of credit may not exceed a combined total of $230 million. RG&E had no amounts outstanding under either agreement during 2004 or 2003.
RG&E uses short-term, unsecured notes to finance working capital needs and for other corporate purposes. RG&E had no such short-term debt outstanding at December 31, 2004 and 2003.
RG&E declared common dividends of $170 million in the second quarter of 2004 and an additional $75 million in the fourth quarter in order to rebalance its capital structure after the sale of Ginna. These funds are being used to reduce debt outstanding at Energy East.
See Energy East's Item 7 -
RG&E Financing Activities for detail of specific debt and preferred stock redemptions.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Rochester Gas and Electric Corporation
Results of Operations
Earnings
RG&E's earnings for 2004 increased $42 million. The increase was primarily a result of:
Additional earnings of $23 million as a result of one-time and ongoing effects from RG&E's 2004 Electric and Natural Gas Rate Agreements, including ratemaking treatment for the sale of Ginna. The one-time effects, which added $10 million, include the flow-through of excess deferred taxes and ITCs and the elimination of certain reserves established pending regulatory determination. Ongoing effects added $13 million to earnings, and include increases as a result of RG&E's electric retail access surcharge and natural gas merchant function charge, and annual credits from the ASGA as provided in RG&E's Electric Rate Agreement.
The effect of a $30 million reduction in earnings for 2003 due to the recognition of terms and conditions of an NYPSC rate order for RG&E effective January 2003, including $26 million for excess electric earnings and related interest.
Those increases were offset by:
A $13 million decrease from lower electric revenue, exclusive of the effects of the Electric Rate Agreement.
Earnings for 2003 decreased $20 million primarily due to:
The recognition of the terms and conditions of an NYPSC rate order for RG&E, effective January 2003, which reduced earnings $30 million, including $26 million for excess electric earnings and related interest.
The above decrease was partially offset by:
An increase of $6 million primarily for higher natural gas deliveries because of colder winter weather in 2003.
A $9 million increase due to a writedown of software development costs that reduced earnings in 2002.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Rochester Gas and Electric Corporation
Other Items
Other Operating Expenses: Net periodic pension income is included in other operating expenses and reduces the amount of expense that would otherwise be reported. Other operating expenses would have been $3 million lower for 2003 if net periodic pension income had not changed compared to the prior year. The effect from changes in pension income reflects any deferral mechanism approved by the NYPSC. These deferrals had the effect of reducing pension income by $4 million in 2004.
Other (Income) and Other Deductions: (See Note 1 to RG&E's Financial Statements.) Changes for 2004 and 2003 include:
An increase of $6 million in Other (Income) for 2004 primarily due to RG&E's 2004 Electric and Natural Gas Rate Agreements.
A decrease of $11 million in Other (Income) for 2003 primarily due to lower merger costs.
Interest Charges, Net: Interest charges, net decreased $21 million in 2004 and increased $16 million in 2003 primarily due to the effect of $21 million of interest expense incurred in 2003 related to the recognition of the terms and conditions of the NYPSC rate order for RG&E, discussed above.
Operating Results for the Electric Delivery Business
Operating Revenues
2004 operating revenues decreased $12 million primarily as a result of:
A net reduction of $19 million due to a change in market structure that allows customers to choose other supply options. Retail revenues declined $123 million but that decrease was partially offset by higher wholesale revenues of $104 million.
Those decreases were partially offset by:
Increases due to certain provisions of RG&E's Electric Rate Agreement, approved in May 2004, including a $4 million increase from a retail access surcharge and a $6 million increase as a result of various credits from amortization of the ASGA.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Rochester Gas and Electric Corporation
Operating revenues for 2003 decreased $29 million primarily as a result of:
A decrease in retail deliveries mainly due to cooler summer weather in 2003.
Operating Expenses:
Operating expenses decreased $157 million in 2004 primarily as a result of:
A net decrease of $112 million due to the regulatory treatment of RG&E's gain on the sale of Ginna, which includes the recognition of a $341 million pretax gain partially offset by the after-tax deferral of the gain of $229 million.
The effect of the recognition of terms and conditions of the NYPSC rate order for RG&E, effective January 2003, that increased operating expenses $30 million in 2003.
A $10 million decrease in operating and maintenance costs because of certain deferral petitions that were resolved as part of RG&E's Electric Rate Agreement.
A $16 million decrease in fuel and purchase power from sources other than Ginna.
Those decreases in operating expenses were offset by the following:
Cost increases resulting from the sale of Ginna and the subsequent purchases of 90% of the plant output amounting to $18 million. Purchases from Ginna increased fuel and purchased power costs by $91 million in 2004. Operating costs, including depreciation and decommissioning, were reduced by $73 million.
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.
The effect of a scheduled refueling outage at Ginna that added $10 million to operating costs in 2002.
The effect of a writedown of software development costs that increased operating costs $10 million in 2002.
Those decreases were partially offset by:
RG&E's recognition of the terms and conditions of the NYPSC rate order effective January 2003, that increased operating expenses $30 million.
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
Operating revenues for 2004 increased $21 million primarily as a result of:
Higher market prices for natural gas purchased of $21 million that were passed on to customers.
A $5 million increase as a result of the merchant function charge included in RG&E's Natural Gas Rate Agreement.
These increases are partially offset by:
A $6 million decrease resulting from lower deliveries, primarily due to warmer weather in the first quarter.
The $61 million increase in 2003 operating revenues was primarily a result of:
Higher market prices of natural gas purchased of $37 million that were passed on to customers.
Higher retail deliveries of $22 million mainly due to colder winter weather in 2003.
A $5 million increase due to higher delivery prices collected from customers effective in March 2003.
Operating Expenses:
2004 operating expenses increased $21 million primarily as a result of:
An increase in natural gas purchased because of higher market prices.
Operating expenses for 2003 increased $51 million primarily as a result of higher natural gas purchased, including:
A $36 million increase due to higher market prices.
An increase of $15 million due to higher retail deliveries because of colder winter weather in 2003.
Rochester Gas and Electric Corporation
Balance Sheets
The
notes on pages 155 through 171 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Balance Sheets
The
notes on pages 155 through 171 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Statements of Income
The
notes on pages 155 through 171 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Statements of Cash Flows
The
notes on pages 155 through 171 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Statements of Changes in Common Stock Equity
The
notes on pages 155 through 171 are an integral part of the financial statements.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 1. Significant Accounting Policies
Background: 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. 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 $40 million at December 31, 2004, and $50 million at December 31, 2003, and are shown net of an allowance for doubtful accounts of $21 million at December 31, 2004, and $27 million at December 31, 2003. Accounts receivable balances do not bear interest although late fees may be assessed. Bad debt expense was $5 million in 2004, $11 million in 2003 and $9 million in 2002. The allowance for doubtful accounts is RG&E's best estimate of the amount of probable credit losses in existing accounts receivable. RG&E determines the allowance based on experience for each operating segment and other economic data. Each month RG&E reviews its allowance for doubtful accounts and its past due accounts over 90 days and/or above a specified amount. RG&E reviews all other balances on a pooled basis by age and type of receivable. When RG&E believes that a receivable will not be recovered, it charges off the account balance against the allowance. RG&E does not have any off-balance sheet credit exposure related to its customers.
Asset retirement obligation: In June 2001 the FASB issued Statement 143. 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. In accordance with Statement 143, RG&E records the fair value of the liability for an asset retirement obligation in the period in which it is incurred and capitalizes the cost by increasing the carrying amount of the related long-lived asset. RG&E adjusts the liability to its present value periodically over time, and depreciates the capitalized cost over the useful life of the related asset. Upon settlement RG&E will either settle the obligation at its recorded amount or incur a gain or a loss. RG&E will defer any timing differences between rate recovery and book expense as either a regulatory asset or a regulatory liability. RG&E's asset retirement obligation was $436 million at December 31, 2003. Substantially all of this amount was related to Ginna, which was sold in June 2004 and reduced the asset retirement obligation $434 million. The remaining balance of $2 million primarily consists of obligations related to cast iron gas mains.
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. RG&E classifies these amounts as accrued removal obligations.
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.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Decommissioning expense: Other operating expenses include nuclear decommissioning expense accruals until early June 2004, which resulted in corresponding decreases in the regulatory asset for the asset retirement obligation. As a result of the sale of Ginna on June 10, 2004, RG&E no longer has a decommissioning obligation and will not incur additional decommissioning expense.
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 - 58 years, distribution property - 54 years and other property - 23 years. RG&E determines depreciation expense for the majority of its 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 4 years for its coal station to 32 years for its hydroelectric stations. RG&E's depreciation accruals were equivalent to 3.6% of average depreciable property for 2004 and 2003 and 3.7% for 2002.
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. ITCs are amortized over the estimated lives of the related assets.
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 2004 presentation.
Notes to Financial Statements
Rochester Gas and Electric Corporation
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, Inc., a subsidiary of RGS Energy. Transactions between RG&E and Energetix, Inc. 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, Inc. (in millions):
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 RG&E sells electricity from owned generation to the NYISO, and subsequently repurchases electricity from the NYISO to serve its customers, RG&E records the transactions on a net basis in its statements of income.
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's electric rate agreement allowed the company to recover its actual electricity supply cost during the period May 1, 2004, through December 31, 2004, through its Electric Supply Reconciliation mechanism.
RG&E does not hold or issue derivative instruments for trading or speculative purposes.
Notes to Financial Statements
Rochester Gas and Electric Corporation
RG&E recognizes the fair value of its natural gas futures and forwards, financial electricity contracts and interest rate agreements as other assets or other liabilities. RG&E had $5 million of derivative assets at December 31, 2004, including $4 million current and $1 million long-term. RG&E had $5 million of derivative liabilities at December 31, 2004, all of which were current. At December 31, 2003, RG&E had $8 million of derivative assets and less than $1 million of derivative liabilities.
As of December 31, 2004, 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 150: In May 2003 the FASB issued Statement 150. 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. RG&E adopted Statement 150 as of July 1, 2003, and classified its $25 million of mandatorily redeemable preferred stock as a liability in its statement of financial position, which it had previously classified as equity. RG&E also began to recognize as interest expense distributions that it had previously recognized as preferred stock dividends. 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. Sale of Ginna
On June 10, 2004, RG&E sold Ginna to CGG and received at closing $429 million in cash. On September 9, 2004, RG&E received an additional $25 million from CGG related to certain post-closing adjustments. As a result, RG&E's statement of income for 2004 reflects a gain on the sale of Ginna of $341 million. The deferral of the asset sale gain, after related taxes of $112 million, is $229 million.
RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna, including providing for an ASGA of $380 million after the post-closing adjustments, and addressing the disposition of the asset sale gain. Upon closing of the sale of Ginna, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. RG&E retained $77 million in excess decommissioning funds, which were credited to customers as part of the ASGA.
Notes to Financial Statements
Rochester Gas and Electric Corporation
A summary of the effects of the sale of Ginna and the related ASGA follows (in thousands):
The ASGA was adjusted subsequent to the sale to reflect provisions of RG&E's 2004 Electric Rate Agreement, including refunds due to customers. Adjustments to the ASGA to reconcile to the balance of the deferred regulatory liability as of December 31, 2004, are as follows (in thousands):
Nuclear insurance: Because of the sale of Ginna, RG&E is no longer subject to the Price-Anderson Act, which 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. Prior to the sale, RG&E carried the maximum available commercial insurance of $300 million and participated in a mandatory financial protection pool for the remaining $10.5 billion of the approximately $10.8 billion public liability limit for a nuclear incident. Under the terms of the sale, RG&E remains liable for assessments under the mandatory financial protection pool for incidents that may have occurred prior to the sale on June 10, 2004. If an incident can be conclusively determined to have occurred prior to the sale, RG&E could be assessed up to $101 million per incident payable at a rate not to exceed $10 million per incident per year. RG&E is not aware of any incidents that would lead to such an assessment.
In addition to the insurance required by the Price-Anderson Act, RG&E also carried nuclear property damage insurance and accidental outage insurance through NEIL. Under those insurance policies, RG&E could be subject to retrospective premium adjustments for six years following the end of the policy period if losses exceed the accumulated funds available to the insurers. The maximum amounts of the adjustments for RG&E's final policy year were $13 million for nuclear property damage insurance and $4 million for accidental outage insurance. RG&E is not aware of any events that would initiate a retrospective premium adjustment under the NEIL policies.
Notes to Financial Statements
Rochester Gas and Electric Corporation
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 restructuring expenses would have been $36 million higher, however RG&E was required by an NYPSC order approving RGS Energy's merger with Energy East 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. RG&E's entire related involuntary severance liability of $4 million was paid during 2003 and deferred for recovery.
Energy East has consolidated the accounting and finance functions of five of its operating companies to one location. In connection with that restructuring, in the fourth quarter of 2003 RG&E began to recognize a $1 million total liability for an enhanced severance program for certain accounting and finance employees who were employed through March 31, 2004. The liability was paid as of June 30, 2004.
Note 4. 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 consist of water rights and had a gross carrying amount of $3 million and accumulated amortization of about $2 million at December 31, 2004 and 2003. Estimated amortization expense for intangible assets is $78 thousand for each of the next five years, 2005 through 2009.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 5. Income Taxes
RG&E's effective tax rate differed from the statutory rate of 35% due to the following:
RG&E's effective tax rate for 2004 differed from the expected annual effective tax rate primarily as a result of the deferred gain from the sale of Ginna. RG&E recorded pretax income of $112 million and income tax expense of $112 million. Other factors contributing to the increase in the effective tax rate were increases in estimates of prior year taxes of $4 million primarily the result of the effects of the combined New York State tax filings for 2002 and 2003. Energy East files a combined unitary income tax return in New York. It allocates the combined unitary tax to its subsidiaries on the basis of its tax sharing agreement. (See Note 1.) In 2004 Energy East revised its estimate of New York State income taxes based on its unitary filing position and allocated $5 million of additional taxes to RG&E. After the federal tax effect, the remaining $3 million was included in RG&E's net income. Those adjustments, coupled with the asset sale gain deferral, increased RG&E's 2004 effective tax rate to 69%.
Notes to Financial Statements
Rochester Gas and Electric Corporation
At December 31, 2004 and 2003, RG&E's deferred tax assets and liabilities were:
RG&E has no federal or state tax credit or loss carryforwards, and no valuation allowances.
Note 6. Long-term Debt
Preferred stock subject to mandatory redemption requirements: On March 1, 2004, RG&E redeemed, at par, as required by a mandatory sinking fund provision, $1.25 million of 6.60% Series V preferred stock, Par Value $100. On May 5, 2004, RG&E redeemed, at par, the remaining $23.75 million of the 6.60% Series V preferred stock.
Other long-term Debt: At December 31, 2004 and 2003, 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.
Notes to Financial Statements
Rochester Gas and Electric Corporation
At December 31, 2004, other long-term debt, including sinking fund obligations (in thousands), that will become due during the next five years is:
Note 7. Bank Loans and Other Borrowings
RG&E uses short-term, unsecured notes to finance working capital needs and for other corporate purposes. RG&E had no such short-term debt outstanding at December 31, 2004 or 2003.
RG&E and NYSEG have a joint $230 million five-year revolving credit facility with certain banks, which in July 2004 replaced their previous 364-day facility. RG&E is permitted to borrow up to $75 million under the facility, NYSEG is permitted to borrow up to $180 million, and RG&E and NYSEG are allowed to issue letters of credit totaling up to $40 million. The aggregate borrowings and letters of credit may not exceed a combined total of $230 million. 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 .175% at December 31, 2004 and was .15% at December 31, 2003, under the previous agreement. RG&E had no amounts outstanding under the agreements, either at December 31, 2004, or December 31, 2003.
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 0.65 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, 2004, RG&E's ratio of earnings before interest expense and income tax to interest expense was 5.6 to 1.0, and its ratio of total indebtedness to total capitalization was 0.55 to 1.0
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 8. Preferred Stock Redeemable Solely at the Option of RG&E
At December 31, 2004 and 2003, RG&E 's serial cumulative preferred stock was:
(1) At December 31, 2004, RG&E had 2,000,000 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 redeemed or purchased the following amount of preferred stock during the three years 2002 through 2004: On May 5, 2004, $12 million of 4% Series F (120,000 shares), $8 million of 4.10% Series H (80,000 shares), $6 million of 4 3/4% Series I (60,000 shares), $5 million of 4.10% Series J (50,000 shares), $6 million of 4.95% Series K (60,000 shares) and $10 million of 4.55% Series M (100,000 shares), all redeemed at a premium.
Note 9. Commitments and Contingencies
Capital spending: RG&E has commitments in connection with its capital spending program. Capital spending is projected to be $91 million in 2005 and is expected to be paid for principally 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.
NYISO billing adjustment: The NYISO frequently bills transmission owners on a retroactive basis when adjustments are necessary. Such retroactive billings can cover several months or years and cannot be reasonably estimated. RG&E records transmission revenue or expense as appropriate when revised amounts can be estimated. On January 25, 2005, the NYISO notified transmission owners, including RG&E, of a revenue allocation formula error related to transmission congestion contracts for periods including May 2000 through October 2002. The NYISO has not yet provided any further details. The correction of the error may result in revised billings to RG&E. RG&E cannot predict at this time either the magnitude or the direction of any billing adjustments.
Notes to Financial Statements
Rochester Gas and Electric Corporation
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 EPA 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 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, three 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 five sites. An estimated liability of $2 million has been recorded related to eight 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 accrued 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.
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 $20 million to $32 million at December 31, 2004. 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 $20 million at December 31, 2004 and $19 million at December 31, 2003.
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.
Notes to Financial Statements
Rochester Gas and Electric Corporation
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. A majority of the investments classified as held for sale in 2003 represented decommissioning trust funds for Ginna. In June 2004 those funds were transferred to CGG or made available to RG&E for general corporate purposes.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 12. Retirement Benefits
RG&E sponsors defined benefit pension plans and postretirement benefit plans applicable to substantially all employees. 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 $441 million at December 31, 2004, and $446 million at December 31, 2003. The sale of Ginna resulted in a decrease in the projected benefit obligation of $52 million, and $51 million in pension funds were transferred as part of the sale.
RG&E's postretirement benefits were unfunded as of December 31, 2004 and 2003.
Notes to Financial Statements
Rochester Gas and Electric Corporation
As of December 31, 2004, RG&E decreased its discount rate from 6.25% to 5.75%.
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 that resulted from the adoption of Statement 106 is being amortized over 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. That 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 that would otherwise be 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 2005 that gradually decreases to 5.0% by the year 2008. 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:
Notes to Financial Statements
Rochester Gas and Electric Corporation
In December 2003 President Bush signed into law the Medicare Act. The Medicare Act introduces a federal subsidy (the subsidy) to sponsors of single-employer defined benefit postretirement health care plans that provide to some or all participants prescription drug benefits that are at least actuarially equivalent to Medicare Part D.
In May 2004 the FASB issued FSP No. FAS 106-2, which provides guidance on accounting for the effects of the Medicare Act and requires certain disclosures regarding the effect of the subsidy. RG&E determined that the effects of the Medicare Act and the subsidy are insignificant because of employer caps and limited employee participation in RG&E's plans that provide postretirement prescription drug benefits.
RG&E's weighted-average asset allocations at December 31, 2004 and 2003, 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 did not include any Energy East common stock at December 31, 2004 and 2003.
RG&E does not anticipate any contributions to its pension fund in 2005.
Expected benefit payments, which reflect expected future service, as appropriate, are as follows:
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 13. Segment Information
Selected financial information for RG&E's operating 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. RG&E measures segment profitability based on net income. Corporate assets that have previously been included in the Other segment have been reclassified to either the Electric Delivery segment or the Natural Gas Delivery segment.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 14. Quarterly Financial Information (Unaudited)
Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of
Rochester Gas & Electric Corporation:
In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Rochester Gas & Electric Corporation at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 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 accompanying index 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards 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 consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligation and effective July 1, 2003, the Company adopted of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.
PricewaterhouseCoopers LLP
New York, New York
March 14, 2005
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE II - Valuation and Qualifying Accounts
Years Ended December 31, 2004, 2003 and 2002
Classification
Beginning
of Year
Additions
Write-offs
Adjustments
End
of Year
(Thousands)
Allowance for Doubtful
Accounts - Accounts
Receivable
$27,182
$4,733
$(4,733)
$(5,700)
$21,482
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
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 May 2, 2005.
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 May 2, 2005.
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 caption "Security Ownership of Certain Beneficial Owners and Management" in Energy East's Proxy Statement, which will be filed with the Commission on or before May 2, 2005.
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 May 2, 2005.
None for CMP, NYSEG or RG&E.
Item 14.
Item 14. Principal Accounting 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 May 2, 2005.
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 Schedules
The following documents are filed as part of this report for Energy East and CMP:
Financial statements
Included in Part II of this report:
Consolidated Balance Sheets as of December 31, 2004 and 2003
For the three years ended December 31, 2004:
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 Registered Public Accounting Firm
Financial statement schedule
Included in Part II of this report:
For the three years ended December 31, 2004
II. Consolidated Valuation and Qualifying Accounts
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:
____________________________
* Furnished pursuant to Regulation S-K Item 601(b)(32).
(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 -
Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on June 21, 2004 - Company's 10-Q for the quarter ended June 30, 2004 - File No.
1-14766
3-5
3-4 -
By-Laws of the Company as amended April 8, 2004 - Company's 10-Q for the quarter ended March 31, 2004 - 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
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
Registrant
Exhibit No.
Filed in
As Exhibit No.
Energy East Corporation
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 -
Supplemental Executive Retirement Plan Amendment No. 2 - Company's 10-Q for the quarter ended June 30, 2004 - File No.
1-14766
10-22
(A)10-7 -
Annual Executive Incentive Plan - Company's 10-K for the year ended December 31, 2000 - File No. 1-14766
10-8
(A)10-8 -
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)10-9 -
Annual Executive Incentive Plan Amendment No. 2 - Company's 10-Q for the quarter
ended June 30, 2001 - File No. 1-14766
10-28
Registrant
Exhibit No.
Filed in
As Exhibit No.
Energy East Corporation
(A)10-10 -
Deferred Compensation Plan, effective January 1, 2004 - Company's 10-K for the year ended December 31, 2003 - File No.
1-14766
10-9
(A)10-11 -
Amended and Restated Employment Agreement dated as of July 1, 2004, by and among the Company, Energy East Management Corporation and W. W. von Schack - Company's 10-Q for the quarter ended June 30, 2004 - File No.
1-14766
10-21
(A)10-12 -
Employment Agreement dated February 8, 2002, by and among the Company, Energy East Management Corporation and K. M. Jasinski - Company's 10-K for the year ended December 31, 2001 - File No. 1-14766
10-15
(A)10-13 -
Restricted Stock Plan - Company's 10-K for the year ended December 31, 1998 - File No. 1-14766
10-36
(A)10-14 -
Restricted Stock Plan Amendment No. 1 - Company's 10-K for the year ended December 31, 2002 - File No. 1-14766
10-16
(A)10-15 -
Form of Restricted Stock Award Grant - Company's 10-K for the year ended December 31, 2002 - File No. 1-14766
10-17
(A)10-16 -
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)10-17 -
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)10-18 -
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)10-19 -
Director's Charitable Giving Program - Company's 10-Q for the quarter ended June 30, 2003 - File No. 1-14766
10-25
(A)10-20 -
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)10-21 -
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
Registrant
Exhibit No.
Filed in
As Exhibit No.
Central Maine Power Company
3-3 -
Amended and Restated By-Laws - Company's 10-Q for the quarter ended June 30, 2001 - File No. 1-5139
3-2
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
Registrant
Exhibit No.
Filed in
As Exhibit No.
Central Maine 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 - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554
10-2.1
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 Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766
10-22
(A)10-13 -
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)10-14 -
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)10-15 -
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)10-16 -
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)10-17 -
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)10-18 -
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)10-19 -
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
Registrant
Exhibit No.
Filed in
As Exhibit No.
Central Maine Power Company
(A)10-20 -
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)10-21 -
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
(A)10-22 -
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)10-23 -
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)10-24 -
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)10-25 -
Deferred Compensation Plan, 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
Registrant
Exhibit No.
Filed in
As Exhibit No.
New York State Electric
& Gas Corporation
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
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
Registrant
Exhibit No.
Filed in
As Exhibit No.
New York State Electric
& Gas Corporation
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
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 -
Supplemental Executive Retirement Plan Amendment No. 1 - Company's 10-K for the year ended December 31, 2001 - File No.
1-3103-2
10-5
(A)10-5 -
Supplemental Executive Retirement Plan Amendment No. 2 - Company's 10-Q for the quarter ended March 31, 2002 - File No.
1-3103-2
10-31
(A)10-6 -
Supplemental Executive Retirement Plan Amendment No. 3 - Company's 10-Q for the quarter ended June 30, 2002 - File No.
1-3103-2
10-32
(A)10-7 -
Supplemental Executive Retirement Plan Amendment No. 4 - Company's 10-Q for the quarter ended June 30, 2003 - File No.
1-3103-2
10-35
Registrant
Exhibit No.
Filed in
As Exhibit No.
New York State Electric
& Gas Corporation
(A)10-8 -
Supplemental Executive Retirement Plan Amendment No. 5 - Company's 10-Q for the quarter ended March 31, 2004 - File No.
1-3103-2
10-33
(A)10-9 -
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)10-10 -
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)10-11 -
Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No.
1-14766
10-22
(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 -
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)10-16 -
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)10-17 -
Form of Severance Agreement for Senior
Vice Presidents Amendment No. 2 - Company's Schedule 14D-9, dated July
30, 1997
(A)10-18 -
Form of Severance Agreement for Senior
Vice Presidents Amendment No. 3 - Company's Schedule 14D-9, dated July
30, 1997
(A)10-19 -
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)10-20 -
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)10-21 -
Form of Severance Agreement for Vice Presidents Amendment No. 2 - Company's Schedule 14D-9, dated July 30, 1997
Registrant
Exhibit No.
Filed in
As Exhibit No.
New York State Electric
& Gas Corporation
(A)10-22 -
Form of Severance Agreement for Vice Presidents Amendment No. 3 - Company's Schedule 14D-9, dated July 30, 1997
(A)10-23 -
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)10-24 -
Employee Invention and Confidentiality Agreement (Existing Executive) - Company's Schedule 14D-9, dated July 30, 1997
(A)10-25 -
Employee Invention and Confidentiality Agreement (Existing Executive) Amendment No. 1 - Company's Schedule 14D-9, dated July 30, 1997
(A)10-26 -
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)10-27 -
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)10-28 -
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)10-29 -
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)10-30 -
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)10-31 -
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)10-32 -
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)10-33 -
Deferred Compensation Plan, 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
Registrant
Exhibit No.
Filed in
As Exhibit No.
Rochester Gas and Electric
Corporation
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
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 -
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 - Company's 10-K for the year ended December 31, 2003 - File No. 1-672
10-7
(A)10-6 -
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
(A)10-7 -
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
Registrant
Exhibit No.
Filed in
As Exhibit No.
Rochester Gas and Electric
Corporation
(A)10-8 -
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)10-9 -
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)10-10 -
Supplemental Executive Retirement Program Amendment No. 4, effective as of May 1, 2004 - Company's 10-Q for the quarter ended March 31, 2004 - File No. 1-672
10-25
(A)10-11 -
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)10-12 -
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)10-13 -
Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No.
1-14766
10-22
(A)10-14 -
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)10-15 -
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)10-16 -
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)10-17 -
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)10-18 -
Supplemental Retirement Benefit Program Amendment No. 4, effective as of May 1, 2004 - Company's 10-Q for the quarter ended March 31, 2004 - File No. 1-672
10-26
(A)10-20 -
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)10-21 -
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
Registrant
Exhibit No.
Filed in
As Exhibit No.
Rochester Gas and Electric
Corporation
(A)10-22 -
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)10-23 -
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)10-24 -
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)10-25 -
Form of Severance Agreement, as amended - Company's 10-K for the year ended December 31, 2002 - File No. 1-672
10-21
(A)10-26 -
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)10-27 -
Deferred Compensation Plan, 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:
A.
Five-Year Revolving Credit Agreement among Energy East, certain lenders, Wachovia Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent and Citibank, N.A., KeyBank N.A. and UBS Loan Finance, LLC, as Co-Documentation Agents, dated as of July 21, 2004.
B.
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.
C.
Revolving Credit Agreement among NYSEG, RG&E, certain lenders, JPMorgan Chase Bank, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent and Citibank, N.A., KeyBank N.A. and UBS Loan Finance, LLC, as Co-Documentation Agents, dated as of July 21, 2004 (the "Joint Revolving Credit Agreement").
D.
The Southern Connecticut Gas Company's Indenture, dated as of March 1, 1948, with The Bridgeport City Trust Company (now US Bank, N.A.), as Trustee, and Supplemental Indentures related thereto.
E.
Connecticut Natural Gas Corporation's Issuing and Paying Agency Agreement with The Connecticut National Bank (now US Bank, N.A.) for Medium Term Notes, Series A, dated November 1, 1991.
F.
Connecticut Natural Gas Corporation's Issuing and Paying Agency Agreement with Shawmut Bank Connecticut, National Association (now US Bank, N.A.) for Medium Term Notes, Series B, dated June 14, 1994, and an Amendment related thereto.
G.
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.
H.
Loan Agreement, dated April 30, 2004, between The Berkshire Gas Company and Banknorth, N.A.
I.
Senior Note Agreement dated as of July 1, 1990 between The Berkshire Gas Company and Allstate Life Insurance Company.
J.
Senior Note Agreement dated as of November 1, 1996 between The Berkshire Gas Company and First Colony Life Insurance Company, and Amendments related thereto.
The total amount of securities authorized under each of such documents does not exceed 10% of the total assets of Energy East.
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 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); 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); a copy of the Participation Agreements dated as of August 1, 2004, between NYSEG and NYSERDA relating to Pollution Control Revenue Bonds (2004 Series A), (2004 Series B) and (2004 Series C); and a copy of the Joint Revolving Credit Agreement. 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 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); a copy of the Participation Agreements dated as of August 1, 2004, between RG&E and NYSERDA relating to Pollution Control Revenue Bonds (2004 Series A) and (2004 Series B); a copy of certain supplemental indentures to the General Mortgage dated September 1, 1918, as supplemented; and a copy of the Joint Revolving Credit Agreement. The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of RG&E.
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 14, 2005
ENERGY EAST CORPORATION
By /s/Kenneth M. Jasinski
Kenneth M. Jasinski
Executive Vice President and
Chief Financial Officer
Date: March 14, 2005
CENTRAL MAINE POWER COMPANY
By /s/R. Scott Mahoney
R. Scott Mahoney
Vice President - Controller &
Treasurer, Clerk
Date: March 14, 2005
NEW YORK STATE ELECTRIC & GAS CORPORATION
By /s/Joseph J. Syta
Joseph J. Syta
Vice President - Controller and Treasurer
Date: March 14, 2005
ROCHESTER GAS AND ELECTRIC CORPORATION
By /s/Joseph J. Syta
Joseph J. Syta
Vice President - 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 14, 2005
PRINCIPAL EXECUTIVE OFFICER
By /s/Wesley W. von Schack
Wesley W. von Schack
Chairman, President, Chief
Executive Officer & Director
Date: March 14, 2005
PRINCIPAL FINANCIAL OFFICER
By /s/Kenneth M. Jasinski
Kenneth M. Jasinski
Executive Vice President and
Chief Financial Officer
Date: March 14, 2005
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 14, 2005
By /s/Richard Aurelio
Richard Aurelio, Director
Date: March 14, 2005
By /s/John T. Cardis
John T. Cardis, Director
Date: March 14, 2005
By /s/James A. Carrigg
James A. Carrigg, Director
Date: March 14, 2005
By /s/Joseph J. Castiglia
Joseph J. Castiglia, Director
Date: March 14, 2005
By /s/Lois B. DeFleur
Lois B. DeFleur, Director
Date: March 14, 2005
By /s/G. Jean Howard
G. Jean Howard, Director
Date: March 14, 2005
By /s/David M. Jagger
David M. Jagger, Director
Date: March 14, 2005
By /s/Seth A. Kaplan
Seth A. Kaplan, Director
Date: March 14, 2005
By /s/John M. Keeler
John M. Keeler, Director
Date: March 14, 2005
By /s/Ben E. Lynch
Ben E. Lynch, Director
Date: March 14, 2005
By /s/Peter J. Moynihan
Peter J. Moynihan, Director
Date: March 14, 2005
By /s/Walter G. Rich
Walter G. Rich, Director
Signatures
(Cont'd)
CENTRAL MAINE POWER COMPANY
Date: March 14, 2005
PRINCIPAL EXECUTIVE OFFICER
By /s/Sara J. Burns
Sara J. Burns
President and Director
Date: March 14, 2005
PRINCIPAL FINANCIAL OFFICER AND
PRINCIPAL ACCOUNTING OFFICER
By /s/R. Scott Mahoney
R. Scott Mahoney
Vice President - Controller &
Treasurer, Clerk
Date: March 14, 2005
By /s/Kenneth M. Jasinski
Kenneth M. Jasinski, Director
Date: March 14, 2005
By /s/Wesley W. von Schack
Wesley W. von Schack, Director
Signatures (Cont'd)
NEW YORK STATE ELECTRIC & GAS CORPORATION
Date: March 14, 2005
PRINCIPAL EXECUTIVE OFFICER
By /s/James P. Laurito
James P. Laurito
President and Director
Date: March 14, 2005
PRINCIPAL FINANCIAL OFFICER AND
PRINCIPAL ACCOUNTING OFFICER
By /s/Joseph J. Syta
Joseph J. Syta
Vice President - Controller and Treasurer
Date: March 14, 2005
By /s/Kenneth M. Jasinski
Kenneth M. Jasinski, Director
Date: March 14, 2005
By /s/Wesley W. von Schack
Wesley W. von Schack, Director
Signatures (Cont'd)
ROCHESTER GAS AND ELECTRIC CORPORATION
Date: March 14, 2005
PRINCIPAL EXECUTIVE OFFICER
By /s/James P. Laurito
James P. Laurito
President and Director
Date: March 14, 2005
PRINCIPAL FINANCIAL OFFICER AND
PRINCIPAL ACCOUNTING OFFICER
By /s/Joseph J. Syta
Joseph J. Syta
Vice President - Controller and Treasurer
Date: March 14, 2005
By /s/Kenneth M. Jasinski
Kenneth M. Jasinski, Director
Date: March 14, 2005
By /s/Wesley W. von Schack
Wesley W. von Schack, Director
____________________________
* Incorporated by reference.
** Furnished pursuant to Regulation S-K Item 601(b)(32).
(A) Management contract or compensatory plan or arrangement.