SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark one)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedDecember 31, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission | Exact name of Registrant as specified in its charter, | IRS Employer |
1-14766 | Energy East Corporation | 14-1798693 |
1-5139 | Central Maine Power Company | 01-0042740 |
1-3103-2 | New York State Electric & Gas Corporation | 15-0398550 |
1-672 | Rochester Gas and Electric Corporation | 16-0612110 |
Securities registered pursuant to Section 12(b) of the Act:
|
| Name of each |
Energy East Corporation | Common Stock (Par Value $.01) | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
Registrant | Title of each class |
Central Maine Power Company | 6% Preferred Stock (Par Value $100) |
Central Maine Power Company | Dividend Series Preferred Stock (Par Value $100): |
New York State Electric & Gas Corporation | Cumulative Preferred Stock (Par Value $100): |
Securities registered pursuant to Section 12(g) of the Act (continued):
Registrant | Title of each class |
Rochester Gas and Electric Corporation | Preferred Stock (Par Value $100): |
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Registrant | ||
Energy East Corporation | Yes X | No |
Central Maine Power Company | Yes | No X |
New York State Electric & Gas Corporation | Yes | No X |
Rochester Gas and Electric Corporation | Yes | No X |
The aggregate market value as of June 30, 2002, of the common stock held by nonaffiliates of Energy East Corporation was $3,265,861,929.
As of February 14, 2003, shares of common stock outstanding for each registrant were:
Registrant | Description | Shares |
Energy East Corporation | Par value $.01 per share | 144,992,967 |
Central Maine Power Company | Par value $5 per share | 31,211,471(1) |
New York State Electric & Gas Corporation | Par value $6.66 2/3 per share | 64,508,477(2) |
Rochester Gas and Electric Corporation | Par value $5 per share | 34,506,513(2) |
(1) All shares are owned by CMP Group, Inc., a wholly-owned subsidiary of Energy East Corporation.
(2) All shares are owned by RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation.
DOCUMENTS INCORPORATED BY REFERENCE
Document | 10-K Part |
Energy East Corporation has incorporated by reference certain portions of its Proxy Statement, which will be filed with the Commission on or before April 30, 2003. |
|
This combined Form 10-K is separately filed byEnergy East Corporation, Central Maine Power Company, New York State Electric & Gas Corporation andRochester Gas and Electric Corporation. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
TABLE OF CONTENTS
PART I
Page | ||
Item 1. | Business | 1 |
(a) General development of business | 1 | |
(b) Financial information about segments | 2 | |
(c) Narrative description of business | 2 | |
Principal business | 2 | |
Other businesses | 3 | |
New product or segment | 4 | |
Sources and availability of raw materials | 4 | |
Franchises | 5 | |
Seasonal business | 6 | |
Working capital items | 6 | |
Single customer | 6 | |
Backlog of orders | 6 | |
Business subject to renegotiation | 6 | |
Competitive conditions | 6 | |
Research and development | 6 | |
Environmental matters | 6 | |
Water and air quality | 7 | |
Waste disposal | 8 | |
Number of employees | 8 | |
(d) Financial information about geographic areas | 8 | |
Item 2. | Properties | 8 |
Item 3. | Legal proceedings | 10 |
Item 4. | Submission of matters to a vote of security holders | 11 |
Executive officers of the Registrants | 12 |
PART II
Item 5. | Market for Registrants' common equity and related stockholder matters | 14 |
Item 6. | Selected financial data | 14 |
Item 7. | Management's discussion and analysis of financial condition and results of operations | 14 |
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 15 |
Item 8. | Financial statements and supplementary data | 18 |
Item 9. | Changes in and disagreements with accountants on accounting and financial disclosure | 18 |
TABLE OF CONTENTS (Cont'd)
PART III
Page | ||
Item 10. | Directors and executive officers of the Registrants | 153 |
Item 11. | Executive compensation | 153 |
Item 12. | Security ownership of certain beneficial owners and management | 153 |
Item 13. | Certain relationships and related transactions | 153 |
Item 14. | Controls and procedures | 154 |
Item 15. | Exhibits, financial statement schedule, and reports on Form 8-K | 154 |
(a) List of documents filed as part of this report | ||
Financial statements | 154 | |
Financial statement schedule | 154 | |
Exhibits | ||
Exhibits delivered with this report | 155 | |
Exhibits incorporated herein by reference | 155 | |
(b) Reports on Form 8-K | 169 |
Signatures | 170 |
Certifications | 176 |
PART I
Item 1. Business
Energy East Corporation (Energy East or the company) makes available free of charge through its Internet Web site, http://www.energyeast.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after those reports are electronically filed with the Securities and Exchange Commission (SEC). Access to the reports is available from the main page of Energy East's Internet Web site through "Financial Information" and then "SEC filings."
(a) General development of business
Energy East: Energy East is a public utility holding company that was organized under the laws of the State of New York in 1997 and became the parent of New York State Electric & Gas Corporation (NYSEG) in May 1998. Energy East is a super-regional energy services and delivery company with operations in New York, Connecticut, Massachusetts, Maine and New Hampshire and corporate offices in New York and Maine.
The company merged with Connecticut Energy Corporation (CNE) on February 8, 2000, merged with CMP Group, Inc., CTG Resources, Inc. and Berkshire Energy Resources (Berkshire Energy) on September 1, 2000, and merged with RGS Energy Group, Inc. on June 28, 2002. (See Item 7 - Energy East and RGS Energy Merger.) All of the 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. The company's consolidated financial statements include CNE's results beginning with February 2000; CMP Group's, CTG Resources' and Berkshire Energy's results beginning with September 2000; and RGS Energy's results beginning with July 2002.
CNE is engaged in the retail distribution of natural gas in Connecticut through its wholly-owned subsidiary, The Southern Connecticut Gas Company (SCG). CMP Group's principal operating subsidiary, Central Maine Power Company (CMP), is primarily engaged in transmitting and distributing electricity generated by others to retail customers in Maine. CTG Resources is the parent of Connecticut Natural Gas Corporation (CNG), a regulated natural gas distribution company in Connecticut. Berkshire Energy's wholly-owned subsidiary, The Berkshire Gas Company (Berkshire Gas), is a regulated natural gas distribution company that operates in western Massachusetts. RGS Energy's principal operating subsidiaries are NYSEG and Rochester Gas and Electric Corporation (RG&E). NYSEG is primarily engaged in purchasing and delivering electricity and natural gas in the central, eastern and western parts of the State of New York. RG&E is primarily engaged in generating, purchasing and delivering electricity and purchasing a nd 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 on June 28, 2002, NYSEG became a wholly-owned subsidiary of RGS Energy.
Rochester Gas and Electric Corporation: RG&E is a public utility organized under the laws of the State of New York in 1904. RGS Energy was incorporated in 1998 in the State of New York and became the holding company for RG&E in August 1999. Effective June 28, 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, 2002:
Regulatory and Rate Matters
(See Item 7 - Electric Delivery Business and Natural Gas Delivery Business.)
(b) Financial information about segments
(See Item 8 - Note 16 to the company's and Note 14 to CMP's Consolidated Financial Statements, and Note 14 to NYSEG's and Note 13 to RG&E's Financial Statements.)
(c) Narrative description of business
(See Item 7 - Energy East and RGS Energy Merger, Electric Delivery Business, Natural Gas Delivery Business and Other Businesses.)
Disposition of Assets
(See Item 7 - Sale of Nuclear Interests and Sale of Other Businesses and Item 8 - Note 10 to the company's and Note 9 to CMP's Consolidated Financial Statements.)
(i) (a) Principal business
The company's principal energy delivery business consists primarily of its regulated electricity transmission, distribution and generation operations in upstate New York and Maine and its regulated natural gas transportation, storage and distribution operations in upstate New York, Connecticut, Maine and Massachusetts.
CMP's principal business consists of its regulated electricity transmission and distribution operations.
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.
RG&E's principal business consists of its regulated electricity generation, transmission and distribution operations and regulated natural gas transportation and distribution operations in western New York. RG&E generates electricity from one nuclear plant, one coal-fired plant, three gas turbine plants and several smaller hydroelectric stations.
CMP's service territory is located in the southern and central areas of Maine, and includes most of Maine's industrial and commercial centers. NYSEG's 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. RG&E's service territory includes the city of Rochester, a major industrial center in the State of New York, and a substantial suburban area with a large and prosperous agricultural area. One of the company's Connecticut service territories extends along the southern Connecticut coast from Westport to Old Saybrook and the other is located principally in the greater Hartford-New Britain area and Greenwich. The company's Massachusetts service territory is in the western area of the state. The approximate areas and populations of the company's service territories are: Maine - 11,000 square miles and one million people, New York - 23,000 square miles and 3.5 million people, Connecticut - 1,400 square miles and 1.6 million people, and Massachusetts - 1,000 square miles and 190,000 people.
In Maine CMP serves electricity customers in the city of Portland and the Lewiston-Auburn, Augusta-Waterville and Bath-Brunswick areas. The larger cities in New York in which NYSEG serves both electricity and natural gas customers are Binghamton, Elmira, Auburn, Geneva, Ithaca and Lockport. RG&E distributes electricity and natural gas to customers in parts of nine counties including and surrounding the city of Rochester, New York. The larger cities in which the company serves natural gas customers in Connecticut are Bridgeport, New Haven, Greenwich and Hartford, and in Massachusetts they are Pittsfield and North Adams.
The company serves approximately 1.8 million electricity customers and 900,000 natural gas customers, including CMP's approximately 564,000 electricity customers, NYSEG's approximately 838,000 electricity customers and 250,000 natural gas customers, and RG&E's approximately 355,000 electricity customers and 291,000 natural gas customers. The service territories reflect diversified economies, including high-tech firms, insurance, light industry, consumer goods manufacturing, pulp and paper, ship building, colleges and universities, agriculture, fishing and recreational facilities. No customer accounts for more than 5% of either electric or natural gas revenues for Energy East, NYSEG or RG&E, or for more than 5% of electric revenues for CMP.
Energy East's operating revenues derived from electricity deliveries were 64% in 2002, 67% in 2001 and 68% in 2000. Its operating revenues derived from natural gas deliveries were 26% in 2002, 27% in 2001 and 26% in 2000. All of CMP's operating revenues are derived from electricity deliveries. Approximately 82% of NYSEG's operating revenues for 2002, 2001 and 2000 was derived from electricity deliveries, with the balance each year derived from natural gas deliveries. Approximately 70% of RG&E's operating revenues for 2002, 2001 and 2000 was derived from electricity deliveries, with the balance each year derived from natural gas deliveries.
(i) (b) Other businesses
The company's other businesses include a nonutility generating company, a liquid fuels distribution company, a retail energy marketing company, telecommunications assets, a propane distribution company, a district heating and cooling system and a Federal Energy Regulatory Commission (FERC) regulated liquefied natural gas peaking plant.
Cayuga Energy owns electric generation facilities that sell power in the New York Independent System Operator and PJM ISO Power Pool wholesale markets at times of high demand. TEN Companies owns and manages a district heating and cooling network in Hartford, Connecticut and owns an interest in the Iroquois Gas Transmission System.
CNE Energy Services Group has an interest in two small 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 the peaking generation market in Connecticut. CNE Venture Tech has an interest in an energy technology venture partnership.
The Union Water-Power Company provides energy services, utility construction and utility locating services.
Energy East Solutions sells electricity and natural gas in wholesale and retail markets in the Northeast and mid-Atlantic regions. Berkshire Propane delivers propane to customers in western Massachusetts, southern Vermont and eastern 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.
Energy East Enterprises includes Maine Natural Gas, a small natural gas delivery company, New Hampshire Gas, a propane air delivery company, and Seneca Lake Storage, which is considering the development of high-deliverability natural gas storage in upstate New York.
Energetix, Inc., a subsidiary of RGS Energy, was formed in 1998 to market electricity and natural gas services throughout upstate and central New York. In August 1998 Energetix expanded into the liquid fuels business by acquiring Griffith Oil Co. Inc., one of the largest distributors of liquid fuels in the State of New York.
(ii) New product or segment - Not applicable
(iii) Sources and availability of raw materials
Electric
(See Item 7 - Electric Delivery Business, Item 7A - Commodity Price Risk and Item 8 - Note 1 to the company's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.)
CMP sold its power entitlements from its nonutility generator (NUG) contracts and from its minority interests in two nuclear stations for a two-year period beginning March 1, 2000. CMP sold its power entitlements from its NUG contracts and from its minority interest in its one remaining nuclear station, which was sold in July 2002, for an additional three-year period beginning March 1, 2002. Under Maine Law adopted in 1997 CMP was mandated to sell its generation assets and relinquish its supply responsibility. However, the Maine Public Utilities Commission (MPUC) can mandate that CMP be a standard-offer provider for supply service should bids by competitive suppliers be deemed unacceptable by the MPUC. CMP no longer owns any generating assets but does retain its power entitlements under long-term contracts from NUGs and contract for power from Vermont Yankee. CMP also has ownership interests in three nuclear facilities that have been shut down. CMP's retail electricity prices are set to provide recovery o f the costs associated with these ongoing obligations. CMP's revenues and purchased power costs will fluctuate as its status as a standard-offer provider changes. There is no effect on net income as its status fluctuates, however, because CMP is ensured cost recovery through Maine Law for any standard-offer obligations.
NYSEG satisfied the majority of its power requirements for 2002 through purchases under long-term contracts from NUGs, the New York Power Authority and Constellation Nuclear and from generation from its several hydroelectric stations. For its remaining power requirements, NYSEG used electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity.NYSEG's electric rate plan provided for a reconciliation and true-up, through the asset sale gain account created by NYSEG's sale in 2001 of its interest in NMP2, of certain actual power supply costs to costs included in rates during 2002. As a result of this reconciliation and true-up, the supply cost risk for 2002 was substantially eliminated.
RG&E satisfied the majority of its power requirements for 2002 through generation from its facilities (nuclear - 67%, coal and natural gas-fired - 30%, and hydroelectric and peaking - 3%) and purchases under long-term contracts from the New York Power Authority and Constellation Nuclear. For its remaining power requirements, RG&E assumed the risk of market prices and used electricity contracts, both physical and financial, to manage its exposure to fluctuations in the cost of electricity.
Nuclear -In March 2002 RG&E, the owner/operator of the Ginna nuclear generating station (Ginna), completed the thirtieth refueling of the reactor core at Ginna. This refueling will support Ginna operations through the fall of 2003. Enrichment, conversion and fabrication services are under contract for all of the requirements through 2009. All of the uranium concentrate requirements are under contract through 2005. In 2004 RG&E plans to secure multi-year contracts that will provide uranium concentrate requirements for the remaining years of Ginna's current license through 2009.
Coal- RG&E's 2003 coal requirements are expected to be approximately 600,000 tons. RG&E's coal supply portfolio contains both spot and term agreements with multiple suppliers. In 2002, 70% of its requirements were purchased under contract and 30% were purchased on the spot market. RG&E maintains a reserve supply of coal ranging from 30 to 60 days supply at maximum burn rates.
Natural Gas
(See Item 7 - Natural Gas Delivery Business, Item 7A - Commodity Price Risk and Item 8 - Note 1 to the company's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.)
The company's natural gas supply mix includes long-term, short-term and spot natural gas purchases transported under both firm and interruptible transportation contracts. The company, NYSEG and RG&E use natural gas futures to manage fluctuations in natural gas commodity prices and provide price stability to customers. During 2002 natural gas supply was purchased from various suppliers under long-term and short-term purchase contracts or in the monthly or daily spot natural gas market as follows:
| Long- or Short-term |
|
NYSEG | 42% | 58% |
RG&E | 100% | - |
CNG | 95% | 5% |
SCG | 94% | 6% |
Berkshire Gas | 95% | 5% |
(iv) Franchises
The company's operating companies, including CMP, NYSEG and RG&E, have valid franchises, with minor exceptions, from the municipalities in which they render service to the public.
Effective in September 2001 Maine Law authorized any natural gas utility providing gas distribution service in the State of Maine to provide gas distribution service to any municipality in Maine that is not already being served by another natural gas utility.
(v) Seasonal business
Sales of electricity are usually highest during the winter months primarily due to space heating usage and fewer daylight hours. Summer peak loads are due to the use of air-conditioning and other cooling equipment. Sales of natural gas are highest during the winter months primarily due to space heating usage.
(vi) Working capital items
The company's operating utilities, including CMP, NYSEG and RG&E, have been granted, through the ratemaking process, an allowance for working capital to operate their ongoing electric and/or natural gas utility systems.
(vii) Single customer - Not applicable
(viii) Backlog of orders - Not applicable
(ix) Business subject to renegotiation - Not applicable
(x) Competitive conditions
(See Item 7 - Electric Delivery Business, Natural Gas Delivery Business, Other Businesses and Accounting Issues.)
(xi) Research and development
The company's expenditures on research and development were $5 million in 2002 (including $1 million for RGS Energy) and $5 million each year in 2001 and 2000, principally for NYSEG's internal research programs and for contributions to research administered by the New York State Energy Research and Development Authority, the Electric Power Research Institute and the New York Gas Group. These expenditures are designed to improve existing energy technologies and to develop new technologies for the delivery and customer use of energy.
RG&E's expenditures on research and development were $2 million each year in 2002 and 2001 and $3 million in 2000. Those expenditures represent RG&E's contributions to research administered by the Electric Power Research Institute, the New York Gas Group, Empire State Electric Energy Research Corporation, the New York State Energy Research and Development Authority, and internal research projects. RG&E's research activities are designed to improve existing energy technologies and develop new technologies for the production, distribution, utilization and conservation of energy while preserving environmental quality.
(xii) Environmental matters
(See Item 3 - Legal proceedings, Item 7 - Electric Delivery Business, and Item 8 - Notes 9, 10 and 11 to the company's and Notes 8, 9 and 10 to CMP's Consolidated Financial Statements, and Notes 8, 9 and 10 to NYSEG's and RG&E's Financial Statements.)
The company, CMP, NYSEG and RG&E are subject to regulation by the federal government and by state and local governments with respect to environmental matters, such as the handling and disposal of toxic substances and hazardous and solid wastes and the handling and use of chemical products. Electric utility companies generally use or generate a range of potentially hazardous products and by-products that are the focus of 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, 2002, were approximately $11 million for Energy East, including $2 million for CMP, $5 million for NYSEG and $4 million for RG&E from July 1, 2002. For the period January 1, 2000, to June 30, 2002, RG&E had an additional $3 million of capital additions to meet environmental requirements. Future capital additions to meet environmental requirements are not expected to be material.
Water and air quality
The company, NYSEG and RG&E are required to comply with federal and state water quality statutes and regulations including the Clean Water Act. The Clean Water Act requires that generating stations be in compliance with federally issued National Pollutant Discharge Elimination System Permits or state issued State Pollutant Discharge Elimination System (SPDES) Permits, which reflect water quality considerations for the protection of the environment. RG&E has SPDES Permits for its three generating stations in New York. The Energy Network (TEN) 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 and are in compliance with the permits.
The company, CMP, NYSEG and RG&E are required to comply with federal and state oil spill statutes and regulations including the Spill Prevention Control and Countermeasures regulations.
RG&E is required to comply with federal and state air quality statutes and regulations for operation of its coal-fired and combustion turbine generating stations. All of RG&E's stations have the required federal or state operating permits. Stack tests and continuous emissions monitoring indicate that the stations are generally in compliance with permit emission limitations, although occasional opacity exceedances occur. Efforts continue in the identification and elimination of the causes of opacity exceedances.
The Clean Air Act Amendments of 1990 (1990 Amendments) limit emissions of sulfur dioxide and nitrogen oxides and require emissions monitoring. The U. S. Environmental Protection Agency (EPA) allocates annual emissions allowances to each of RG&E's coal-fired and combustion turbine generating stations based on statutory emissions limits under Phase II (which began January 1, 2000) of the 1990 Amendments. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. A similar allowance program under Title I of the 1990 Amendments controls nitrogen oxides emissions from RG&E's coal-fired station and a combustion turbine generating station. Another requirement of the 1990 Amendments is for the coal-fired station and a combustion turbine generating station to have a facility operating permit (Title V permit). The Title V permits required for each station have been granted. Future requirements of the 1990 Amendments may require further r eduction of sulfur dioxide and nitrogen oxides emissions, as well as new limits on mercury emissions from coal-fired combustion generating stations. However, specific control requirements have not been determined by the EPA.
Regulations may be adopted in early 2003 by the State of New York that would further limit acid rain precursor emissions from electric generating units, at an additional cost to RG&E. Emissions reduction targets could be set 50% below the current federal limits for sulfur dioxide and could be set 40% below the current federal limits for nitrogen oxides. Emissions reductions would be achieved through a market-based allowance trading system similar to those under the 1990 Amendments. Draft regulations provide for a phased-in implementation to begin in 2004 and end in 2008. The cost of allowances beyond those allocated to RG&E is unknown.
RG&E purchases emission allowances as necessary in order to comply with the Clean Air Act, and estimates its cost for allowances will be $5 million for 2003. In addition, control equipment is to be 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 or make additional capital expenditures to comply with the Clean Air Act.
Waste disposal
A low level radioactive waste management and contingency plan for Ginna provides assurance that RG&E is properly prepared to handle interim storage of Ginna's low level radioactive waste until 2010 should permanent or long-term disposal facilities not be available. Licensing and construction of additional storage facilities would extend on-site storage capability for low level radioactive waste beyond 2009, whether or not RG&E's license to operate Ginna is extended.
RG&E has contracted with the U. S. Department of Energy (DOE) for disposal of high level radioactive waste including spent fuel (spent fuel) from Ginna (currently at a cost of approximately $1 per megawatt-hour of net generation). The DOE's schedule for start of operations of their high level radioactive waste repository will be no sooner than 2010, one year after RG&E's current license to operate Ginna is scheduled to expire. RG&E's Ginna Spent Fuel Storage Pool has a capacity for spent fuel that is adequate beyond 2009. If further DOE schedule slippage should occur, construction of pre-licensed dry storage facilities would extend the on-site storage capability for spent fuel at Ginna, whether or not RG&E's license to operate Ginna is extended.
(xiii) Number of employees
As of January 31, 2003, Energy East had 8,228 employees, which includes 1,373 CMP employees, 2,959 NYSEG employees and 1,916 RG&E employees.
(d)Financial information about geographic areas Not applicable
Item 2. Properties
(See Item 7 - Sale of Nuclear Interests and Other Businesses.)
CMP's electric system includes substations and transmission and distribution lines, all of which are located in the State of Maine. NYSEG's electric system includes hydroelectric and gas turbine generating stations, substations and transmission and distribution lines, substantially all of which are located in the State of New York. RG&E's electric system includes nuclear, coal-fired, combustion turbine and hydroelectric generating stations, substations and transmission and distribution lines, all of which are located in the State of New York. TEN owns interests in three natural gas-fired peaking generating stations, two that are operated by Cayuga Energy, a wholly-owned subsidiary, and located in the State of New York, and one for which Cayuga Energy manages fuel procurement and electricity sales that is located in Pennsylvania.
The operating companies generating facilities consist of the following:
|
| Generating capability | |
RG&E | Nuclear | (Ontario, NY) | 480 |
NYSEG | Hydroelectric | (Various - 7 locations) | 60 |
RG&E | Coal-fired | (Greece, NY) | 257 |
Total - all stations | 1,090 |
(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%. Those facilities have been permanently shut down and are in the process of being decommissioned.
CMP owns 301 substations in Maine having an aggregate transformer capacity of 6,506,334 kilovolt-amperes (Kva). The transmission system consists of 2,554 circuit miles of line. The distribution system consists of 22,216 pole miles of overhead lines and 152 miles of underground lines.
NYSEG owns 430 substations in New York having an aggregate transformer capacity of 12,710,510 Kva. The transmission system consists of 4,389 circuit miles of line. The distribution system consists of 34,096 pole miles of overhead lines and 2,364 miles of underground lines.
RG&E owns 158 substations in New York having an aggregate transformer capacity of 2,447,596 Kva. The transmission system consists of 742 circuit miles of overhead lines and 424 circuit miles of underground lines. The distribution system consists of 16,495 circuit miles of overhead lines and 4,497 circuit miles of underground lines.
The operating companies' natural gas systems consist of the following:
|
| Miles of | Miles of |
NYSEG | New York State | 74 | 7,542 |
RG&E | New York State | 109 | 4,474 |
SCG | Connecticut | - | 3,622 |
CNG | Connecticut | - | 3,506 |
Berkshire Gas | Massachusetts | - | 717 |
Maine Natural Gas | Maine | 2 | 63 |
New Hampshire Gas |
|
|
|
Substantially all of the company's utility plant is subject to liens or mortgages securing its subsidiaries' first mortgage bonds. None of CMP's utility plant is subject to liens or mortgages securing first mortgage bonds. NYSEG's and RG&E's first mortgage bond indentures constitute direct first mortgage liens on substantially all of their respective properties. (See Item 8 - Note 6 to the company's and Note 5 to CMP's Consolidated Financial Statements, and Note 5 to NYSEG's and RG&E's Financial Statements.)
Item 3. Legal proceedings
(See Item 7 - Electric Delivery Business and Natural Gas Delivery Business and Item 8 - Note 11 to the company's and Note 10 to CMP's Consolidated Financial Statements, and Note 10 to NYSEG's and RG&E's Financial Statements.)
Since the New York State Public Service Commission (NYPSC), Connecticut Department of Public Utility Control (DPUC), MPUC and Massachusetts Department of Telecommunications and Energy (DTE) have allowed the company's operating companies to recover in rates remediation costs for certain of the sites referred to in the second and fourth paragraphs of Note 11 to the company's and Note 10 to CMP's Consolidated Financial Statements and the second and fourth paragraphs of Note 10 to NYSEG's and RG&E's Financial Statements there is a reasonable basis to conclude that such operating companies will be permitted to recover in rates any remediation costs that they may incur for all of the sites referred to in those paragraphs. Therefore, the company, CMP, NYSEG and RG&E believe that the ultimate disposition of the matters referred to in the paragraphs of the Notes referred to above in the company's and CMP's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements will not have a mat erial adverse effect on their results of operations or financial position.
(a) In August 1997 NYSEG was notified by the New York State Department of Environmental Conservation (NYSDEC) that NYSDEC was contemplating enforcement action against NYSEG with respect to violations of regulations concerning opacity of air emissions at all of the company's New York coal-fired stations. NYSEG is in the process of negotiating a consent order with the NYSDEC to resolve the NYSDEC's demand for a penalty of approximately $650,000. The company sold its New York coal-fired stations to The AES Corporation (AES) in May 1999.
(b) NYSEG received a letter in October 1999 from the New York State Attorney General's office alleging that NYSEG may have constructed and operated major modifications to certain emission sources at the Goudey and Greenidge generating stations, which it formerly owned, without obtaining the required prevention of significant deterioration or new source review permits. The Goudey and Greenidge plants were sold to AES in May 1999. The letter requested that NYSEG and AES provide the Attorney General's office with a large number of documents relating to this allegation. In January 2000 NYSEG received a subpoena from the NYSDEC ordering production of similar documents. The NYSDEC subsequently requested similar documents with respect to the Hickling and Jennison generating stations, which the company formerly owned. Those stations were also sold to AES in May 1999.
In April 2000 NYSEG received a letter from the EPA requesting information with respect to the operation of the Milliken and Kintigh generating stations, which the company formerly owned. Those stations were also sold to AES in May 1999. NYSEG furnished documents pursuant to the Attorney General's, NYSDEC's and EPA's requests.
In May 2000 NYSEG received a notice of violation from the NYSDEC alleging that two projects at Goudey and four projects at Greenidge were constructed without the necessary permits having been obtained.
In April 2001 EPA notified NYSEG by telephone that EPA would be issuing notices of violation alleging that various projects at the Milliken and Kintigh generating stations were constructed without the necessary permits having been obtained.
NYSEG believes it has complied with the applicable rules and regulations and there is no basis for the Attorney General's, NYSDEC's and EPA's allegations. NYSEG believes that any liability related to this matter will be the responsibility of AES in accordance with the asset purchase agreement.
(c) In October 2000 NYSEG and Pennsylvania Electric Company (Penelec) received a letter from EME Homer City Generation, L.P. (EME), a subsidiary of the purchaser of the Homer City generating station (Station) in which NYSEG and Penelec each formerly owned a one-half interest. The letter gave NYSEG and Penelec notice that the EPA has found alleged violations of the federal Clean Air Act related to the Station. EME has indicated that it will claim that certain fines, penalties and costs arising out of or related to these alleged violations, which NYSEG believes may be material, are liabilities retained by NYSEG and Penelec under the terms of the asset purchase agreement for the Station. While it will continue to examine this matter, NYSEG believes that such fines, penalties and costs are not liabilities retained by it.
(d) In October 1999 RG&E received a letter from the New York State Attorney General's office alleging that RG&E may have constructed and operated major modifications to the Beebee and Russell generating stations without obtaining the required prevention of significant deterioration or new source review permits. The letter requested that RG&E provide the Attorney General's office with a large number of documents relating to this allegation. In January 2000 RG&E received a subpoena from the NYSDEC ordering production of similar documents.
The NYSDEC served RG&E with a notice of violation in May 2000 alleging that between 1983 and 1987 RG&E completed five projects at Russell Station and two projects at Beebee Station without obtaining the appropriate permits. RG&E believes it has complied with the applicable rules and there is no basis for the Attorney General's and NYSDEC's allegations.
RG&E is not able to definitively predict the outcome of this matter. A number of options that would resolve the notice of violation are under investigation.
Item 4. Submission of matters to a vote of security holders
None for Energy East, CMP, NYSEG or RG&E.
* * * * * * * * * * *
Executive Officers of the Registrants
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Energy East Corporation | ||
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Kenneth M. Jasinski | 54 | Executive Vice President and Chief Financial Officer, February 2002 to date; Executive Vice President, General Counsel & Secretary, August 2000 to February 2002; Executive Vice President and General Counsel, April 1999 to August 2000; Senior Vice President and General Counsel, April 1998 to April 1999; Executive Vice President of NYSEG, April 1998 to April 1999; Partner of Huber Lawrence & Abell (attorneys at law) to April 1998. |
Robert D. Kump | 41 | Vice President, Treasurer & Secretary, February 2002 to date; Vice President and Treasurer, November 1999 to February 2002; Treasurer, October 1998 to November 1999; Treasurer of NYSEG to August 2000. |
Robert E. Rude | 50 | Vice President and Controller, November 1999 to date; Controller, October 1998 to November 1999; Executive Director, Corporate Planning of NYSEG, October 1998 to October 2000; Director, Corporate Planning and Rates of NYSEG to October 1998. |
Robert M. Allessio | 52 | President and Chief Executive Officer of Berkshire Energy Resources and The Berkshire Gas Company, September 2000 to date; President and Chief Operating Officer of The Berkshire Gas Company, August 1999 to September 2000; Vice President, Utility Operations of The Berkshire Gas Company to August 1999. |
Richard R. Benson | 45 | Vice President, Human Resources of Energy East Management Corporation, October 2000 to date; Executive Director, Human Resources of NYSEG, October 1998 to October 2000; Director, Human Resources of NYSEG to October 1998. |
Sara J. Burns | 47 | President of CMP, September 1998 to date; Chief Operating Officer, Distribution Services of CMP to September 1998. |
Michael I. German | 52 | Senior Vice President, Business Development of Energy East Management Corporation, March 2002 to date; Senior Vice President of Energy East Corporation, April 1998 to March 2002; President and Chief Executive Officer of The Energy Network, Inc., October 2000 to date; President and Chief Operating Officer of NYSEG, April 1999 to October 2000; Executive Vice President and Chief Operating Officer of NYSEG, April 1998 to April 1999; Executive Vice President of NYSEG to April 1998. |
James P. Laurito | 46 | President and Chief Operating Officer of Connecticut Natural Gas Corporation and The Southern Connecticut Gas Company, October 2000 to date; President of TEN Companies, Inc. (formerly The Energy Network, Inc.), January 1999 to October 2000; Vice President, Business Development of TEN Companies, Inc. to January 1999. |
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| Positions, offices and business |
F. Michael McClain | 53 | Vice President, Finance of Energy East Management Corporation, October 2000 to date; Vice President, Corporate Development of CMP Group, Inc., September 1998 to October 2000; Vice President, Corporate Development of CMP, February 1998 to September 1998; Group Vice President and Chief Operating Officer of Petroleum Group, Dead River Company to February 1998. |
Angela M. Sparks-Beddoe | 38 | Vice President, Public Affairs of Energy East Management Corporation, January 2001 to date; Director, Legislative Affairs of NYSEG, February 1999 to January 2001; Manager, Federal Government Affairs of NYSEG to February 1999. |
Ralph R. Tedesco | 49 | President and Chief Operating Officer of NYSEG, October 2000 to date; Senior Vice President, Customer Service Business Unit of NYSEG to October 2000. |
Denis E. Wickham | 54 | Senior Vice President, Transmission and Energy Supply of Energy East Management Corporation, October 2000 to date; Senior Vice President, Energy Operating Services of NYSEG, June 1998 to October 2000; Vice President, Electric Resource Planning of NYSEG to June 1998. |
Paul C. Wilkens | 55 | President of RG&E, June 2002 to date; Senior Vice President of RGS Energy August 1999 to June 2002; Senior Vice President of RG&E, March 1998 to June 2002; Director, Gas Services of RG&E to March 1998. |
Central Maine Power Company
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New York State Electric & Gas Corporation
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Rochester Gas & Electric Corporation
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Wesley W. von Schack and Kenneth M. Jasinski each have an employment agreement for a term ending February 7, 2006. 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. Michael I. German has an employment agreement for a term ending on December 31, 2004. Mr. German's agreement provides for his employment as Senior Vice President, Business Development of Energy East Management Corporation and President and Chief Executive Officer of The Energy Network, Inc. Each agreement provides for automatic one-year extensions unless either party to an agreement gives notice that such agreement is not to be extended.
Robert M. Allessio, Sara J. Burns and F. Michael McClain each have an employment agreement for a term of three years beginning September 1, 2000, which is automatically extended each month unless either party to an agreement gives written notice that it is not to be extended. Ms. Burns' agreement provides for her employment as President of CMP and Mr. Allessio's agreement provides for his employment as President and Chief Executive Officer of Berkshire Gas. Paul C. Wilkens has an employment agreement for a term of three years beginning June 28, 2002, which is automatically extended each month unless either party to the agreement gives written notice that it is not to be extended. Mr. Wilkens' agreement provides for his employment as President of RG&E.
Each officer holds office for the term for which he or she is elected or appointed, and until his or her successor is elected and qualifies. The term of office for each officer extends to and expires at the meeting of the Board of Directors following the next annual meeting of shareholders.
PART II
Item 5. Market for Registrants' common equity and related stockholder matters
See Item 8 - Note 17 to the company's Consolidated Financial Statements.
CMP Group, Inc., 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 Group, Inc., a wholly-owned subsidiary of Energy East, owns all of NYSEG's and all of RG&E's common stock. See Item 8 - NYSEG's and RG&E's Statements of Changes in Common Stock Equity for information regarding dividends declared.
Item 6. Selected financial data
See the information under the headingSelected financial data for each registrant, which is included in this report as follows:
Energy East - page 19
CMP - page 72
NYSEG - page 96
RG&E - page 125
Item 7. Management's discussion and analysis of financial condition and results of operations
See the information under the headingManagement's discussion and analysis of financial condition and results of operationsfor each registrant, which is included in this report as follows:
Energy East - pages 20 to 38
CMP - pages 72 to 75
NYSEG - pages 96 to 102
RG&E - pages 125 to 131
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk represents the risk of changes in value of a financial or commodity instrument, derivative or nonderivative, caused by fluctuations in interest rates and commodity prices. The following discussion of the companies' risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those contemplated in the "forward-looking" statements. The companies handle market risks in accordance with established policies, which may include various derivative transactions. (See Item 8 - Note 1 to the company's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.)
The financial instruments held or issued by the companies are for purposes other than trading or speculation. Quantitative and qualitative disclosures are discussed as they relate to the following market risk exposure categories: Interest Rate Risk, Commodity Price Risk and Other Market Risk.
Interest Rate Risk: The companies are exposed to risk resulting from interest rate changes on their variable-rate debt and commercial paper. The company and its subsidiaries use interest rate swap agreements to manage interest rate risk and/or to maintain desired fixed-to-floating rate ratios. Amounts paid and received under those agreements are recorded as adjustments to the interest expense of the specific debt issues. The companies estimate that, at December 31, 2002, a 1% change in average interest rates would change annual interest expense for variable rate debt by about $4.6 million for Energy East, including $0.2 million for CMP, $1.3 million for NYSEG and $0.7 million for RG&E. (See Item 8 - Notes 6 and 12 to the company's and Notes 5 and 11 to CMP's Consolidated Financial Statements, and Notes 5 and 12 to NYSEG's and Notes 5 and 11 RG&E's Financial Statements.)
The company also uses financial instruments to lock in the treasury rate component of future financings to mitigate risk resulting from interest rate changes.
Commodity Price Risk: Commodity price risk is a significant issue for the company, NYSEG and RG&E due to volatility experienced in both the electric and natural gas wholesale markets. The companies manage this risk through a combination of regulatory mechanisms, such as allowing for the pass-through of the market price of electricity and natural gas to customers, and through comprehensive risk management processes. These measures mitigate the companies' commodity price exposure, but do not completely eliminate it.
Although CMP has no long-term supply responsibilities, the MPUC can mandate that CMP be a standard-offer provider for supply service should bids by competitive suppliers be deemed unacceptable by the MPUC. (See Item 7 - CMP Electricity Supply Responsibility.) In September 2001 the MPUC chose Constellation Power Source Maine, LLC as the new supplier of standard-offer electricity to CMP's residential and small commercial standard-offer class for a three-year period beginning March 1, 2002. In January 2003 the MPUC chose suppliers of standard-offer electricity for the six months beginning March 1, 2003: FPL Energy Power Marketing, Inc. for medium class customers and Select Energy , Inc. for larger customers.
All of Energy East's natural gas utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. (See Item 7 - Natural Gas Supply Agreements, NYSEG Natural Gas Rate Plan and Connecticut Regulatory Proceedings.)
NYSEG and RG&E use natural gas futures to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures is included in the commodity cost when the related sales commitments are fulfilled.
NYSEG and RG&E use electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity. The cost or benefit of those contracts is included in the amount expensed for electricity purchased when the electricity is sold.
NYSEG's electric rate plan offers retail customers choice in their electricity supply including a variable rate option, an option to purchase electricity supply from an alternative energy company, and a bundled rate option. Based on the results from the enrollment period that ended December 31, 2002, approximately 30% of NYSEG's total electric load is now provided by an alternative energy company or at the market price. NYSEG's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the bundled rate option, which combines delivery and supply service at a fixed price. For calendar years 2003 and 2004 the supply component is based on average electricity forward prices for 2003 and 2004 during September 2002, plus a 35% margin to cover the costs and risk that NYSEG is assuming by providing a bundled rate option to retail customers. NYSEG is actively hedging the load required to serve customers who select the bundled rate option. As of Ja nuary 31, 2003, NYSEG's load was 93% hedged for on-peak periods and 87% hedged for off-peak periods in 2003 and 86% hedged for both on-peak and off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.7 million in 2003 and $1 million in 2004. The percent of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.
RG&E faces commodity price risk that relates to market fluctuations in the price of electricity and natural gas. Under its electric settlement, RG&E's electric rates were capped at specified levels through June 30, 2002. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. As of January 31, 2003, RG&E's load was 90% hedged for on-peak periods and fully hedged for off-peak periods in 2003 and fully hedged for both on-peak and off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of on-peak electricity would change earnings by $0.2 million in 2003. The percent of RG&E's hedged load is based on RG&E's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast. RG&E has filed a request with the NYPSC for new electric rates commencing i n January 2003. The NYPSC has not ruled on the rate request; therefore, RG&E's current fixed electric rates will remain in effect until a new rate order is issued. A new rate order is expected to be issued in March 2003, for electric rates retroactive to January 2003. (See Item 7 - RG&E 2002 Electric and Gas Rate Proceeding.)
While owned coal-fired and nuclear generation provides RG&E with a natural hedge against electric price risk, it also subjects it to operating risk. Operating risk is managed through a combination of strict operating and maintenance practices and the use of derivative contracts.
The broad and continued decline in credit quality across the energy supply and marketing industries combined with the withdrawal of many entities from energy trading operations could limit the company's ability to purchase electricity and place financial hedges with counterparties that meet its credit requirements. While the company has been successful in implementing its hedging strategies by finding creditworthy counterparties or requiring adequate financial
assurances in the form of cash or letters of credit, continued contraction and credit deterioration across the energy supply and marketing industries may adversely affect the company's ability to effectively implement its hedging strategies going forward.
Other Market Risk: The companies' pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in those markets as well as changes in interest rates cause the companies to recognize increased or decreased pension income or expense. If the expected return on plan assets were to change by 1/4%, pension income would change by approximately $6 million. (See Item 8 - Note 15 to the company's and Note 13 to CMP's Consolidated Financial Statements, and Note 13 to NYSEG's and Note 12 to RG&E's Financial Statements.)
Forward-looking Statements
This Form 10-K contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements.
In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties and that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated industry; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of changing energy prices; the operation of the New York Independent System Operator and ISO New England, Inc.; the operation of a regional transmission organization; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements now that most generation assets have been sold; the company's ability to expand its products and services, including its en ergy infrastructure in the Northeast; the company's ability to integrate the operations of Berkshire Energy, CMP Group, CNE, CTG Resources and RGS Energy with its operations and achieve anticipated synergies; market risk; the ability to obtain adequate and timely rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; and other considerations, such as the effect of the volatility in the equity markets on pension benefit cost, that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.
Item 8. Financial statements and supplementary data
Index to 2002 Financial Statements
Page | |
Energy East Corporation | |
Consolidated Statements of Income | 39 |
Consolidated Balance Sheets | 40 |
Consolidated Statements of Cash Flows | 42 |
Consolidated Statements of Changes in Common Stock Equity | 43 |
Notes to Consolidated Financial Statements | 44 |
Report of Independent Accountants | 70 |
Financial Statement Schedule | |
II. Consolidated Valuation and Qualifying Accounts | 71 |
Central Maine Power Company | |
Consolidated Balance Sheets | 76 |
Consolidated Statements of Income | 78 |
Consolidated Statements of Cash Flows | 79 |
Consolidated Statements of Changes in Common Stock Equity | 80 |
Notes to Consolidated Financial Statements | 81 |
Report of Independent Accountants | 94 |
Financial Statement Schedule | |
II. Consolidated Valuation and Qualifying Accounts | 95 |
New York State Electric & Gas Corporation | |
Statements of Income | 103 |
Balance Sheets | 104 |
Statements of Cash Flows | 106 |
Statements of Changes in Common Stock Equity | 107 |
Notes to Financial Statements | 108 |
Report of Independent Accountants | 123 |
Financial Statement Schedule | |
II. Valuation and Qualifying Accounts | 124 |
Rochester Gas and Electric Corporation | |
Balance Sheets | 132 |
Statements of Income | 134 |
Statements of Cash Flows | 135 |
Statements of Changes in Common Stock Equity | 136 |
Notes to Financial Statements | 137 |
Report of Independent Accountants | 151 |
Financial Statement Schedule | |
II. Valuation and Qualifying Accounts | 152 |
Item 9. Changes in and disagreements with accountants on accounting and
financial disclosure
None for Energy East, CMP, NYSEG or RG&E.
Selected Financial Data
Energy East Corporation
2002(1) | 2001 | 2000(4) | 1999 | 1998 | |||||
(Thousands, except per share amounts) | |||||||||
Operating Revenues | $4,008,918 | $3,759,787 | $2,959,520 | $2,278,608 | $2,499,568 | ||||
Depreciation and amortization | $246,996 | $204,281 | $165,524 | $648,970 | (5) | $191,462 | |||
Other taxes | $230,558 | $192,772 | $165,767 | $179,028 | $204,483 | ||||
Interest Charges, Net | $257,747 | $217,066 | $152,520 | $132,908 | $125,557 | ||||
Net Income | $188,603 | (2) | $187,607 | (3) | $235,034 | $218,751 | $194,205 | ||
Earnings Per Share, |
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Dividends Paid Per Share | $.96 | $.92 | $.88 | $.84 | $.78 | ||||
Average Common |
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Book Value Per Share of |
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Capital Spending | $229,387 | $222,875 | $168,320 | $82,674 | $137,350 | ||||
Total Assets | $10,269,879 | $7,269,232 | $7,013,728 | $3,773,171 | $4,902,085 | ||||
Long-term Obligations, |
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All per share amounts and shares outstanding have been restated to reflect the two-for-one common stock split effective April 1, 1999.
Reclassifications: Certain amounts included in Selected Financial Data have been reclassified to conform with the 2002 presentation.
(1) Due to the completion of the company's merger transaction during 2002 the consolidated financial statements include RGS Energy's results beginning with July 2002.
(2) Includes the writedown of CMP Group's investment in NEON Communications, Inc. that decreased net income $7 million and earnings per share six cents and the effect of restructuring expenses that decreased net income $24 million and earnings per share 19 cents.
(3) Includes the writedown of CMP Group's investment in NEON Communications, Inc. that decreased net income $46 million and earnings per share 39 cents.
(4) 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.
(5) Depreciation and amortization includes accelerated amortization of the Nine Mile Point 2 nuclear generating station (NMP2) related to the sale of the company's coal-fired generation assets, authorized by the NYPSC.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Liquidity and Capital Resources
Restructuring
In 2002 Energy East initiated a corporate restructuring to achieve optimum organizational efficiency and effectiveness. The savings from this initiative are essential for the company to meet the rate reduction or efficiency targets imputed in utility rates by regulators, as well as to meet the expectations of customers and investors. In the fourth quarter of 2002 Energy East recorded $41 million of restructuring expenses, including $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 a 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 are $20 million for a voluntary early retirement program that will be paid from the companies' pension plans and $3 million for an involuntary severance program, primarily for salaried employees of the company's six operating utilities, and $1 million for other associated costs.
Those programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by April 30, 2003. That includes approximately 70 from CMP, 260 from NYSEG, 245 from RG&E and 75 from Berkshire Gas, CNG and SCG. The employees affected by the involuntary severance program were notified in January 2003.
Energy East and RGS Energy Merger
On June 28, 2002, Energy East completed its merger with RGS Energy. Under the merger agreement 45% of RGS Energy common stock, 15.6 million shares, was converted into 27.5 million shares of Energy East common stock valued at $612 million. The value of the shares issued was determined based on the market price of Energy East's stock at the end of the day on June 27, 2002. The remaining 55% of the RGS Energy common stock was exchanged for $753 million in cash, which was $39.50 per RGS Energy share. The purchase price was about $1.4 billion, which includes $11 million of merger-related costs. The transaction was accounted for using the purchase method. Energy East's consolidated statements of income and cash flows include RGS Energy's results of operations beginning with July 2002. (See Item 8 - Note 3 to the company's Consolidated Financial Statements.)
As a result of the merger RGS Energy became a wholly-owned subsidiary of Energy East. RG&E continues to be a wholly-owned subsidiary of RGS Energy and NYSEG became a wholly-owned subsidiary of RGS Energy.
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 generation, transmission and distribution operations in upstate New York and Maine.
Regional Transmission Organization (RTO): In July 2001 the FERC issued an order requiring the New York Independent System Operator (NYISO) and neighboring New England and Mid-Atlantic independent system operators (ISOs) to negotiate to form a single Northeast RTO. The NYISO and other parties involved in negotiating the formation of the Northeast RTO participated in mediation facilitated by a FERC administrative law judge (ALJ), leading to a business plan detailing the process to develop a Northeast RTO. The business plan, coupled with an ALJ's report, were submitted to the FERC. NYSEG, CMP and RG&E have consistently advocated the formation of a Northeast/Mid-Atlantic RTO, including PJM Interconnection, L.L.C. (PJM), or functionally combined markets throughout the Northeast because they believe that a larger wholesale power market is essential to facilitate greater liquidity and competition.
In January 2002 the ISO New England, Inc. (ISO New England) and the NYISO entered into an agreement to consider forming an RTO, and PJM entered into an agreement to form common market systems with the Midwest ISO. The ISO New England and the NYISO submitted a joint petition to the FERC on August 23, 2002, asking for a declaratory order stating that a merger of the two ISOs, as described in the petition, would satisfy FERC requirements for an RTO. On November 22, 2002, the New England ISO and the NYISO withdrew their proposal, citing opposition from stakeholders, including CMP, NYSEG and RG&E. The companies opposed the proposal because, among other things, it failed to demonstrate that the benefits outweighed the costs and failed to recognize the need for a larger market.
In October 2001 FERC commenced a proceeding to consider national standard market design issues and on July 31, 2002, issued a Notice of Proposed Rulemaking (the SMD NOPR). The SMD NOPR proposes rules that would require, among other things, changes in the wholesale power markets, transmission planning services and charges, market power monitoring and mitigation, and the organization and structure of ISOs. CMP, NYSEG and RG&E filed comments jointly with other transmission owners in November 2002 and January 2003. The companies generally support the proposed SMD because it would functionally combine the Northeast markets. The companies plan to file additional comments in 2003. The proposals in the SMD NOPR include the adoption of an energy market based on locational marginal pricing (LMP), which represents a significant change for some regions of the country. The NYISO already operates a market based on LMP, and ISO New England is in the process of developing and implementing an LMP system.
Transmission Planning and Expansion: In June and July 2001 FERC issued orders that addressed a number of transmission planning and expansion issues that would directly affect CMP, NYSEG and RG&E as transmission owners. The FERC orders discussed giving exclusive responsibility for the transmission planning process to a Northeast RTO, rather than the transmission owners. The orders also discussed redefining the cost-sharing responsibilities of interconnecting generators for transmission expansion costs. On April 24, 2002, and August 16, 2002, FERC issued NOPRs regarding generation interconnection terms, conditions and cost allocation. FERC is expected to issue a final rule in 2003. Additional transmission planning and
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
expansion proposals are included in the SMD NOPR. The company is unable to predict the ultimate effect, if any, of the expected rulemakings on its transmission system or on future capital expenditures.
On January 15, 2003, FERC issued a proposed policy statement on transmission pricing. FERC proposes a 50 basis point return on equity adder on facilities over which transmission owners turn control to an RTO. The NYISO and ISO New England satisfy most of the requirements of an RTO. Additionally, FERC proposes that unaffiliated third parties will receive the equivalent of an additional 150 basis point adder applicable to transmission facilities that transmission owning utilities divest. Finally, FERC proposes a 100 basis point adder for new transmission facilities found appropriate through an RTO planning process. The company is evaluating FERC's policy proposal and plans to file comments.
Electric Transmission Rates: On June 28, 2002, CMP made its required annual informational filing with FERC updating its local transmission formula rates. CMP's annual transmission revenue requirement increased by $0.6 million reflecting increased costs associated with transmission constraints during periods of high demand. Rates pursuant to this filing became effective June 1, 2002, and reflect actual cost and revenues from the 2001 calendar year.
Sale of Nuclear Interests: (See Item 8 - Note 10 to the company's and Note 9 to CMP's Consolidated Financial Statements.) On July 31, 2002, Vermont Yankee Nuclear Power Corporation sold the Vermont Yankee nuclear power plant, including CMP's 4% ownership interest, to Entergy Corporation. Any benefits realized from the sale, which are expected to be less than $1 million, will be used to reduce CMP customers' future obligations for stranded costs. The transaction included a power purchase agreement that calls for Entergy to provide all of the plant's electricity to the sellers through 2012, the year the operating license for the plant expires.
In November 2001 NYSEG sold its 18% interest in the Nine Mile Point 2 nuclear generating station (NMP2) to Constellation Nuclear.In October 2001 the NYPSC issued an order approving the sale. For its share of NMP2, NYSEG received at closing $59 million in cash and a $59 million 11% promissory note. On April 12, 2002, Constellation Nuclear paid the remaining balance plus accrued interest on the promissory note. (See Item 8 - Note 9 to NYSEG's Financial Statements.)
Upon completion of the sale of NMP2, an asset sale gain of approximately $110 million was recorded, in accordance with the NYPSC's order, as a regulatory liability under Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (Statement 71). The gain includes a gross up for unfunded future income taxes and is being returned to customers in accordance with NYSEG's current electric rate plan, which was approved by the NYPSC in February 2002.
CMP Alternative Rate Plan: In September 2000 the MPUC approved CMP's Alternative Rate Plan (ARP 2000). ARP 2000 applies only to CMP's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services. The revenue requirement related to transmission services is established by FERC. Recovery of stranded costs, primarily overmarket NUG contracts and nuclear decommissioning costs, has been provided for under Maine's Restructuring Law. ARP 2000 began January 1,
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007.
On June 25, 2002, the MPUC approved a filing allowing CMP's distribution prices to change effective July 1, 2002. As a result, distribution rates for customers not subject to special contracts decreased by 4.84%. The reduction reflects a decrease of 3.03% in distribution rates resulting from expiring amortizations and the application of a price cap mechanism, and an additional one-time decrease of 1.81% reflecting over-collections of certain costs, such as for low-income assistance programs and insurance proceeds related to environmental remediation.
CMP Electricity Supply Responsibility: Under Maine Law adopted in 1997 CMP was mandated to sell its generation assets and relinquish its supply responsibilities. CMP no longer owns any generating assets but does retain its power entitlements under long-term contracts from NUGs and a power purchase contract with Vermont Yankee, and its ownership interests in three nuclear facilities that have been shut down. CMP's retail electricity prices are set to provide recovery of the costs associated with these ongoing obligations.
Under Maine Law the MPUC can mandate that CMP be a standard-offer provider for supply service if the MPUC should deem bids by competitive suppliers to be unacceptable. CMP has no standard-offer obligations through August 2003. If in the future CMP should have standard-offer obligations there would be no effect on net income because CMP is ensured cost recovery through Maine Law. CMP's revenues and purchased power costs will fluctuate, however, as its status as a standard-offer provider changes. (See the company's Operating Results for the Electric Delivery Business, CMP's Results of Operations and Item 8 - Note 9 to the company's and Note 8 to CMP's Consolidated Financial Statements.)
In September 2001 the MPUC chose Constellation Power Source Maine, LLC as the new supplier of standard-offer electricity to CMP's residential and small commercial standard-offer class for a three-year period beginning March 1, 2002. In January 2003 the MPUC chose suppliers of standard-offer electricity for the six months beginning March 1, 2003: FPL Energy Power Marketing, Inc. for medium class customers and Select Energy, Inc. for larger customers.
MPUC Stranded Cost Proceeding: In December 2001 the MPUC approved a stipulation among CMP, the Office of the Public Advocate and the Industrial Energy Consumer Group settling all issues related to the setting of CMP's stranded cost revenue requirement for the period March 1, 2002, through February 28, 2005. In January 2002 CMP submitted a compliance filing to the MPUC setting the three-year stranded cost revenue requirement. The amount of the revenue requirement reflects the ongoing costs related to CMP's remaining nondivested generating resources and the decommissioning of two nuclear power plants, offset by revenues to be received for the output from the remaining nondivested generating resources and amortization of amounts from CMP's gain on sale of generation assets account. Under the terms of the stipulation, parties can request a review of stranded costs if revenues differ significantly from anticipated costs. On December 17, 2002, the MPUC initiated an investigation to review CMP's&nb sp;current level of recovery of stranded costs, including the costs associated with decommissioning the Yankee Atomic plant. As ordered by the MPUC in this proceeding, CMP made its initial filing on February 7, 2003, concluding that no change in the current stranded costs rate is appropriate. CMP expects the MPUC to act on its filing by July 1, 2003.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
NYSEG Electric Rate Plan: In February 2002 the NYPSC issued an Order (NYPSC February 2002 Order) approving a five-year NYSEG electric rate plan, which extends through December 31, 2006, and Energy East's merger with RGS Energy. The electric rate plan resulted from a settlement reached by the company, NYSEG, RGS Energy, RG&E, the NYPSC Staff, the Attorney General of the State of New York, the New York State Consumer Protection Board, Multiple Intervenors and other parties. NYSEG's 1998 electric rate and restructuring agreement and an NYPSC Order issued in January 2002, regarding temporary rates for NYSEG's electric customers, were superseded by the NYPSC February 2002 Order. The NYPSC February 2002 Order also provided for the discontinuance of several outstanding NYSEG proceedings. NYSEG's and the company's earnings were lower in 2002 (one year earlier than expected) as a result of the electric rate plan because NYSEG's electric rates now reflect the sale of generation assets that was c ompleted in 1999.
The NYPSC February 2002 Order reduced annualized electric rates by $205 million for NYSEG customers effective March 1, 2002, which amounted to an overall average reduction of 13% for most customers. In the first rate year ending December 31, 2002, approximately $55 million of the annualized reduction was funded with the partial amortization of an asset sale gain account created by 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 returns on equity in excess of 15.5% for 2002, and equal sharing on the greater of returns on equity in excess of 12.5% on electric delivery, or 15.5% on the total electric business (including supply) for each of the years 2003 through 2006. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $700 million.
NYPSC-mandated Contracts with Two Customers: In March and April 2002 the NYPSC issued orders directing NYSEG to enter into long-term electric service contracts with Nucor Steel Auburn, Inc. and Corning Incorporated, that in NYSEG's opinion contain unduly low and preferential rates. In April 2002 NYSEG petitioned for rehearing of these orders on the basis that each order, and each underlying contract, violates law, NYSEG's tariffs and NYPSC guidelines. In May 2002 the NYPSC denied NYSEG's petitions for rehearing. On July 24, 2002, NYSEG filed a petition with the New York State Supreme Court, Albany County, asking the court to overturn the NYPSC's orders directing NYSEG to enter into the long-term electric service contracts because the rates and the terms of those mandated contracts are unduly preferential and violate the law, NYSEG's tariffs and the NYPSC's guidelines. Oral arguments were held in the proceeding on September 13, 2002. On December 9, 2002, the State Supreme Court dismissed NYSE G's petition. NYSEG has appealed that dismissal to the Appellate Division, Third Department, of the New York State Supreme Court. On September 24, 2002, and November 25, 2002, consistent with the NYPSC's orders, NYSEG signed the mandated contracts under protest, subject to review by the courts.
Lost revenues associated with these long-term electric service contracts are recovered through the asset sale gain account created by NYSEG's sale in 2001 of its interest in NMP2 and do not affect earnings. After giving effect to the amortization of the asset sale gain account to fund the first year of the electric rate reduction (see NYSEG Electric Rate Plan), the remaining balance would be entirely consumed by discounts offered to these two large industrial customers. NYSEG believes that the remaining balance should not be used for discounts provided to just two customers, but should be available to fund other economic development projects and for the recovery of uncontrollable costs.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Nonutility Generation: In December 1999 NYSEG notified the owners of Allegheny Hydro No. 8 and Allegheny Hydro No. 9 demanding that they each provide adequate assurance that they will perform their individual contractual obligations under two power purchase agreements with NYSEG, including the obligation to pay back overpayments made by NYSEG over the course of the agreements. Such overpayments are the cumulative difference between the rate NYSEG pays for power under the agreements and its actual avoided costs. At the end of 2002 this cumulative overpayment was more than $170 million and is expected to grow substantially by 2030 when both agreements expire. Allegheny and its lenders filed a motion in the New York State Supreme Court (N.Y. County) seeking a declaration that NYSEG's demand for adequate assurance was improper. The motion was denied by the court in September 2002. Unless a settlement can be reached, the matter is expected to proceed to trial.
CMP and NYSEG together expensed approximately $611 million for NUG power in 2002. They estimate that their combined NUG power purchases will total $613 million in 2003, $632 million in 2004, $642 million in 2005, $578 million in 2006 and $544 million in 2007. 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 2002, averaged 8.7 cents per kilowatt-hour for CMP and 8.3 cents per kilowatt-hour for NYSEG. Recovery of these NUG costs is provided for in CMP's and NYSEG's current regulatory plans. (See Item 8 - Note 9 to the company's Consolidated Financial Statements.)
RG&E 2002 Electric and Gas Rate Proceeding: On February 15, 2002, RG&E filed a request with the NYPSC for new electric and natural gas rates to go into effect on January 15, 2003. Subsequently, the date for a decision by the NYPSC was extended to March 2003 with a "make-whole" provision under which rates and any associated mechanisms would be adjusted to put RG&E and its customers in the same position they would have been had rates been allowed to go into effect as of January 15, 2003. The filing included both a traditional single-year filing and elements of a multi-year proposal for potential settlement negotiations. The single-year filing, as updated, provides a basis to increase annual electric rates by $40 million, or 5.7%, and increase annual natural gas rates by $19 million, or 6.6%, for the 12-month period ending June 30, 2003. RG&E's current base rates for electric and natural gas service will remain in effect until a new order is issued by the NYPSC. A lack of progre ss did not justify continuation of settlement discussions at that time and the parties proceeded on a litigation track. Evidentiary hearings took place in late October 2002. On December 17, 2002, the ALJ in this proceeding issued a recommended decision that, if approved, would result in a $9 million, or 3.3%, overall increase for natural gas service and no increase for electric service. Briefs on exception to the recommended decision were filed on January 7, 2003. Briefs opposing exceptions were filed on January 17, 2003. Following the submission of briefs settlement conferences in the natural gas rate proceeding were held.
As part of the current RG&E rate proceeding, the ALJ found RG&E to have excess electric earnings of $45 million, including interest, from RG&E's prior rate plan. RG&E continues to believe its reserve of $26 million for the estimated five-year excess earnings is appropriate. The calculation of the excess earnings will be subject to final approval by the NYPSC. RG&E is unable to predict what the NYPSC's ultimate determination of excess earnings under RG&E's prior rate plan will be.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Ginna Station: Several nuclear power plant operators have identified defects in their reactor vessel heads, which has prompted heightened Nuclear Regulatory Commission (NRC) oversight. During the summer of 2001 RG&E thoroughly reviewed this issue and an inspection plan was implemented during the spring 2002 refueling outage. Although the inspection demonstrated that the Ginna station could continue to operate with the existing head, RG&E decided to replace the reactor vessel head in order to avoid significant expenditures associated with maintenance, inspections and length of future outages. The replacement is scheduled to be completed during the fall 2003 refueling outage. The duration of the 2003 refueling outage is not expected to be significantly different than the duration of previous outages. The cost of the replacement is estimated to be $13 million and is expected to be recovered in rates.
Ginna Relicensing: The Ginna station operating license expires in 2009. On July 31, 2002, RG&E filed a license renewal application with the NRC, which, if approved, would extend the license through September 2029. The NRC has deemed the application complete. The NRC held two sets of public meetings in 2002, and plans to hold one more in 2003. RG&E's renewal application was unopposed. A decision on this matter is expected by the end of 2004.
Natural Gas Delivery Business
The company's natural gas delivery business consists of its regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts.
Natural Gas Supply Agreements: Four of Energy East's natural gas companies - NYSEG, SCG, CNG and Berkshire Gas - have a two-year strategic alliance with BP Energy Company, effective April 1, 2002, for the acquisition, optimization and management of certain natural gas supply, transportation and storage services, including portfolio management. The alliance provides the companies with greater supply flexibility, enhances the benefits of a larger natural gas portfolio and is based on sharing incremental savings. The companies still own and control their natural gas assets and work with BP Energy to obtain the lowest cost supply while maintaining reliability of service. The Energy East natural gas companies have received the required regulatory approvals concerning the alliance.
RG&E entered into a two-year supply portfolio management agreement that began April 1, 2002, with Dynegy Marketing and Trade, for Dynegy to assist RG&E in the cost-effective management of RG&E's firm contractual rights to natural gas supply, transportation and storage services. The agreement is designed to ensure that RG&E can reliably meet its customers' supply requirements while seeking to minimize the annual delivered cost of natural gas. On October 16, 2002, Dynegy announced that it would exit the marketing and trading business over the next several months. As a result of Dynegy's actions RG&E terminated its agreement with Dynegy and entered into a new portfolio management agreement with Entergy-Koch Trading, LP. The new arrangement with Entergy-Koch will extend through March 31, 2004, and includes the same reliability and cost-minimization objectives as the prior agreement with Dynegy. RG&E is assessing its position relative to the Dynegy termination and will take appr opriate action to resolve any outstanding issues.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
NYSEG Natural Gas Rate Plan: On November 20, 2002, the NYPSC approved the joint proposal that NYSEG filed with the NYPSC on September 13, 2002, and that had been endorsed by NYPSC Staff, the NY State Consumer Protection Board, large customer groups and numerous gas marketers. The approved natural gas rate plan became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, and implements a gas supply charge to collect the actual costs of gas and contains an earnings sharing mechanism. The earnings sharing mechanism requires equal sharing of earnings between NYSEG customers and shareholders of returns on equity in excess of 11.5% for the 27-month period ended December 31, 2004, and in excess of 12.5% for each of the calendar years from 2005 through 2008. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $240 million.
Connecticut Regulatory Proceedings: During 2001 the Connecticut Office of Consumer Counsel (OCC) filed appeals in State Superior Court arguing that the DPUC's order in December 2000 approving an SCG multi-year incentive rate plan (IRP) and its order in May 2001 approving a CNG IRP were unlawful. In March 2001 the OCC filed a Motion to Stay the implementation of the DPUC's order concerning the SCG IRP, but the court denied the motion in June 2001. In August 2001 the court appeals for SCG's and CNG's IRPs were combined.
In October 2001 SCG and CNG reached a settlement with the OCC, also endorsed by Prosecutorial Staff of the DPUC, resolving numerous outstanding regulatory and legal proceedings. The proceedings resolved by the settlement include a review of past SCG affiliate transactions, SCG's Purchased Gas Adjustment Clause (PGA) charges and credits, alleged overearnings at SCG and CNG, and a court appeal of the DPUC-approved IRPs for SCG and CNG.
SCG and CNG received a final decision from the DPUC approving the settlement in February 2002. The settlement provided rate reductions of $1.5 million for SCG and $0.5 million for CNG, effective October 1, 2001, extends the approved IRPs for an additional year through September 2005 and maintains an earnings sharing mechanism (ESM) that generally shares any earnings above the authorized returns on equity equally between shareholders and customers. The settlement also permits the recovery of SCG deferred gas costs through the PGA and through the customer portion of earnings sharing by the end of the IRP in 2005. Merger-enabled gas costs savings for both companies are also shared equally between customers and shareholders, with the shareholder portion recovered through the PGA.
In June 2002 the DPUC initiated proceedings to address the need for an interim rate decrease for SCG. Upon review of SCG's financial reports the DPUC concluded that a rate decrease was not required. SCG's earnings in excess of its allowed rate of return were primarily the result of merger-enabled gas costs savings and provided a direct benefit to customers because of the ESM that is an integral part of SCG's IRP.
In April 2002 the DPUC initiated a semiannual review of CNG's PGA. The DPUC issued its draft decision in December 2002, disallowing approximately $1 million of natural gas costs that would be returned to customers through the PGA. As a result, at December 31, 2002, CNG recognized a liability of $1 million for those costs. The DPUC has postponed its final decision in this matter.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Berkshire Gas Rate Increase: In January 2002 the DTE approved a rate increase of $2.3 million, or 4.5%, on total annual revenues for Berkshire Gas. The new rates became effective February 1, 2002. The DTE's approval included Berkshire Gas' proposal for a 10-year incentive-based rate plan with a midperiod review after five years. After the initial rate increase, rates will be frozen until September 2004, at which time rates will be adjusted annually based on inflation less a 1% consumer dividend. The DTE also approved Berkshire Gas' proposed rate design based on seasonal rates for residential and small commercial and industrial customers that are the same in the winter and summer. Berkshire Gas' proposal for service quality enhancements will be addressed in another proceeding.
RG&E 2002 Electric and Gas Rate Proceeding: See Electric Delivery Business.
NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive natural gas and electricity 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 a separate phase of this proceeding, the NYPSC issued an order in November 2001 directing the development of embedded cost of service studies for use in implementing unbundled rates. The embedded cost of service studies have been filed and are currently under review.
Other Businesses
The company's other businesses include a nonutility generating company, a liquid fuels distribution company, a retail energy marketing company, telecommunications assets, a propane distribution company, a district heating and cooling system, a FERC-regulated liquefied natural gas peaking plant and an energy services and construction company.
Sale of Other Businesses: The company continues to rationalize its nonutility businesses to ensure they fit its strategic focus. On August 12, 2002, Berkshire Service Solutions, Inc., an energy services provider and a subsidiary of Berkshire Energy, was sold at a loss of about $2 million. Berkshire Energy is a wholly-owned subsidiary of Energy East. During the fourth quarter of 2002 CNE Venture Tech Inc., a subsidiary of CNE, sold its 5% interest in the Nth Power Technologies Fund II, LP, at a loss of about $1 million.
Maine Natural Gas: In June 2001 Maine Natural Gas began construction of a new natural gas distribution system to serve the towns of Bowdoin, Brunswick and Topsham, Maine. It has served natural gas to certain larger customers since November 2001 and began serving residential and commercial customers in early 2002. Maine Natural Gas is also expanding its distribution system in Windham and Gorham, Maine.
Natural Gas Storage Facility: In August 2001 Seneca Lake Storage, Inc. (SLSI), a subsidiary of the company, announced plans to develop a high-deliverability natural gas storage facility in depleted salt caverns in the Town of Reading, New York. SLSI is currently assessing the demand for the facility. The storage facility would be linked to interstate pipelines, have a working gas capacity of 300,000 dekatherms (dth) and be capable of delivering up to 50,000 dth a day. In February 2002 FERC issued a certificate allowing the construction of certain
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
natural gas storage facilities and requiring that the facilities be completed and made available for service within one year of the order. In December 2002 the FERC granted a request by SLSI to modify the certificate to extend by one year the date within which SLSI has to complete construction of the proposed facilities and initiate service.
Other Matters
Accounting Issues
Statement 71: Statement 71, Accounting for the Effects of Certain Types of Regulation, allows companies that meet certain criteria to capitalize, as regulatory assets, incurred 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, Connecticut, Maine and Massachusetts; however, the company cannot predict what effect a competitive market or future actions of the NYPSC, MPUC, DPUC or DTE 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.
Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The company adopted Statement 143 as of January 1, 2003. The adoption of Statement 143 did not have a material effect on the company's financial position or results of operations. (See Item 8 - Note 1 to the company's Consolidated Financial Statements.)
Statement 145: In April 2002 the FASB issued Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. Early application of the provisions of Statement 145 is encouraged and the company elected to do so beginning in April 2002. The company now classifies the aggregate of gains and/or losses from the early extinguishment of debt as other income or other deductions on its income statement, as appropriate, instead of as an extraordinary item. The company has reclassified such extraordinary items presented on its income statements in prior periods. The remaining provisions of Statement 145 did not have a material effect on the company's financial position or results of operations.
Statement 146: In June 2002 the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities. Statement 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than at a plan or commitment date for the exit or disposal activity. It establishes fair value as the objective for initial measurement of the liability. The provisions of Statement 146 are effective for exit or disposal activities initiated after December 31, 2002. The company and its subsidiaries have determined that their adoption of Statement 146 on January 1, 2003, did not have a material effect on their results of operations or financial position.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Contractual Obligations and Commercial Commitments
At December 31, 2002, the company's contractual obligations and commercial commitments that will become due during the next five years are:
2003 | 2004 | 2005 | 2006 | 2007 | |
(Thousands) | |||||
Contractual Obligations | |||||
Long-term debt | $542,909 | $41,322 | $59,229 | $338,967 | $230,695 |
Capital lease obligations | 2,495 | 2,517 | 2,382 | 2,190 | 2,055 |
Operating leases | 16,572 | 15,663 | 13,955 | 12,281 | 12,222 |
Nonutility generator purchase |
|
|
|
|
|
Nuclear plant obligations | 58,134 | 54,078 | 60,448 | 61,742 | 52,045 |
Unconditional purchase obligations | 297,123 | 260,024 | 218,672 | 188,439 | 175,622 |
Other long-term obligations | 8,015 | 8,735 | 8,816 | 6,819 | 5,909 |
Total contractual cash obligations | $1,538,646 | $1,013,986 | $1,005,456 | $1,188,449 | $1,022,192 |
| |||||
Lines of credit | $754,750 | $258,000 | $258,000 | - | - |
Standby letters of credit | 334,100 | 334,100 | - | - | - |
Guarantees | 61,600 | 2,500 | - | - | - |
Total commercial commitments | $1,150,450 | $594,600 | $258,000 | - | - |
Energy East has two revolving credit agreements in which it covenants not to permit, without the consent of the lenders, its ratio of consolidated indebtedness to consolidated total capitalization at the last day of any fiscal quarter to exceed 0.65 to 1.00. Continued unremedied failure to comply with this covenant for 15 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. Energy East's ratio of consolidated indebtedness to consolidated total capitalization was 0.59 to 1.00 at December 31, 2002.
CMP has a revolving credit facility, which is secured by its accounts receivable, in which it covenants that (i) its consolidated total debt shall at all times be no more than 65% of the sum of its consolidated total debt and its total stockholders equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00. Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2002, CMP's consolidated total debt ratio was 33.6% and its interest coverage ratio was 3.73 to 1.00.
NYSEG and RG&E have a joint revolving credit agreement in which they each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2002, the ratio of earnings
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
before interest expense and income tax to interest expense was 3.4 to 1.0 for NYSEG and 2.3 to 1.0 for RG&E, and the ratio of total indebtedness to total capitalization was 0.53 to 1.00 for NYSEG and 0.52 to 1.00 for RG&E.
NYSEG has two letters of credit and reimbursement agreements in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 as of the last day of any fiscal quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2002.
Critical Accounting Policies
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 policies include the determination of the appropriate accounting for its pensions and other postretirement benefits, the effects of utility regulation on its financial statements and its risk management activities and the estimates and assumptions used to complete its annual goodwill and other intangibles impairment analyses.
Goodwill and Other Intangible Assets: As required by Statement 142, effective January 1, 2002, the company no longer amortizes goodwill and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized and are reviewed for impairment. The impairment test includes various assumptions. The primary assumptions are the discount rate and forecasted cash flows. Changes in those assumptions could have a significant effect on the company's determination of an impairment. (See Item 8 - Note 4 to the company's and Note 3 to CMP's Consolidated Financial Statements and Note 3 to NYSEG's and RG&E's Financial Statements.)
Pension and Other Postretirement Benefit Plans: The company has pension and other postretirement benefit plans covering substantially all of its employees. In accordance with Statement of Financial Accounting Standards No. 87, Employer's Accounting for Pensions, and Statement of Financial Accounting Standards No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, the valuation of benefit obligations and the performance of plan assets are subject to various assumptions. The primary assumptions include the discount rate, expected return on plan assets, rate of compensation increase, health care cost inflation rates, expected years of future service under the pension benefit plans and the methodology used to amortize gains or losses. Changes in those assumptions could also 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, 2002, the company decreased the discount rate from 7.0 % to 6.5% and the expected return on plan assets from 9.0% to 8.75% effective January 1, 2003. (See the company's, CMP's, NYSEG's and RG&E's Results of Operations, Other Items.)
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Risk Management: See Item 7A - Quantitative and Qualitative Disclosures About Market Risk and Item 8 - Note 1 to the company's Consolidated Financial Statements and NYSEG's and RG&E's Financial Statements.
Utility Regulation: The company's regulated utilities are subject to regulation by their respective state regulatory commissions and the FERC. 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 upon cost basis regulation reviewed and approved by those regulatory commissions. (See Other Matters, Accounting Issues, Statement 71.)
Investing and Financing Activities
Investing Activities: Capital spending totaled $229 million in 2002, $223 million in 2001 and $168 million in 2000, including capital spending for RGS Energy and nuclear fuel for RG&E beginning July 1, 2002. Capital spending does not include the amounts representing the company's merger transaction for RGS Energy in 2002 nor the four merger transactions in 2000. (See Item 8 - Note 3 to the company's Consolidated Financial Statements.) Capital spending in all three years was financed with internally generated funds and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements and governmental mandates.
Capital spending is projected to be $338 million in 2003, which includes RGS Energy and nuclear fuel. It is expected to be paid for with internally generated funds and will be primarily for the same purposes described above and merger integration. (See Item 8 - Note 9 to the company's Consolidated Financial Statements.)
The company's pension plans generated pretax noncash pension income (net of amounts capitalized) of $70 million in 2002, compared to $76 million in 2001 and $68 million in 2000. The company expects noncash pension income (net of amounts capitalized) for 2003 to decline, affecting earnings by approximately 15 cents per share as compared to 2002. That expected decrease is due to the significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute its pension liability (reduced from 7% to 6.5% as of December 31, 2002) and return on assets (reduced from 9% to 8.75% effective January 1, 2003). The company anticipates minimal funding requirements in 2003 as total plan assets approximates the projected benefit obligation. The company is currently unable to predict the effect that future equity market performance will have on pension income for 2004 and beyond. (See Item 8 - Note 15 to the company's Consolidated Financial Statements.)
Financing Activities: (See Item 8 - Note 6 to the company's Consolidated Financial Statements.)
The company raised its common stock dividend 4% in January 2003 to a new annual rate of $1.00 per share.
During 2002 the company repurchased 113,500 shares of its common stock at an average price of $18.85 per share. Future repurchases will depend on expected cash flows, alternative uses of cash, and overall economic and market conditions.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
In August 2001 the company began issuing new common shares through its Dividend Reinvestment and Stock Purchase Plan (DRIP) rather than purchasing them on the open market. During 2002 the company issued 852,824 shares at an average price of $20.92 per share through its DRIP, substantially out of treasury stock. The company expects to issue approximately one million shares per year under this plan.
In December 2002 the company amended its DRIP to allow nonshareholders who reside in Connecticut, Maine, Massachusetts or New York State to enroll directly in the Plan by making an initial cash investment.
The company and its subsidiaries have credit agreements with various expiration dates in 2003 and 2005. The agreements provided for maximum borrowings of $755 million at December 31, 2002 and 2001. (See Contractual Obligations and Commercial Commitments.)
The company and its subsidiaries use short-term, unsecured notes and drawings on their credit agreements (see above) to finance certain refundings and for other corporate purposes. There was $322 million of such short-term debt outstanding at December 31, 2002, and $173 million outstanding at December 31, 2001. The weighted-average interest rate on short-term debt was 2.1% at December 31, 2002, and 2.6% at December 31, 2001.
In May 2001 the company filed a shelf registration statement with the SEC to sell up to $1 billion in an unspecified combination of debt and trust preferred securities. The company has issued $995 million of debt and trust preferred securities under the shelf registration statement to fund the cash portion of the consideration for the merger with RGS Energy, for general corporate purposes, such as short-term debt reduction and to fund an equity contribution to NYSEG in 2001. (See Energy East and RGS Energy Merger.)
In June 2002 the company issued $400 million of 6.75% 10-year notes due June 2012 under the shelf registration statement described above. The proceeds were used to help fund the RGS Energy merger.
In July 2002 the company entered into a fixed-to-floating interest rate swap on the company's 5.75% notes due November 2006. The company receives a fixed rate of 5.75% and will pay a rate based on the six month London Interbank Offered Rate (LIBOR) plus 1.565%, on a notional amount of $250 million through November 2006.
In July 2002 the company terminated a fixed-to-floating interest rate swap on the company's 8.05% notes due November 2010. The company received $16 million, the value of the swap on the date of termination, and will amortize about $15 million of that gain over the remaining life of the notes.
CMP issued the following Series E Medium Term Notes, the proceeds of which were used to repay $50 million of maturing medium-term notes, as well as short-term debt and for general corporate purposes in 2002: in May 2002 - $37.5 million, 6.50%, due May 2009 and $37.5 million, 6.65%, due May 2012; in August 2002 - $15 million, 5.70%, due August 2012; in September 2002 - $15 million, 4.25%, due September 2007; and in November 2002 - $15 million, quarterly adjustable rate based on the three month LIBOR plus 0.6%, due January 2006.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
In May 2002 NYSEG redeemed, at a premium, $150 million of 8 7/8% Series first mortgage bonds due November 1, 2021, and redeemed, at par, the remaining $21.34 million of two 9 7/8% Series first mortgage bonds due 2020. The redemptions were financed with internally generated cash and the proceeds from the prepayment of a promissory note by Constellation Nuclear in April 2002. (See Sale of Nuclear Interests). NYSEG incurred a $10 million reduction to earnings in the second quarter of 2002 as a result of these redemptions, but will save over $16 million each year in interest costs. (See Other Matters, Statement 145.)
In November 2002 NYSEG issued $150 million of 4 3/8% unsecured notes due November 2007 and $100 million of 5 1/2% unsecured notes due November 2012. NYSEG used the net proceeds from those notes to refund commercial paper that was used in October 2002 to repay $150 million of maturing 6 3/4% Series first mortgage bonds and to repay $100 million of 8.30% Series first mortgage bonds that were called on December 15, 2002.
In 2003 NYSEG plans to call its remaining first mortgage bonds: $50 million of 7.55% Series first mortgage bonds callable on April 1, 2003, and $100 million of 7.45% Series first mortgage bonds callable on July 15, 2003. Additional financing needed by NYSEG to call its remaining first mortgage bonds is expected to be completed in June 2003. Through financial instruments issued in September 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.085%.
On January 9, 2003, RG&E used a $50 million equity contribution from its parent, RGS Energy, along with internally generated funds, to pay off the remaining $80 million balance of a 7% promissory note that was due to mature in 2014.
In July 2002 CNG paid at maturity $10 million of medium term notes using short-term debt. In October 2002 CNG redeemed $3.5 million of Series AA first mortgage bonds, including $2.5 million pursuant to a sinking fund provision and $1 million at a premium, using short-term debt.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Results of Operations
Due to the various mergers completed by the company, its results of operations include for 2002: RGS Energy beginning with July 2002; and for 2000: CNE beginning with February 2000 and CMP Group, CTG Resources and Berkshire Energy beginning with September 2000.
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| 2002 | 2001 | |
(Thousands, except per share amounts) | |||||
Operating Revenues | $4,008,918 | $3,759,787 | $2,959,520 | 7% | 27% |
Operating Income | $592,176 | $636,888 | $513,921 | (7%) | 24% |
Net Income | $188,603 | $187,607 | $235,034 | 1% | (20%) |
Average Common |
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Earnings Per Share, |
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Dividends Paid Per Share | $.96 | $.92 | $.88 | 4% | 5% |
Earnings Per Share
Earnings per share for 2002 were $1.44 compared to $1.61 for 2001, and include the nonrecurring items shown in the following table. The decrease in earnings for 2002 excluding nonrecurring items was primarily the result of an electric rate reduction of $205 million ordered by the NYPSC for NYSEG, effective March 1, 2002, which reduced earnings 50 cents per share. Other items that reduced earnings include: 16 cents per share for higher operating costs, such as the cost of merger integration efforts; 15 cents per share for fewer wholesale sales at lower market prices and 7 cents per share for a loss on early retirement of debt. Those decreases were significantly offset by increases of 29 cents per share due to lower natural gas costs, which includes the benefit of NYSEG's natural gas supply charge that went into effect October 1, 2002; 13 cents per share for higher electric deliveries (primarily residential and commercial) due to warmer summer weather in 2002 and colder winter weather in the fourth quarter of 2002; and 19 cents per share due to the elimination of goodwill amortization in 2002.
Earnings per share for 2001 were $1.61 compared to $2.06 for 2000, and include the nonrecurring items shown in the following table. The increase in 2001 earnings excluding nonrecurring items was primarily due to 20 cents per share for cost control efforts, 10 cents per share due to earnings from the merged companies, 1 cent per share for a loss on early retirement of debt in 2000 and 4 cents per share for a loss on the sale of XENERGY in 2000. Those increases were partially offset by 23 cents per share for lower electric and natural gas deliveries due to warmer weather and 13 cents per share for reduced electric transmission revenues.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
2002 | 2001 | 2000 | |
Earnings Per Share, basic and diluted | $1.44 | $1.61 | $2.06 |
Restructuring expenses | .19 | - | - |
Writedown of investment in NEON Communications |
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|
Benefit from sale of coal-fired generation assets | - | - | (.07) |
Earnings Per Share, excluding nonrecurring items | $1.69 | $2.00 | $1.99 |
The company provides information on earnings exclusive of nonrecurring items because it believes this information may be helpful to investors in assessing the company's results of ongoing operations. The company cautions investors that its view of nonrecurring items may differ from that of other companies and earnings exclusive of nonrecurring items should not be used as a surrogate for reported earnings prepared in accordance with generally accepted accounting principles.
Other Items
Other operating expenses includes net periodic pension benefit income of $70 million in 2002, $76 million in 2001 and $68 million in 2000. Other operating expenses would have been $6 million lower for 2002 and would have been $8 million higher for 2001 without those changes in net periodic pension benefit income. Net periodic pension benefit income represented 22% of net income for 2002, 24% for 2001 and 17% for 2000. The earnings effect from differences between actual and projected pension benefit income was based on any earnings sharing mechanisms approved by state utility commissions.
Other (income) decreased $8 million in 2002 primarily due to a decrease in miscellaneous income of $6 million, and decreased $14 million in 2001 primarily due to an $18 million decrease in interest income largely due to funds used to finance the company's merger transactions in 2000. Other deductions increased $10 million in 2002 primarily due to NYSEG's $16 million loss on early retirement of debt and were unchanged in 2001. (See Financing Activities and Item 8 - Note 1 to the company's Consolidated Financial Statements.)
Interest charges increased $41 million in 2002 including $34 million because of the addition of RGS Energy and $17 million for additional borrowings to finance the company's merger transaction with RGS Energy. Those increases were partially offset by $10 million of interest savings due to NYSEG's refinancings and repayments of first mortgage bonds. Interest charges increased $65 million in 2001 due to a $32 million increase for additional borrowings to finance the company's merger transactions, including the RGS Energy merger, and a $32 million increase for interest charges due to the acquisitions of CNE, CMP Group, CTG Resources and Berkshire Energy in 2000.
The $18 million increase in preferred stock dividends in 2002 includes $16 million due to the company's issuance of trust preferred securities in July 2001 and $2 million because of the addition of RGS Energy. Preferred stock dividends increased $13 million in 2001 due to the company's issuance of trust preferred securities in July 2001.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
The effective tax rate was 31% in 2002 and 43% in 2001. The decrease is the result of various items including the elimination of goodwill amortization in 2002, the flow-through effect (in 2001 only) of the sale of NMP2, a lower state income tax rate in 2002 due to combined filing benefits, and an increase in distributions on trust preferred securities that were outstanding for a full year in 2002.
Operating Results for the Electric Delivery Business
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| 2002 | 2001 | |
(Thousands) | |||||
Deliveries - Megawatt-hours |
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Operating Revenues | $2,568,247 | $2,504,896 | $2,023,610 | 3% | 24% |
Operating Expenses | $2,119,218 | $1,951,475 | $1,540,953 | 9% | 27% |
Operating Income | $449,029 | $553,421 | $482,657 | (19%) | 15% |
Operating Revenues: The $63 million increase in operating revenues for 2002 is primarily due to the addition of RG&E's delivery revenues of $369 million and increased retail deliveries of $33 million primarily due to warmer summer weather in 2002. Those increases were partially offset by a reduction of $138 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002; $114 million due to a rate reduction for NYSEG, effective March 1, 2002; and lower wholesale revenues of $64 million primarily due to lower market prices for electricity.
Operating revenues for 2001 increased $481 million compared to 2000 primarily due to the first full year of CMP's delivery revenues, which added $565 million, and amortization of deferred gains of $9 million. Those increases were partially offset by $37 million due to lower wholesale deliveries because of warmer weather, $32 million as a result of CMP no longer collecting revenue for the supply of electricity to certain retail customers and $22 million due to reduced transmission revenues.
Operating Expenses: Operating expenses for 2002 increased $168 million. The increase in operating expenses for 2002 was $131 million excluding $25 million for restructuring expenses in 2002 and $12 million for the effect of the sale of NYSEG's share of NMP2 in 2001. That increase includes $291 million for the addition of RG&E's operating expenses; $15 million of purchased power costs for higher retail deliveries due to warmer summer weather in 2002 and colder winter weather in the fourth quarter of 2002; $15 million for merger integration efforts; and $44 million for purchased power costs to replace energy previously provided by NMP2, which was partially offset by a $35 million decrease in certain operating expenses due to the sale of NMP2. Those increases were partially offset by decreases including $138 million of electricity purchased because CMP is no longer the standard-offer provider for the supply of electricity, $32 million due to lower market prices for electricity and $9 million due to the elimination of goodwill amortization in 2002.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Operating expenses for 2001 increased $411 million. The increase in operating expense for 2001 was $423 million, excluding $12 million for the effect of the sale of NYSEG's share of NMP2, primarily due to the first full year of CMP's operating costs of $490 million. That increase was partially offset by $31 million because of lower purchased power costs primarily due to lower deliveries, $17 million for lower electricity supply costs because CMP no longer supplies electricity unless directed to by the MPUC, and $18 million due to cost control efforts relating to retirement benefits and compensation.
Operating Results for the Natural Gas Delivery Business
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| 2002 | 2001 | |
(Thousands) | |||||
Deliveries - Dekatherms |
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Operating Revenues | $1,032,539 | $1,026,124 | $772,131 | 1% | 33% |
Operating Expenses | $882,883 | $936,606 | $699,402 | (6%) | 34% |
Operating Income | $149,656 | $89,518 | $72,729 | 67% | 23% |
Operating Revenues: Operating revenues increased $6 million for 2002. Operating revenues increased $126 million due to the addition of RG&E's delivery revenues and $8 million due to increased deliveries primarily because of colder winter weather in the fourth quarter of 2002. Those increases were partially offset by a $98 million decrease because of lower market prices of natural gas that are passed on to customers and a $30 million decrease due to fewer wholesale customers.
For 2001, operating revenues increased $254 million primarily due to the first full year of revenues from SCG - $69 million, CNG - $245 million and Berkshire Gas - $45 million. Recovery of natural gas costs primarily from nonresidential deliveries also added $27 million to revenues. Those increases were partially offset by $116 million due to lower deliveries because of warmer weather and $11 million due to lower natural gas prices for wholesale sales.
Operating Expenses: Operating expenses decreased $54 million for 2002. The decrease in operating expenses for 2002 was $69 million excluding $15 million for restructuring expenses. That decrease was primarily due to a $159 million decrease in purchased gas costs caused by lower market prices, a $33 million decrease in purchased gas due to fewer wholesale customers and a $15 million decrease due to the elimination of goodwill amortization in 2002. Those decreases were partially offset by $115 million for the addition of RG&E's operating expenses, $9 million for increased purchases of natural gas due to higher deliveries because of colder winter weather in the fourth quarter of 2002, $9 million for higher uncollectible expenses and $6 million for merger integration efforts.
Operating expenses for 2001 increased $237 million primarily due to the first full year of natural gas purchases and operating costs for SCG - $58 million, CNG - $218 million and Berkshire Gas - $41 million. Those increases were partially offset by $60 million of reduced purchased natural gas costs due to lower prices and deliveries and $13 million for cost control efforts relating to retirement benefits and compensation.
Energy East Corporation
Consolidated Statements of Income
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands, except per share amounts) | |||
Operating Revenues | |||
Sales and services | $4,008,918 | $3,759,787 | $2,959,520 |
Operating Expenses | |||
Electricity purchased and fuel used in generation | 1,276,087 | 1,334,507 | 1,073,728 |
Natural gas purchased | 603,258 | 694,038 | 496,509 |
Gasoline, propane and oil purchased | 143,770 | 3,688 | 1,560 |
Other operating expenses | 713,384 | 566,498 | 434,405 |
Maintenance | 162,122 | 139,395 | 108,106 |
Depreciation and amortization | 246,996 | 204,281 | 165,524 |
Other taxes | 230,558 | 192,772 | 165,767 |
Restructuring expenses | 40,567 | - | - |
Gain on sale of generation assets | - | (84,083) | - |
Deferral of asset sale gain | - | 71,803 | - |
Total Operating Expenses | 3,416,742 | 3,122,899 | 2,445,599 |
Operating Income | 592,176 | 636,888 | 513,921 |
Writedown of Investment | 12,209 | 78,422 | - |
Other (Income) | (26,883) | (35,257) | (49,671) |
Other Deductions | 29,847 | 20,216 | 19,514 |
Interest Charges, Net | 257,747 | 217,066 | 152,520 |
Preferred Stock Dividends of Subsidiaries | 32,129 | 14,455 | 963 |
Income Before Income Taxes | 287,127 | 341,986 | 390,595 |
Income Taxes | 98,524 | 154,379 | 155,561 |
Net Income | $188,603 | $187,607 | $235,034 |
Earnings Per Share, basic and diluted | $1.44 | $1.61 | $2.06 |
Average Common Shares Outstanding | 131,117 | 116,708 | 114,213 |
The notes on pages 44 through 69 are an integral part of the financial statements.
Energy East Corporation
Consolidated Balance Sheets
December 31 | 2002 | 2001 |
(Thousands) | ||
Assets | ||
Current Assets | ||
Cash and cash equivalents | $250,490 | $437,014 |
Special deposits | 47,643 | 1,555 |
Accounts receivable, net | 737,876 | 564,671 |
Note receivable | 380 | 12,126 |
Fuel, at average cost | 117,678 | 92,234 |
Materials and supplies, at average cost | 22,953 | 21,466 |
Accumulated deferred income tax benefits, net | 8,697 | 4,170 |
Prepayments and other current assets | 85,787 | 41,600 |
Total Current Assets | 1,271,504 | 1,174,836 |
Utility Plant, at Original Cost | ||
Electric | 5,787,762 | 3,874,972 |
Natural gas | 2,347,011 | 1,771,636 |
Common | 360,776 | 213,362 |
8,495,549 | 5,859,970 | |
Less accumulated depreciation | 3,873,267 | 2,270,516 |
Net Utility Plant in Service | 4,622,282 | 3,589,454 |
Construction work in progress | 179,557 | 36,978 |
Total Utility Plant | 4,801,839 | 3,626,432 |
Other Property and Investments, Net | 452,710 | 216,556 |
Regulatory and Other Assets | ||
Regulatory assets | ||
Nuclear plant obligations | 524,679 | 199,797 |
Unfunded future income taxes | 208,164 | 164,657 |
Unamortized loss on debt reacquisitions | 45,353 | 53,965 |
Demand-side management program costs | 8,394 | 18,137 |
Environmental remediation costs | 106,262 | 85,835 |
Nonutility generator termination agreements | 168,014 | 9,480 |
Other | 361,960 | 239,258 |
Total regulatory assets | 1,422,826 | 771,129 |
Other assets | ||
Goodwill, net | 1,518,173 | 897,807 |
Prepaid pension benefits | 540,426 | 435,901 |
Other | 262,401 | 146,571 |
Total other assets | 2,321,000 | 1,480,279 |
Total Regulatory and Other Assets | 3,743,826 | 2,251,408 |
Total Assets | $10,269,879 | $7,269,232 |
The notes on pages 44 through 69 are an integral part of the financial statements.
Energy East Corporation
Consolidated Balance Sheets
December 31 | 2002 | 2001 | ||
(Thousands) | ||||
Liabilities | ||||
Current Liabilities | ||||
Current portion of long-term debt | $545,404 | $225,678 | ||
Notes payable | 322,200 | 173,383 | ||
Accounts payable and accrued liabilities | 361,499 | 224,150 | ||
Interest accrued | 44,310 | 36,183 | ||
Taxes accrued | 30,036 | 7,020 | ||
Other | 200,927 | 142,926 | ||
Total Current Liabilities | 1,504,376 | 809,340 | ||
Regulatory and Other Liabilities | ||||
Regulatory liabilities | ||||
Deferred income taxes | 203,926 | 157,196 | ||
Gain on sale of generation assets | 126,325 | 251,254 | ||
Pension benefits | 67,205 | 52,642 | ||
Other | 104,937 | 68,879 | ||
Total regulatory liabilities | 502,393 | 529,971 | ||
Other liabilities | ||||
Deferred income taxes | 702,426 | 461,600 | ||
Nuclear plant obligations | 314,013 | 199,797 | ||
Other postretirement benefits | 391,049 | 282,791 | ||
Environmental remediation costs | 133,933 | 102,930 | ||
Other | 448,156 | 241,975 | ||
Total other liabilities | 1,989,577 | 1,289,093 | ||
Total Regulatory and Other Liabilities | 2,491,970 | 1,819,064 | ||
Long-term debt | 3,351,959 | 2,471,278 | ||
Total Liabilities | 7,348,305 | 5,099,682 | ||
Commitments | - | - | ||
Preferred Stock of Subsidiaries |
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Common Stock Equity |
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Capital in excess of par value | 1,447,664 | 842,989 | ||
Retained earnings | 1,061,428 | 998,281 | ||
Accumulated other comprehensive income (loss) | (34,167) | (22,335) | ||
Treasury stock, at cost (574 shares at December 31, 2002 |
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Total Common Stock Equity | 2,460,612 | 1,781,177 | ||
Total Liabilities and Stockholders' Equity | $10,269,879 | $7,269,232 | ||
The notes on pages 44 through 69 are an integral part of the financial statements.
Energy East Corporation
Consolidated Statements of Cash Flows
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Operating Activities | |||
Net income | $188,603 | $187,607 | $235,034 |
Adjustments to reconcile net income to net cash | |||
Depreciation and amortization | 255,782 | 247,847 | 228,543 |
Income taxes and investment tax credits deferred, net | 43,564 | 4,588 | 29,114 |
Restructuring expenses | 40,567 | - | - |
Gain on sale of generation assets | - | (84,083) | - |
Deferral of asset sale gain | - | 71,803 | - |
Pension income | (70,189) | (76,229) | (67,849) |
Writedown of investment | 12,209 | 78,422 | - |
Changes in current operating assets and liabilities | |||
Accounts receivable, net | (24,247) | 125,121 | (83,688) |
Sale of accounts receivable program | - | (152,000) | - |
Inventory | 6,111 | (25,445) | (13,623) |
Prepayments and other current assets | (3,998) | 3,119 | (1,341) |
Accounts payable and accrued liabilities | 5,551 | (123,832) | (10,289) |
Interest accrued | (3,118) | 874 | 8,097 |
Taxes accrued | 4,895 | 1,125 | 2,897 |
Other current liabilities | 4,089 | (53,372) | (11,994) |
Other assets | (66,279) | (44,163) | (68,889) |
Other liabilities | 16,896 | (6,848) | 12,210 |
Net Cash Provided by Operating Activities | 410,436 | 154,534 | 258,222 |
Investing Activities | |||
Acquisitions, net of cash acquired | (681,397) | - | (1,442,717) |
Utility plant additions | (224,450) | (208,677) | (154,009) |
Sale of generation assets | 59,442 | 59,441 | - |
Temporary investments | - | - | 1,017,249 |
Other property and investments additions | (29,177) | (30,271) | (48,143) |
Other property and investments sold | 12,138 | 18,967 | 32,946 |
Special deposits | (5,166) | 19,909 | (21,954) |
Other | 1,490 | (19,344) | 11,002 |
Net Cash Used in Investing Activities | (867,120) | (159,975) | (605,626) |
Financing Activities | |||
Issuance of common stock | 17,844 | 7,201 | - |
Repurchase of common stock | (2,139) | (24,116) | (163,493) |
Issuance of mandatorily redeemable trust |
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Repayments of first mortgage bonds and preferred |
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Long-term note issuances | 767,807 | 355,553 | 601,095 |
Long-term note repayments | (97,124) | (29,965) | (20,771) |
Notes payable three months or less, net | 166,702 | (269,012) | 183,866 |
Notes payable issuances | 28,400 | 54,445 | 16,345 |
Notes payable repayments | (50,154) | (31,045) | (8,265) |
Dividends on common stock | (125,456) | (107,342) | (99,606) |
Net Cash Provided by Financing Activities | 270,160 | 298,829 | 374,224 |
Net (Decrease) Increase in Cash and Cash Equivalents | (186,524) | 293,388 | 26,820 |
Cash and Cash Equivalents, Beginning of Year | 437,014 | 143,626 | 116,806 |
Cash and Cash Equivalents, End of Year | $250,490 | $437,014 | $143,626 |
The notes on pages 44 through 69 are an integral part of the financial statements.
Energy East Corporation
Consolidated Statements of Changes in Common Stock Equity
| Common Stock |
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| Accumulated |
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Balance, January 1, 2000 | 109,343 | $1,108 | $660,936 | $782,588 | $(1,681) | $(38,997) | $1,403,954 |
Net income | 235,034 | 235,034 | |||||
Other comprehensive income, net of tax | (33,142) | (33,142) | |||||
Comprehensive income | 201,892 | ||||||
Common stock dividends |
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Common stock issued - merger transactions | 16,269 | 163 | 373,545 | 373,708 | |||
Common stock repurchased | (7,958) | (80) | (163,413) | (163,493) | |||
Treasury stock transactions, net | 2 | (8) | 57 | 49 | |||
Amortization of capital stock issue expense | 18 | 18 | |||||
Balance, December 31, 2000 | 117,656 | 1,191 | 871,078 | 918,016 | (34,823) | (38,940) | 1,716,522 |
Net income | 187,607 | 187,607 | |||||
Other comprehensive income, net of tax | 12,488 | 12,488 | |||||
Comprehensive income | 200,095 | ||||||
Common stock dividends |
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Common stock issued - dividend reinvestment and stock purchase plan |
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Common stock repurchased | (1,306) | (13) | (24,103) | (24,116) | |||
Capital stock issue expense | (11,498) | (11,498) | |||||
Amortization of capital stock issue expense | 315 | 315 | |||||
Balance, December 31, 2001 | 116,718 | 1,182 | 842,989 | 998,281 | (22,335) | (38,940) | 1,781,177 |
Net income | 188,603 | 188,603 | |||||
Other comprehensive income, net of tax | (11,832) | (11,832) | |||||
Comprehensive income | 176,771 | ||||||
Common stock dividends |
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Common stock issued - merger transaction | 27,509 | 275 | 611,807 | 612,082 | |||
Common stock issued - dividend reinvestment and stock purchase plan |
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Common stock repurchased | (114) | (1) | (2,138) | (2,139) | |||
Capital stock issue expense | (52) | (52) | |||||
Treasury stock transactions, net | (1) | (23,171) | 23,172 | - | |||
Amortization of capital stock issue expense | 385 | 385 | |||||
Balance, December 31, 2002 | 144,966 | $1,455 | $1,447,664 | $1,061,428 | $(34,167) | $(15,768) | $2,460,612 |
The notes on pages 44 through 69 are an integral part of the financial statements.
Notes to Consolidated Financial Statements
Energy East Corporation
Note 1. Significant Accounting Policies
Background: Energy East Corporation (Energy East or the company) is a registered public utility holding company under the Public Utility Holding Company Act of 1935. Energy East is a super-regional energy services and delivery company with operations in New York, Connecticut, Massachusetts, Maine and New Hampshire and corporate offices in New York and Maine. Its wholly-owned subsidiaries - and their principal operating utilities - are: Berkshire Energy Resources - The Berkshire Gas Company, CMP Group, Inc. - Central Maine Power Company (CMP); Connecticut Energy Corporation (CNE) - The Southern Connecticut Gas Company (SCG); CTG Resources, Inc. - Connecticut Natural Gas Corporation (CNG); and RGS Energy Group, Inc. (RGS Energy) - New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E).
Accounts receivable: Accounts receivable include unbilled revenues of $237 million at December 31, 2002, and $143 million at December 31, 2001, and are shown net of an allowance for doubtful accounts of $59 million at December 31, 2002, and $18 million at December 31, 2001. Bad debt expense was $46 million in 2002, $34 million in 2001 and $24 million in 2000. Bad debt expense for 2002 includes RGS Energy beginning July 1, 2002, and for 2001 includes CNE, CMP Group, CTG Resources and Berkshire Energy for a full year for the first time.
In August 2001 NYSEG terminated its agreement to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allowed NYSEG to receive up to $152 million from the sale of such interests. All fees related to the agreement beginning April 1, 2001, are included in interest expense on the consolidated statements of income and were approximately $3 million. Fees related to the sale of accounts receivable through March 31, 2001, are included in other deductions on the consolidated statements of income and amounted to approximately $2 million in 2001 and $10 million in 2000. NYSEG's sale of accounts receivable before the agreement was terminated did not constitute a securitization transaction because the accounts receivable were not transferred to a special purpose entity, and therefore, were not transformed into securities.
Basic and diluted earnings per share:Basic earnings per share (EPS) is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the period. The weighted-average common shares outstanding for diluted EPS include the incremental effect of stock options issued and exclude stock options issued in tandem with stock appreciation rights (SARs). All stock options are issued in tandem with SARs and, historically, substantially all stock option plan participants have exercised the SARs instead of the stock options. The numerator used in calculating both basic and diluted EPS for each period is the reported net income. The reconciliation of basic and diluted EPS for each period follows:
Notes to Consolidated Financial Statements
Energy East Corporation
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Numerator | |||
Net Income | $188,603 | $187,607 | $235,034 |
Denominator | |||
Basic average common shares outstanding | 131,117 | 116,708 | 114,213 |
Potentially dilutive common shares | 215 | 198 | 170 |
Options issued with SARs | (215) | (198) | (170) |
Dilutive average common shares | 131,117 | 116,708 | 114,213 |
Earnings per Share, basic | $1.44 | $1.61 | $2.06 |
Earnings per Share, diluted | $1.44 | $1.61 | $2.06 |
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: 4.7 million in 2002, 2.1 million in 2001 and 1.9 million in 2000.
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. Those investments are included in cash and cash equivalents on the consolidated balance sheets.
Supplemental Disclosure of Cash Flows Information | 2002 | 2001 | 2000 |
(Thousands) | |||
Interest, net of amounts capitalized | $238,305 | $208,431 | $132,009 |
Income taxes, net of benefits received | $54,418 | $113,274 | $154,108 |
Acquisitions: | |||
Fair value of assets acquired | $3,264,093 | - | $2,526,971 |
Liabilities assumed | (1,826,528) | - | (651,589) |
Preferred stock of subsidiaries | (72,000) | - | (37,591) |
Common stock issued | (612,082) | - | (373,708) |
Cash acquired | (72,086) | - | (21,366) |
Net cash paid for acquisitions | $681,397 | - | $1,442,717 |
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 includes estimated cost of removal, in service at each operating company. The weighted-average service lives of certain classifications of property are: transmission property - 51 years, distribution property - 42 years, generation property - 41 years, gas production property - 26 years, gas storage property - 24 years and other property - 28 years. The company's depreciation accruals were equivalent to 3.5% of average depreciable property for 2002, 3.1% for 2001 and 3.1% for 2000, which was weighted for the effect of the mergers completed in June 2002 and September 2000.
Estimates: Preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Notes to Consolidated Financial Statements
Energy East Corporation
Goodwill:The excess of the cost over fair value of net assets of purchased businesses is recorded as goodwill and goodwill was amortized on a straight-line basis over five to 40 years until December 31, 2001. Beginning in 2002 the company evaluates the carrying value of goodwill for impairment at least annually and on an interim basis if there are indications that goodwill might be impaired. Any impairments would be recognized when the fair value of goodwill is less than its carrying value. (See Note 4.)
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 have paid if a separate income tax return had been filed. The determination and allocation of the income tax provision and its components are outlined and agreed to in the tax sharing agreements among Energy East and its subsidiaries.
Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.
Other (Income) and Other Deductions:
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Dividends | $(233) | $(1,844) | $(44) |
Interest income | (13,213) | (13,125) | (31,233) |
Noncash returns | (6,693) | (2,404) | (1,360) |
Allowance for funds used during construction | (1,401) | (652) | (713) |
Gains from the sale of nonutility property | (231) | (3,628) | - |
Earnings from equity investments | (4,631) | (7,162) | (2,232) |
Miscellaneous | (481) | (6,442) | (14,089) |
Total other (income) | $(26,883) | $(35,257) | $(49,671) |
NYSEG early retirement of debt | $16,145 | - | $2,766 |
Fees on sale of accounts receivable | - | $2,495 | 10,368 |
Miscellaneous | 13,702 | 17,721 | 6,380 |
Total other deductions | $29,847 | $20,216 | $19,514 |
Principles of consolidation: These financial statements consolidate the company's majority-owned subsidiaries after eliminating intercompany transactions.
Reclassifications: Certain amounts have been reclassified on the consolidated financial statements to conform with the 2002 presentation.
Regulatory assets and liabilities: Pursuant to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, the company capitalizes, as regulatory assets, incurred costs that are probable of recovery in future electric and natural gas rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.
Notes to Consolidated Financial Statements
Energy East Corporation
Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Unamortized loss on debt reacquisitions is amortized over the lives of the related debt issues. Nuclear plant obligations, demand-side management program costs, gain on sale of generation assets, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with the company's current rate plans. The company earns a return on substantially all regulatory assets for which funds have been spent.
Revenue recognition: The company recognizes revenues upon delivery of energy and energy-related products and services to its customers.
Pursuant to Maine Law, since March 1, 2000, CMP has been prohibited from selling power to its retail customers. CMP does not enter into any purchase and sales arrangements for power with the ISO New England, the New England Power Pool, or any other independent system operator or similar entity. All of CMP's power entitlements under its NUG and other purchase power contracts are sold to unrelated third parties under bilateral contracts for the period March 1, 2002, through February 28, 2005.
NYSEG and RG&E enter into power purchase and sales transactions with the NYISO. When sales of owned generation are sold to the NYISO, and subsequently repurchased from the NYISO to serve their customers, the transactions are recorded on a net basis in the consolidated statements of income.
Risk management: All of Energy East's natural gas utilities 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 to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures is included in the commodity cost when the related sales commitments are fulfilled.
The company uses electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity. The cost or benefit of those contracts is included in the amount expensed for electricity purchased when the electricity is sold.
The company uses interest rate swap agreements to manage the risk of increases in variable interest rates and to maintain desired fixed-to-floating rate ratios. It records amounts paid and received under the agreements as adjustments to the interest expense of the specific debt issues.
The company also uses financial instruments to lock in the treasury rate component of future financings to mitigate risk resulting from interest rate changes.
The company does not hold or issue financial instruments for trading or speculative purposes.
The company recognizes the fair value of its natural gas futures, financial electricity contracts and interest rate agreements as assets or liabilities on the consolidated balance sheets. The company's derivative asset was $80 million at December 31, 2002, and its derivative liability was $9 million at December 31, 2002, and $32 million at December 31, 2001. All of the
Notes to Consolidated Financial Statements
Energy East Corporation
arrangements are designated as cash flow hedging instruments except for the company's $250 million fixed-to-floating interest rate swap agreement, which is designated as a fair value hedge. Changes in the fair value of the cash flow hedging instruments are recognized in other comprehensive income until the underlying transaction occurs. When the underlying transaction occurs, the amounts in accumulated other comprehensive income are reported in the consolidated statements of income. Changes in the fair value of the interest rate swap agreement are recorded in the same period as the offsetting change in the fair value of the underlying debt instrument.
The company uses quoted market prices to fair value derivatives and adjusts for volatility and inflation when the period of the derivative exceeds the period for which market prices are readily available.
As of December 31, 2002, the maximum length of time over which the company is hedging its exposure to the variability in future cash flows for forecasted transactions is 84 months. The company estimates that gains of $16 million will be reclassified from accumulated other comprehensive income into earnings in 2003, 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.
Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability. The company adopted Statement 143 as of January 1, 2003. The company recognized an asset retirement obligation of approximately $415 million, a regulatory asset of $141 million, a regulatory liabil ity of $5 million, an increase in utility plant of $74 million and a decrease in accumulated depreciation of $205 million. There was no effect on net income. Previously the company had recognized $266 million of the obligation as accumulated depreciation.
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 and the cost of removal less salvage are charged to accumulated depreciation.
Notes to Consolidated Financial Statements
Energy East Corporation
Note 2. Restructuring
In the fourth quarter of 2002 the company recorded $41 million of restructuring expenses, including $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 are $20 million for a voluntary early retirement program that will be paid from the companies' pension plans and $3 million for an involuntary severance program, primarily for salaried employees of the company's six operating utilities, and $1 million for other associated costs.
Those programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by April 30, 2003. That includes approximately 70 from CMP, 260 from NYSEG, 245 from RG&E and 75 from Berkshire Gas, CNG and SCG. The employees affected by the involuntary severance program were notified in January 2003.
Note 3. Acquisition of RGS Energy Group
On June 28, 2002, the company acquired all of the outstanding common stock of RGS Energy for a combination of cash and Energy East common stock. The company's consolidated statements of income and cash flows include RGS Energy's results of operations beginning with July 2002. RGS Energy, through its regulated subsidiary RG&E, engages in generating, purchasing and delivering electricity and purchasing and delivering natural gas in an area centered around the city of Rochester, New York. Through its unregulated subsidiary, Energetix, Inc., RGS Energy engages in retail electric, natural gas and liquid fuel businesses throughout upstate New York. In connection with Energy East's merger with RGS Energy, NYSEG became a wholly-owned subsidiary of RGS Energy.
Under the merger agreement 45% of the RGS Energy common stock, 15.6 million shares, was converted into 27.5 million shares of Energy East common stock valued at $612 million. The value of the shares issued was determined based on the market price of Energy East's stock at the end of the day on June 27, 2002. The remaining 55% of the RGS Energy common stock was exchanged for $753 million in cash ($39.50 per RGS Energy share). The purchase price was about $1.4 billion, which includes $11 million of merger-related costs.
The following table summarizes the components of the purchase price and preliminary allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition. RGS Energy did not push goodwill down to its subsidiaries. As of December 31, 2002, $29 million was allocated to intangible assets based on a preliminary appraisal. The allocation of the purchase price will be adjusted when final appraisals are received, RG&E's electric and gas rate cases are finalized and actual amounts for estimated liabilities become known.
Notes to Consolidated Financial Statements
Energy East Corporation
Calculation of the purchase price for assets acquired | |
(Thousands) | |
Cash paid for stock purchased | $753,483 |
Common stock issued | 612,082 |
Merger-related fees and expenses | 11,000 |
Total purchase price for common equity | 1,376,565 |
Plus fair market value of liabilities and preferred stock assumed | |
Current and other liabilities | 883,502 |
Long-term debt | 932,026 |
Preferred stock | 72,000 |
Total liabilities and preferred stock | 1,887,528 |
Total purchase price for assets acquired | $3,264,093 |
Allocation of purchase price for assets acquired | |
Property, plant and equipment | $1,203,282 |
Goodwill | 622,342 |
Intangible assets subject to amortization | 22,019 |
Intangible assets not amortized | 6,600 |
All other assets, including working capital | 1,409,850 |
Total | $3,264,093 |
The following pro forma information for the company for the years ended December 31, 2002 and 2001, which is based on unaudited data, gives effect to the company's merger with RGS Energy as if it had been completed at the beginning of each period presented. This information does not reflect future revenues or cost savings that may result from the merger and is not indicative of actual results of operations had the merger occurred at the beginning of the periods presented or of results that may occur in the future.
Year Ended December 31 | 2002 | 2001 |
(Thousands, except per share amounts) | ||
Operating Revenues | $4,690,489 | $5,290,279 |
Net Income | $201,521 | $262,741 |
Earnings per Share of Common Stock | $1.39 | $1.82 |
Pro forma adjustments reflected in the amounts presented include: (1) adjusting RGS Energy's nonutility assets to fair value based on an independent appraisal, (2) adjusting depreciation and amortization of assets to the accounting base recognized in recording the combination, (3) elimination of amortization of goodwill, (4) amortization of other intangible assets with finite lives, (5) elimination of merger costs, (6) additional interest expense and preferred stock dividends due to the issuance of merger-related debt and securities, (7) adjustments for estimated tax effects of the above adjustments and (8) additional common shares issued in connection with the merger. The pro forma results include a loss of 19 cents per share for restructuring expenses and the writedown of CMP Group's investment in NEON Communications of 6 cents per share in 2002 and 39 cents per share in 2001. The pro forma results of operations for 2002 include the results of operations of RGS Energy for the six months ended June 30, 2 002, as follows: Operating revenues - $681,571; Operating expenses - $615,851; Operating income - $65,720; Income before income taxes - $36,850; and Net income - $15,550.
Notes to Consolidated Financial Statements
Energy East Corporation
Note 4. Goodwill and Other Intangible Assets
Effective January 1, 2002, the company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As required by Statement 142 the company no longer amortizes goodwill and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized (amortized intangible assets) and are reviewed for impairment.
The company determined that there was no impairment of goodwill as of January 1, 2002. There was no reclassification of goodwill to intangible assets and no reclassification of intangible assets to goodwill as of January 1, 2002. Annual impairment testing was also completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for the companies at September 30, 2002.
The changes in the carrying amount of goodwill on the company's balance sheets, by operating segment, for the year ended December 31, 2002, are:
Electric Delivery | Natural Gas Delivery |
|
| |
(Thousands) | ||||
Balance, January 1, 2002 | $325,174 | $554,787 | $17,846 | $897,807 |
Goodwill acquired during the year | 494,063 | 123,516 | 4,763 | 622,342 |
Goodwill written off related to | ||||
sale of business | - | - | (1,709) | (1,709) |
Other adjustments | 406 | (653) | (20) | (267) |
Balance, December 31, 2002 | $819,643 | $677,650 | $20,880 | $1,518,173 |
Other Intangible Assets: At December 31, 2002, the company's unamortized intangible assets had a carrying amount of $14 million and primarily consisted of trade names and pension assets. At December 31, 2001, the company's unamortized intangible assets had a carrying amount of $4 million and primarily consisted of pension assets. At December 31, 2002, the company's amortized intangible assets had a gross carrying amount of $47 million and primarily consisted of customer lists and investments in pipelines. Customer lists acquired in 2002 with a carrying amount of $14 million will be amortized over three to 10 years. At December 31, 2001, the company's amortized intangible assets had a gross carrying amount of $26 million and primarily consisted of investments in pipelines. Accumulated amortization was $15 million at December 31, 2002, and $5 million at December 31, 2001.
Estimated amortization expense for intangible assets for the next five years (in thousands) is:
2003 | 2004 | 2005 | 2006 | 2007 |
$4,362 | $4,285 | $3,512 | $2,723 | $2,667 |
Notes to Consolidated Financial Statements
Energy East Corporation
Transitional Information: Results of operations information for the company as though goodwill had been accounted for under Statement 142 for all years presented is:
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands, except per share data) | |||
Reported net income | $188,603 | $187,607 | $235,034 |
Add back: Goodwill amortization | - | 25,379 | 18,486 |
Adjusted net income | $188,603 | $212,986 | $253,520 |
Reported basic and diluted earnings per share: | $1.44 | $1.61 | $2.06 |
Add back: Goodwill amortization | - | .22 | .16 |
Adjusted basic and diluted earnings per share | $1.44 | $1.83 | $2.22 |
Note 5. Income Taxes
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Current | $50,663 | $147,497 | $129,220 |
Deferred, net | |||
Accelerated depreciation | 19,258 | 12,312 | 628 |
Pension benefits | 36,932 | 30,430 | 24,051 |
Statement 106 postretirement benefits | (4,627) | (4,079) | (11,417) |
Demand-side management | (2,189) | (9,295) | (8,335) |
Asset sale gain account amortization | 29,367 | - | - |
Restructuring expenses | (15,816) | - | - |
Miscellaneous | (12,540) | (20,371) | 23,676 |
ITC | (2,524) | (2,115) | (2,262) |
Total | $98,524 | $154,379 | $155,561 |
The company's effective tax rate differed from the statutory rate of 35% due to the following:
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Tax expense at statutory rate | $111,740 | $124,754 | $137,045 |
Depreciation and amortization not normalized | 5,125 | 26,373 | 8,032 |
ITC amortization | (2,524) | (2,115) | (2,262) |
Trust preferred securities | (9,932) | (4,389) | - |
State taxes, net of federal benefit | 9,724 | 14,692 | 21,386 |
Other, net | (15,609) | (4,936) | (8,640) |
Total | $98,524 | $154,379 | $155,561 |
The effective tax rate was 31% in 2002 and 43% in 2001. The decrease is the result of various items including the elimination of goodwill amortization in 2002, the flow-through effect (in 2001 only) of the sale of NMP2, a lower state income tax rate in 2002 due to combined filing benefits, and an increase in distributions on trust preferred securities that were outstanding for a full year in 2002.
Notes to Consolidated Financial Statements
Energy East Corporation
The company's deferred tax assets and liabilities consisted of the following:
December 31 | 2002 | 2001 |
(Thousands) | ||
Current Deferred Tax Assets | $8,697 | $4,170 |
Noncurrent Deferred Tax Liabilities | ||
Depreciation | $750,739 | $573,071 |
Unfunded future income taxes | 129,481 | 80,125 |
Accumulated deferred ITC | 45,039 | 29,370 |
Deferred gain on sale of generation assets | 63,969 | (109,246) |
Pension benefits | 87,717 | 102,109 |
Statement 106 postretirement benefits | (92,182) | (64,013) |
Nuclear decommissioning | (44,093) | - |
Other | (34,318) | 7,380 |
Total Noncurrent Deferred Tax Liabilities | $906,352 | 618,796 |
Less amounts classified as regulatory liabilities | ||
Deferred income taxes | 203,926 | 157,196 |
Noncurrent Deferred Income Taxes | $702,426 | $461,600 |
Energy East and its subsidiaries have no federal tax credit or loss carryforwards, nor do they have any valuation allowances.
Note 6. Long-term Debt
At December 31, 2002 and 2001, the company's consolidated long-term debt was:
Amount | ||||
Maturity Dates | Interest Rates | 2002 | 2001 | |
(Thousands) | ||||
First mortgage bonds(1) | 2003 to 2032 | 5.84% to 10.06% | $890,500 | $609,840 |
Pollution control notes - fixed | 2006 to 2034 | 5 3/8% to 6.15% | 351,000 | 325,500 |
Pollution control notes - variable | 2015 to 2032 | 0.75% to 4.43% | 408,900 | 307,000 |
Various long-term debt(2) | 2003 to 2030 | 0.95% to 10.48% | 1,924,130 | 1,137,809 |
Putable asset term securities(3) | 2033 | 7.75% | 300,000 | 300,000 |
Obligations under capital leases | 34,447 | 36,960 | ||
Unamortized premium and discount on debt, net | (11,614) | (20,153) | ||
| 3,897,363 | 2,696,956 | ||
Less debt due within one year - included in current liabilities | 545,404 | 225,678 | ||
Total | $3,351,959 | $2,471,278 | ||
At December 31, 2002, long-term debt, including sinking fund obligations, and capital lease payments (in thousands) that will become due during the next five years are:
2003 | 2004 | 2005 | 2006 | 2007 | ||||
$545,404 | $43,839 | $61,611 | $341,157 | $232,750 |
As a registered holding company under the Public Utility Holding Company Act of 1935, Energy East is prohibited from obtaining upstream guarantees and credit support from its subsidiaries. Energy East has no secured indebtedness and none of its assets are mortgaged, pledged or otherwise subject to lien. None of Energy East's debt obligations are guaranteed or secured by its subsidiaries.
Notes to Consolidated Financial Statements
Energy East Corporation
(1) For Energy East, in addition to the information provided for CMP, NYSEG and RG&E below, Berkshire Gas and SCG have first mortgage bonds that are secured by liens on substantially all of their respective utility properties. Berkshire Gas has other long-term debt that is secured by its properties, and CTG Resources and CNE have subsidiaries with long-term debt that is secured by properties of those subsidiaries.
CMP has no long-term debt obligations that are secured. CMP has no intercompany collateralizations and has no guarantees to affiliates or subsidiaries. CMP's debt has no guarantees from parent or affiliates or any additional credit supports.
NYSEG's first mortgage bonds, totaling $150 million at December 31, 2002, are secured by a first mortgage lien on substantially all of its properties. NYSEG has no other secured indebtedness. None of NYSEG's other debt obligations are guaranteed or secured by any of its affiliates.
RG&E's first mortgage bonds, totaling $705.5 million at December 31, 2002, are secured by a first mortgage lien on substantially all of its properties. Other than the promissory note described below, RG&E has no other secured indebtedness. None of RG&E's other debt obligations are guaranteed or secured by any of its affiliates.
(2) Includes RG&E's promissory note in connection with the Kamine Global Settlement Agreement, collateralized by a mortgage, the lien for which is subordinate to the first mortgage lien. On January 9, 2003, RG&E paid off the remaining $80 million balance of this note that was due to mature in 2014.
(3) The Putable Asset Term Securities bear interest at 7.75% until November 15, 2003, and then, as provided by an agreement, will either be redeemed by the company or will bear interest at a fixed or floating rate until November 15, 2033, unless extended to November 15, 2034. At December 31, 2002, the $300 million Putable Asset Term Securities were classified as current portion of long-term debt as a result of this provision.
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.
In the event of a cross-default of other long-term debt obligations of CMP, The Finance Authority of Maine, under a Loan Agreement, may declare an amount equal to the unpaid principal amount, currently less than $10 million, and interest accrued immediately due and payable.
NYSEG has provisions in its unsecured indenture and the reimbursement agreements relating to certain series of pollution control bonds, which provide that default by NYSEG with respect to any other debt in excess of $40 million in the case of the unsecured indenture and $5 million in the case of the reimbursement agreements will be considered a default under those respective documents.
Notes to Consolidated Financial Statements
Energy East Corporation
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 7. Bank Loans and Other Borrowings
The company and its subsidiaries have credit agreements with various expiration dates in 2003 and 2005 and pay fees in lieu of compensating balances in connection with the credit agreements. The agreements provided for maximum borrowings of $755 million at December 31, 2002 and 2001.
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 $322 million of such short-term debt outstanding at December 31, 2002, and $173 million outstanding at December 31, 2001. The weighted-average interest rate on short-term debt was 2.1% at December 31, 2002, and 2.6% at December 31, 2001.
In its revolving credit agreements Energy East covenants not to permit, without the consent of the lenders, its ratio of consolidated indebtedness to consolidated total capitalization at the last day of any fiscal quarter to exceed 0.65 to 1.00. Continued unremedied failure to comply with this covenant for 15 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. Energy East's ratio of consolidated indebtedness to consolidated total capitalization was 0.59 to 1.00 at December 31, 2002.
In its revolving credit facility, which is 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 stockholders equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00. Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2002, CMP's consolidated total debt ratio was 33.6% and its interest coverage ratio was 3.73 to 1.00.
In their joint revolving credit agreement NYSEG and RG&E each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2002, the ratio of earnings before interest expense and income tax to interest expense was 3.4 to 1.0 for NYSEG and 2.3 to 1.0 for RG&E. At December 31, 2002, the ratio of total indebtedness to total capitalization was 0.53 to 1.00 for NYSEG and 0.52 to 1.00 for RG&E.
NYSEG has two letters of credit and reimbursement agreements in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 as of the last day of any fiscal
Notes to Consolidated Financial Statements
Energy East Corporation
quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2002.
Note 8. Preferred Stock of Subsidiaries
Trust preferred securities: The company-obligated mandatorily redeemable trust preferred securities are 81/4% Capital Securities issued by Energy East Capital Trust I, a Delaware business trust that is a wholly-owned finance subsidiary of the company. The assets of the trust consist solely of the company's 81/4% junior subordinated debt securities maturing on July 31, 2031. The company has fully and unconditionally guaranteed the trust's payment obligations with respect to the Capital Securities.
At December 31, 2002 and 2001, the consolidated preferred stock was:
| Par |
| Shares |
| |||||
Redeemable solely at the option of subsidiaries: | |||||||||
3.50% | $100 | $101.00 | 220,000 | $22,000 | $22,000 | ||||
3.75% | 100 | 104.00 | 78,379 | 7,838 | 7,838 | ||||
4% F | 100 | 105.00 | 120,000 | 12,000 | - | ||||
4.10% H | 100 | 101.00 | 80,000 | 8,000 | - | ||||
4.10% J | 100 | 102.50 | 50,000 | 5,000 | - | ||||
4.15% (1954) | 100 | 102.00 | 4,317 | 432 | 432 | ||||
4.40% | 100 | 102.00 | 7,093 | 709 | 709 | ||||
4 1/2% (1949) | 100 | 103.75 | 11,800 | 1,180 | 1,180 | ||||
4.55% M | 100 | 101.00 | 100,000 | 10,000 | - | ||||
4.60% | 100 | 101.00 | 30,000 | 3,000 | 3,000 | ||||
4.75% | 100 | 101.00 | 50,000 | 5,000 | 5,000 | ||||
4.75% I | 100 | 101.00 | 60,000 | 6,000 | - | ||||
4.80% | 100 | 100.00 | 2,574 | 257 | 259 | ||||
4.95% K | 100 | 102.00 | 60,000 | 6,000 | - | ||||
5.25% | 100 | 102.00 | 50,000 | 5,000 | 5,000 | ||||
6% Noncallable | 100 | - | 5,180 | 518 | 518 | ||||
6.00% | 100 | 110.00 | 4,104 | 411 | 413 | ||||
8.00% Noncallable | 3.125 | - | 108,843 | 340 | 340 | ||||
Preferred stock issuance costs | (2,723) | (3,316) | |||||||
Total | $90,962 | $43,373 | |||||||
Subject to mandatory redemption requirements: | |||||||||
6.60% V(2) | $100 | $100.00 | 250,000 | $25,000 | - | ||||
(1) At December 31, 2002, the company and its subsidiaries had 15,790,801 shares of $100 par value preferred stock, 16,800,000 shares of $25 par value preferred stock, 775,472 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
(2) This RG&E series is subject to a mandatory sinking fund sufficient to redeem, at par, on March 1 of each year from 2004 through 2008, 12,500 shares, and on March 1, 2009, the balance of the shares. RG&E has the option to redeem up to an additional 12,500 shares on the same terms and dates as applicable to the mandatory sinking fund. In the event RG&E should be in arrears in the sinking fund requirement, RG&E may not redeem or pay dividends on any stock subordinate to the preferred stock.
The company's subsidiaries redeemed or purchased the following amounts of preferred stock during the three years 2000 through 2002:
Subsidiary Company | Date | Series | Amount |
CMP | October 1, 2000 | 7.999% | $9.9 million* |
CNG | September 26, 2000 | 8.00% | $3,250* |
CNG | Various 2001 | 6.00% | $45,900* |
CNG | Various 2001 | 8.00% | $41,222** |
CNG | June 7, 2002 | 6.00% | $2,500* |
Berkshire | September 30, 2001 | 4.80% | $41,000* |
Berkshire | September 30, 2002 | 4.80% | $1,500* |
* Redeemed ** Substantially all purchased at a premium
Voting rights of preferred shares issued by subsidiaries:
Trust preferred securities - Holders of trust preferred securities have no voting rights, except that they may vote on certain transactions if such transaction would cause Energy East Capital Trust I or a successor entity to be classified other than as a grantor trust for U.S. federal income tax purposes, and they may vote on certain matters affecting the powers, preferences or special rights of the trust preferred securities.
Preferred stock redeemable solely at the option of subsidiaries - If preferred stock dividends on any series of preferred stock of a subsidiary, other than the 6% Noncallable series and the 8.00% series, are in default in an amount equivalent to four full quarterly dividends, the holders of the preferred stock of such subsidiary are entitled to elect a majority of the directors of such subsidiary (and, in the case of the 6.00% series, the largest number of directors constituting a minority of the board) and their privilege continues until all dividends in default have been paid. The holders of preferred stock, other than the 6% Noncallable series and the 8.00% series, are not entitled to vote in respect of any other matters except those, if any, in respect of which voting rights cannot be denied or waived under some mandatory provision of law, and except that the charters of the respective subsidiaries contain provisions to the effect that such holders shall be entitled to vote on certain ma tters affecting the rights and preferences of the preferred stock.
Holders of the 6% Noncallable series and the 8.00% series are entitled to one vote per share and have full voting rights on all matters.
Whenever holders of preferred stock shall be entitled to vote, they shall be entitled to cast one vote for each share of preferred stock held by them. Holders of NYSEG common stock are entitled to one vote per share on all matters, except in the election of directors with respect to
Notes to Consolidated Financial Statements
Energy East Corporation
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 9. Commitments
Capital spending: The company has commitments in connection with its capital spending program. Capital spending is projected to be $338 million in 2003, which includes RGS Energy and nuclear fuel, and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. The company's capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration .
Nonutility generator power purchase contracts: CMP and NYSEG together expensed approximately $611 million for NUG power in 2002, $593 million in 2001 and $439 million in 2000 (CMP beginning on September 1, 2000, the date it was acquired). CMP and NYSEG estimate that their combined NUG power purchases will total $613 million in 2003, $632 million in 2004, $642 million in 2005, $578 million in 2006 and $544 million in 2007.
Note 10. Jointly-Owned Generation Assets and Nuclear Generation Insurance
and Decommissioning
Cayuga Energy, Inc.: Cayuga Energy, Inc. owns an 85% interest in South Glens Falls Energy, L.L.C., 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, L.L.C., operates the plant as an exempt wholesale generator.
CMP: CMP has ownership interests in three nuclear generating facilities in New England. The largest is a 38% interest in Maine Yankee Atomic Power Company. CMP also owns a 9.5% interest in Yankee Atomic Electric Company and a 6% interest in Connecticut Yankee Atomic Power Company. Maine Yankee, Yankee Atomic and Connecticut Yankee have been permanently shut down and are in the process of being decommissioned.
On July 31, 2002, Vermont Yankee Nuclear Power Corporation sold the Vermont Yankee nuclear power plant, including CMP's 4% ownership interest, to Entergy Corporation. Any benefits realized from the sale, which are expected to be less than $1 million, will be used to reduce CMP customers' future obligations for stranded costs. The transaction included a power purchase agreement that calls for Entergy to provide all of the plant's electricity to the sellers through 2012, the year the operating license for the plant expires.
Sale of Nine Mile Point 2: In November 2001 NYSEG and RG&E sold their interests in NMP2 to Constellation Nuclear. In October 2001 the NYPSC issued an order approving the sale.
Notes to Consolidated Financial Statements
Energy East Corporation
NYSEG: For its 18% share of NMP2, NYSEG received at closing $59 million in cash and a $59 million 11% promissory note. On April 12, 2002, Constellation Nuclear paid the remaining balance plus accrued interest on the promissory note. NYSEG's 18% share of NMP2's operating expenses until it was sold is included in various categories on the statements of income.
Upon completion of the sale of NMP2, NYSEG recorded an asset sale gain of approximately $110 million, in accordance with the NYPSC's order approving the sale, as a regulatory liability under Statement 71. The gain includes a gross up for unfunded future income taxes and is being returned to customers in accordance with NYSEG's current electric rate plan, which was approved by the NYPSC in February 2002.
RG&E: For its 14% share of NMP2, the October 2001 NYPSC order provided for RG&E to establish a regulatory asset of approximately $326 million at the time of closing. RG&E agreed to a one-time $20 million pretax accelerated amortization of the regulatory asset that was recorded in the third quarter of 2001. In addition, RG&E accelerated its recognition of approximately $13 million of previously deferred investment tax credits. RG&E also agreed to amortize the regulatory asset by an additional $30 million per year during the period from the closing of the sale of NMP2 until RG&E's base electric rates are reset. The $30 million annual amortization reflects RG&E's projected savings for its share of NMP2 operating expenses compared to the estimated cost of electricity purchases to replace RG&E's presale share of the output. The terms associated with the recovery of the remaining regulatory asset will be established in future RG&E rate proceedings. The settlemen t further provides that it constitutes a final and irrevocable resolution of all RG&E ratemaking issues associated with the sale of NMP2 and RG&E's ability to recover through rates the costs associated with its investment in NMP2.
NYSEG and RG&E's pre-existing decommissioning funds for NMP2 were transferred to Constellation, which has taken responsibility for all future decommissioning funding.
The transaction included a power purchase agreement that calls for Constellation to provide electricity to NYSEG and RG&E, at fixed prices, for 10 years. The power purchase agreement is a contract for physical delivery of NYSEG's 18% share and RG&E's 14% share of 90% of the output from NMP2. NYSEG and RG&E recorded expenses for electricity purchased in 2001 and 2002 in accordance with the agreement at the time the power was physically delivered, at prices pursuant to the agreement. The contract is not required to be marked-to-market and is not considered a derivative instrument because it qualifies for the normal purchases and normal sales exception in Statement 133, as amended.
After the power purchase agreement is completed a revenue sharing agreement will begin. The revenue sharing agreement could provide NYSEG and RG&E additional revenue through 2021, which would mitigate increases in electricity prices. Both agreements are based on plant output. No amounts were recorded under the revenue sharing agreement in 2002 because any benefit that may occur between 2011 and 2021 cannot be estimated. Any benefits from the revenue sharing agreement will be deferred for customers.
Notes to Consolidated Financial Statements
Energy East Corporation
Nuclear insurance: The Price-Anderson Act is a federal statute providing, among other things, a limit on the maximum liability of nuclear reactor owners for damages resulting from a single nuclear incident. The public liability limit for a nuclear incident is approximately $9.5 billion and is subject to inflation and changes in the number of licensed reactors. RG&E carries the maximum available commercial insurance of $300 million and participates in the mandatory financial protection pool for the remaining $9.2 billion. Under the Price-Anderson Act, RG&E would be liable for up to $88 million per incident payable at a rate not to exceed $10 million per incident per year.
In addition to the insurance required by the Price-Anderson Act, RG&E also carries nuclear property damage insurance and accidental outage insurance through Nuclear Electric Insurance Limited. Under those insurance policies, RG&E could be subject to assessments if losses exceed the accumulated funds available to the insurers. The maximum amounts of the assessments for the current policy year are $13 million for nuclear property damage insurance and $3 million for accidental outage insurance.
Nuclear plant decommissioning costs: The estimated liability, in 2003 dollars, for decommissioning the various interests in nuclear plants, including spent fuel storage, is $387 million for CMP, which was updated in 2002 to include spent fuel storage and increases in projected costs, and $434 million for RG&E. The amount currently billed or accrued for those costs is recovered by CMP and RG&E through their electric rates.
Note 11. Environmental Liability
From time to time environmental laws, regulations and compliance programs may require changes in the company's operations and facilities and may increase the cost of electric and natural gas service.
The U.S. Environmental Protection Agency and various state environmental agencies, as appropriate, notified the company that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at 19 waste sites. The 19 sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the 19 sites, nine 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 of the 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 17 of the 19 sites. Remediation costs have been paid at the remaining two sites, and the company expects no additional liability to be incurred. An estimated liability of $5 million has been recorded related to 12 sites where the company believes it is probable that it will incur remediation costs, although it has not been notified that it is among the potentially responsible parties. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to the company.
Notes to Consolidated Financial Statements
Energy East Corporation
The company has a program to investigate and perform necessary remediation at its 59 sites where gas was manufactured in the past. Eight sites are included in the New York State Registry, eight sites are included in the New York Voluntary Cleanup Program, four sites are part of Maine's Voluntary Response Action Program and three of those four sites are part of Maine's Uncontrolled Sites Program, three sites are included in the Connecticut Inventory of Hazardous Waste Sites, and three sites are on the Massachusetts Department of Environmental Protection's list of confirmed disposal sites. The company has entered into consent orders with various environmental agencies to investigate and, where necessary, remediate 39 of its 59 sites.
The company's estimate for all costs related to investigation and remediation of its 59 sites ranges from $126 million to $220 million at December 31, 2002. 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 the company's consolidated balance sheets was $126 million at December 31, 2002, and $101 million at December 31, 2001. The company recorded a corresponding regulatory asset, net of insurance recoveries, since it expects to recover the net costs in rates.
The company has reported petroleum spill incidents to the New York State Spill Incidents Report database and has recorded an estimated liability of $2 million to remediate these spill incidents.
Energy East's environmental liabilities are recorded on an undiscounted basis unless payments are fixed and determinable. Nearly all of Energy East's environmental liability accruals, which are expected to be paid through the year 2017, have been established on an undiscounted basis. Insurance settlements have been received by Energy East subsidiaries during the last three years, which they accounted for as reductions in their related regulatory assets.
Notes to Consolidated Financial Statements
Energy East Corporation
Note 12. Fair Value of Financial Instruments
The carrying amounts and estimated fair values of the company's financial instruments included on its consolidated balance sheets are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.
December 31 | 2002 | 2002 | 2001 | 2001 |
Carrying | Estimated | Carrying | Estimated | |
(Thousands) | ||||
Investments - classified as |
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First mortgage bonds | $888,870 | $973,232 | $606,112 | $623,055 |
Pollution control notes - fixed | $351,000 | $364,865 | $325,500 | $333,056 |
Pollution control notes - variable | $408,900 | $408,900 | $307,000 | $307,000 |
Various long-term debt | $1,915,160 | $2,088,303 | $1,123,557 | $1,124,911 |
Putable asset term securities | $298,986 | $335,288 | $297,827 | $310,017 |
The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values. Special deposits may include restricted funds set aside as collateral for first mortgage bonds and collateral received from counterparties. The carrying amount approximates fair value because the special deposits have been invested in securities that mature within one year.
The company evaluated the carrying value of CMP Group's investment in NEON Communications, Inc. because there had been a significant decline in the market value of NEON common shares. That decline was consistent with the market performance of telecommunications businesses as a whole. A decline was determined to be other than temporary during the third quarter of 2001 and the investment was written down to its fair market value of $12 million at September 30, 2001. That writedown totaled $46 million after taxes, or 39 cents per share.
During the first half of 2002 the company determined that additional declines in NEON's market value were other than temporary and further wrote down the cost basis of its investment in NEON. The investment was written down to $2 million based on the closing market price of NEON common shares on March 31, 2002. That writedown totaled $6 million after taxes, or five cents per share. In the second quarter of 2002 the NEON common shares were delisted from NASDAQ and NEON filed a reorganization plan under the U.S. Bankruptcy Code. The company wrote off its remaining $2 million investment during the second quarter of 2002, which was $1 million after taxes, or one cent per share.
The investment in NEON was classified as available-for-sale, accounted for by the cost method and carried at its fair value, with changes in fair value recognized in other comprehensive income. No income or loss related to the investment in NEON was included in the company's operating income in earlier periods.
Notes to Consolidated Financial Statements
Energy East Corporation
Note 13. Stock-Based Compensation
The company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, to account for its stock-based compensation plans. Compensation expense would have been the same in 2002, 2001 and 2000 had it been determined consistent with Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, because stock appreciation rights (SARs) were granted along with any options granted. SARs will continue to be issued along with any options granted.
The company may grant options and SARs to senior management and certain other key employees under its stock option plan. Options granted in 2000, 2001 and 2002 vest over either one-year or two-year periods, subject to, with certain exceptions, continuous employment. All options expire 10 years after the grant date. Of the 10 million shares authorized at December 31, 2002 and 2001, unoptioned shares totaled 1.9 million at December 31, 2002, and 4.5 million at December 31, 2001.
The company recorded compensation expense (benefit) for options/SARs of $12 million in 2002, less than $(1) million in 2001 and $(1) million in 2000.
During 2002, 2,810,500 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $20.34. 347,863 SARs with a weighted-average exercise price of $16.26 were exercised in 2002. 74,337 options/SARs with an exercise price of $19.43 were forfeited in 2002. The 7,024,347 options/SARs outstanding at December 31, 2002, had a weighted-average exercise price of $20.95. Of those outstanding at December 31, 2002, 91,309 options/SARs with exercise prices ranging from $10.88 to $14.69 and a weighted- average remaining life of four years had a weighted-average exercise price of $10.88 and 6,933,038 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of eight years had a weighted-average exercise price of $21.08. Of those exercisable at December 31, 2002, 91,309 options/SARs with exercise prices ranging from $10.88 to $14.69 had a weighted-average price of $10.88 and 4,611,209 options/SARs with exercise prices ranging fro m $17.94 to $28.72 had a weighted-average exercise price of $21.66.
During 2001, 1,799,000 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $18.88. 54,332 SARs with a weighted-average exercise price of $17.51 were exercised in 2001. 34,000 options/SARs with an exercise price of $21.03 were forfeited in 2001. The 4,636,047 options/SARs outstanding at December 31, 2001, had a weighted-average exercise price of $20.95. Of those outstanding at December 31, 2001, 191,309 options/SARs with exercise prices ranging from $10.88 to $14.69 and a weighted-average remaining life of five years had a weighted-average exercise price of $10.88 and 4,444,738 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of eight years had a weighted-average exercise price of $21.38. Of those exercisable at December 31, 2001, 191,309 options/SARs with exercise prices ranging from $10.88 to $14.69 had a weighted-average price of $10.88 and 2,939,545 options/SARs with exercise prices ranging fro m $17.94 to $28.72 had a weighted-average exercise price of $22.17.
Notes to Consolidated Financial Statements
Energy East Corporation
During 2000, 1,070,597 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $23.06. 2,797 options with a weighted-average exercise price of $16.43 and 107,731 SARs with a weighted-average exercise price of $17.56 were exercised in 2000. 312,548 options/SARs with an exercise price of $23.99 were forfeited in 2000. The 2,925,379 options/SARs outstanding at December 31, 2000, had a weighted-average exercise price of $22.15. Of those outstanding at December 31, 2000, 197,309 options/SARs with exercise prices ranging from $10.88 to $14.69 and a weighted-average remaining life of six years had a weighted-average exercise price of $10.88 and 2,728,070 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of eight years had a weighted-average exercise price of $22.97. Of those exercisable at December 31, 2000, 197,309 options/SARs with exercise prices ranging from $10.88 to $14.69 had a weighted-average pri ce of $10.88 and 1,470,287 options/SARs with exercise prices ranging from $17.94 to $28.72 had a weighted-average exercise price of $22.98.
The company's Long-term Executive Incentive Share Plan provides participants cash awards if certain shareholder return criteria are achieved. There were 59,130 performance shares outstanding at December 31, 2002, and 95,418 performance shares outstanding at December 31, 2001. Compensation expense for 2002 was $0.4 million, there was no compensation expense for 2001 and compensation expense was $1 million for 2000. Beginning January 1, 2001, no new performance shares were granted under this plan (other than dividend performance shares). The plan will be eliminated in 2003.
Notes to Consolidated Financial Statements
Energy East Corporation
Note 14. Accumulated Other Comprehensive Income
| Balance January |
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Foreign currency translation adjustment, net of income tax benefit of $ - for 2000, 2001 |
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Net unrealized gains (losses) |
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Minimum pension liability adjustment, net of income tax benefit of $339 for 2000, $1,828 for 2001 and $39,378 for 2002 |
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Unrealized gains (losses) on derivatives qualified as hedges: |
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Net unrealized gains (losses) on derivatives qualified as hedges |
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Accumulated Other Comprehensive |
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(See Risk management in Note 1.)
Notes to Consolidated Financial Statements
Energy East Corporation
Note 15. Retirement Benefits
Pension Benefits | Postretirement Benefits | |||
2002 | 2001 | 2002 | 2001 | |
(Thousands) | ||||
Change in projected benefit obligation | ||||
Benefit obligation at January 1 | $1,369,448 | $1,242,769 | $408,427 | $395,857 |
Service cost | 29,318 | 23,967 | 6,040 | 5,091 |
Interest cost | 111,943 | 90,949 | 32,215 | 25,024 |
Plan participants' contributions | - | - | 212 | 255 |
Plan amendments | 465 | 39,614 | (11,922) | (26,967) |
Actuarial loss | 114,742 | 37,949 | 55,240 | 31,895 |
Business combination | 501,454 | - | 92,198 | - |
Curtailment | - | (670) | - | (394) |
Special termination benefits | 64,909 | 2,551 | - | - |
Benefits paid | (98,415) | (67,681) | (25,140) | (22,334) |
Projected benefit obligation at December 31 | $2,093,864 | $1,369,448 | $557,270 | $408,427 |
Change in plan assets | ||||
Fair value of plan assets at January 1 | $1,822,052 | $1,925,905 | $38,634 | $40,226 |
Actual return on plan assets | (244,955) | (37,564) | (3,248) | (1,804) |
Employer contributions | 329 | 433 | 23,215 | 22,291 |
Plan participants' contributions | - | - | 212 | 255 |
Business combination | 585,390 | - | - | - |
Adjustment | - | 959 | 415 | - |
Benefits paid | (98,415) | (67,681) | (25,140) | (22,334) |
Fair value of plan assets at December 31 | $2,064,401 | $1,822,052 | $34,088 | $38,634 |
Funded status | $(29,463) | $452,604 | $(523,182) | $(369,793) |
Unrecognized net actuarial loss (gain) | 527,617 | (59,273) | 106,401 | 46,983 |
Unrecognized prior service cost (benefit) | 50,741 | 58,277 | (54,929) | (60,365) |
Unrecognized net transition |
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Prepaid (accrued) benefit cost | $540,426 | $435,901 | $(391,049) | $(282,791) |
Amounts recognized in the balance sheet | ||||
Prepaid benefit cost | $540,426 | $435,901 | $99 | $516 |
Accrued benefit cost | - | - | (391,148) | (283,307) |
Additional minimum liability | (185,321) | (43,872) | - | - |
Intangible asset | 6,226 | 2,517 | - | - |
Regulatory liability | 76,913 | 37,022 | - | - |
Accumulated other comprehensive income | 102,182 | 4,333 | - | - |
Net amount recognized | $540,426 | $435,901 | $(391,049) | $(282,791) |
CMP Group's, CNE's and CTG Resources' postretirement benefits were partially funded as of December 31, 2002 and 2001.
The company recorded a minimum pension liability of $185 million at December 31, 2002, as required by Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions. The effect of the minimum pension liability is recognized in other long-term liabilities, intangible assets, regulatory liability and other comprehensive income, as appropriate, and is prescribed when the accumulated benefit obligation in the plan exceeds the fair value of the underlying pension plan assets and accrued pension liabilities. The increase in the unfunded
Notes to Consolidated Financial Statements
Energy East Corporation
accumulated benefit obligation is primarily due to a reduction in the assumed discount rate, investment market conditions and a voluntary early retirement program offered by the company as part of its restructuring. (See Note 2.)
Pension Benefits | Postretirement Benefits | |||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |
Weighted-average assumptions | ||||||
Discount rate | 6.5% | 7.0% | 7.25% | 6.5% | 7.0% | 7.25% |
Expected return on plan assets | 9.0% | 9.0% | 9.0% | 9.0% | 9.0% | 9.0% |
Rate of compensation increase | 4.0% | 4.0% | 4.0% | 4.0% | 4.0% | 4.0% |
As of December 31, 2002, the company decreased its discount rate from 7.0% to 6.5% and its expected return on plan assets from 9.0% to 8.75% effective January 1, 2003.
The company assumed a 10% annual rate of increase in the costs of covered health care benefits for 2003 that gradually decreases to 5% by the year 2006.
| Pension Benefits | Postretirement Benefits | ||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |
(Thousands) | ||||||
Components of net periodic benefit cost | ||||||
Service cost | $29,318 | $23,967 | $20,979 | $6,040 | $5,091 | $7,031 |
Interest cost | 111,943 | 90,949 | 70,486 | 32,215 | 25,024 | 24,213 |
Expected return |
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Special termination benefits | 64,909 | 2,551 | - | - | - | - |
Deferral for future recovery | (32,086) | - | - | - | - | (5,395) |
Net periodic benefit cost | $(52,346) | $(85,430) | $(77,942) | $39,274 | $24,988 | $30,786 |
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 the company charged to expense for providing health care benefits to retirees and their eligible dependents. The amount of postretirement benefit cost deferred was $88 million as of December 31, 2002, and $68 million as of December 31, 2001. The company expects to recover any deferred postretirement costs by 2012. The transition obligation for postretirement benefits is being amortized over a period of 20 years.
A 1% increase or decrease in the health care cost inflation rate from assumed rates would have the following effects:
1% Increase | 1% Decrease | |
Effect on total of service and interest cost components | $2 million | $(2 million) |
Effect on postretirement benefit obligation | $33 million | $(28 million) |
Notes to Consolidated Financial Statements
Energy East Corporation
Note 16. Segment Information
Selected financial information for the company's business segments is presented in the table below. The company's electric delivery segment consists of its regulated transmission, distribution and generation operations in New York and Maine and its natural gas delivery segment consists of its regulated transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts. Other includes: the company's corporate assets, interest income, interest expense and operating expenses; intersegment eliminations; and nonutility businesses.
Electric | Natural Gas |
|
| |
(Thousands) | ||||
2002 | ||||
Operating Revenues | $2,568,247 | $1,032,539 | $408,132 | $4,008,918 |
Depreciation and Amortization | $162,515 | $71,329 | $13,152 | $246,996 |
Operating Income | $449,029 | $149,656 | $(6,509) | $592,176 |
Interest Charges, Net | $183,716 | $73,177 | $854 | $257,747 |
Income Taxes | $94,238 | $26,557 | $(22,271) | $98,524 |
Net Income | $170,337 | $51,128 | $(32,862) | $188,603 |
Total Assets | $6,035,461 | $3,058,885 | $1,175,533 | $10,269,879 |
Capital Spending | $137,414 | $86,301 | $5,672 | $229,387 |
2001 | ||||
Operating Revenues | $2,504,896 | $1,026,124 | $228,767 | $3,759,787 |
Depreciation and Amortization | $118,882 | $75,432 | $9,967 | $204,281 |
Operating Income | $553,421 | $89,518 | $(6,051) | $636,888 |
Interest Charges, Net | $154,011 | $55,785 | $7,232 | $217,028 |
Income Taxes | $178,125 | $18,144 | $(41,890) | $154,379 |
Net Income | $228,782 | $17,938 | $(59,113) | $187,607 |
Total Assets | $4,175,280 | $2,467,647 | $626,305 | $7,269,232 |
Capital Spending | $95,627 | $106,116 | $21,132 | $222,875 |
2000 | ||||
Operating Revenues | $2,023,610 | $772,131 | $163,779 | $2,959,520 |
Depreciation and Amortization | $105,067 | $49,769 | $10,688 | $165,524 |
Operating Income | $482,657 | $72,729 | $(41,465) | $513,921 |
Interest Charges, Net | $105,826 | $41,229 | $5,448 | $152,503 |
Income Taxes | $146,529 | $12,182 | $(3,150) | $155,561 |
Net Income | $228,971 | $15,632 | $(9,569) | $235,034 |
Total Assets | $4,212,623 | $2,406,848 | $394,257 | $7,013,728 |
Capital Spending | $70,651 | $68,170 | $29,499 | $168,320 |
Notes to Consolidated Financial Statements
Energy East Corporation
Note 17. Quarterly Financial Information (Unaudited)
Quarter Ended | March 31 | June 30 | September 30 | December 31 | ||||
(Thousands, except per share amounts) | ||||||||
| ||||||||
Operating Revenues | $1,028,578 | $714,874 | $1,016,189 | $1,249,277 | ||||
Operating Income | $238,869 | $81,476 | $113,500 | $158,331 | ||||
Net Income | $105,570 | (1) | $5,323 | (1) | $23,742 | $53,968 | (2) | |
Earnings Per Share, |
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Dividends Per Share | $.24 | $.24 | $.24 | $.24 | ||||
Average Common |
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Common Stock Price(3) |
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Operating Revenues | $1,271,139 | $849,010 | $798,848 | $840,790 | ||||
Operating Income | $262,528 | $90,161 | $94,567 | $189,632 | ||||
Net Income (Loss) | $115,601 | $26,574 | $(21,057) | (1) | $66,489 | |||
Earnings (Loss) Per Share, |
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Dividends Per Share | $.23 | $.23 | $.23 | $.23 | ||||
Average Common |
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Common Stock Price(3) |
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(1)Includes the effect of writedowns of CMP Group's investment in NEON Communications, Inc. that decreased net income and earnings per share as follows: $6 million and five cents in the first quarter of 2002, $1 million and one cent in the second quarter of 2002 and $46 million and 39 cents in the third quarter of 2001.
(2)Includes the effect of restructuring expenses recorded in the fourth quarter of 2002 that decreased net income $24 million and earnings per share 17 cents.
(3)The company's common stock is listed on the New York Stock Exchange. The number of shareholders of record was 39,620 at December 31, 2002.
Report of Independent Accountants
To the Shareholders and Board of Directors,
Energy East Corporation and Subsidiaries
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 154 present fairly, in all material respects, the financial position of Energy East Corporation and its subsidiaries ("the Company") at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing in Item 15(a)(2) on page 154 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 1 and 14 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative and hedging activities pursuant to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133). In addition, as discussed in Notes 1 and 4 to the consolidated financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
PricewaterhouseCoopers LLP
New York, New York
January 31, 2003
ENERGY EAST CORPORATION
SCHEDULE II - Consolidated Valuation and Qualifying Accounts
Years Ended December 31, 2002, 2001 and 2000
| Beginning |
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(Thousands) | ||||||||
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Allowance for Doubtful |
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Nuclear Refueling |
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Allowance for Doubtful |
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Allowance for Doubtful |
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Deferred Tax Asset |
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(a) Uncollectible accounts charged against the allowance, net of recoveries.
(b) Includes $30,750 due to the merger with RGS Energy.
(c) Due to the merger with RGS Energy. RG&E recognizes estimated nonfuel expenses for refueling outages at its Ginna nuclear power plant over the period between refueling outages.
(d) Includes $6,300 which represents an estimate for NYSEG of the write-offs that will not be recovered in rates.
(e) Includes $11,520 due to the mergers with CNE, CMP Group, CTG Resources and Berkshire Energy, and $(259) due to the sale of XENERGY, Inc.
(f) Due to the sale of XENERGY, Inc.
Selected Financial Data
Central Maine Power Company
Predecessor | ||||||
|
| From | To |
|
| |
(Thousands) | ||||||
Operating Revenues | $653,521 | $815,050 | $277,518 | $613,475 | $954,463 | $941,530 |
Depreciation and amortization | $38,793 | $36,537 | $13,830 | $23,661 | $49,517 | $56,257 |
Other taxes | $24,172 | $20,925 | $6,621 | $12,961 | $22,291 | $27,747 |
Interest Charges, Net | $28,584 | $27,338 | $8,506 | $31,072 | $53,175 | $51,014 |
Net Income | $54,933 | $54,440 | $23,651 | $29,878 | $68,740 | $54,823 |
Capital Spending | $37,985 | $46,273 | $23,031 | $56,026 | $65,097 | $42,384 |
Total Assets | $1,786,323 | $1,865,800 | $1,928,797 | - | $1,946,757 | $2,223,480 |
Long-term Obligations, |
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Management's discussion and analysis of financial condition and results of operations
Central Maine Power Company
Liquidity and Capital Resources
Restructuring
See Energy East's Item 7, Restructuring, for this discussion.
Electric Delivery Business
CMP's electric delivery business consists of its regulated electricity transmission and distribution operations.
Regional Transmission Organization: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Transmission Planning and Expansion: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Electric Transmission Rates: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Sale of Nuclear Interests: See Energy East's Item 7, Electric Delivery Business, for the discussion of the sale of Vermont Yankee.
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.
Management's discussion and analysis of financial condition and results of operations
Central Maine Power Company
MPUC Stranded Cost Proceeding: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Nonutility Generation: CMP expensed approximately $211 million for NUG power in 2002. It estimates that its NUG purchases will total $216 million in 2003, $215 million in 2004, $219 million in 2005, $166 million in 2006 and $154 million in 2007. CMP continues to seek ways to provide relief to its customers from above-market NUG contracts that state regulations ordered it to sign, and which, in 2002, averaged 8.7 cents per kilowatt-hour. Recovery of these NUG costs is provided for in CMP's current regulatory plans. (See Item 8 - Note 8 to CMP's Consolidated Financial Statements.)
Other Matters
Accounting Issues
Statement 71: See Energy East's Item 7, Other Matters, Statement 71, for this discussion.
Statement 145: See Energy East's Item 7, Other Matters, Statement 145, for this discussion.
Contractual Obligations and Commercial Commitments
At December 31, 2002, CMP's contractual obligations and commercial commitments that will become due during the next five years are:
2003 | 2004 | 2005 | 2006 | 2007 | |
(Thousands) | |||||
Contractual Obligations | |||||
Long-term debt | $51,182 | $11,112 | $21,183 | $41,183 | $16,183 |
Capital lease obligations | 1,793 | 1,807 | 1,823 | 1,564 | 1,355 |
Operating leases | 3,425 | 3,386 | 3,246 | 3,202 | 3,202 |
Nonutility generator purchase |
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Nuclear plant obligations | 30,094 | 41,251 | 42,135 | 36,278 | 32,861 |
Other long-term obligations | 7,096 | 6,560 | 7,084 | 5,231 | 4,321 |
Total contractual cash obligations | $309,365 | $278,976 | $294,744 | $253,174 | $211,608 |
Other Commercial Commitments | |||||
Lines of credit | $75,000 | $75,000 | $75,000 | - | - |
Total commercial commitments | $75,000 | $75,000 | $75,000 | - | - |
CMP has a revolving credit facility, which is secured by its accounts receivable, in which it covenants that (i) its consolidated total debt shall at all times be no more than 65% of the sum of its consolidated total debt and its total stockholders equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00. Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2002, CMP's consolidated total debt ratio was 33.6% and its interest coverage ratio was 3.73 to 1.00.
Management's discussion and analysis of financial condition and results of operations
Central Maine Power Company
Critical Accounting Policies
See Energy East's Item 7, Critical Accounting Policies for the discussion of Goodwill and Other Intangible Assets, Pension and Other Postretirement Benefit Plans and Utility Regulation.
Investing and Financing Activities
Investing Activities: Capital spending totaled $38 million in 2002, $46 million in 2001 and $79 million in 2000 (including $23 million from acquisition and $56 million to acquisition), including nuclear fuel. Capital spending in all three years was financed with internally generated funds and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements and governmental mandates.
Capital spending is projected to be $42 million in 2003. It is expected to be paid for with internally generated funds and will be primarily for the same purposes described above and merger integration. (See Item 8 - Note 8 to CMP's Consolidated Financial Statements.)
CMP's pension plans generated pretax noncash pension expense (net of amounts capitalized) of $2 million in 2002, compared to less than $1 million in 2001 and $1 million of pretax noncash pension income (net of amounts capitalized) in 2000. CMP expects noncash pension expense (net of amounts capitalized) for 2003 to increase, affecting earnings by approximately $2 million. The increase is due to the significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute its pension liability (reduced from 7% to 6.5% as of December 31, 2002) and return on assets (reduced from 9% to 8.75% effective January 1, 2003). CMP estimates funding requirements of $5 million to $10 million in 2003 as total plan assets are less than the projected benefit obligation. CMP is currently unable to predict the effect that future equity market performance will have on pension income for 2004 and beyond. (See Item 8 - Note 13 to CMP's Consolidated Financi al Statements.)
Financing Activities: In January 2002 CMP cancelled its shares of treasury stock, which had a carrying value of $19 million, and restored the shares to the status of authorized but unissued shares of common stock of the corporation.
CMP issued the following Series E Medium Term Notes, the proceeds of which were used to repay $50 million of maturing medium-term notes, as well as short-term debt and for general corporate purposes in 2002: in May 2002 - $37.5 million, 6.50%, due May 2009 and $37.5 million, 6.65%, due May 2012; in August 2002 - $15 million, 5.70%, due August 2012; in September 2002 - $15 million, 4.25%, due September 2007; and in November 2002 - $15 million, quarterly adjustable rate based on the three month LIBOR plus 0.6%, due January 2006.
CMP has a three-year 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 provide initial financing for construction and for other corporate purposes. There was no such short-term debt outstanding at December 31, 2002, and $47 million outstanding at December 31, 2001. The weighted-average interest rate on short-term debt was 2.5% at December 31, 2001.
Management's discussion and analysis of financial condition and results of operations
Central Maine Power Company
Results of Operations
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| 2002 | 2001 | |
(Thousands) | |||||
Deliveries - Megawatt-hours |
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Operating Revenues | $653,521 | $815,050 | $890,993 | (20%) | (9%) |
Operating Expenses | $549,974 | $701,306 | $794,926 | (22%) | (12%) |
Operating Income | $103,547 | $113,744 | $96,067 | (9%) | 18% |
Earnings Available for |
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Earnings for 2002 increased less than $1 million primarily due to the elimination of goodwill amortization in 2002 of $9 million, offset by a restructuring charge of $3 million and the cessation of amortization for the voluntary earnings credit of $6 million.
Earnings for 2001 increased $2 million, primarily due to cost control efforts.
Operating Revenues: The $161 million decrease in operating revenues for 2002 is primarily because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002, which reduced revenues $138 million.
Operating revenues decreased $76 million in 2001 primarily because CMP no longer collects revenue for the supply of electricity to certain retail customers, a reduction of $103 million. Those decreases were partially offset by higher revenues of $21 million, primarily transmission, and amortization of deferred gains of $21 million.
Operating Expenses: Operating expenses for 2002 decreased $151 million primarily due to a decrease in electricity purchased of $162 million, including $138 million because CMP is no longer the standard-offer provider for the supply of electricity effective March 2002. Operating expenses also decreased $9 million due to the elimination of goodwill amortization in 2002. Those decreases were partially offset by an increase of $5 million due to restructuring expenses, a $3 million increase in other taxes primarily due to an MPUC conservation assessment and the cessation of amortization for the voluntary earnings credit of $11 million.
Operating expenses for 2001 decreased $94 million primarily due to lower electricity supply costs of $69 million because CMP no longer supplies electricity unless directed to by the MPUC, and $26 million due to cost control efforts relating to compensation and fees.
Other Items
Other operating expenses includes net periodic pension benefit cost of $2 million in 2002 and less than $1 million in 2001, and $1 million of net periodic pension benefit income in 2000. Other operating expenses would have been $2 million lower for 2002 without the change in net periodic pension benefit cost.
Central Maine Power Company
Consolidated Balance Sheets
December 31 | 2002 | 2001 |
(Thousands) | ||
Assets | ||
Current Assets | ||
Cash and cash equivalents | $20,415 | $20,777 |
Accounts receivable, net | 124,711 | 123,615 |
Materials and supplies, at average cost | 7,096 | 9,018 |
Accumulated deferred income tax benefits, net | 1,902 | 74 |
Prepayments and other current assets | 6,411 | 10,439 |
Total Current Assets | 160,535 | 163,923 |
Utility Plant, at Original Cost | ||
Electric | 1,316,023 | 1,312,778 |
Less accumulated depreciation | 499,381 | 488,159 |
Net Utility Plant in Service | 816,642 | 824,619 |
Construction work in progress | 2,952 | 5,546 |
Total Utility Plant | 819,594 | 830,165 |
Other Property | 5,880 | 5,988 |
Investment in Associated Companies, at Equity | 27,137 | 29,868 |
Regulatory and Other Assets | ||
Regulatory assets | ||
Nuclear plant obligations | 211,268 | 199,797 |
Unfunded future income taxes | 101,791 | 90,471 |
Unamortized loss on debt reacquisitions | 9,722 | 11,006 |
Demand-side management program costs | 8,394 | 14,054 |
Environmental remediation costs | 4,440 | 6,075 |
Nonutility generator termination agreement | 7,195 | 7,619 |
Other | 58,259 | 132,368 |
Total regulatory assets | 401,069 | 461,390 |
Other assets | ||
Goodwill, net | 325,580 | 325,174 |
Prepaid pension benefits | 23,124 | 29,886 |
Other | 23,404 | 19,406 |
Total other assets | 372,108 | 374,466 |
Total Regulatory and Other Assets | 773,177 | 835,856 |
Total Assets | $1,786,323 | $1,865,800 |
The notes on pages 81 through 93 are an integral part of the financial statements.
Central Maine Power Company
Consolidated Balance Sheets
December 31 | 2002 | 2001 |
(Thousands) | ||
Liabilities | ||
Current Liabilities | ||
Current portion of long-term debt | $52,975 | $52,959 |
Notes payable | - | 46,500 |
Accounts payable and accrued liabilities | 45,551 | 64,104 |
Interest accrued | 6,056 | 5,181 |
Other | 54,693 | 40,206 |
Total Current Liabilities | 159,275 | 208,950 |
Regulatory and Other Liabilities | ||
Regulatory liabilities | ||
Deferred income taxes | 112,119 | 92,630 |
Gain on sale of generation assets | 112,009 | 190,779 |
Pension benefits | - | 7,355 |
Other | 11,926 | 21,840 |
Total regulatory liabilities | 236,054 | 312,604 |
Other liabilities | ||
Deferred income taxes | 4,605 | 17,385 |
Nuclear plant obligations | 211,268 | 199,797 |
Other postretirement benefits | 71,236 | 66,801 |
Environmental remediation costs | 2,987 | 2,790 |
Other | 127,986 | 119,575 |
Total other liabilities | 418,082 | 406,348 |
Total Regulatory and Other Liabilities | 654,136 | 718,952 |
Long-term debt | 291,796 | 235,133 |
Total Liabilities | 1,105,207 | 1,163,035 |
Commitments | - | - |
Preferred Stock |
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|
Capital in excess of par value | (2,723) | (3,316) |
Common Stock Equity |
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Capital in excess of par value | 485,297 | 498,141 |
Retained earnings | 31,682 | 31,304 |
Accumulated other comprehensive (loss) | (24,768) | (2,148) |
Treasury stock, at cost (1,231 shares at December 31, 2001) | - | (19,000) |
Total Common Stock Equity | 648,268 | 670,510 |
Total Liabilities and Stockholder's Equity | $1,786,323 | $1,865,800 |
The notes on pages 81 through 93 are an integral part of the financial statements.
Central Maine Power Company
Consolidated Statements of Income
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| Predecessor |
(Thousands) | ||||
Operating Revenues | ||||
Sales and services | $653,521 | $815,050 | $277,518 | $613,475 |
Operating Expenses | ||||
Electricity purchased and fuel used |
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Other operating expenses | 180,038 | 173,553 | 60,882 | 151,245 |
Maintenance | 37,151 | 40,007 | 14,273 | 24,468 |
Depreciation and amortization | 38,793 | 36,537 | 13,830 | 23,661 |
Other taxes | 24,172 | 20,925 | 6,621 | 12,961 |
Restructuring expenses | 5,495 | - | - | - |
Total Operating Expenses | 549,974 | 701,306 | 231,479 | 563,447 |
Operating Income | 103,547 | 113,744 | 46,039 | 50,028 |
Other (Income) | (5,041) | (6,745) | (3,329) | (15,235) |
Other Deductions | 2,035 | 3,450 | 439 | 2,423 |
Interest Charges, Net | 28,584 | 27,338 | 8,506 | 31,072 |
Recovery of Non-Provided Deferred |
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Gain on Sale of Investments and |
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Income Before Income Taxes | 77,969 | 89,701 | 41,703 | 107,412 |
Income Taxes | 23,036 | 35,261 | 18,052 | 77,534 |
Net Income | 54,933 | 54,440 | 23,651 | 29,878 |
Preferred Stock Dividends | 1,442 | 1,442 | 547 | 1,490 |
Earnings Available for Common Stock | $53,491 | $52,998 | $23,104 | $28,388 |
The notes on pages 81 through 93 are an integral part of the financial statements.
Central Maine Power Company
Consolidated Statements of Cash Flows
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| Predecessor |
(Thousands) | ||||
Operating Activities | ||||
Net income | $54,933 | $54,440 | $23,651 | $29,878 |
Adjustments to reconcile net income to net cash | ||||
Depreciation and amortization | 25,857 | 20,783 | 15,042 | 29,645 |
Income taxes and investment tax |
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Restructuring expenses | 5,495 | - | - | - |
Pension expense (income) | 2,467 | 54 | (1,404) | - |
Changes in current operating assets | ||||
Accounts receivable, net | 1,154 | 15,721 | (21,140) | 29,067 |
Inventory | 1,921 | 34 | 648 | 405 |
Prepayments and other current assets | 4,028 | (827) | 8,962 | (11,102) |
Accounts payable and accrued liabilities | (18,553) | (10,319) | (8,042) | (17,612) |
Interest accrued | 874 | 97 | 1,493 | 912 |
Taxes accrued | 6,118 | - | - | - |
Other current liabilities | 11,303 | (13,798) | (4,773) | 19,735 |
Asset sale settlement costs | - | (12,000) | - | - |
Deferred NUG costs | - | (17,871) | - | - |
Other assets | (12,942) | 4,795 | (12,462) | (8,088) |
Other liabilities | (11,307) | (4,298) | 5,153 | 9,412 |
Net Cash Provided by Operating Activities | 79,961 | 60,157 | 14,743 | 72,448 |
Investing Activities | ||||
Utility plant additions | (38,054) | (46,279) | (23,104) | (56,181) |
Contributions in aid of construction, net | - | (19,130) | (5,274) | 36,246 |
Other | 69 | 6 | 73 | 155 |
Net Cash Used in Investing Activities | (37,985) | (65,403) | (28,305) | (19,780) |
Financing Activities | ||||
Repayments of preferred stock and first |
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Long-term note issuances | 120,000 | 75,000 | - | 125,000 |
Long-term note repayments | (61,283) | (20,483) | (8,994) | (60,788) |
Notes payable three months or less, net | (23,000) | (23,500) | 46,500 | - |
Notes payable issuances | (28,500) | - | - | - |
Notes payable repayments | 5,000 | 23,500 | - | - |
Dividends on common and preferred stock | (54,555) | (46,427) | (190,361) | (35,492) |
Net Cash (Used in) Provided by |
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Net (Decrease) Increase in Cash and |
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Cash and Cash Equivalents, Beginning of Year | 20,777 | 17,933 | 194,260 | 112,872 |
Cash and Cash Equivalents, End of Year | $20,415 | $20,777 | $17,933 | $194,260 |
The notes on pages 81 through 93 are an integral part of the financial statements.
Central Maine Power Company
Consolidated Statements of Changes in Common Stock Equity
| Common Stock |
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| Accumulated |
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| |
Balance, January 1, 2000 | 31,211 | $162,213 | $280,450 | $100,754 | - | $(19,000) | $524,417 |
Net income | 53,529 | 53,529 | |||||
Dividends declared | |||||||
Preferred stock | (2,037) | (2,037) | |||||
Common stock | (33,708) | (33,708) | |||||
Liquidating Dividend | (190,000) | (190,000) | |||||
Merger transaction, net | 410,447 | (95,076) | 315,371 | ||||
Amortization of capital stock issue expense | (171) | (171) | |||||
Balance, December 31, 2000 | 31,211 | 162,213 | 500,897 | 23,291 | - | (19,000) | 667,401 |
Net income | 54,440 | 54,440 | |||||
Other comprehensive income, net of tax | $(2,148) | (2,148) | |||||
Comprehensive income | 52,292 | ||||||
Dividends declared | |||||||
Preferred stock | (1,442) | (1,442) | |||||
Common stock | (44,985) | (44,985) | |||||
Merger transaction, net | (2,756) | (2,756) | |||||
Balance, December 31, 2001 | 31,211 | 162,213 | 498,141 | 31,304 | (2,148) | (19,000) | 670,510 |
Net income | 54,933 | 54,933 | |||||
Other comprehensive income, net of tax | (22,620) | (22,620) | |||||
Comprehensive income | 32,313 | ||||||
Dividends declared | |||||||
Preferred stock | (1,442) | (1,442) | |||||
Common stock | (53,113) | (53,113) | |||||
Cancellation of treasury stock | (6,156) | (12,844) | 19,000 | - | |||
Balance, December 31, 2002 | 31,211 | $156,057 | $485,297 | $31,682 | $(24,768) | - | $648,268 |
The notes on pages 81 through 93 are an integral part of the financial statements.
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 1. Significant Accounting Policies
Background: Central Maine Power Company (CMP) is primarily engaged in the transmission and distribution of electricity generated by others to retail customers in Maine. CMP is the principal operating utility of CMP Group, Inc. Effective September 1, 2000, CMP Group became a wholly-owned subsidiary of Energy East Corporation. The acquisition was accounted for under the purchase method of accounting and adjustments were included in CMP's financial statements under the push down method of accounting.
Accounts receivable:Accounts receivable include unbilled revenues of $33 million at December 31, 2002, and $32 million at December 31, 2001, and are shown net of an allowance for doubtful accounts of $2 million at December 31, 2002, and $3 million at December 31, 2001. Bad debt expense was $3 million in 2002 and 2001 and $5 million in 2000 (including $2 million from acquisition and $3 million to acquisition).
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. Those investments are included in cash and cash equivalents on the consolidated balance sheets.
|
|
|
| Predecessor |
(Thousands) | ||||
Cash paid during the year ended December 31: | ||||
Interest, net of amounts capitalized | $24,213 | $23,813 | $6,082 | $10,322 |
Income taxes, net of benefits received | $1,739 | $4,228 | $183 | $24,553 |
Depreciation and amortization: CMP determines depreciation expense using the straight-line method. The average service lives of certain classifications of property are: transmission property - 40 years, distribution property - 38 years and other property - 25 years. CMP's depreciation accruals were equivalent to 2.9% of average depreciable property for 2002 and 2001 and 2.8% for 2000.
Estimates: Preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Goodwill:The excess of the cost over fair value of net assets and as a result of push down accounting is recorded as goodwill and was amortized on a straight-line basis over 40 years until December 31, 2001. Beginning in 2002 CMP evaluates the carrying value of goodwill for impairment at least annually and on an interim basis if there are indications that goodwill might be impaired. Any impairments would be recognized when the fair value of goodwill is less than its carrying value. (See Note 3.)
Notes to Consolidated Financial Statements
Central Maine Power Company
Income taxes: Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.
CMP computes its income tax provision on a separate return method. SEC regulations require that no Energy East subsidiary pay more income taxes than it would have paid if a separate income tax return had been filed. The determination and allocation of CMP's income tax provision and its components are outlined and agreed to in the tax sharing agreement with Energy East.
Other (Income) and Other Deductions:
|
|
|
| Predecessor |
(Thousands) | ||||
Interest income | $(1,057) | $(1,252) | $(1,308) | $(6,533) |
Noncash return | (1,201) | (1,612) | (304) | (4,788) |
Gains from the sale of nonutility property | (117) | (1,294) | (117) | (376) |
Earnings from equity investments | (2,778) | (2,497) | (1,532) | (2,816) |
Miscellaneous | 112 | (90) | (68) | (722) |
Total other (income) | $(5,041) | $(6,745) | $(3,329) | $(15,235) |
Miscellaneous | $2,035 | $3,450 | $439 | $2,423 |
Total other deductions | $2,035 | $3,450 | $439 | $2,423 |
Principles of consolidation: CMP's financial statements consolidate its majority-owned subsidiaries after eliminating intercompany transactions.
Reclassifications: Certain amounts have been reclassified on the consolidated financial statements to conform with the 2002 presentation.
Regulatory assets and liabilities: Pursuant to Statement 71, CMP capitalizes, as regulatory assets, incurred 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. Approximately $300 million of the regulatory liability resulting from CMP's sale of non-nuclear assets was used to offset regulatory assets in March 2000.
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.
Notes to Consolidated Financial Statements
Central Maine Power Company
Revenue recognition: CMP recognizes revenues upon delivery of energy and energy-related products and services to its customers.
Pursuant to Maine Law, since March 1, 2000, CMP has been prohibited from selling power to its retail customers. CMP does not enter into any purchase and sales arrangements for power with the ISO New England, the New England Power Pool, or any other independent system operator or similar entity. All of CMP's power entitlements in its NUG and other purchase power contracts are sold to unrelated third parties under bilateral contracts for the period March 1, 2002, through February 28, 2005.
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 and the cost of removal less salvage are charged to accumulated depreciation.
Note 2. Restructuring
In the fourth quarter of 2002 Energy East recorded $41 million of restructuring expenses, 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 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.
Those programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by April 30, 2003, including approximately 70 from CMP. The employees affected by the involuntary severance program were notified in January 2003.
Note 3. Goodwill and Other Intangible Assets
Effective January 1, 2002, CMP adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As required by Statement 142 CMP no longer amortizes goodwill and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized (amortized intangible assets) and are reviewed for impairment.
CMP determined that there was no impairment of goodwill as of January 1, 2002. There was no reclassification of goodwill to intangible assets and no reclassification of intangible assets to goodwill as of January 1, 2002. Annual impairment testing was also completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for CMP at September 30, 2002.
The carrying amount of goodwill on CMP's balance sheets was $326 million as of December 31, 2002 and $325 million as of December 31, 2001, and is included in CMP's electric delivery operating segment. The increase was due to tax adjustments.
Notes to Consolidated Financial Statements
Central Maine Power Company
Other Intangible Assets: CMP's unamortized intangible assets consist of pension assets and had a carrying amount of $2 million at December 31, 2002, and $3 million at December 31, 2001. CMP's amortized intangible assets primarily consist of technology rights, and had a gross carrying amount and accumulated amortization of less than $0.3 million at December 31, 2002 and 2001. Estimated amortization expense for intangible assets is $9 thousand for each of the next five years, 2003 through 2007.
Transitional Information: Results of operations information for CMP as though goodwill had been accounted for under Statement 142 for all years presented is:
|
|
|
| Predecessor |
(Thousands) | ||||
Reported net income | $54,933 | $54,440 | $23,651 | $29,878 |
Add back: Goodwill amortization | - | 8,575 | 2,949 | - |
Adjusted net income | $54,933 | $63,015 | $26,600 | $29,878 |
Note 4. Income Taxes
|
|
|
| Predecessor |
(Thousands) | ||||
Current | $14,450 | $8,749 | $10,437 | $12,278 |
Deferred, net |
|
|
|
|
Pension benefits | 180 | 1,475 | 9 | (479) |
Asset sale gain | - | - | - | 75,060 |
Miscellaneous | 7,170 | 25,959 | 5,836 | (7,009) |
ITC | (715) | (715) | (237) | (3,875) |
Total | $23,036 | $35,261 | $18,052 | $77,534 |
CMP's effective tax rate differed from the statutory rate of 35% due to the following:
|
|
|
| Predecessor |
(Thousands) | ||||
Tax expense at statutory rate | $27,289 | $31,396 | $14,596 | $37,594 |
Depreciation and amortization not normalized | (446) | 287 | 496 | (594) |
ITC amortization | (715) | (715) | (237) | (3,875) |
State taxes, net of federal benefit | 3,169 | 5,286 | 2,421 | 6,234 |
Other, net | (6,261) | (993) | 776 | 38,175* |
Total | $23,036 | $35,261 | $18,052 | $77,534 |
* Reflects effect of MPUC rate case settlement.
Notes to Consolidated Financial Statements
Central Maine Power Company
CMP's deferred tax assets and liabilities consisted of the following:
December 31 | 2002 | 2001 |
(Thousands) | ||
Current Deferred Tax Assets | $1,902 | $74 |
Noncurrent Deferred Tax Liabilities | ||
Depreciation | $170,512 | $161,765 |
Unfunded future income taxes | (44,745) | 36,916 |
Accumulated deferred ITC | 41,535 | 9,099 |
Deferred gain on generation plant sale | 8,384 | (78,403) |
Other | (58,962) | (19,362) |
Total Noncurrent Deferred Tax Liabilities | 116,724 | 110,015 |
Less amounts classified as regulatory liabilities | ||
Deferred income taxes | 112,119 | 92,630 |
Noncurrent Deferred Income Taxes | $4,605 | $17,385 |
CMP has no federal or state tax credit or loss carryforwards, nor does it have any valuation allowances.
Note 5. Long-term Debt
At December 31, 2002 and 2001, CMP's consolidated long-term debt was:
Amount | ||||
Maturity Dates | Interest Rates | 2002 | 2001 | |
(Thousands) | ||||
Pollution control notes | 2014 | 5 3/8% | $19,500 | $19,500 |
Various medium-term notes | 2003 to 2025 | 2.00% to 8.13% | 270,000 | 200,000 |
Various long-term debt | 2005 to 2020 | 7.05% to 10.48% | 31,034 | 42,317 |
Obligations under capital leases | 25,666 | 27,563 | ||
Unamortized discount on debt | (1,429) | (1,288) | ||
344,771 | 288,092 | |||
Less debt due within one year - included in current liabilities | 52,975 | 52,959 | ||
Total | $291,796 | $235,133 | ||
At December 31, 2002, long-term debt, including sinking fund obligations, and capital lease payments (in thousands) that will become due during the next five years are:
2003 | 2004 | 2005 | 2006 | 2007 | ||||
$52,975 | $12,919 | $23,006 | $42,747 | $17,538 |
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.
Cross-default Provisions: In the event of a cross-default of other long-term debt obligations of CMP, The Finance Authority of Maine, under a Loan Agreement, may declare an amount equal to the unpaid principal amount, currently less than $10 million, and interest accrued immediately due and payable.
Notes to Consolidated Financial Statements
Central Maine Power Company
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 or base-rate-priced loans. The arrangement provides for payment of fees including: at December 31, 2002, 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; and at December 31, 2001, a facility fee of 0.125% per annum and a utilization fee of 0.1% per annum for each day the outstanding balance exceeded 25% of the total facility.
CMP uses short-term borrowings and drawings on its credit facility (see above) to provide initial financing for construction and for other corporate purposes. There was no such short-term debt outstanding at December 31, 2002, and $47 million outstanding at December 31, 2001. The weighted-average interest rate on short-term debt was 2.5% at December 31, 2001.
In its revolving credit facility, which is secured by it 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 stockholders equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00. Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2002, CMP's consolidated total debt ratio was 33.6% and its interest coverage ratio was 3.73 to 1.00.
Note 7. Preferred Stock
At December 31, 2002 and 2001, CMP's cumulative preferred stock was:
| Par |
| Shares |
| |
6% Noncallable(2) | $100 | - | 5,713 | $571 | $571 |
3.50% | 100 | $101.00 | 220,000 | 22,000 | 22,000 |
4.60% | 100 | 101.00 | 30,000 | 3,000 | 3,000 |
4.75% | 100 | 101.00 | 50,000 | 5,000 | 5,000 |
5.25% | 100 | 102.00 | 50,000 | 5,000 | 5,000 |
Total | $35,571 | $35,571 | |||
(1) At December 31, 2002, 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's redemptions during the three years 2000 through 2002: On October 1, 2000, CMP redeemed, at par, $9.9 million of 7.999% Flexible Money Market Preferred Stock Series A.
Notes to Consolidated Financial Statements
Central Maine Power Company
Voting rights of preferred shares: 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 $42 million in 2003 and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. CMP's capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.
Nonutility generator power purchase contracts: CMP expensed approximately $211 million for NUG power in 2002, $225 million in 2001 and $243 million in 2000 (including $81 million from acquisition and $162 million to acquisition). CMP estimates that NUG power purchases will total $216 million in 2003, $215 million in 2004, $219 million in 2005, $166 million in 2006 and $154 million in 2007.
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 9. Jointly-Owned Generation Assets and Nuclear Generation Insurance and Decommissioning
CMP has ownership interests in three nuclear generating facilities in New England, which are accounted for under the equity method. All three facilities have permanently ceased operations, and are in the process of being decommissioned.
| Maine | Yankee | Connecticut |
Ownership Share | 38% | 9.5% | 6% |
Operating Status | Permanently | Permanently | Permanently |
Location | Wiscasset, | Rowe, | Haddam, |
2002 Energy, Capacity, Decommissioning and Other Costs |
|
|
|
Capacity Share | N/A | N/A | N/A |
Equity Interest at December 31, 2002 | $21.5 | - | $3.4 |
Maine Yankee: In August 1997 the Board of Directors of Maine Yankee Atomic Power Company voted to permanently shut down and decommission the Maine Yankee plant. The plant had experienced a number of operational and regulatory problems and did not operate after December 6, 1996. The decision to close the plant was based on an economic analysis of the costs, risks and uncertainties associated with operating the plant compared to those associated with closing and decommissioning it.
Yankee Atomic: In 1993 the FERC approved a settlement agreement regarding recovery of decommissioning costs and plant investment, and all issues with respect to the prudence of the owners decision to discontinue operation of the Yankee Atomic plant.
Connecticut Yankee: In December 1996 the Board of Directors of Connecticut Yankee Atomic Power Company voted to permanently shut down and decommission the Connecticut Yankee plant for economic reasons. The plant did not operate after July 22, 1996.
Vermont Yankee: On July 31, 2002, Vermont Yankee Nuclear Power Corporation sold the Vermont Yankee nuclear power plant, including CMP's 4% ownership interest, to Entergy Corporation. Any benefits realized from the sale, which are expected to be less than $1 million, will be used to reduce CMP customers' future obligations for stranded costs. The transaction included a power purchase agreement that calls for Entergy to provide all of the plant's electricity to the sellers through 2012, the year the operating license for the plant expires.
Notes to Consolidated Financial Statements
Central Maine Power Company
Operating expenses: CMP is obligated to pay its proportionate share of the operating expenses, including depreciation, operation and maintenance expenses, and a return on invested capital, for each of the Yankee Companies referred to above. CMP is also required to pay its share of the estimated decommissioning costs of each of the Yankee Companies, which are included in CMP's stranded costs for purposes of rate recovery.
Nuclear insurance: CMP is exempt from the provisions of the Price-Anderson Act because it no longer has an interest in a nuclear generating plant that is operating. As required by the NRC, CMP carries nuclear property damage insurance, which is obtained through Nuclear Electric Insurance Limited, for its interests in nonoperating nuclear generating plants.
Nuclear plant decommissioning costs: CMP's estimated liability, in 2003 dollars, for decommissioning its various interests in nuclear plants is $387 million, which was updated in 2002 to include spent fuel storage and increases in projected costs. The amount currently billed for those costs is recovered by CMP through its electric rates.
Note 10. Environmental Liability
From time to time environmental laws, regulations and compliance programs may require changes in CMP's operations and facilities and may increase the cost of electric service.
The U.S. Environmental Protection Agency and various state environmental agencies, as appropriate, notified CMP that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at five waste sites. The five sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the five sites, four sites are included in Maine's Uncontrolled Sites Program, one is included on the Massachusetts Non-Priority Confirmed Disposal Site list and two of the sites are also included on the National Priorities list.
Any liability may be joint and several for certain of those sites. CMP has recorded an estimated liability of $1 million related to the five sites. An estimated liability of $1 million has been recorded related to three additional sites where CMP believes it is probable that it will incur remediation and/or monitoring costs, although it has not been notified that it is among the potentially responsible parties. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to CMP.
CMP has a program to investigate and perform necessary remediation at its four sites where gas was manufactured in the past. Those four sites are part of Maine's Voluntary Response Action Program and three of those four sites are part of Maine's Uncontrolled Sites Program.
CMP's estimate for all costs related to investigation and remediation of the four sites ranges from $2 million to $5 million at December 31, 2002. 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
Central Maine Power Company
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, 2002, and $1 million at December 31, 2001.
CMP's environmental liability accruals, the majority of which are expected to be paid within the next four 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.
December 31 | 2002 | 2002 | 2001 | 2001 |
Carrying | Estimated | Carrying | Estimated | |
(Thousands) | ||||
Pollution control notes - fixed | $19,500 | $20,085 | $19,500 | 19,377 |
Various medium-term notes | $268,571 | $286,935 | $198,712 | $204,681 |
Various long-term debt | $31,034 | $39,122 | $42,317 | $42,317 |
The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values.
Note 12. Accumulated Other Comprehensive Income
| Minimum | Accumulated |
Balance, January 1, 2001 | - | - |
Before-tax amount | $(3,629) | $(3,629) |
Tax benefit | 1,481 | 1,481 |
Balance, December 31, 2001 | (2,148) | (2,148) |
Before-tax amount | (38,213) | (38,213) |
Tax benefit | 15,593 | 15,593 |
Balance, December 31, 2002 | $(24,768) | $(24,768) |
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 13. Retirement Benefits
Pension Benefits | Postretirement Benefits | |||
2002 | 2001 | 2002 | 2001 | |
(Thousands) | ||||
Change in projected benefit obligation | ||||
Benefit obligation at January 1 | $182,495 | $165,671 | $101,841 | $89,832 |
Service cost | 3,931 | 3,368 | 1,783 | 1,475 |
Interest cost | 12,763 | 12,199 | 7,744 | 5,911 |
Plan amendments | - | 2,546 | (1,410) | (6,394) |
Actuarial loss | 16,176 | 5,771 | 19,157 | 17,017 |
Special termination benefits | 3,679 | 2,551 | - | - |
Benefits paid | (10,218) | (9,611) | (5,478) | (6,000) |
Projected benefit obligation at December 31 | $208,826 | $182,495 | $123,637 | $101,841 |
Change in plan assets | ||||
Fair value of plan assets at January 1 | $151,273 | $166,232 | $15,084 | $12,991 |
Actual return on plan assets | (18,585) | (5,782) | (1,663) | (906) |
Employer contributions | - | 434 | 5,478 | 9,000 |
Benefits paid | (10,218) | (9,611) | (5,478) | (6,000) |
Fair value of plan assets at December 31 | $122,470 | $151,273 | $13,421 | $15,085 |
Funded status | $(86,356) | $(31,222) | $(110,216) | $(86,756) |
Unrecognized net actuarial loss | 107,153 | 58,592 | 45,749 | 25,831 |
Unrecognized prior service cost (benefit) | 2,327 | 2,516 | (6,769) | (5,876) |
Prepaid (accrued) benefit cost | $23,124 | $29,886 | $(71,236) | $(66,801) |
Amounts recognized in the | ||||
Prepaid benefit cost | $23,124 | $29,886 | - | - |
Accrued benefit liability | - | - | $(71,236) | $(66,801) |
Additional minimum liability | (87,581) | (42,806) | - | - |
Intangible asset | 2,327 | 2,516 | - | - |
Regulatory liability | 43,412 | 36,661 | - | - |
Accumulated other comprehensive income | 41,842 | 3,629 | - | - |
Net amount recognized | $23,124 | $29,886 | $(71,236) | $(66,801) |
CMP recorded a minimum pension liability of $88 million at December 31, 2002, as required by Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions. The adjustment is reflected 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 is primarily due to a reduction in the assumed discount rate, investment market conditions and a voluntary early retirement program offered by Energy East as part of its restructuring. (See Note 2.)
Notes to Consolidated Financial Statements
Central Maine Power Company
Pension Benefits | Postretirement Benefits | |||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |
Weighted-average assumptions | ||||||
Discount rate | 6.5% | 7.0% | 7.25% | 6.5% | 7.0% | 7.25% |
Expected return on plan assets | 9.0% | 9.0% | 9.0% | 9.0% | 9.0% | 9.0% |
Rate of compensation increase | 4.0% | 4.0% | 4.0% | 4.0% | 4.0% | 4.0% |
As of December 31, 2002, CMP decreased its discount rate from 7.0% to 6.5% and its expected return on plan assets from 9.0% to 8.75% effective January 1, 2003.
CMP assumed a 10% annual rate of increase in the costs of covered health care benefits for 2003 that gradually decreases to 5% by the year 2006.
Pension Benefits | Postretirement Benefits | |||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |
(Thousands) | ||||||
Components of net periodic | ||||||
Service cost | $3,931 | $3,368 | $3,730 | $1,783 | $1,475 | $1,628 |
Interest cost | 12,763 | 12,199 | 11,335 | 7,744 | 5,911 | 6,271 |
Expected return on plan assets | (15,192) | (15,675) | (14,165) | (996) | (1,105) | (986) |
Amortization of prior service cost | 190 | 29 | 207 | (517) | (517) | - |
Recognized net actuarial |
|
|
|
|
|
|
Amortization of transition |
|
|
|
|
|
|
Special termination benefits | 3,679 | 2,551 | - | - | - | - |
Adjustment to plan | - | (18) | 18 | 357 | - | 283 |
Net periodic benefit cost | $6,763 | $2,618 | $(103) | $9,912 | $5,764 | $9,235 |
Net periodic benefit cost is included in other operating expenses on the consolidated statements of income. For 2000 the net periodic benefit cost for pension benefits of $(103,000) includes $(127,000) from acquisition and $24,000 to acquisition; and the net periodic benefit cost for postretirement benefits of $9,235,000 includes $2,582,000 from acquisition and $6,653,000 to acquisition.
The net periodic benefit cost for postretirement benefits represents the cost CMP charged to expense for providing health care benefits to retirees and their eligible dependents. The amount of postretirement benefit cost deferred was $38 million as of December 31, 2002, and $42 million as of December 31, 2001. The transition obligation for postretirement benefits is being amortized over a period of 20 years. CMP expects to recover any deferred postretirement costs related to the transition obligation by 2012.
A 1% increase or decrease in the health care cost inflation rate from assumed rates would have the following effects:
1% Increase | 1% Decrease | |
Effect on total of service and interest cost components | $1 million | $(1) million |
Effect on postretirement benefit obligation | $13 million | $(11) million |
Notes to Consolidated Financial Statements
Central Maine Power Company
Note 14. Segment Information
Selected financial information for CMP's business segments is presented in the table below. CMP's electric delivery business, which it conducts in the State of Maine, consists of its transmission and distribution operations. All Operating Revenues; Depreciation and Amortization; Operating Income; Interest Charges, Net; Income Taxes and Earnings Available for Common Stock relate to CMP's electric delivery business. Other consists of CMP's corporate assets.
Electric |
|
| |
(Thousands) | |||
2002 | |||
Total Assets | $1,777,727 | $8,596 | $1,786,323 |
Capital Spending | $37,985 | - | $37,985 |
2001 | |||
Total Assets | $1,857,157 | $8,643 | $1,865,800 |
Capital Spending | $46,182 | $91 | $46,273 |
2000 | |||
Total Assets | $1,919,630 | $9,167 | $1,928,797 |
Capital Spending |
|
|
|
Note 15. Quarterly Financial Information (Unaudited)
Quarter Ended | March 31 | June 30 | September 30 | December 31 |
(Thousands) | ||||
2002 | ||||
Operating Revenues | $200,614 | $139,208 | $153,663 | $160,036 |
Operating Income | $44,945 | $10,048 | $23,100 | $25,454 |
Net Income | $23,283 | $5,293 | $11,372 | $14,985 |
Earnings Available for |
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2001 | ||||
Operating Revenues | $230,161 | $192,472 | $200,229 | $192,188 |
Operating Income | $43,955 | $10,513 | $24,082 | $35,194 |
Net Income | $22,246 | $3,775 | $11,275 | $17,144 |
Earnings Available for |
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Report of Independent Accountants
To the Shareholder and Board of Directors,
Central Maine Power Company and Subsidiaries
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 154 present fairly, in all material respects, the financial position of Central Maine Power Company and its subsidiaries ("the Company") at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing in Item 15(a)(2) on page 154 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 conduc ted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 1 and 3 to the consolidated financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
PricewaterhouseCoopers LLP
New York, New York
January 31, 2003
CENTRAL MAINE POWER COMPANY
SCHEDULE II - Consolidated Valuation and Qualifying Accounts
Years Ended December 31, 2002, 2001 and 2000
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(a) Uncollectible accounts charged against the allowance, net of recoveries.
(b) Includes $1,842 from acquisition and $2,674 to acquisition.
Selected Financial Data
New York State Electric & Gas Corporation
2002 | 2001 | 2000 | 1999 | 1998 | |||||
(Thousands) | |||||||||
Operating Revenues | $1,878,579 | $2,037,874 | $2,123,024 | $2,094,040 | $2,012,757 | ||||
Depreciation and amortization | $98,342 | $101,083 | $109,484 | $616,244 | (3) | $145,119 | |||
Other taxes | $118,703 | $128,186 | $126,846 | $166,215 | $186,799 | ||||
Interest Charges, Net | $93,321 | $103,624 | $103,279 | $128,063 | $123,144 | ||||
Net Income | $132,718 | (1) | $194,807 | $219,595 | (2) | $206,134 | (4) | $213,798 | |
Capital Spending | $89,641 | $74,290 | $78,869 | $69,249 | $126,704 | ||||
Total Assets | $3,032,959 | $3,014,423 | $2,952,985 | $2,948,150 | $3,732,885 | ||||
Long-term Obligations, |
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(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) Includes the effect of the benefit from the sale of an affiliate's coal-fired generation assets that increased net income $8 million.
(3) Depreciation and amortization includes accelerated amortization of NMP2 related to the sale of an affiliate's coal-fired generation assets, authorized by the NYPSC.
(4) Includes the effect of the loss from the early retirement of debt that decreased net income $18 million and the writeoff of NMP2 net of the benefit from the sale of an affiliate's coal-fired generation assets that decreased net income $5 million.
Management's discussion and analysis of financial condition and results of operations
Liquidity and Capital Resources
Restructuring
See Energy East's Item 7, Restructuring, for this discussion.
Energy East and RGS Energy Merger
See Energy East's Item 7, Energy East and RGS Energy Merger, for this discussion.
Electric Delivery Business
NYSEG's principal electric business is transmitting and distributing electricity. It also generates electricity primarily from its several hydroelectric stations.
Regional Transmission Organization: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Transmission Planning and Expansion: 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
Sale of Nuclear Interests: See Energy East's Item 7, Electric Delivery Business, for the discussion of the sale of NMP2.
NYSEG Electric Rate Plan: See Energy East's Item 7, Electric Delivery Business, for this discussion.
NYPSC-mandated Contracts with Two Customers: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Nonutility Generation: See Energy East's Item 7, Electric Delivery Business, for this discussion.
NYSEG expensed approximately $400 million for NUG power in 2002. It estimates that its purchases will total $398 million in 2003, $417 million in 2004, $423 million in 2005, $412 million in 2006 and $390 million in 2007. 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 2002, averaged 8.3 cents per kilowatt-hour. Recovery of these NUG costs is provided for in NYSEG's current regulatory plan. (See Item 8 - Note 8 to NYSEG's Financial Statements.)
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, Natural Gas Delivery Business, for this discussion.
Other Matters
Accounting Issues
Statement 71: See Energy East's Item 7, Other Matters, Statement 71, for this discussion.
Statement 145: See Energy East's Item 7, Other Matters, Statement 145, 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, 2002, NYSEG's contractual obligations and commercial commitments that will become due during the next five years are:
2003 | 2004 | 2005 | 2006 | 2007 | |
(Thousands) | |||||
Contractual Obligations | |||||
Long-term debt | - | - | - | $37,000 | $150,000 |
Capital lease obligations | $702 | $710 | $559 | 626 | 700 |
Operating leases | 2,974 | 2,458 | 1,425 | - | - |
Nonutility generator purchase |
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NYPA purchase power contracts | 54,165 | 48,623 | 34,812 | 25,310 | 25,460 |
NMP2 power purchase agreement | 55,909 | 50,183 | 53,161 | 49,392 | 53,045 |
Capacity contracts - electric | 27,476 | 19,272 | - | - | - |
Capacity contracts - natural gas | 48,944 | 46,285 | 35,804 | 27,887 | 8,309 |
Total contractual cash obligations | $587,793 | $584,318 | $548,442 | $552,510 | $627,472 |
Other Commercial Commitments | |||||
Lines of credit | $150,000 | - | - | - | - |
Standby letters of credit | 334,100 | $334,100 | - | - | - |
Total commercial commitments | $484,100 | $334,100 | - | - | - |
NYSEG and RG&E have a joint revolving credit agreement in which they each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2002, NYSEG's ratio of earnings before interest expense and income tax to interest expense was 3.4 to 1.0, and its ratio of total indebtedness to total capitalization was 0.53 to 1.00.
NYSEG has two letters of credit and reimbursement agreements in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 as of the last day of any fiscal quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2002.
Critical Accounting Policies
See Energy East's Item 7, Critical Accounting Policies, for this discussion.
Management's discussion and analysis of financial condition and results of operations
New York State Electric & Gas Corporation
Investing and Financing Activities
Investing Activities: Capital spending, including nuclear fuel, totaled $90 million in 2002, $74 million in 2001 and $79 million in 2000. Capital spending in all three years was financed with internally generated funds and was primarily for necessary improvements to existing facilities, the extension of energy delivery service and compliance with environmental requirements and governmental mandates.
Capital spending is projected to be $95 million in 2003. It is expected to be paid for with internally generated funds and will be primarily for the same purposes described above and merger integration. (See Item 8 - Note 8 to NYSEG's Financial Statements.)
NYSEG's pension plans generated pretax noncash pension income (net of amounts capitalized) of $68 million in 2002, compared to $72 million in 2001 and $65 million in 2000. NYSEG expects noncash pension income (net of amounts capitalized) for 2003 to decline, affecting earnings by approximately $12 million compared to 2002. That expected decrease is due to the significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute its pension liability (reduced from 7% to 6.5% as of December 31, 2002) and return on assets (reduced from 9% to 8.75% effective January 1, 2003). NYSEG does not anticipate funding requirements in 2003 as total plan assets exceed the projected benefit obligation. NYSEG is currently unable to predict the effect that future equity market performance will have on pension income for 2004 and beyond. (See Item 8 - Note 13 to NYSEG's Financial Statements.)
Financing Activities: In May 2002 NYSEG redeemed, at a premium, $150 million of 8 7/8% Series first mortgage bonds due November 1, 2021, and redeemed, at par, the remaining $21.34 million of two 9 7/8% Series first mortgage bonds due 2020. The redemptions were financed with internally generated cash and the proceeds from the prepayment of a promissory note by Constellation Nuclear in April 2002. (See Sale of Nuclear Interests). NYSEG incurred a $10 million reduction to earnings in the second quarter of 2002 as a result of these redemptions, but will save over $16 million each year in interest costs. (See Other Matters, Statement 145.)
In November 2002 NYSEG issued $150 million of 4 3/8% unsecured notes due November 2007 and $100 million of 5 1/2% unsecured notes due November 2012. NYSEG used the net proceeds from those notes to refund commercial paper that was used in October 2002 to repay $150 million of maturing 6 3/4% Series first mortgage bonds and to repay $100 million of 8.30% Series first mortgage bonds that were called on December 15, 2002.
In December 2002 NYSEG and RG&E entered into a joint $200 million 364-day revolving credit facility with certain banks. NYSEG is permitted to borrow up to $150 million and RG&E is permitted to borrow up to $75 million under the facility. NYSEG had no amounts outstanding under this agreement during 2002 nor under its previous agreement during 2002 and 2001.
Management's discussion and analysis of financial condition and results of operations
New York State Electric & Gas Corporation
NYSEG uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. At December 31, 2002, NYSEG had $64 million of such short-term debt outstanding at a weighted-average interest rate of 1.82%. NYSEG had no short-term debt outstanding at December 31, 2001.
In 2003 NYSEG plans to call its remaining first mortgage bonds: $50 million of 7.55% Series first mortgage bonds callable on April 1, 2003, and $100 million of 7.45% Series first mortgage bonds callable on July 15, 2003. Additional financing needed by NYSEG to call its remaining first mortgage bonds is expected to be completed in June 2003. Through financial instruments issued in September 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.085%.
Results of Operations
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| 2002 | 2001 | |
(Thousands) | |||||
Operating Revenues | $1,878,579 | $2,037,874 | $2,123,024 | (8%) | (4%) |
Operating Income | $328,739 | $448,525 | $468,972 | (27%) | (4%) |
Earnings Available for |
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Earnings
Earnings for 2002 decreased $62 million. The decrease was primarily due to $68 million for an electric price reduction, effective March 1, 2002; lower wholesale deliveries that resulted in higher net purchased power costs of $28 million; $15 million of restructuring expenses; a $10 million loss from the early retirement of debt (see Financing Activities); and $7 million for merger integration costs. Those decreases were partially offset by increases of $31 million for lower natural gas costs, $17 million for higher electric and natural gas retail deliveries due to colder winter weather and warmer summer weather, $8 million for cost control efforts, and $6 million of interest savings due to the early retirement of debt.
Earnings for 2001 decreased $25 million primarily due to $14 million for lower electric transmission revenues, $11 million for higher prices of natural gas purchased, $5 million for lower retail natural gas deliveries because of warmer weather in 2001 and an $8 million nonrecurring benefit in 2000 from the sale of an affiliate's coal-fired generation assets. Those decreases were partially offset by cost control efforts of $13 million.
Other Items
Other operating expenses includes net periodic pension benefit income of $68 million in 2002, $72 million in 2001 and $65 million in 2000. Other operating expenses would have been $4 million lower for 2002 and would have been $7 million higher for 2001 without those changes in net periodic pension benefit income. Net periodic pension benefit income represented 31% of net income for 2002, 24% for 2001 and 19% for 2000.
Management's discussion and analysis of financial condition and results of operations
New York State Electric & Gas Corporation
Other deductions increased $15 million in 2002 primarily due to a loss on the early retirement of debt. (See Financing Activities.) Other deductions decreased $10 million in 2001 primarily due to the termination of the sale of accounts receivable in August 2001 and a loss on the early retirement of debt in 2000. Fees related to the sale of accounts receivable were included in other deductions in 2000 and in the first quarter of 2001. (See Item 8 - Note 1 to NYSEG's Financial Statements.)
Interest charges decreased $10 million in 2002 as a result of refinancings and repayments of first mortgage bonds. (See Financing Activities.)
Operating Results for the Electric Delivery Business
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| 2002 | 2001 | |||
(Thousands) | |||||||
Deliveries - Megawatt-hours |
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Operating Revenues | $1,545,107 | $1,689,464 | $1,746,138 | (9%) | (3%) | ||
Operating Expenses | $1,277,752 | $1,249,775 | $1,309,337 | 2% | (5%) | ||
Operating Income | $267,355 | $439,689 | $436,801 | (39%) | 1% | ||
Operating Revenues: The $144 million decrease in operating revenues for 2002 is primarily due to a price reduction, effective March 1, 2002, that decreased revenues $114 million and lower wholesale revenues of $64 million due to lower market prices and lower deliveries. Those decreases were partially offset by increased retail deliveries of $41 million primarily due to warmer summer weather and colder winter weather.
Operating revenues decreased $57 million in 2001 due to lower wholesale deliveries of $37 million and lower transmission revenues of $22 million. As a result of the expiration of an agreement to purchase power from a plant it formerly owned, the company had less power available to sell into the wholesale market. The lower transmission revenues resulted from less congestion on the transmission lines.
Operating Expenses: Operating expenses increased $28 million for 2002, primarily due to $20 million of restructuring expenses, $12 million for the effect of the sale of NYSEG's share of NMP2 in 2001, $15 million of purchased power costs for higher retail deliveries due to warmer summer weather and colder winter weather, $9 million of merger integration costs and $6 million for electricity purchased that was deferred in accordance with the electric rate plan. A $44 million increase for purchased power costs to replace energy previously provided by NMP2 was partially offset by a $35 million decrease in certain operating expenses due to the sale of NMP2. Those increases were partially offset by decreases of $32 million for lower market prices for electricity and $20 million due to the elimination of a regulatory amortization of demand-side management program costs.
Management's discussion and analysis of financial condition and results of operations
New York State Electric & Gas Corporation
Operating expenses for 2001 decreased $59 million. The decrease was due to lower purchased power costs of $31 million primarily due to lower wholesale deliveries and $15 million for cost control efforts relating to retirement benefits and compensation and a $12 million decrease for the effect of the sale of NYSEG's share of NMP2.
Operating Results for the Natural Gas Delivery Business
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| 2002 | 2001 | |
(Thousands) | |||||
Deliveries - Dekatherms |
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Operating Revenues | $333,472 | $348,409 | $376,886 | (4%) | (8%) |
Operating Expenses | $272,088 | $339,573 | $344,715 | (20%) | (1%) |
Operating Income | $61,384 | $8,836 | $32,171 | 595% | (73%) |
Operating Revenues: The $15 million decrease in operating revenues for 2002 is primarily due to lower market prices of natural gas of $20 million that were passed on to nonresidential and wholesale customers, partially offset by $5 million for increased deliveries due to colder winter weather.
The $28 million decrease in revenues for 2001 is primarily due to lower deliveries of $38 million because of warmer winter weather and $11 million due to lower natural gas prices for wholesale sales, partially offset by gas cost recovery from nonresidential deliveries of $22 million.
Operating Expenses: Operating expenses decreased $67 million for 2002 primarily due to an $81 million decrease in natural gas purchased as a result of lower natural gas prices due to market conditions and the deferral of gas costs for future recovery. That decrease was partially offset by increases of $6 million for restructuring expenses and $4 million of gas purchases for higher deliveries due to colder winter weather.
Operating expenses for 2001 decreased $5 million primarily due to lower natural gas deliveries of $26 million and cost control efforts of $9 million relating to retirement benefits and compensation, partially offset by $29 million for increases in the price of natural gas.
New York State Electric & Gas Corporation
Statements of Income
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Operating Revenues | |||
Electric | $1,545,107 | $1,689,464 | $1,746,138 |
Natural Gas | 333,472 | 348,410 | 376,886 |
Total Operating Revenues | 1,878,579 | 2,037,874 | 2,123,024 |
Operating Expenses | |||
Electricity purchased and fuel used in generation | 836,027 | 801,877 | 830,008 |
Natural gas purchased | 170,726 | 247,156 | 243,482 |
Other operating expenses | 215,278 | 237,513 | 256,772 |
Maintenance | 85,013 | 85,814 | 87,460 |
Depreciation and amortization | 98,342 | 101,083 | 109,484 |
Other taxes | 118,703 | 128,186 | 126,846 |
Restructuring expenses | 25,751 | - | - |
Gain on sale of generation assets | - | (84,083) | - |
Deferral of asset sale gain | - | 71,803 | - |
Total Operating Expenses | 1,549,840 | 1,589,349 | 1,654,052 |
Operating Income | 328,739 | 448,525 | 468,972 |
Other (Income) | (6,941) | (10,033) | (7,270) |
Other Deductions | 19,248 | 4,431 | 14,064 |
Interest Charges, Net | 93,321 | 103,624 | 103,279 |
Income Before Income Taxes | 223,111 | 350,503 | 358,899 |
Income Taxes | 90,393 | 155,696 | 139,304 |
Net Income | 132,718 | 194,807 | 219,595 |
Preferred Stock Dividends | 396 | 396 | 396 |
Earnings Available for Common Stock | $132,322 | $194,411 | $219,199 |
The notes on pages 108 through 122 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Balance Sheets
December 31 | 2002 | 2001 |
(Thousands) | ||
Assets | ||
Current Assets | ||
Cash and cash equivalents | $11,490 | $21,617 |
Special deposits | 44,205 | 1,432 |
Accounts receivable, net | 260,189 | 292,687 |
Note receivable, current | - | 12,126 |
Fuel, at average cost | 29,000 | 32,094 |
Materials and supplies, at average cost | 5,573 | 7,027 |
Accumulated deferred income tax benefits, net | 4,232 | 3,930 |
Prepayments | 26,571 | 26,421 |
Total Current Assets | 381,260 | 397,334 |
Utility Plant, at Original Cost | ||
Electric | 2,551,775 | 2,562,194 |
Natural gas | 671,321 | 654,224 |
Common | 121,661 | 132,928 |
3,344,757 | 3,349,346 | |
Less accumulated depreciation | 1,371,892 | 1,341,964 |
Net Utility Plant in Service | 1,972,865 | 2,007,382 |
Construction work in progress | 40,166 | 22,885 |
Total Utility Plant | 2,013,031 | 2,030,267 |
Other Property and Investments, Net | 41,365 | 43,242 |
Regulatory and Other Assets | ||
Regulatory assets | ||
Unfunded future income taxes | - | 12,984 |
Unamortized loss on debt reacquisitions | 35,631 | 42,959 |
Environmental remediation costs | 52,434 | 53,167 |
Other | 23,563 | 22,000 |
Total regulatory assets | 111,628 | 131,110 |
Other assets | ||
Goodwill, net | 11,199 | 11,199 |
Prepaid pension benefits | 395,586 | 334,769 |
Note receivable | - | 47,553 |
Other | 78,890 | 18,949 |
Total other assets | 485,675 | 412,470 |
Total Regulatory and Other Assets | 597,303 | 543,580 |
Total Assets | $3,032,959 | $3,014,423 |
The notes on pages 108 through 122 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Balance Sheets
December 31 | 2002 | 2001 |
(Thousands) | ||
Liabilities | ||
Current Liabilities | ||
Current portion of long-term debt | $702 | $150,873 |
Notes payable | 64,000 | - |
Accounts payable and accrued liabilities | 169,884 | 109,476 |
Interest accrued | 12,289 | 15,967 |
Taxes accrued | 11,091 | 7,499 |
Other | 58,577 | 65,268 |
Total Current Liabilities | 316,543 | 349,083 |
Regulatory and Other Liabilities | ||
Regulatory liabilities | ||
Unfunded future income taxes | 5,856 | - |
Deferred income taxes | 26,199 | 17,308 |
Gain on sale of generation assets | 14,315 | 60,476 |
Other | 25,036 | 29,810 |
Total regulatory liabilities | 71,406 | 107,594 |
Other liabilities | ||
Deferred income taxes | 347,355 | 310,456 |
Other postretirement benefits | 197,193 | 187,916 |
Environmental remediation costs | 75,100 | 76,100 |
Other | 56,683 | 85,126 |
Total other liabilities | 676,331 | 659,598 |
Total Regulatory and Other Liabilities | 747,737 | 767,192 |
Long-term debt | 1,017,902 | 1,039,135 |
Total Liabilities | 2,082,182 | 2,155,410 |
Commitments | - | - |
Preferred Stock |
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Common Stock Equity |
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Capital in excess of par value | 277,297 | 270,835 |
Retained earnings | 206,519 | 164,197 |
Accumulated other comprehensive income (loss) | 26,745 | (16,235) |
Total Common Stock Equity | 940,618 | 848,854 |
Total Liabilities and Stockholder's Equity | $3,032,959 | $3,014,423 |
The notes on pages 108 through 122 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Statements of Cash Flows
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Operating Activities | |||
Net income | $132,718 | $194,807 | $219,595 |
Adjustments to reconcile net income to net cash | |||
Depreciation and amortization | 76,476 | 149,611 | 163,283 |
Income taxes and investment tax credits deferred, net | 38,053 | 14,933 | 1,257 |
Restructuring expenses | 25,751 | - | - |
Gain on sale of generation assets | - | (84,083) | - |
Deferral of asset sale gain | - | 71,803 | - |
Pension income | (67,569) | (71,855) | (64,854) |
Changes in current operating assets and liabilities | |||
Accounts receivable, net | 32,498 | 60,159 | (61,745) |
Sale of accounts receivable program | - | (152,000) | - |
Loan receivable, affiliated company | - | - | 17,789 |
Note receivable, current | - | (12,126) | - |
Inventory | 4,548 | (3,049) | (11,948) |
Accounts payable and accrued liabilities | 25,230 | (57,272) | 25,241 |
Other current liabilities | (6,690) | (6,242) | 4,815 |
Other assets | (35,311) | (15,019) | (3,392) |
Other liabilities | 817 | (1,215) | (16,291) |
Net Cash Provided by Operating Activities | 226,521 | 88,452 | 273,750 |
Investing Activities | |||
Utility plant additions | (89,466) | (79,885) | (81,386) |
Sale of generation assets | 59,442 | 59,441 | - |
Proceeds from sale of utility plant | 6,536 | 546 | 4,272 |
Special deposits | (5,166) | 19,909 | (21,954) |
Other | 1,050 | 4,475 | 5,072 |
Net Cash (Used in) Provided by Investing Activities | (27,604) | 4,486 | (93,996) |
Financing Activities | |||
Equity contribution from parent | - | 100,000 | - |
Repayments of first mortgage bonds and preferred |
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Long-term note issuances | 247,807 | - | - |
Notes payable three months or less, net | 64,000 | (123,000) | (40,240) |
Dividends on common and preferred stock | (90,396) | (65,939) | (210,998) |
Net Cash Used in Financing Activities | (209,044) | (88,939) | (276,630) |
Net (Decrease) Increase in Cash and |
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Cash and Cash Equivalents, Beginning of Year | 21,617 | 17,618 | 114,494 |
Cash and Cash Equivalents, End of Year | $11,490 | $21,617 | $17,618 |
The notes on pages 108 through 122 are an integral part of the financial statements.
New York State Electric & Gas Corporation
Statements of Changes in Common Stock Equity
| Common Stock |
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| Accumulated |
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Balance, January 1, 2000 | 64,508 | $430,057 | $170,678 | $26,731 | - | $627,466 |
Net income | 219,595 | 219,595 | ||||
Other comprehensive income, net of tax | $1,327 | 1,327 | ||||
Comprehensive income | 220,922 | |||||
Cash dividends declared | ||||||
Preferred stock (at serial rates) | ||||||
Redeemable - optional | (396) | (396) | ||||
Common Stock | (210,601) | (210,601) | ||||
Balance, December 31, 2000 | 64,508 | 430,057 | 170,678 | 35,329 | 1,327 | 637,391 |
Net income | 194,807 | 194,807 | ||||
Other comprehensive income (loss), |
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Comprehensive income | 177,245 | |||||
Equity contribution from parent | 100,000 | 100,000 | ||||
Cash dividends declared | ||||||
Preferred stock (at serial rates) | ||||||
Redeemable - optional | (396) | (396) | ||||
Common Stock | (65,543) | (65,543) | ||||
Amortization of capital stock issue expense | 157 | 157 | ||||
Balance, December 31, 2001 | 64,508 | 430,057 | 270,835 | 164,197 | (16,235) | 848,854 |
Net income | 132,718 | 132,718 | ||||
Other comprehensive income, net of tax | 42,980 | 42,980 | ||||
Comprehensive income | 175,698 | |||||
Equity contribution from parent | 6,462 | 6,462 | ||||
Cash dividends declared | ||||||
Preferred stock (at serial rates) | ||||||
Redeemable - optional | (396) | (396) | ||||
Common Stock | (90,000) | (90,000) | ||||
Balance, December 31, 2002 | 64,508 | $430,057 | $277,297 | $206,519 | $26,745 | $940,618 |
The notes on pages 108 through 122 are an integral part of the financial statements.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 1. Significant Accounting Policies
Background: New York State Electric & Gas Corporation (NYSEG) is primarily engaged in electricity transmission and distribution operations and natural gas transportation, storage and distribution operations in upstate New York. In connection with Energy East Corporation's merger with RGS Energy Group, Inc. (RGS Energy) on June 28, 2002, NYSEG became a wholly-owned subsidiary of RGS Energy.
Accounts receivable: Accounts receivable include unbilled revenues of $79 million at December 31, 2002, and $74 million at December 31, 2001, and are shown net of an allowance for doubtful accounts of $10 million at December 31, 2002 and $6 million at December 31, 2001. Bad debt expense was $18 million in 2002, $14 million in 2001 and $13 million in 2000.
In August 2001 NYSEG terminated its agreement to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allowed NYSEG to receive up to $152 million from the sale of such interests. All fees related to the agreement beginning April 1, 2001, are included in interest expense on the statements of income and were approximately $3 million. Fees related to the sale of accounts receivable through March 31, 2001, are included in other deductions on the statements of income and amounted to approximately $2 million in 2001 and $10 million in 2000. NYSEG's sale of accounts receivable before the agreement was terminated did not constitute a securitization transaction because the accounts receivable were not transferred to a special purpose entity, and therefore, were not transformed into securities.
Statements of cash flows: NYSEG considers all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents. Those investments are included in cash and cash equivalents on the balance sheets.
Supplemental Disclosure of Cash Flows Information | 2002 | 2001 | 2000 |
(Thousands) | |||
Cash paid during the year ended December 31: | |||
Interest, net of amounts capitalized | $89,688 | $98,654 | $98,169 |
Income taxes, net of benefits received | $58,844 | $132,942 | $153,406 |
Depreciation and amortization: NYSEG determines depreciation expense using straight-line rates, based on the average service lives of groups of depreciable property, which includes estimated cost of removal, in service. The average service lives of certain classifications of property are: transmission property - 55 years, distribution property - 44 years, generation property - 50 years, gas storage property - 20 years and other property - 38 years. NYSEG's depreciation accruals were equivalent to 3.2% of average depreciable property for 2002, 2.9% for 2001 and 3.1% for 2000.
Estimates: Preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Notes to Financial Statements
New York State Electric & Gas Corporation
Goodwill:The excess of the cost over fair value of net assets of purchased businesses is recorded as goodwill and was amortized on a straight-line basis over 40 years until December 31, 2001. Beginning in 2002 NYSEG evaluates the carrying value of goodwill for impairment at least annually and on an interim basis if there are indications that goodwill might be impaired. Any impairments would be recognized when the fair value of goodwill is less than its carrying value. (See Note 3.)
Income taxes: Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.
NYSEG computes its income tax provision on a separate return method. SEC regulations require that no Energy East subsidiary pay more income taxes than it would have paid if a separate income tax return had been filed. The determination and allocation of NYSEG's income tax provision and its components is outlined and agreed to in the tax sharing agreement with Energy East.
Other (Income) and Other Deductions:
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Dividends | $(92) | $(1,844) | $(44) |
Interest income | (4,617) | (3,852) | (3,276) |
Noncash return | (1,313) | (792) | (1,056) |
Miscellaneous | (919) | (3,545) | (2,894) |
Total other (income) | $(6,941) | $(10,033) | $(7,270) |
NYSEG early retirement of debt | $16,145 | - | $2,766 |
Fees on sale of accounts receivable | - | $2,495 | 10,368 |
Miscellaneous | 3,103 | 1,936 | 930 |
Total other deductions | $19,248 | $4,431 | $14,064 |
Reclassifications: Certain amounts have been reclassified on the financial statements to conform with the 2002 presentation.
Regulatory assets and liabilities: Pursuant to Statement 71, NYSEG capitalizes, as regulatory assets, incurred 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. Demand-side management program costs, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with NYSEG's current rate plans. NYSEG earns a return on all regulatory assets for which funds have been spent.
Notes to Financial Statements
New York State Electric & Gas Corporation
Revenue recognition: NYSEG recognizes revenues upon delivery of energy and energy-related products and services to its customers.
NYSEG enters into power purchase and sales transactions with the NYISO. When sales of owned generation are sold to the NYISO, and subsequently repurchased from the NYISO to serve its customers, the transactions are recorded on a net basis in the statements of income.
Risk management: NYSEG has a gas supply charge that allows it to recover through rates the market price of purchased natural gas, substantially eliminating its exposure to natural gas price risk. NYSEG uses natural gas futures to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures 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 electricity 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.
In September 2002 NYSEG entered into a $150 million interest rate hedge on the benchmark 10-year Treasury Security in anticipation of its expected issuance of long-term notes in June 2003.
NYSEG does not hold or issue financial instruments for trading or speculative purposes.
NYSEG recognizes the fair value of its natural gas futures, financial electricity contracts and interest rate agreements as assets or liabilities on its balance sheets. NYSEG's derivative asset was $55 million at December 31, 2002, and its derivative liability was $5 million at December 31, 2002, and $30 million at December 31, 2001. All of the arrangements are designated as cash flow hedging instruments. Changes in the fair value of the cash flow hedging instruments are recognized in other comprehensive income until the underlying transaction occurs. When the underlying transaction occurs, the amounts in accumulated other comprehensive income are reported in the statements of income.
NYSEG uses quoted market prices to fair value derivatives and 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, 2002, the maximum length of time over which NYSEG is hedging its exposure to the variability in future cash flows for forecasted transactions is 84 months. NYSEG estimates that gains of $14 million will be reclassified from accumulated other comprehensive income into earnings in 2003, as the underlying transactions occur.
Notes to Financial Statements
New York State Electric & Gas Corporation
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.
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 and the cost of removal less salvage are charged to accumulated depreciation.
Note 2. Restructuring
In the fourth quarter of 2002 Energy East recorded $41 million of restructuring expenses, 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.
Those programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by April 30, 2003, including approximately 260 from NYSEG. The employees affected by the involuntary severance program were notified in January 2003.
Note 3. Goodwill and Other Intangible Assets
Effective January 1, 2002, NYSEG adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As required by Statement 142 NYSEG no longer amortizes goodwill and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized (amortized intangible assets) and are reviewed for impairment.
NYSEG determined that there was no impairment of goodwill as of January 1, 2002. There was no reclassification of goodwill to intangible assets and no reclassification of intangible assets to goodwill as of January 1, 2002. Annual impairment testing was also completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for NYSEG at September 30, 2002.
The carrying amount of goodwill on NYSEG's balance sheets was $11 million as of December 31, 2002 and 2001, and is included in NYSEG's natural gas delivery operating segment.
Other Intangible Assets: NYSEG's unamortized intangible assets primarily consist of franchises and consents, and had a carrying amount of $1 million at December 31, 2002 and 2001. NYSEG's amortized intangible assets consist of hydroelectric licenses, and had a gross carrying amount of $1.5 million and accumulated amortization of $1 million at December 31, 2002 and 2001. Estimated amortization expense for intangible assets for the next five years is $48 thousand for the years 2003 through 2005 and $31 thousand for 2006 and 2007.
Notes to Financial Statements
New York State Electric & Gas Corporation
Transitional Information: Results of operations information for NYSEG as though goodwill had been accounted for under Statement 142 for all years presented is:
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Reported net income | $132,718 | $194,807 | $219,595 |
Add back: Goodwill amortization | - | 383 | 383 |
Adjusted net income | $132,718 | $195,190 | $219,978 |
Note 4. Income Taxes
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Current | $52,420 | $140,764 | $138,804 |
Deferred, net |
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Pension benefits | 31,847 | 28,917 | 24,316 |
Statement 106 postretirement benefits | 605 | (3,479) | (11,417) |
Demand-side management | (1,429) | (8,499) | (8,335) |
Asset sale gain account amortization | 19,465 | - | - |
Deferred gas costs | 5,313 | - | - |
Restructuring expenses | (10,268) | - | - |
Gas supply deferral | 5,813 | - | - |
Miscellaneous | (21,237) | (11,221) | 2,597 |
ITC | (365) | (822) | (1,661) |
Total | $90,393 | $155,696 | $139,304 |
NYSEG's effective tax rate differed from the statutory rate of 35% due to the following:
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Tax expense at statutory rate | $78,089 | $122,676 | $125,615 |
Depreciation and amortization not normalized | 2,566 | 15,182 | 4,408 |
ITC amortization | (365) | (822) | (1,661) |
State taxes, net of federal benefit | 10,716 | 16,526 | 19,172 |
Other, net | (613) | 2,134 | (8,230) |
Total | $90,393 | $155,696 | $139,304 |
Notes to Financial Statements
New York State Electric & Gas Corporation
NYSEG's deferred tax assets and liabilities consisted of the following:
December 31 | 2002 | 2001 |
(Thousands) | ||
Current Deferred Tax Assets | $4,232 | $3,930 |
Noncurrent Deferred Tax Liabilities | ||
Depreciation | $297,978 | $300,325 |
Unfunded future income taxes | 902 | 7,599 |
Accumulated deferred ITC | 15,548 | 15,590 |
Deferred gain on generation plant sale | (14,766) | (30,843) |
Pension benefits | 129,940 | 106,732 |
Statement 106 retirement benefits | (52,849) | (53,454) |
Other | (3,199) | (18,185) |
Total Noncurrent Deferred Tax Liabilities | 373,554 | 327,764 |
Less amounts classified as regulatory liabilities | ||
Deferred income taxes | 26,199 | 17,308 |
Noncurrent Deferred Income Taxes | $347,355 | $310,456 |
NYSEG has no federal or state tax credit or loss carryforwards, nor does it have any valuation allowances.
Note 5. Long-term Debt
At December 31, 2002 and 2001, NYSEG's long-term debt was:
Amount | ||||
Maturity Dates | Interest Rates | 2002 | 2001 | |
(Thousands) | ||||
First mortgage bonds(1) | 2023 | 7.45% and 7.55% | $150,000 | $571,340 |
Pollution control notes - fixed | 2006 to 2034 | 5.70% to 6.15% | 306,000 | 306,000 |
Pollution control notes - variable | 2015 to 2029 | 1.32% to 4.43% | 307,000 | 307,000 |
Long-term notes | 2007 and 2012 | 4 3/8% and 5.5% | 250,000 | - |
Obligations under capital leases | 8,781 | 9,396 | ||
Unamortized premium and discount on debt, net | (3,177) | (3,728) | ||
1,018,604 | 1,190,008 | |||
Less debt due within one year - included in current liabilities | 702 | 150,873 | ||
Total | $1,017,902 | $1,039,135 | ||
At December 31, 2002, long-term debt and capital lease payments (in thousands) that will become due during the next five years are:
2003 | 2004 | 2005 | 2006 | 2007 | ||||
$702 | $710 | $559 | $37,626 | $150,700 |
(1) NYSEG's first mortgage bonds are secured by a first mortgage lien on substantially all of its properties. NYSEG has no other secured indebtedness. None of NYSEG's other debt obligations are guaranteed or secured by any of its affiliates.
Notes to Financial Statements
New York State Electric & Gas Corporation
Cross-default Provisions: NYSEG has provisions in its unsecured indenture and the reimbursement agreements relating to certain series of pollution control bonds, which provide that default by NYSEG with respect to any other debt in excess of $40 million in the case of the unsecured indenture and $5 million in the case of the reimbursement agreements will be considered a default under those respective documents.
Note 6. Bank Loans and Other Borrowings
NYSEG uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. At December 31, 2002, NYSEG had $64 million of such short-term debt outstanding at a weighted-average interest rate of 1.82%. NYSEG had no short-term debt outstanding at December 31, 2001.
NYSEG and RG&E have a joint $200 million 364-day revolving credit facility with certain banks, which they entered into in December 2002. NYSEG is permitted to borrow up to $150 million under the facility. At NYSEG's and RG&E's option, the interest rate on borrowings is related to the prime rate or the Eurodollar rate. The agreement provides for payment of a commitment fee, which was .15% at December 31, 2002, and .125% at December 31, 2001, under a previous agreement. NYSEG had no amounts outstanding under this agreement at December 31, 2002, nor at December 31, 2001, under a previous agreement.
In their joint revolving credit agreement NYSEG and RG&E each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2002, NYSEG's ratio of earnings before interest expense and income tax to interest expense was 3.4 to 1.0, and its ratio of total indebtedness to total capitalization was 0.53 to 1.00.
NYSEG has two letters of credit and reimbursement agreements in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 as of the last day of any fiscal quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2002.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 7. Preferred Stock
At December 31, 2002 and 2001, NYSEG's serial cumulative preferred stock was:
| Par |
| Shares |
| |
Redeemable solely at NYSEG's option: | |||||
3.75% | $100 | $104.00 | 78,379 | $7,838 | $7,838 |
4 1/2% (1949) | 100 | 103.75 | 11,800 | 1,180 | 1,180 |
4.40% | 100 | 102.00 | 7,093 | 709 | 709 |
4.15% (1954) | 100 | 102.00 | 4,317 | 432 | 432 |
Total | $10,159 | $10,159 | |||
(1) At December 31, 2002, 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 2000 through 2002.
Voting rights of preferred shares: 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 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.
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.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 8. Commitments
Capital spending: NYSEG has commitments in connection with its capital spending program. Capital spending is projected to be $95 million in 2003 and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. NYSEG's capital spending will be primarily for necessary improvements to existing facilities, the extension of energy delivery service, compliance with environmental requirements and governmental mandates and merger integration.
Nonutility generator power purchase contracts: NYSEG expensed approximately $400 million for NUG power in 2002, $368 million for NUG power in 2001 and $358 million in 2000. NYSEG estimates that its purchases will total $398 million in 2003, $417 million in 2004, $423 million in 2005, $412 million in 2006 and $390 million in 2007.
Note 9. Nuclear Generation Assets
In November 2001 NYSEG sold its 18% interest in NMP2 to Constellation Nuclear. In October 2001 the NYPSC issued an order approving the sale. For its share of NMP2, NYSEG received at closing $59 million in cash and a $59 million 11% promissory note. On April 12, 2002, Constellation Nuclear paid the remaining balance plus accrued interest on the promissory note. NYSEG's 18% share of NMP2's operating expenses until it was sold is included in various categories on the statements of income.
Upon completion of the sale of NMP2, NYSEG recorded an asset sale gain of approximately $110 million, in accordance with the NYPSC's order approving the sale, as a regulatory liability under Statement 71. The gain includes a gross up for unfunded future income taxes and is being returned to customers in accordance with NYSEG's current electric rate plan, which was approved by the NYPSC in February 2002.
NYSEG's pre-existing decommissioning funds were transferred to Constellation, which has taken responsibility for all future decommissioning funding.
The transaction included a power purchase agreement that calls for Constellation to provide electricity to NYSEG, at fixed prices, for 10 years. The power purchase agreement is a contract for physical delivery of NYSEG's 18% share of 90% of the output from NMP2. NYSEG recorded expenses for electricity purchased in 2001 and 2002 in accordance with the agreement at the time the power was physically delivered, at prices pursuant to the agreement. The contract is not required to be marked-to-market and is not considered a derivative instrument because it qualifies for the normal purchases and normal sales exception in Statement 133, as amended.
After the power purchase agreement is completed a revenue sharing agreement will begin. The revenue sharing agreement could provide NYSEG additional revenue through 2021, which would mitigate increases in electricity prices. Both agreements are based on plant output. No amounts were recorded under the revenue sharing agreement in 2002 because any benefit that may occur between 2011 and 2021 cannot be estimated. Any benefits from the revenue sharing agreement will be deferred for customers.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 10. Environmental Liability
From time to time environmental laws, regulations and compliance programs may require changes in NYSEG's operations and facilities and may increase the cost of electric and natural gas service.
The U.S. Environmental Protection Agency and the New York State Department of Environmental Conservation (NYSDEC), as appropriate, notified NYSEG that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at nine waste sites, not including its sites where gas was manufactured in the past, which are discussed below. With respect to the nine sites, seven sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites and three of the sites are also included on the National Priorities list.
Any liability may be joint and several for certain of those sites. NYSEG has recorded an estimated liability of $1 million related to seven of the nine sites. Remediation costs have been paid at the remaining two sites, and NYSEG expects no additional liability to be incurred. The ultimate cost to remediate the sites may be significantly more than the estimated amount. 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 $75 million to $171 million at December 31, 2002. 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 $75 million at December 31, 2002, and $76 million at December 31, 2001. NYSEG recorded a corresponding regulatory asset, net of insurance recoveries, since it expects to recover the net costs in rates.
NYSEG's environmental liability accruals, which are expected to be paid through the year 2017, have been established on an undiscounted basis. NYSEG received insurance settlements during the last three years, which it accounted for as reductions in its related regulatory asset.
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 11. Accumulated Other Comprehensive Income
| Balance |
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Unrealized gains (losses) |
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Minimum pension liability adjustment, net of income tax benefit (expense) of $339 for 2000, $(67) for 2001 and $6 |
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Unrealized gains (losses) on derivatives qualified as hedges: |
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Net unrealized (losses) gains |
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Accumulated Other Comprehensive |
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(See Risk management in Note 1.)
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 12. Fair Value of Financial Instruments
The carrying amounts and estimated fair values of NYSEG's financial instruments included on its balance sheets are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.
December 31 | 2002 | 2002 | 2001 | 2001 |
Carrying | Estimated | Carrying | Estimated | |
(Thousands) | ||||
Investments - classified as |
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First mortgage bonds | $149,016 | $167,817 | $567,612 | $584,555 |
Pollution control notes - fixed | $306,000 | $319,790 | $306,000 | $313,679 |
Pollution control notes - variable | $307,000 | $307,000 | $307,000 | $307,000 |
Long-term notes | $247,807 | $257,805 | - | - |
The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values. Special deposits may include restricted funds set aside as collateral for first mortgage bonds and collateral received from counterparties. The carrying amount approximates fair value because the special deposits have been invested in securities that mature within one year.
Note 13. Retirement Benefits
Pension Benefits | Postretirement Benefits | |||
2002 | 2001 | 2002 | 2001 | |
(Thousands) | ||||
Change in projected benefit obligation | ||||
Benefit obligation at January 1 | $954,532 | $864,100 | $244,667 | $256,160 |
Service cost | 17,418 | 16,416 | 2,942 | 2,901 |
Interest cost | 65,884 | 63,109 | 17,625 | 15,145 |
Plan amendments | - | 34,653 | (10,597) | (19,663) |
Actuarial loss | 56,044 | 22,027 | 34,017 | 2,548 |
Special termination benefits | 21,917 | - | - | - |
Benefits paid | (55,367) | (45,773) | (13,724) | (12,424) |
Projected benefit obligation at December 31 | $1,060,428 | $954,532 | $274,930 | $244,667 |
Change in plan assets | ||||
Fair value of plan assets at January 1 | $1,424,135 | $1,494,848 | - | - |
Actual return on plan assets | (154,876) | (24,940) | - | - |
Employer contributions | - | - | $13,724 | $12,424 |
Benefits paid | (55,367) | (45,773) | (13,724) | (12,424) |
Fair value of plan assets at December 31 | $1,213,892 | $1,424,135 | - | - |
Funded status | $153,464 | $469,603 | $(274,930) | $(244,667) |
Unrecognized net actuarial loss (gain) | 204,038 | (173,376) | 44,576 | 10,024 |
Unrecognized prior service cost (benefit) | 46,552 | 54,249 | (47,500) | (53,657) |
Unrecognized net transition (asset) obligation | (8,468) | (15,707) | 80,661 | 100,384 |
Prepaid (accrued) benefit cost | $395,586 | $334,769 | $(197,193) | $(187,916) |
NYSEG's postretirement benefits were unfunded as of December 31, 2002 and 2001.
Notes to Financial Statements
New York State Electric & Gas Corporation
Pension Benefits | Postretirement Benefits | |||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |
Weighted-average assumptions | ||||||
Discount rate | 6.5% | 7.0% | 7.25% | 6.5% | 7.0% | 7.25% |
Expected return on plan assets | 9.0% | 9.0% | 9.0% | N/A | N/A | N/A |
Rate of compensation increase | 4.0% | 4.0% | 4.0% | N/A | N/A | N/A |
As of December 31, 2002, NYSEG decreased its discount rate from 7.0% to 6.5% and its expected return on plan assets from 9.0% to 8.75% effective January 1, 2003.
NYSEG assumed a 10% annual rate of increase in the costs of covered health care benefits for 2003 that gradually decreases to 5% by the year 2006.
Pension Benefits | Postretirement Benefits | |||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |
(Thousands) | ||||||
Components of net periodic benefit cost | ||||||
Service cost | $17,418 | $16,416 | $16,429 | $2,942 | $2,901 | $6,020 |
Interest cost | 65,884 | 63,109 | 58,200 | 17,625 | 15,145 | 20,244 |
Expected return |
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Amortization of transition |
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Deferral for future recovery | - | - | - | - | - | (4,774) |
Special termination benefits | 21,917 | - | - | - | - | - |
Net periodic benefit cost | $(60,817) | $(83,943) | $(76,085) | $23,001 | $16,674 | $27,703 |
Net periodic benefit cost is included in other operating expenses on the statements of income. 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. The amount of postretirement benefit cost deferred was $0.4 million as of December 31, 2002, and $3 million as of December 31, 2001. NYSEG expects to recover any deferred postretirement costs by March 2003. The transition obligation for postretirement benefits is being amortized over a period of 20 years.
A 1% increase or decrease in the health care cost inflation rate from assumed rates would have the following effects:
1% Increase | 1% Decrease | |
Effect on total of service and interest cost components | $1 million | $(1 million) |
Effect on postretirement benefit obligation | $17 million | $(15 million) |
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 14. Segment Information
Selected financial information for NYSEG's business segments is presented in the table below. NYSEG's electric delivery segment consists of its regulated transmission, distribution and generation operations. Its natural gas delivery segment consists of its regulated transportation, storage and distribution operations. Other includes NYSEG's corporate assets.
Electric | Natural Gas |
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(Thousands) | ||||
2002 | ||||
Operating Revenues | $1,545,107 | $333,472 | - | $1,878,579 |
Depreciation and Amortization | $79,361 | $18,981 | - | $98,342 |
Operating Income | $267,355 | $61,384 | - | $328,739 |
Interest Charges, Net | $71,951 | $21,370 | - | $93,321 |
Income Taxes | $76,392 | $14,001 | - | $90,393 |
Earnings Available for |
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Total Assets | $2,202,507 | $733,392 | $97,060 | $3,032,959 |
Capital Spending | $64,377 | $25,264 | - | $89,641 |
2001 | ||||
Operating Revenues | $1,689,464 | $348,410 | - | $2,037,874 |
Depreciation and Amortization | $82,394 | $18,689 | - | $101,083 |
Operating Income | $439,689 | $8,836 | - | $448,525 |
Interest Charges, Net | $89,138 | $14,486 | - | $103,624 |
Income Taxes | $157,916 | $(2,220) | - | $155,696 |
Earnings Available for |
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Total Assets | $2,250,852 | $697,280 | $66,291 | $3,014,423 |
Capital Spending | $50,391 | $23,899 | - | $74,290 |
2000 | ||||
Operating Revenues | $1,746,138 | $376,886 | - | $2,123,024 |
Depreciation and Amortization | $91,257 | $18,227 | - | $109,484 |
Operating Income | $436,801 | $32,171 | - | $468,972 |
Interest Charges, Net | $84,211 | $19,068 | - | $103,279 |
Income Taxes | $133,736 | $5,568 | - | $139,304 |
Earnings Available for |
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Total Assets | $2,209,848 | $660,357 | $82,780 | $2,952,985 |
Capital Spending | $57,912 | $20,957 | - | $78,869 |
Notes to Financial Statements
New York State Electric & Gas Corporation
Note 15. Quarterly Financial Information (Unaudited)
Quarter Ended | March 31 | June 30 | September 30 | December 31 | ||
(Thousands) | ||||||
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Operating Revenues | $557,255 | $425,445 | $424,891 | $470,988 | ||
Operating Income | $142,930 | $61,519 | $60,340 | $63,950 | (2) | |
Net Income | $69,621 | $13,145 | (1) | $23,296 | $26,656 | (2) |
Earnings Available for |
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Operating Revenues | $625,461 | $455,540 | $459,994 | $496,879 | ||
Operating Income | $165,149 | $83,319 | $74,154 | $125,903 | ||
Net Income | $79,598 | $33,219 | $32,107 | $49,883 | ||
Earnings Available for |
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(1) Includes the effect of the early retirement of debt that decreased net income $10 million.
(2) Includes the effect of restructuring expenses that decreased operating income $26 million and net income $15 million.
Report of Independent Accountants
To the Shareholder and Board of Directors,
New York State Electric & Gas Corporation
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) on page 154 present fairly, in all material respects, the financial position of New York State Electric & Gas Corporation ("the Company") at December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing in Item 15(a)(2) on page 154 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 statement s in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 1 and 11 to the financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative and hedging activities pursuant to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133). In addition, as discussed in Notes 1 and 3 to the financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
PricewaterhouseCoopers LLP
New York, New York
January 31, 2003
NEW YORK STATE ELECTRIC & GAS CORPORATION
SCHEDULE II - Valuation and Qualifying Accounts
Years Ended December 31, 2002, 2001 and 2000
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(a) Uncollectible accounts charged against the allowance, net of recoveries.
(b) Represents an estimate of the write-offs that will not be recovered in rates.
Selected Financial Data
Rochester Gas and Electric Corporation
2002 | 2001 | 2000 | 1999 | 1998 | |
(Thousands) | |||||
Operating Revenues | $992,940 | $1,039,476 | $1,044,149 | $1,090,448 | $1,033,491 |
Depreciation and amortization | $102,758 | $112,643 | $112,110 | $117,289 | $116,102 |
Other taxes | $89,370 | $87,718 | $90,090 | $112,613 | $117,973 |
Interest Charges, Net | $59,838 | $62,416 | $60,922 | $56,563 | $46,041 |
Net Income | $50,067 | $73,650 | $95,529 | $94,488 | $94,138 |
Capital Spending | $123,591 | $147,639 | $143,544 | $108,245 | $111,625 |
Total Assets | $2,491,412 | $2,453,007 | $2,454,773 | $2,408,787 | $2,461,172 |
Long-term Obligations and |
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Reclassifications: Certain amounts included in Selected Financial Data have been reclassified to conform with the 2002 presentation.
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Liquidity and Capital Resources
Restructuring
See Energy East's Item 7, Restructuring, for this discussion.
Energy East and RGS Energy Merger
See Energy East's Item 7, Energy East and RGS Energy Merger, for this discussion.
Electric Delivery Business
RG&E's electric delivery business consists of its regulated electricity transmission and distribution operations in western New York. It also generates electricity from its one nuclear plant, one coal-fired plant, three gas turbines and several smaller hydroelectric stations.
Regional Transmission Organization: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Transmission Planning and Expansion: See Energy East's Item 7, Electric Delivery Business, for this discussion.
RG&E 2002 Electric and Gas Rate Proceeding: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Ginna Station: 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
Ginna Relicensing: See Energy East's Item 7, Electric Delivery Business, for this discussion.
Sale of RG&E's Interest in NMP2: In November 2001 RG&E sold its 14% interest in NMP2 to Constellation Nuclear. For its share of NMP2, RG&E received at closing $50 million in cash and a $50 million 11% promissory note. On April 12, 2002, Constellation Nuclear paid the remaining balance plus accrued interest on the promissory note. RG&E also received about $2 million in cash for the sale of its share of certain transmission assets related to NMP2. (See Item 8 - Note 9 to RG&E's Financial Statements.)
In October 2001 the NYPSC issued an order approving the sale of NMP2, which provided for the establishment of a regulatory asset of approximately $326 million at the time of closing. RG&E agreed to a one-time $20 million pretax accelerated amortization of the regulatory asset that was recorded in the third quarter of 2001. In addition, RG&E accelerated its recognition of approximately $13 million of previously deferred investment tax credits. RG&E also agreed to amortize the regulatory asset by an additional $30 million per year during the period from the closing of the sale of NMP2 until RG&E's base electric rates are reset. The $30 million annual amortization reflects RG&E's projected savings for its share of NMP2 operating expenses compared to the estimated cost of electricity purchases to replace RG&E's presale share of the output. The terms associated with the recovery of the remaining regulatory asset will be established in future RG&E rate proceedings. The settlement fur ther provides that it constitutes a final and irrevocable resolution of all RG&E ratemaking issues associated with the sale of NMP2 and RG&E's ability to recover through rates the costs associated with its investment in NMP2.
Natural Gas Delivery Business
RG&E's natural gas delivery business consists of transporting, storing and distributing natural gas.
Natural Gas Supply Agreements: See Energy East's Item 7, Natural Gas Delivery Business, for this discussion.
RG&E 2002 Electric and Gas Rate Proceeding: See Electric Delivery Business.
NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 7, Natural Gas Delivery Business, for this discussion.
Other Matters
Accounting Issues
Statement 71: See Energy East's Item 7, Other Matters, Statement 71, for this discussion.
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. RG&E adopted Statement 143 as of January 1, 2003. The adoption of Statement 143 did not have a material effect on RG&E's financial position or results of operations. (See Item 8 - Note 1 to RG&E's Financial Statements.)
Statement 145: See Energy East's Item 7, Other Matters, Statement 145, for this discussion.
Contractual Obligations and Commercial Commitments
At December 31, 2002, contractual obligations and commercial commitments that will become due during the next five years are:
2003 | 2004 | 2005 | 2006 | 2007 | |
(Thousands) | |||||
Contractual Obligations | |||||
Long-term debt | $159,935 | - | - | - | - |
Preferred stock | - | $1,250 | $1,250 | $1,250 | $1,250 |
Operating leases | 3,800 | 3,900 | 3,900 | 3,900 | 3,900 |
NMP2 power purchase agreement | 40,341 | 38,438 | 41,794 | 34,357 | 38,175 |
Capacity contracts - electric | 3,524 | 1,860 | 1,860 | 1,860 | 1,000 |
Nuclear plant obligations |
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Capacity contracts - natural gas | 66,764 | 55,363 | 51,241 | 49,633 | 49,633 |
Total contractual cash obligations | $302,404 | $113,638 | $118,358 | $116,464 | $113,142 |
Other Commercial Commitments | |||||
Lines of credit | $75,000 | - | - | - | - |
Total commercial commitments | $75,000 | - | - | - | - |
RG&E and NYSEG have a joint revolving credit agreement in which they each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2002, RG&E's ratio of earnings before interest expense and income tax to interest expense was 2.3 to 1.0, and its ratio of total indebtedness to total capitalization was 0.52 to 1.00.
Critical Accounting Policies
See Energy East's Item 7, Critical Accounting Policies, for this discussion.
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Investing and Financing Activities
Investing Activities: Capital spending totaled $124 million in 2002, $148 million in 2001 and $144 million in 2000, including nuclear fuel. Capital spending in all three years was financed primarily with internally generated funds and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements and governmental mandates.
Capital spending is projected to be $146 million in 2003, including nuclear. It is expected to be paid for with internally generated funds and will be primarily for the same purposes described above and merger integration. (See Item 8 - Note 8 to RG&E's Financial Statements.)
RG&E's pension plans generated pretax noncash pension income (net of amounts capitalized) of $21 million in 2002, compared to $23 million in 2001 and 2000. RG&E expects noncash pension income (net of amounts capitalized) for 2003 to decline, affecting earnings by approximately $3 million. That expected decrease is due to the significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute its pension liability (reduced from 7% to 6.5% as of December 31, 2002) and return on assets (reduced from 9% to 8.75% effective January 1, 2003). RG&E anticipates minimal funding requirements in 2003 as total plan assets approximates the projected benefit obligation. RG&E is currently unable to predict the effect that future equity market performance will have on pension income for 2004 and beyond. (See Item 8 - Note 12 to RG&E's Financial Statements.)
Financing Activities: In December 2002 RG&E and NYSEG entered into a joint $200 million 364-day revolving credit facility with certain banks. RG&E is permitted to borrow up to $75 million and NYSEG is permitted to borrow up to $150 million under the facility. RG&E had no amounts outstanding under this agreement during 2002.
RG&E uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. RG&E had no such short-term debt outstanding at December 31, 2002 and 2001.
On June 20, 2002, RG&E issued $125 million of 6.65% Series UU first mortgage bonds, due June 2032, the proceeds of which were used to repay short-term debt, for additional capital expenditures and for general corporate purposes.
On December 30, 2002, RG&E received a $50 million equity contribution from its parent, RGS Energy Group, Inc. On January 9, 2003, RG&E used the contribution, along with internally generated funds, to pay off the remaining $80 million balance of a promissory note that was due to mature in 2014.
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Results of Operations
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(Thousands) | |||||
Operating Revenues | $992,940 | $1,039,476 | $1,044,149 | (4%) | - |
Operating Income | $131,759 | $169,749 | $206,401 | (22%) | (18%) |
Earnings Available for |
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Earnings
Earnings for 2002 decreased $24 million primarily due to lower wholesale electric revenues of $16 million largely due to lower wholesale market prices, a $9 million writedown of software development costs that management determined to have no future economic value, an electric price reduction, effective July 1, 2001, that decreased earnings $8 million, and higher replacement power costs of $7 million due to a scheduled refueling outage at the Ginna nuclear plant. There was no refueling outage in 2001. Lower merger-related costs of $8 million and higher electric and natural gas deliveries of about $6 million due to warmer summer weather and a colder heating season increased earnings for 2002.
Earnings for 2001 decreased $22 million primarily due to electric price reductions, effective July 1, 2000, that decreased earnings $12 million and nonrecurring expenses of $10 million related to RGS Energy's merger with Energy East.
Other Items
Other operating expenses includes net periodic pension benefit income of $21 million in 2002 and $23 million in 2001 and 2000. Other operating expenses would have been $2 million lower for 2002 without those changes in net periodic pension benefit income. Net periodic pension benefit income represented 42% of net income for 2002, 32% for 2001 and 24% for 2000. The earnings effect from differences between actual and projected pension benefit income was based on earnings sharing mechanisms approved by the NYPSC.
Other deductions decreased $13 million in 2002 compared to 2001 primarily due to lower merger costs of $10 million. Other deductions increased $17 million in 2001 primarily due to higher merger costs of $14 million. (See Other (Income) and Other Deductions in Item 8 - Note 1 to RG&E's Financial Statements.)
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Operating Results for the Electric Delivery Business
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(Thousands) | |||||
Deliveries - Megawatt-hours |
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Operating Revenues | $705,982 | $728,099 | $721,737 | (3%) | 1% |
Operating Expenses | $604,768 | $594,419 | $547,974 | 2% | 8% |
Operating Income | $101,214 | $133,680 | $173,763 | (24%) | (23%) |
Operating Revenues: The $22 million decrease in operating revenues for 2002 is primarily due to lower wholesale revenues of $24 million largely due to lower market prices and a price reduction, effective July 1, 2001, that reduced revenues $12 million. Those decreases are partially offset by increased retail deliveries of $12 million due to warmer summer weather.
Operating revenues for 2001 increased $6 million primarily due to higher wholesale sales because of increased output from RG&E's generation facilities.
RG&E's electric revenues include $120 million in 2002, $107 million in 2001 and $78 million in 2000 related to energy sales to Energetix.
Operating Expenses: The $10 million increase in operating expenses is primarily due to higher purchased power costs of $46 million as a result of electricity now being purchased instead of generated due to the sale of NMP2 in November 2001 and replacement power that was needed during the scheduled refueling of the Ginna nuclear plant in 2002. There was no refueling outage in 2001. A $10 million writedown of software development costs that management determined to have no future economic value also contributed to the increase. Those increases were partially offset by a $20 million decrease in accelerated amortization associated with a NMP2 regulatory asset and a $21 million decrease in other operating expenses due to the sale of NMP2.
The $46 million increase in operating expenses for 2001 includes a $20 million increase in accelerated amortization associated with a NMP2 regulatory asset, higher purchased power costs of $10 million, largely due to higher market prices, and a $9 million increase in fuel for generation. Generation fuel consumption increased primarily because of higher availability of RG&E's generation plants including Ginna, which had a scheduled refueling during 2000. Other operating expenses for 2001 also increased $5 million for the amortization of the NMP2 regulatory asset beginning in November 2001 and $4 million due to accruals for the 2002 scheduled refueling of Ginna. Those increases were offset by a $6 million decrease in 2001 in the amount set aside to earnings and tax reserves, in accordance with the provisions of a return on equity test in RG&E's Electric Settlement, and a $2 million decrease because of a reduction in RG&E's uncollectible reserve in 2001.
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
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(Thousands) | |||||
Retail Deliveries - Dekatherms | 52,012 | 49,903 | 55,757 | 4% | (10%) |
Operating Revenues | $286,958 | $311,377 | $322,412 | (8%) | (3%) |
Operating Expenses | $256,413 | $275,308 | $289,774 | (7%) | (5%) |
Operating Income | $30,545 | $36,069 | $32,638 | (15%) | 11% |
Operating Revenues: The $24 million decrease in operating revenues for 2002 is primarily due to a $33 million decrease because of lower market prices of gas that are passed on to customers, partially offset by $9 million for higher retail deliveries primarily because of colder winter weather in the fourth quarter of 2002.
The $11 million decrease in operating revenues for 2001 is primarily due to lower market prices of natural gas of $7 million that were passed on to customers and lower retail deliveries of $4 million because of warmer weather.
RG&E's natural gas revenues include $19 million in 2002, $22 million in 2001 and $2 million in 2000 for sales of natural gas to Energetix.
Operating Expenses: Operating expenses for 2002 decreased $19 million primarily due to a decrease in purchased natural gas of $26 million mainly due to lower natural gas prices, which was partially offset by a $4 million writedown of software development costs that management determined to have no future economic value.
Operating expenses for 2001 decreased $14 million primarily due to a $7 million decrease in the cost of natural gas purchased largely due to a lower volume of purchases and a $2 million decrease because of a reduction in RG&E's uncollectible reserve in 2001.
Rochester Gas and Electric Corporation
Balance Sheets
December 31 | 2002 | 2001 |
(Thousands) | ||
Assets | ||
Current Assets | ||
Cash and cash equivalents | $86,385 | $19,462 |
Special deposits | 2,841 | 1,169 |
Accounts receivable, net | 126,227 | 115,587 |
Note receivable | - | 10,097 |
Affiliate receivable | 20,330 | 86,320 |
Fuel, at average cost | 20,555 | 27,005 |
Materials and supplies, at average cost | 6,467 | 5,244 |
Prepayments and other current assets | 35,324 | 22,153 |
Total Current Assets | 298,129 | 287,037 |
Utility Plant, at Original Cost | ||
Electric | 1,919,964 | 1,862,805 |
Natural gas | 515,829 | 496,594 |
Common | 157,416 | 133,825 |
2,593,209 | 2,493,224 | |
Less accumulated depreciation | 1,526,832 | 1,454,283 |
Net Utility Plant in Service | 1,066,377 | 1,038,941 |
Construction work in progress | 133,195 | 141,591 |
Total Utility Plant | 1,199,572 | 1,180,532 |
Other Property and Investments, Net | 226,373 | 222,860 |
Regulatory and Other Assets | ||
Regulatory assets | ||
Nuclear plant obligations | 313,412 | 327,221 |
Unfunded future income taxes | 52,058 | 52,549 |
Environmental remediation costs | 11,290 | 12,588 |
Nonutility generator termination agreement | 160,819 | 169,838 |
Other | 163,655 | 122,910 |
Total regulatory assets | 701,234 | 685,106 |
Other assets | ||
Note receivable | - | 40,387 |
Other | 66,104 | 37,085 |
Total other assets | 66,104 | 77,472 |
Total Regulatory and Other Assets | 767,338 | 762,578 |
Total Assets | $2,491,412 | $2,453,007 |
The notes on pages 137 through 150 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Balance Sheets
December 31 | 2002 | 2001 |
(Thousands) | ||
Liabilities | ||
Current Liabilities | ||
Current portion of long-term debt | $159,935 | $104,387 |
Accounts payable and accrued liabilities | 67,787 | 72,089 |
Affiliate payable | 7,365 | 30,667 |
Interest accrued | 10,509 | 12,338 |
Taxes accrued | 3,451 | 4,381 |
Other | 40,523 | 49,617 |
Total Current Liabilities | 289,570 | 273,479 |
Regulatory and Other Liabilities | ||
Regulatory liabilities | ||
Deferred income taxes | 18,179 | 18,739 |
Other | 56,617 | 38,465 |
Total regulatory liabilities | 74,796 | 57,204 |
Other liabilities | ||
Deferred income taxes | 225,325 | 223,659 |
Nuclear waste disposal | 102,745 | 101,268 |
Other postretirement benefits | 65,983 | 60,238 |
Environmental remediation costs | 22,356 | 22,356 |
Other | 99,036 | 98,426 |
Total other liabilities | 515,445 | 505,947 |
Total Regulatory and Other Liabilities | 590,241 | 563,151 |
Long-term debt | 752,254 | 787,243 |
Total Liabilities | 1,632,065 | 1,623,873 |
Commitments | - | - |
Preferred Stock |
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Common Stock Equity |
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Capital in excess of par value | 555,889 | 505,889 |
Retained earnings | 154,267 | 174,054 |
Treasury stock, at cost (4,379 shares at December 31, 2002 |
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Total Common Stock Equity | 787,347 | 757,134 |
Total Liabilities and Stockholder's Equity | $2,491,412 | $2,453,007 |
The notes on pages 137 through 150 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Statements of Income
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Operating Revenues | |||
Electric | $705,982 | $728,099 | $721,737 |
Natural Gas | 286,958 | 311,377 | 322,412 |
Total Operating Revenues | 992,940 | 1,039,476 | 1,044,149 |
Operating Expenses | |||
Electricity purchased and fuel used |
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Natural gas purchased | 159,170 | 184,690 | 192,038 |
Other operating expenses | 264,930 | 279,549 | 258,727 |
Maintenance | 56,757 | 55,950 | 54,994 |
Depreciation and amortization | 102,758 | 112,643 | 112,110 |
Other taxes | 89,370 | 87,718 | 90,090 |
Total Operating Expenses | 861,181 | 869,727 | 837,748 |
Operating Income | 131,759 | 169,749 | 206,401 |
Other (Income) | (15,950) | (14,808) | (12,289) |
Other Deductions | 6,184 | 19,572 | 2,567 |
Interest Charges, Net | 59,838 | 62,416 | 60,922 |
Income Before Income Taxes | 81,687 | 102,569 | 155,201 |
Income Taxes | 31,620 | 28,919 | 59,672 |
Net Income | 50,067 | 73,650 | 95,529 |
Preferred Stock Dividends | 3,700 | 3,700 | 3,700 |
Earnings Available for Common Stock | $46,367 | $69,950 | $91,829 |
The notes on pages 137 through 150 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Statements of Cash Flows
Year Ended December 31 | 2002 | 2001 | 2000 | |||
(Thousands) | ||||||
Operating Activities | ||||||
Net income | $50,067 | $73,650 | $95,529 | |||
Adjustments to reconcile net income to net cash | ||||||
Depreciation and amortization | 164,833 | 165,248 | 158,152 | |||
Income taxes and investment tax credits deferred, net | (12,838) | (38,417) | (10,022) | |||
Pension income | (21,025) | (23,332) | (22,790) | |||
Writedown of investments | 13,718 | - | - | |||
Accelerated amortization of NMP2 regulatory asset | - | 20,000 | - | |||
Changes in current operating assets and liabilities | ||||||
Accounts receivable, net | (3,410) | 17,457 | (76,615) | |||
Inventory | 5,227 | 9,834 | (8,705) | |||
Prepayments | (14,842) | (10,724) | 3,362 | |||
Accounts payable and accrued liabilities | 820 | 16,971 | 39,737 | |||
Taxes accrued | (930) | (7,545) | 4,510 | |||
Other current liabilities | (10,042) | (16,676) | (2,295) | |||
Other assets | (39,561) | (18,097) | (2,127) | |||
Other liabilities | 18,622 | 26,894 | 22,187 | |||
Net Cash Provided by Operating Activities | 150,639 | 215,263 | 200,923 | |||
Investing Activities | ||||||
Utility plant additions | (122,788) | (152,292) | (143,311) | |||
Sale of generation assets | 50,484 | 52,416 | - | |||
Nuclear generating plant decommissioning fund | (17,362) | (20,736) | (20,736) | |||
Other | (5,661) | (6,948) | (1,503) | |||
Net Cash Used in Investing Activities | (95,327) | (127,560) | (165,550) | |||
Financing Activities | ||||||
Equity contribution from parent | 50,000 | - | - | |||
Repayments of first mortgage bonds and preferred |
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Long-term debt issuances, net of discount or premiums | 125,000 | 199,534 | - | |||
Repayment of promissory notes | (4,522) | (4,073) | (3,781) | |||
Treasury stock acquired, net | - | - | (33,986) | |||
Notes payable three months or less, net | - | (98,000) | 98,000 | |||
Dividends on common and preferred stock | (58,867) | (65,971) | (66,689) | |||
Other | - | 191 | (460) | |||
Net Cash Used in Financing Activities | 11,611 | (72,789) | (36,916) | |||
Net Increase (Decrease) in Cash and Cash Equivalents | 66,923 | 14,914 | (1,543) | |||
Cash and Cash Equivalents, Beginning of Year | 19,462 | 4,548 | 6,091 | |||
Cash and Cash Equivalents, End of Year | $86,385 | $19,462 | $4,548 | |||
The notes on pages 137 through 150 are an integral part of the financial statements.
Rochester Gas and Electric Corporation
Statements of Changes in Common Stock Equity
| Common Stock |
|
|
|
| |
Balance, January 1, 2000 | 38,886 | $194,429 | $505,839 | $137,854 | $(83,252) | $754,870 |
Net income | 95,529 | 95,529 | ||||
Dividends declared | ||||||
Preferred stock | (3,700) | (3,700) | ||||
Common stock | (62,989) | (62,989) | ||||
Treasury stock transactions, net | (33,986) | (33,986) | ||||
Other adjustments | 50 | (510) | (460) | |||
Balance, December 31, 2000 | 38,886 | 194,429 | 505,889 | 166,184 | (117,238) | 749,264 |
Net income | 73,650 | 73,650 | ||||
Dividends declared | ||||||
Preferred stock | (3,700) | (3,700) | ||||
Common stock | (62,271) | (62,271) | ||||
Other adjustments | 191 | 191 | ||||
Balance, December 31, 2001 | 38,886 | 194,429 | 505,889 | 174,054 | (117,238) | 757,134 |
Net income | 50,067 | 50,067 | ||||
Equity contribution from parent | 50,000 | 50,000 | ||||
Dividends declared | ||||||
Preferred stock | (3,700) | (3,700) | ||||
Common stock | (66,154) | (66,154) | ||||
Balance, December 31, 2002 | 38,886 | $194,429 | $555,889 | $154,267 | $(117,238) | $787,347 |
The notes on pages 137 through 150 are an integral part of the financial statements.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 1. Significant Accounting Policies
Background: Rochester Gas & Electric Corporation (RG&E) is primarily engaged in electricity generation, transmission and distribution operations and natural gas transportation and distribution operations in western New York. RG&E is an operating utility of RGS Energy Group, Inc. (RGS Energy). Effective June 28, 2002, RGS Energy became a wholly-owned subsidiary of Energy East Corporation. The acquisition was accounted for under the purchase method of accounting. RGS Energy did not push goodwill down to RG&E.
Accounts receivable:Accounts receivable include unbilled revenues of $59 million at December 31, 2002, and $51 million at December 31, 2001, and are shown net of an allowance for doubtful accounts of $31 million at December 31, 2002, and $29 million at December 31, 2001. Bad debt expense was $9 million in 2002, $5 million in 2001 and $9 million in 2000.
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. Those investments are included in cash and cash equivalents on the balance sheets.
Supplemental Disclosure of |
|
|
|
(Thousands) | |||
Interest, net of amounts capitalized | $58,145 | $61,801 | $58,753 |
Income taxes, net of benefits received (2001 includes $19,780 related to a gain on sale of generation assets) |
|
|
|
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 - 54 years, distribution property - 49 years, generation property - 41 years and other property - 23 years. RG&E's depreciation accruals were equivalent to 3.7% of average depreciable property for 2002, 3.5% for 2001 and 3.0% for 2000.
Estimates: Preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Income taxes: Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.
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 have paid if a separate income tax return had been 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.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Other (Income) and Other Deductions:
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Interest income | $(4,377) | $(4,601) | $(2,602) |
Noncash return | (8,513) | (8,744) | (8,810) |
Miscellaneous | (3,060) | (1,463) | (877) |
Total other (income) | $(15,950) | $(14,808) | $(12,289) |
Merger costs | $4,350 | $13,901 | - |
Miscellaneous | 1,834 | 5,671 | $2,567 |
Total other deductions | $6,184 | $19,572 | $2,567 |
Reclassifications: Certain amounts have been reclassified on the financial statements to conform with the 2002 presentation.
Regulatory assets and liabilities: Pursuant to Statement 71, RG&E capitalizes, as regulatory assets, incurred 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. 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 RGS Energy and Energetix, a subsidiary of RGS Energy. Transactions between RG&E and Energetix are primarily for the purchase of commodity and delivery services for both electricity and natural gas at tariff rates, and for related administrative services. In addition, RG&E provides certain administrative services to RGS Energy. The following table provides a summary of amounts included in RG&E's revenues for sales to Energetix (in millions):
Year Ended December 31 | 2002 | 2001 | 2000 |
Electric revenue | $120 | $107 | $78 |
Natural gas revenue | $19 | $22 | $2 |
RG&E's receivable from Energetix, included in RG&E's balance sheet as an affiliate receivable, consists primarily of electric and natural gas services provided to Energetix's customers, and income tax payments made on behalf of Energetix. RG&E's liability to Energetix, included in RG&E's balance sheet as an affiliate payable, primarily consists of income tax benefits created by Energetix losses in prior years.
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 sales of owned generation are sold to the NYISO, and subsequently repurchased from the NYISO to serve its customers, the transactions are recorded on a net basis in the statements of income.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Risk management: RG&E has a purchased gas adjustment clause that allows it to recover through rates any changes in the market price of purchased natural gas, substantially eliminating RG&E's exposure to natural gas price risk. RG&E uses natural gas futures to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures contracts 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 electricity contracts is included in the amount expensed for electricity purchased when the electricity is sold.
RG&E does not hold or issue financial instruments for trading or speculative purposes.
RG&E recognizes the fair value of its natural gas futures and financial electricity contracts as assets or liabilities on its balance sheets. RG&E's derivative asset was $11 million at December 31, 2002, and its derivative liability was $4 million at December 31, 2002, and $20 million at December 31, 2001. All of these arrangements are designated as cash flow hedging instruments. RG&E defers the fair value of the hedging instruments as regulatory assets or regulatory liabilities.
As of December 31, 2002, the maximum length of time over which RG&E is hedging its exposure to the variability in future cash flows for forecasted transactions is 13 months.
RG&E has commodity purchase and sales contracts for both capacity and energy that have been designated and qualify for the normal purchases and normal sales exception in Statement 133, as amended.
Statement 143: In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability. RG&E adopted Statement 143 as of January 1, 2003. RG&E recognized an asset retirement obligation of approximately $414 million, a regulatory asset of $140 million, a regulatory liability of $1 million, an increase in utility plant of $74 million and a decrease in accumulated depreciation of $201 million. There was no effect on net income. Previously RG&E had recognized $262 million of the obligation as accumulated depreciation.
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 and the cost of removal less salvage are charged to accumulated depreciation.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 2. Restructuring
In the fourth quarter of 2002 Energy East recorded $41 million of restructuring expenses. The restructuring expenses would have been $36 million higher, however RG&E was required by an NYPSC order approving RGS Energy's merger with the company to defer its portion of the restructuring charge for future recovery in rates. The employee positions affected by the restructuring were identified in the fourth quarter of 2002. Included in the amounts deferred by RG&E are $32 million for a voluntary early retirement program that will be paid from RG&E's pension plan and $4 million for an involuntary severance program, primarily for salaried employees.
Those programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by April 30, 2003, including approximately 245 from RG&E. The employees affected by the involuntary severance program were notified in January 2003.
Note 3. Other Intangible Assets
Effective January 1, 2002, RG&E adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As required by Statement 142 RG&E amortizes intangible assets with finite lives (amortized intangible assets) and reviews them for impairment. There was no reclassification of intangible assets as of January 1, 2002. RG&E has no goodwill or intangible assets with indefinite lives.
Other Intangible Assets: 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, 2002 and 2001. Estimated amortization expense for intangible assets is $78 thousand for each of the next five years, 2003 through 2007.
Note 4. Income Taxes
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Current | $44,458 | $67,336 | $69,694 |
Deferred, net |
|
|
|
Pension benefits | 8,373 | 8,396 | 7,877 |
Asset sale gain | (12,391) | 75,709 | 2,580 |
Nuclear decommissioning | (4,785) | (4,717) | (4,508) |
Statement 106 postretirement benefits | (2,418) | (1,810) | (2,293) |
Ginna outage | 1,501 | (3,041) | 318 |
Excess earnings accrual | - | (1,654) | (6,602) |
Unbilled revenue | - | - | 4,326 |
GCA | - | 797 | (3,453) |
Merger accrual | - | (1,826) | - |
Cost of removal | 202 | 2,726 | (1,331) |
Kamine amortization | 1,373 | 2,249 | 1,305 |
Deferred competition implementation | - | (2,349) | 2,359 |
Purchased software and internal development | (5,489) | 5,035 | 112 |
Miscellaneous | (1,243) | (1,843) | (554) |
ITC | (1,695) | (14,928) | (2,141) |
Total | $31,620 | $28,919 | $59,672 |
Notes to Financial Statements
Rochester Gas and Electric Corporation
RG&E 's effective tax rate differed from the statutory rate of 35% due to the following:
Year Ended December 31 | 2002 | 2001 | 2000 |
(Thousands) | |||
Tax expense at statutory rate | $28,590 | $35,899 | $54,320 |
Depreciation and amortization not normalized | 3,210 | 4,820 | 3,503 |
ITC amortization | (1,695) | (14,928) | (2,141) |
State taxes, net of federal benefit | 4,762 | 4,876 | 6,440 |
Cost of removal not normalized | (2,005) | (1,269) | (2,525) |
Audit settlement/reserve for disputed items | (2,032) | (2,334) | (4,059) |
Deferral to equal rate base | 567 | (2,246) | 460 |
Other, net | 223 | 4,101 | 3,674 |
Total | $31,620 | $28,919 | $59,672 |
RG&E 's deferred tax liabilities consisted of the following:
December 31 | 2002 | 2001 |
(Thousands) | ||
Noncurrent Deferred Tax Liabilities | ||
Depreciation | $148,713 | $128,050 |
Unfunded future income taxes | 52,058 | 52,549 |
Accumulated deferred ITC | 16,996 | 18,692 |
Deferred loss on generation plant sale | 123,480 | 142,304 |
Nuclear decommissioning | (44,093) | (40,764) |
Statement 106 postretirement benefits | (23,866) | (21,650) |
Uncollectible accounts | (10,112) | (10,113) |
Excess earnings accrual | (10,553) | (8,256) |
Pension | 6,476 | (2,196) |
Gas demand charges | (3,449) | (3,680) |
Site remediation | (2,848) | (3,348) |
Statement 112 postemployment benefits | (2,677) | (2,685) |
NMP2 outage deferred accounting | (4,782) | (4,925) |
Other | (1,839) | (1,580) |
Total Noncurrent Deferred Tax Liabilities | 243,504 | 242,398 |
Less amounts classified as regulatory liabilities | ||
Deferred income taxes | 18,179 | 18,739 |
Noncurrent Deferred Income Taxes | $225,325 | $223,659 |
RG&E has no federal or state tax credit or loss carryforwards, nor does it have any valuation allowances.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 5. Long-term Debt
At December 31, 2002 and 2001, RG&E 's long-term debt was:
Amount | ||||
Maturity Dates | Interest Rates | 2002 | 2001 | |
(Thousands) | ||||
First mortgage bonds(1) | 2003 to 2032 | 5.84% to 7.45% | $705,500 | $680,500 |
Pollution control securities - fixed | 2033 | 5.95% | 25,500 | 25,500 |
Pollution control notes - variable | 2032 | 0.75% to 1.6% | 101,900 | 101,900 |
Various long-term debt(2) | 2014 | 7.00% | 79,935 | 84,457 |
Unamortized discount on debt | (646) | (727) | ||
912,189 | 891,630 | |||
Less debt due within one year - included in current liabilities | 159,935 | 104,387 | ||
Total | $752,254 | $787,243 | ||
At December 31, 2002, long-term debt, including sinking fund obligations, and capital lease payments (in thousands) that will become due during the next five years are:
2003 | 2004 | 2005 | 2006 | 2007 |
$159,935 | - | - | - | - |
(1) RG&E's first mortgage bonds are secured by a first mortgage lien on substantially all of its properties. Other than the promissory note described below, RG&E has no other secured indebtedness. None of RG&E's other debt obligations are guaranteed or secured by any of its affiliates.
(2) RG&E's promissory note in connection with the Kamine Global Settlement Agreement, collateralized by a mortgage, the lien for which is subordinate to the first mortgage lien. On January 9, 2003, RG&E paid off the remaining balance of this note that was due to mature in 2014.
Cross-default Provision: RG&E has a provision in a participation agreement relating to certain series of pollution control bonds, which provides that default by RG&E with respect to bonds issued under its first mortgage indenture will be considered a default under the participation agreement.
Note 6. Bank Loans and Other Borrowings
RG&E uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. RG&E had no such short-term debt outstanding at December 31, 2002 and 2001.
RG&E and NYSEG have a joint $200 million 364-day revolving credit facility with certain banks, which they entered into in December 2002. RG&E is permitted to borrow up to $75 million under the facility. At RG&E's and NYSEG's option, the interest rate on borrowings is related to the prime rate or the Eurodollar rate. The agreement provides for payment of a commitment fee, which was .15% at December 31, 2002, and .125% at December 31, 2001, under a previous agreement. RG&E had no amounts outstanding under this agreement during 2002.
Notes to Financial Statements
Rochester Gas and Electric Corporation
In their joint revolving credit agreement RG&E and NYSEG each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. 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, 2002, RG&E's ratio of earnings before interest expense and income tax to interest expense was 2.3 to 1.0, and its ratio of total indebtedness to total capitalization was 0.52 to 1.00.
Note 7. Preferred Stock
At December 31, 2002 and 2001, RG&E 's serial cumulative preferred stock was:
| Par |
| Shares Authorized |
| |
Redeemable solely at RG&E's option: | |||||
4% F | $100 | $105.00 | 120,000 | $12,000 | $12,000 |
4.10% H | 100 | 101.00 | 80,000 | 8,000 | 8,000 |
4.75% I | 100 | 101.00 | 60,000 | 6,000 | 6,000 |
4.10% J | 100 | 102.50 | 50,000 | 5,000 | 5,000 |
4.95% K | 100 | 102.00 | 60,000 | 6,000 | 6,000 |
4.55% M | 100 | 101.00 | 100,000 | 10,000 | 10,000 |
Total | $47,000 | $47,000 | |||
Subject to mandatory redemption requirements: | |||||
6.60% V(2) | 100 | 100.00 | 250,000 | $25,000 | $25,000 |
(1) At December 31, 2002, RG&E had 1,280,000 shares of $100 par value cumulative preferred stock, 4,000,000 shares of $25 par value cumulative preferred stock and 5,000,000 shares of $1 par value preference stock authorized but unissued.
(2) This RG&E series is subject to a mandatory sinking fund sufficient to redeem, at par, on March 1 of each year from 2004 through 2008, 12,500 shares, and on March 1, 2009, the balance of the shares. RG&E has the option to redeem up to an additional 12,500 shares on the same terms and dates as applicable to the mandatory sinking fund. In the event RG&E should be in arrears in the sinking fund requirement, RG&E may not redeem or pay dividends on any stock subordinate to the preferred stock.
RG&E had no redemptions or purchases of preferred stock during the three years 2000 through 2002.
Voting rights of preferred shares issued:
Preferred stock redeemable solely at the option of RG&E - 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
Notes to Financial Statements
Rochester Gas and Electric Corporation
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 RG&E's common stock are entitled to one vote per share on all matters.
Note 8. Commitments
Capital spending: RG&E has commitments in connection with its capital spending program. Capital spending is projected to be $146 million in 2003, including nuclear fuel, and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. RG&E 's capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.
Note 9. Nuclear Generation Assets, Insurance and Decommissioning
Sale of Nine Mile Point 2: In November 2001 RG&E sold its 14% interest in NMP2 to Constellation Nuclear. For its share of NMP2, RG&E received at closing $50 million in cash and a $50 million 11% promissory note. On April 12, 2002, Constellation Nuclear paid the remaining balance plus accrued interest on the promissory note. RG&E also received about $2 million in cash for the sale of its share of certain transmission assets related to NMP2. RG&E's 14% share of NMP2's operating expenses until it was sold is included in various categories on the statements of income.
In October 2001 the NYPSC issued an order approving the sale of NMP2, which provided for the establishment of a regulatory asset of approximately $326 million at the time of closing. RG&E agreed to a one-time $20 million pretax accelerated amortization of the regulatory asset that was recorded in the third quarter of 2001. In addition, RG&E accelerated its recognition of approximately $13 million of previously deferred investment tax credits. RG&E also agreed to amortize the regulatory asset by an additional $30 million per year during the period from the closing of the sale of NMP2 until RG&E's base electric rates are reset. The $30 million annual amortization reflects RG&E's projected savings for its share of NMP2 operating expenses compared to the estimated cost of electricity purchases to replace RG&E's presale share of the output. The terms associated with the recovery of the remaining regulatory asset will be established in future RG&E rate proceedings. The sett lement further provides that it constitutes a final and irrevocable resolution of all RG&E ratemaking issues associated with the sale of NMP2 and RG&E's ability to recover through rates the costs associated with its investment in NMP2.
RG&E's pre-existing decommissioning funds for NMP2 were transferred to Constellation, which has taken responsibility for all future decommissioning funding.
Notes to Financial Statements
Rochester Gas and Electric Corporation
The transaction included a power purchase agreement that calls for Constellation to provide electricity to RG&E, at fixed prices, for 10 years. The power purchase agreement is a contract for physical delivery of RG&E's 14% share of 90% of the output from NMP2. RG&E recorded expenses for electricity purchased in 2001 and 2002 in accordance with the agreement at the time the power was physically delivered, at prices pursuant to the agreement. The contract is not required to be marked-to-market, qualifies as non-trading activity and is not considered a derivative instrument because it qualifies for the normal purchases and sales exception.
After the power purchase agreement is completed a revenue sharing agreement will begin. The revenue sharing agreement could provide RG&E additional revenue through 2021, which would mitigate increases in electricity prices. Both agreements are based on plant output. No amounts were recorded under the revenue sharing agreement in 2002 because any benefit that may occur between 2011 and 2021 cannot be estimated. Any benefits from the revenue sharing agreement will be deferred for customers.
Nuclear insurance: The Price-Anderson Act is a federal statute providing, among other things, a limit on the maximum liability of nuclear reactor owners for damages resulting from a single nuclear incident. The public liability limit for a nuclear incident is approximately $9.5 billion and is subject to inflation and changes in the number of licensed reactors. RG&E carries the maximum available commercial insurance of $300 million and participates in the mandatory financial protection pool for the remaining $9.2 billion. Under the Price-Anderson Act, RG&E would be liable for up to $88 million per incident payable at a rate not to exceed $10 million per incident per year.
In addition to the insurance required by the Price-Anderson Act, RG&E also carries nuclear property damage insurance and accidental outage insurance through Nuclear Electric Insurance Limited. Under those insurance policies, RG&E could be subject to assessments if losses exceed the accumulated funds available to the insurers. The maximum amounts of the assessments for the current policy year are $13 million for nuclear property damage insurance and $3 million for accidental outage insurance.
Nuclear plant decommissioning costs: RG&E's estimated liability, in 2003 dollars, for decommissioning Ginna, including spent fuel storage, is $434 million. The amount currently accrued for those costs is recovered by RG&E through its electric rates.
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 service.
The U.S. Environmental Protection Agency and various state environmental agencies, as appropriate, notified RG&E that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at four waste sites. The four sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the four sites, two sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites and two of the sites are also included on the National Priorities List.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Any liability may be joint and several for certain of those sites. RG&E has recorded an estimated liability of $1 million related to the four sites. An estimated liability of $4 million has been recorded related to nine sites where RG&E believes it is probable that it will incur remediation costs, although it has not been notified that it is among the potentially responsible parties. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to RG&E.
RG&E has a program to investigate and perform necessary remediation at its eight sites where gas was manufactured in the past. One site is part of New York's Voluntary Clean-up Program and seven sites are pending addition to that program.
RG&E's estimate for all costs related to investigation and remediation of six of the eight sites ranges from $18 million to $32 million at December 31, 2002. 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 the company, 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, reflected on RG&E 's balance sheets was $18 million at December 31, 2002 and 2001.
RG&E's environmental liability accruals, which are expected to be paid within the next 15 years, have been established on an undiscounted basis. RG&E received insurance settlements during the last three years, which it accounted for as reductions in its related regulatory asset.
Note 11. Fair Value of Financial Instruments
The carrying amounts and estimated fair values of RG&E 's financial instruments included on its balance sheets are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.
December 31 | 2002 | 2002 | 2001 | 2001 |
Carrying | Estimated | Carrying | Estimated | |
(Thousands) | ||||
Investments - classified as |
|
|
|
|
First mortgage bonds | $704,854 | $761,839 | $679,773 | $673,152 |
Pollution control notes - fixed | $25,500 | $24,990 | $25,500 | $25,252 |
Pollution control notes - variable | $101,900 | $101,900 | $101,900 | $100,907 |
Long-term notes | $79,935 | $91,166 | $84,457 | $83,634 |
The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 12. Retirement Benefits
Pension Benefits | Postretirement Benefits | |||
2002 | 2001 | 2002 | 2001 | |
(Thousands) | ||||
Change in projected benefit obligation | ||||
Benefit obligation at January 1 | $494,433 | $487,961 | $91,987 | $85,354 |
Service cost | 7,161 | 6,652 | 1,152 | 1,019 |
Interest cost | 33,769 | 33,717 | 6,200 | 6,145 |
Plan amendments | 2,089 | - | 1,011 | - |
Actuarial loss | 24,997 | 5,317 | 4,278 | 4,454 |
Special termination benefits | 32,086 | - | - | - |
Benefits paid | (41,234) | (39,214) | (5,161) | (4,985) |
Projected benefit obligation at December 31 | $553,301 | $494,433 | $99,467 | $91,987 |
Change in plan assets | ||||
Fair value of plan assets at January 1 | $645,375 | $712,691 | - | - |
Actual return on plan assets | (77,817) | (28,102) | - | - |
Employer contributions | - | - | 5,161 | 4,985 |
Benefits paid | (41,234) | (39,214) | (5,161) | (4,985) |
Fair value of plan assets at December 31 | $526,324 | $645,375 | - | - |
Funded status | $(26,977) | $150,942 | $(99,467) | $(91,987) |
Unrecognized net actuarial loss (gain) | 6,531 | (161,576) | 742 | (3,536) |
Unrecognized prior service cost | 17,522 | 16,981 | 10,375 | 10,432 |
Unrecognized net transition obligation | - | - | 22,367 | 24,853 |
Prepaid (accrued) benefit cost | $(2,924) | $6,347 | $(65,983) | $(60,238) |
RG&E's postretirement benefits were unfunded as of December 31, 2002 and 2001.
Pension Benefits | Postretirement Benefits | |||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |
Weighted-average assumptions | ||||||
Discount rate | 6.5% | 7.0% | 7.25% | 6.5% | 7.0% | 7.25% |
Expected return on plan assets | 9.0% | 8.5% | 8.5% | N/A | N/A | N/A |
Rate of compensation increase | 4.0% | 5.0% | 5.0% | N/A | N/A | N/A |
As of December 31, 2002, RG&E decreased its discount rate from 7.0% to 6.5% and its expected return on plan assets from 9.0% to 8.75% effective January 1, 2003.
RG&E assumed a 10% annual rate of increase in the costs of covered health care benefits for 2003 that gradually decreases to 5% by the year 2006.
Notes to Financial Statements
Rochester Gas and Electric Corporation
Pension Benefits | Postretirement Benefits | |||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |
(Thousands) | ||||||
Components of net periodic | ||||||
Service cost | $7,161 | $6,652 | $6,202 | $1,153 | $1,019 | $962 |
Interest cost | 33,769 | 33,717 | 34,430 | 6,200 | 6,145 | 5,914 |
Expected return on plan assets | (56,589) | (55,985) | (54,021) | - | - | - |
Unrecognized transition obligation | - | - | 376 | 2,485 | 2,485 | 2,485 |
Amortization of prior service cost | 1,548 | 1,406 | 1,406 | 1,068 | 1,068 | 1,068 |
Recognized net actuarial gain | (8,704) | (10,768) | (11,044) | - | - | (78) |
Special termination benefits | 32,086 | - | - | - | - | - |
Deferral for future recovery | (32,086) | - | - | - | - | - |
Net periodic benefit cost | $(22,815) | $(24,978) | $(22,651) | $10,906 | $10,717 | $10,351 |
Net periodic benefit cost is included in other operating expenses on the statements of income. The net periodic benefit cost for postretirement benefits represents the cost RG&E charged to expense for providing health care benefits to retirees and their eligible dependents. RG&E expects to recover any costs related to the transition obligation by 2011. The transition obligation for postretirement benefits is being recognized over a period of 20 years.
A 1% increase or decrease in the health care cost inflation rate from assumed rates would have the following effects:
1% Increase | 1% Decrease | |
Effect on total of service and interest cost components | $29 thousand | $(41 thousand) |
Effect on postretirement benefit obligation | $70 thousand | $(104 thousand) |
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 13. Segment Information
Selected financial information for RG&E's business segments is presented in the table below. RG&E's electric delivery segment consists of its regulated transmission, distribution and generation operations. Its natural gas delivery segment consists of its regulated transportation, storage and distribution operations. Other includes RG&E's corporate assets.
Electric | Natural Gas |
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| |
(Thousands) | ||||
2002 | ||||
Operating Revenues | $705,982 | $286,958 | - | $992,940 |
Depreciation and Amortization | $87,817 | $14,941 | - | $102,758 |
Operating Income | $101,214 | $30,545 | - | $131,759 |
Interest Charges, Net | $49,459 | $10,379 | - | $59,838 |
Income Taxes | $24,169 | $7,451 | - | $31,620 |
Earnings Available for |
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Total Assets | $1,850,461 | $502,305 | $138,646 | $2,491,412 |
Capital Spending | $91,700 | $31,891 | - | $123,591 |
2001 | ||||
Operating Revenues | $728,099 | $311,377 | - | $1,039,476 |
Depreciation and Amortization | $99,979 | $12,664 | - | $112,643 |
Operating Income | $133,680 | $36,069 | - | $169,749 |
Interest Charges, Net | $51,102 | $11,314 | - | $62,416 |
Income Taxes | $20,501 | $8,418 | - | $28,919 |
Earnings Available for |
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|
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Total Assets | $1,846,641 | $475,681 | $130,685 | $2,453,007 |
Capital Spending | $103,801 | $43,838 | - | $147,639 |
2000 | ||||
Operating Revenues | $721,737 | $322,412 | - | $1,044,149 |
Depreciation and Amortization | $99,662 | $12,448 | - | $112,110 |
Operating Income | $173,763 | $32,638 | - | $206,401 |
Interest Charges, Net | $50,045 | $10,877 | - | $60,922 |
Income Taxes | $50,452 | $9,220 | - | $59,672 |
Earnings Available for |
|
|
|
|
Total Assets | $1,914,803 | $456,075 | $83,895 | $2,454,773 |
Capital Spending | $113,151 | $30,393 | - | $143,544 |
Notes to Financial Statements
Rochester Gas and Electric Corporation
Note 14. Quarterly Financial Information (Unaudited)
Quarter Ended | March 31 | June 30 | September 30 | December 31 |
(Thousands) | ||||
2002 | ||||
Operating Revenues | $278,290 | $218,807 | $231,368 | $264,475 |
Operating Income (Loss) | $45,241 | $(2,865) | $35,422 | $53,961 |
Net Income (Loss) | $20,728 | $(17,009) | $17,287 | $29,061 |
Earnings (Loss) Available for |
|
|
|
|
2001 | ||||
Operating Revenues | $330,167 | $226,416 | $228,840 | $254,053 |
Operating Income(1) | $86,726 | $41,481 | $10,787 | $30,755 |
Net Income | $42,888 | $11,515 | $6,336 | $12,911 |
Earnings Available for |
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|
|
|
(1) Certain amounts have been reclassified to conform with the 2002 presentation.
Report of Independent Accountants
To the Shareholder and Board of Directors,
Rochester Gas and Electric Corporation
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) on page 154 present fairly, in all material respects, the financial position of Rochester Gas and Electric Corporation ("the Company") at December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing in Item 15(a)(2) on page 154 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 ac cordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
New York, New York
January 31, 2003
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE II - Valuation and Qualifying Accounts
Years Ended December 31, 2002, 2001 and 2000
| Beginning |
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| End |
(Thousands) | |||||
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(a) RG&E recognizes estimated nonfuel expenses for refueling outages at its Ginna nuclear power plant over the period between refueling outages. RG&E sold its ownership interest in NMP2 in November 2001.
PART III
Item 10. Directors and executive officers of the Registrants
Incorporated herein by reference to the information under the captions "Election of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in Energy East's Proxy Statement, which will be filed with the Commission on or before April 30, 2002.
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 99-1and for RG&E is set forth in RG&E's Exhibit 99-1.
Information regarding executive officers of the registrants is on pages 12, 13 and 14 of this report.
Item 11. Executive compensation
Incorporated herein by reference to the information under the captions "Stock Performance Graph," "Executive Compensation," "Employment, Change in Control and Other Arrangements," "Directors' Compensation" and "Report of Executive Compensation and Succession Committee" in Energy East's Proxy Statement, which will be filed with the Commission on or before April 30, 2002.
Information regarding executive compensation for CMP is set forth in CMP's Exhibit 99-1, for NYSEG is set forth in NYSEG's Exhibit 99-1and for RG&E is set forth in RG&E's Exhibit 99-1.
Item 12. Security ownership of certain beneficial owners and management
Incorporated herein by reference to the information under the captions "Security Ownership of Management" and "Equity Compensation Plan Information" in Energy East's Proxy Statement, which will be filed with the Commission on or before April 30, 2002.
CMP Group, Inc., 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 Group, Inc., a wholly-owned subsidiary of Energy East, is the beneficial owner of 100% of NYSEG's common stock and 100% of RG&E's common stock. Information regarding ownership of equity securities of Energy East is set forth in NYSEG's Exhibit 99-1 and in RG&E's Exhibit 99-1.
Item 13. Certain relationships and related transactions
Incorporated herein by reference to the information under the caption "Election of Directors"
in Energy East's Proxy Statement, which will be filed with the Commission on or before April 30, 2002.
None for CMP, NYSEG or RG&E.
Item 14. 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 a date within 90 days of filing this report. "Disclosure controls and procedures" are controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, within the time periods specified in the Securities and Exchange Commission's rules and forms, is recorded, processed, summarized and reported, and is accumulated and communicated to the company's management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that their respective company's disclosure controls and procedures are effective.
Energy East, CMP, NYSEG and RG&E each maintain a system of internal controls designed to provide reasonable assurance to its management and board of directors regarding the preparation of reliable published financial statements and the safeguarding of assets against loss or unauthorized use. Each company's system of internal controls contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. There were no significant changes in the companies' internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluations, including any corrective actions with regard to significant deficiencies and material weaknesses.
Item 15. Exhibits, financial statement schedule, and reports on Form 8-K
(a) The following documents are filed as part of this report for Energy East and CMP:
(1) Financial statements | ||
a) | Consolidated Balance Sheets as of December 31, 2002 and 2001 | |
b) | For the three years ended December 31, 2002: | |
Consolidated Statements of Income | ||
Consolidated Statements of Cash Flows | ||
Consolidated Statements of Changes in Common Stock Equity | ||
c) | Notes to Consolidated Financial Statements | |
d) | Report of Independent Accountants | |
(2) Financial statement schedule | ||
For the three years ended December 31, 2002 | ||
II. Consolidated Valuation and Qualifying Accounts |
(a) The following documents are filed as part of this report for NYSEG and RG&E:
(1) Financial statements | ||
a) | Balance Sheets as of December 31, 2002 and 2001 | |
b) | For the three years ended December 31, 2002: | |
Statements of Income | ||
Statements of Cash Flows | ||
Statements of Changes in Common Stock Equity | ||
c) | Notes to Financial Statements | |
d) | Report of Independent Accountants | |
(2) Financial statement schedule | ||
For the three years ended December 31, 2002 | ||
II. Valuation and Qualifying Accounts |
Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the Consolidated Financial Statements, Financial Statements or notes thereto.
Exhibits
(a)(1) The following exhibits are delivered with this report:
Registrant | Exhibit No. | Description |
Energy East Corporation | (A)10-16 - | Restricted Stock Plan Amendment No. 1. |
Energy East Corporation | (A)10-17 - | Form of Restricted Stock Award Grant. |
Energy East Corporation | 21 - | Subsidiaries. |
Energy East Corporation | 23 - | Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements. |
Central Maine Power Company | (A)10-24 - | Employment Agreement between the Company and Kathleen A. Case dated May 12, 1999. |
Central Maine Power Company | 21 - | Subsidiaries. |
Central Maine Power Company | 23 - | Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements. |
Central Maine Power Company | 99-1 - | Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, and security ownership of management. |
New York State Electric | 4-7 - | Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002. |
New York State Electric | 4-8 - | First Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002. |
New York State Electric | 4-9 - | Second Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002. |
New York State Electric | 23 - | Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements. |
New York State Electric | 99-1 - | Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, and security ownership of management. |
Rochester Gas and Electric | (A)10-21 - | Form of Severance Agreement, as amended. |
Rochester Gas and Electric | 23 - | Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements. |
Rochester Gas and Electric | 99-1 - | Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, and security ownership of management. |
(a)(2) The following exhibits are incorporated herein by reference:
Registrant | Exhibit No. | Filed in | As Exhibit No. |
Energy East Corporation | 2-1 - | Agreement and Plan of Merger, dated as of February 16, 2001, by and among RGS Energy Group, Inc., the Company and Eagle Merger Corp. - Company's Current Report on Form 8-K dated February 20, 2001 - File No. 1-14766 |
|
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 |
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Energy East Corporation | 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. |
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Energy East Corporation | 3-3 - | By-Laws of the Company as amended April 12, 2001 - Company's 10-Q for the quarter ended March 31, 2001 - File No. 1-14766 |
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Energy East Corporation | 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 |
|
Energy East Corporation | 4-2 - | Second 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 |
|
Energy East Corporation | 4-3 - | 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 |
|
Energy East Corporation | 4-4 - | 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 |
|
Registrant | Exhibit No. | Filed in | As Exhibit No. |
Energy East Corporation | 4-5 - | Fifth Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of April 8, 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. |
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Energy East Corporation | 4-6 - | 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. |
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Energy East Corporation | 4-7 - | 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 |
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Energy East Corporation | 4-8 - | 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 |
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Energy East Corporation | (A)10-1 - | Deferred Compensation Plan for Directors - Company's 10-Q for the quarter ended September 30, 2000 - File No. 1-14766 |
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Energy East Corporation | (A)10-2 - | Amended and Restated Director Share Plan - Company's 10-Q for the quarter ended September 30, 2000 - File No. 1-14766 |
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Energy East Corporation | (A)10-3 - | Deferred Compensation Plan - Director Share Plan - Company's 10-Q for the quarter ended September 30, 2000 - File No. 1-14766 |
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Energy East Corporation | (A)10-4 - | Supplemental Executive Retirement Plan - Company's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766 |
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Energy East Corporation | (A)10-5 - | Supplemental Executive Retirement Plan Amendment No. 1 - Company's 10-K for the year ended December 31, 2001 - File No. |
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Energy East Corporation | (A)10-6 - | Annual Executive Incentive Plan - Company's 10-K for the year ended December 31, 2000 - File No. 1-14766 |
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Energy East Corporation | (A)10-7 - | Annual Executive Incentive Plan Amendment No. 1 - Company's 10-K for the year ended December 31, 2000 - File No. 1-14766 |
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Registrant | Exhibit No. | Filed in | As Exhibit No. |
Energy East Corporation | (A)10-8 - | Annual Executive Incentive Plan Amendment No. 2 - Company's 10-Q for the quarter |
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Energy East Corporation | (A)10-9 - | Long-Term Executive Incentive Share Plan - Company's 10-Q for the quarter ended June 30, 2001 - File No. 1-14766 |
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Energy East Corporation | (A)10-10 - | Long-Term Executive Incentive Share Plan Amendment No. 1 - Company's 10-Q for the quarter ended June 30, 2001 - File |
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Energy East Corporation | (A)10-11 - | Deferred Compensation Plan - Salaried Employees - Company's 10-K for the year ended December 31, 1999 - File No. 1-14766 |
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Energy East Corporation | (A)10-12 - | Employment Agreement dated February 8, 2002, for W. W. von Schack - Company's |
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Energy East Corporation | (A)10-13 - | Employment Agreement dated February 8, 2002, for K. M. Jasinski - Company's 10-K for the year ended December 31, 2001 - File No. 1-14766 |
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Energy East Corporation | (A)10-14 - | Employment Agreement dated March 1, 2002, for M. I. German - Company's 10-K for the year ended December 31, 2001 - File No. |
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Energy East Corporation | (A)10-15 - | Restricted Stock Plan - Company's 10-K for the year ended December 31, 1998 - File No. 1-14766 |
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Energy East Corporation | (A)10-18 - | 2000 Stock Option Plan - Company's 10-Q for the quarter ended June 30, 2000 - File No. |
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Energy East Corporation | (A)10-19 - | 2000 Stock Option Plan Amendment No. 1 - Company's 10-K for the year ended December 31, 2000 - File No. 1-14766 |
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Energy East Corporation | (A)10-20 - | Award Agreement under the 2000 Stock Option Plan - Company's 10-Q for the quarter ended June 30, 2000 - File No. 1-14766 |
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Energy East Corporation | (A)10-21 - | 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 |
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Energy East Corporation | (A)10-22 - | 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 |
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Energy East Corporation | (A)10-23 - | 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 |
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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 |
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Central Maine Power Company | 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 |
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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 |
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Central Maine Power Company | 4-1 - | Indenture, dated as of August 1, 1989, between the Company and The Bank of New York, as Trustee, relating to the Medium- |
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Central Maine Power Company | 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 |
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Central Maine Power Company | 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 |
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Central Maine Power Company | 10-2 - | Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Registration No. |
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Central Maine Power Company | 10-3 - | Amendment No. 1 dated as of March 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554 |
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Central Maine Power Company | 10-4 - | Amendment No. 2 dated as of January 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554 |
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Central Maine Power Company | 10-5 - | Amendment No. 3 dated as of October 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Maine Yankee Atomic Power Company's 10-K for the year ended December 31, 1985 - File No. 1-6554 |
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Central Maine Power Company | 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 |
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Central Maine Power Company | 10-7 - | Capital Funds Agreement dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company - Registration No. 2-32333 |
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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 |
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Central Maine Power Company | 10-9 - | Amendatory Agreement between the Company and Maine Yankee Atomic Power Company dated as of August 6, 1997, amending Company Exhibits 10-2 and 10-6 - Company's 10-K for the year ended December 31, 2001 - File No. 1-5139 |
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Central Maine Power Company | (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 |
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Central Maine Power Company | (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 |
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Central Maine Power Company | (A)10-12 - | Energy East Corporation's Annual Executive Incentive Plan - Energy East Corporation's |
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Central Maine Power Company | (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 |
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Central Maine Power Company | (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 |
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Central Maine Power Company | (A)10-15 - | Energy East Corporation's Restricted Stock Plan - Energy East Corporation's 10-K for the year ended December 31, 1998 - File No. |
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Central Maine Power Company | (A)10-16 - | Energy East Corporation's Restricted Stock Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766 |
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Central Maine Power Company | (A)10-17 - | Energy East Corporation's Form of Restricted Stock Award Grant - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766 |
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Central Maine Power Company | (A)10-18 - | Energy East Corporation's 2000 Stock Option Plan - Energy East Corporation's 10-Q for |
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Central Maine Power Company | (A)10-19 - | Energy East Corporation's 2000 Stock Option Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766 |
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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 |
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Central Maine Power Company | (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 |
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Central Maine Power Company | (A)10-22 - | Employment Agreement between the Company and Curtis I. Call dated June 30, 1997 - Company's 10-K for the year ended December 31, 1998 - File No. 1-5139 |
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Central Maine Power Company | (A)10-23 - | First Amendment dated as of March 18, 1999 to the Employment Agreement between the Company and Curtis I. Call dated June 30, 1997 - Company's 10-K for the year ended December 31, 1999 - File No. 1-5139 |
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New York State Electric | 3-1 - | Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office |
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New York State Electric | 3-2 - | Certificate of Amendment of the Certificate |
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New York State Electric | 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 |
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New York State Electric | 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. |
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New York State Electric | 3-5 - | Certificate of Amendment of the Certificate |
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New York State Electric | 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. |
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New York State Electric | 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 |
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Registrant | Exhibit No. | Filed in | As Exhibit No. |
New York State Electric | 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 |
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New York State Electric | 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 |
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New York State Electric | 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 |
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New York State Electric | 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. |
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New York State Electric | 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 |
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New York State Electric | 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 |
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New York State Electric | 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 |
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New York State Electric | 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 |
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New York State Electric | 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 |
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New York State Electric | 4-1 - | First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (JPMorgan Chase Bank is Successor Trustee) - Registration |
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New York State Electric & Gas Corporation Supplemental Indentures to First Mortgage dated as of
July 1, 1921:
4-2 - | No. 37 - Registration No. 33-31297 | 4-2 |
4-3 - | No. 39 - Registration No. 33-31297 | 4-3 |
4-4 - | No. 43 - Registration No. 33-31297 | 4-4 |
4-5 - | No. 51 - Registration No. 2-59840 | 2-B(46) |
4-6 - | No. 75 - Registration No. 2-59840 | 2-B(70) |
Registrant | Exhibit No. | Filed in | As Exhibit No. | |||
New York State Electric | 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 |
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New York State Electric | 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 |
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New York State Electric | 10-3 - | Asset Purchase Agreement by and among Niagara Mohawk Power Corporation, the Company, Rochester Gas and Electric Corporation, Central Hudson Gas & Electric Corporation and Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000 - Company's 10-K for the year ended December 31, 2000 - File No. 1-3103-2 |
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New York State Electric | (A)10-4 - | 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 |
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New York State Electric | (A)10-5 - | Amendment No. 1 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001 - Company's 10-K for the year ended December 31, 2001 - File No. 1-3103-2 |
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New York State Electric | (A)10-6 - | Amendment No. 2 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001 - Company's 10-Q |
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New York State Electric | (A)10-7 - | Amendment No. 3 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001 - Company's 10-Q |
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New York State Electric | (A)10-8 - | Energy East Corporation's Supplemental Executive Retirement Plan - Energy East Corporation's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766 |
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New York State Electric | (A)10-9 - | Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2001 - File No. 1-14766 |
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New York State Electric | (A)10-10 - | Energy East Corporation's Annual Executive Incentive Plan - Energy East Corporation's |
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Registrant | Exhibit No. | Filed in | As Exhibit No. |
New York State Electric | (A)10-11 - | Energy East Corporation's Annual Executive Incentive Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766 |
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New York State Electric | (A)10-12 - | Energy East Corporation's Annual Executive Incentive Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2001 - File No. 1-14766 |
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New York State Electric | (A)10-13 - | Energy East Corporation's Long-Term Executive Incentive Share Plan - Energy East Corporation's 10-Q for the quarter ended June 30, 2001 - File No. 1-14766 |
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New York State Electric | (A)10-14 - | Energy East Corporation's Long-Term Executive Incentive Share Plan Amendment No. 1 - Energy East Corporation's 10-Q for |
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New York State Electric | (A)10-15 - | Long-Term Executive Incentive Share Plan Deferred Compensation Agreement - Company's 10-K for the year ended December 31, 1995 - File No. 1-3103-2 |
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New York State Electric | (A)10-16 - | Form of Severance Agreement for Senior |
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New York State Electric | (A)10-17 - | Form of Severance Agreement for Senior |
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New York State Electric | (A)10-18 - | Form of Severance Agreement for Senior |
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New York State Electric | (A)10-19 - | Form of Severance Agreement for Senior |
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New York State Electric | (A)10-20 - | Form of Severance Agreement for Vice Presidents - Company's 10-K for the year ended December 31, 1993 - File No. |
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New York State Electric | (A)10-21 - | 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 |
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New York State Electric | (A)10-22 - | Form of Severance Agreement for Vice Presidents Amendment No. 2 - Company's Schedule 14D-9, dated July 30, 1997 |
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New York State Electric | (A)10-23 - | Form of Severance Agreement for Vice Presidents Amendment No. 3 - Company's Schedule 14D-9, dated July 30, 1997 |
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New York State Electric | (A)10-24 - | Form of Amendment to the Company's Severance Agreements - Company's 10-Q |
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Registrant | Exhibit No. | Filed in | As Exhibit No. |
New York State Electric | (A)10-25 - | Employee Invention and Confidentiality Agreement (Existing Executive) - Company's Schedule 14D-9, dated July 30, 1997 |
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New York State Electric | (A)10-26 - | Employee Invention and Confidentiality Agreement (Existing Executive) Amendment No. 1 - Company's Schedule 14D-9, dated July 30, 1997 |
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New York State Electric | (A)10-27 - | Deferred Compensation Plan for Salaried Employees - Company's 10-K for the year ended December 31, 1995 - File No. |
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New York State Electric | (A)10-28 - | Energy East Corporation's Restricted Stock Plan - Energy East Corporation's 10-K for |
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New York State Electric | (A)10-29 - | 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 |
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New York State Electric | (A)10-30 - | 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 |
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New York State Electric | (A)10-31 - | Energy East Corporation's 2000 Stock |
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New York State Electric | (A)10-32 - | Energy East Corporation's 2000 Stock Option Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766 |
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New York State Electric | (A)10-33 - | 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 |
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New York State Electric | (A)10-34 - | 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. |
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Rochester Gas and Electric | 3-1 - | Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office |
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Rochester Gas and Electric | 3-2 - | Certificate of Amendment of the Certificate of Incorporation of the Company under Section 805 of the Business Corporation Law filed |
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Rochester Gas and Electric | 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 |
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Registrant | Exhibit No. | Filed in | As Exhibit No. |
Rochester Gas and Electric | 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 |
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Rochester Gas and Electric | 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 |
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Rochester Gas and Electric | 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. |
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Rochester Gas and Electric | 10-2 - | Agreement dated March 9, 1990 between Company and Mellon Bank, N.A. - |
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Rochester Gas and Electric | 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 |
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Rochester Gas and Electric | 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 |
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Rochester Gas and Electric | 10-5 - | Revenue Sharing Agreement regarding the sale of the Company's interest in Nine Mile Point 2 Nuclear Plant to Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000 - Company's 10-K for the year ended December 31, 2000 - File No. 1-672 |
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Rochester Gas and Electric | 10-6 - | Power Purchase Agreement regarding the sale of the Company's interest in Nine Mile Point 2 Nuclear Plant to Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000 - Company's 10-K for the year ended December 31, 2000 - File No. 1-672 |
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Rochester Gas and Electric | (A)10-7 - | Unfunded Retirement Income Plan Restatement as of July 1, 1995 - Company's 10-K for the year ended December 31, 1995 - File No. 1-672 |
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Rochester Gas and Electric | (A)10-8 - | Employment Agreement, dated June 28, 2002, for Paul C. Wilkens - Company's 10-Q for the quarter ended June 30, 2002 - File |
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Registrant | Exhibit No. | Filed in | As Exhibit No. |
Rochester Gas and Electric | (A)10-9 - | Supplemental Executive Retirement Program effective January 1, 1999 - Company's 10-Q for the quarter ended March 31, 2000 - File No. 1-672 |
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Rochester Gas and Electric | (A)10-10 - | Supplemental Executive Retirement Program Amendment No. 1, effective November 1, 2001 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-672 |
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Rochester Gas and Electric | (A)10-11 - | Supplemental Executive Retirement Program Amendment No. 2, effective May 1, 2002 - Company's 10-Q for the quarter ended June 30, 2002 - File No. 1-672 |
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Rochester Gas and Electric | (A)10-12 - | Supplemental Executive Retirement Benefit Program effective July 1, 1999 - Company's 10-Q for the quarter ended March 31, 2000 - File No. 1-672 |
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Rochester Gas and Electric | (A)10-13 - | Supplemental Executive 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 |
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Rochester Gas and Electric | (A)10-14 - | Supplemental Executive 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 |
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Rochester Gas and Electric | (A)10-15 - | Energy East Corporation's Restricted Stock Plan - Energy East Corporation's 10-K for the year ended December 31, 1998 - File No. 1-14766 |
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Rochester Gas and Electric | (A)10-16 - | Energy East Corporation's Restricted Stock Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766 |
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Rochester Gas and Electric | (A)10-17 - | Energy East Corporation's Form of Restricted Stock Award Grant - Energy East Corporation's 10-K for the year ended December 31, 2002 - File No. 1-14766 |
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Rochester Gas and Electric | (A)10-18 - | Energy East Corporation's 2000 Stock Option Plan - Energy East Corporation's 10-Q for |
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Rochester Gas and Electric | (A)10-19 - | Energy East Corporation's 2000 Stock Option Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2000 - File No. 1-14766 |
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Rochester Gas and Electric | (A)10-20 - | Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan - Energy East Corporation's 10-K for |
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Registrant | Exhibit No. | Filed in | As Exhibit No. |
Rochester Gas and Electric | (A)10-22 - | Separation Agreement and General Release between T.S. Richards, Energy East Corporation and RGS Energy Group, Inc. dated June 28, 2002 - Company's 10-Q for the quarter ended June 30, 2002 - File No. |
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_____________________________
(A) Management contract or compensatory plan or arrangement.
Energy East agrees to furnish to the Commission, upon request, a copy of the following documents. The total amount of securities authorized under each of such documents does not exceed 10% of the total assets of Energy East:
A. | Three-Year Revolving Credit Agreement among Energy East, certain lenders, Bank One, N.A. and Bayerische Landesbank Girozentrale, as Co-Syndication Agents, Citibank, N.A. and Fleet National Bank, as Co-Documentation Agents, and JPMorgan Chase Bank, as Administrative Agent, dated as of July 24, 2002. |
B. | The Southern Connecticut Gas Company's Indenture, dated as of March 1, 1948, with The Bridgeport City Trust Company (now State Street Bank and Trust Company), as Trustee, and Supplemental Indentures related thereto. |
C. | Connecticut Natural Gas Corporation's Issuing and Paying Agency Agreement with The Connecticut National Bank (now State Street Bank and Trust Company) for Medium Term Notes, Series A, dated November 1, 1991. |
D. | Connecticut Natural Gas Corporation's Issuing and Paying Agency Agreement with Shawmut Bank Connecticut, National Association (now State Street Bank and Trust Company) for Medium Term Notes, Series B, dated June 14, 1994, and an Amendment related thereto. |
E. | The Berkshire Gas Company's First Mortgage Indenture and Deed of Trust, dated as of July 1, 1954, with Chemical Corn Exchange Bank (now JPMorgan Chase Bank), and the Supplemental Indenture related thereto. |
F. | The Berkshire Gas Company's Mortgage and Security Agreement, dated as of August 31, 2000, with KeyBank National Association, and Letter Agreement related thereto. |
G. | The Berkshire Gas Company's Term Loan Agreement, dated as of December 14, 1993, with Fleet National Bank, and Amendments related thereto. |
H. | Senior Note Agreement dated as of July 1, 1990 between The Berkshire Gas Company and Allstate Life Insurance Company. |
I. | Senior Note Agreement dated as of November 1, 1996 between The Berkshire Gas Company and First Colony Life Insurance Company. |
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 such agreement does not exceed 10% of the total assets of CMP.
NYSEG agrees to furnish to the Commission, upon request, a copy of the Participation Agreements dated as of June 1, 1987, and December 1, 1988, between NYSEG and New York State Energy Research and Development Authority (NYSERDA) relating to Adjustable Rate Pollution Control Revenue Bonds (1987 Series A), and (1988 Series A), respectively; a copy of the Participation Agreements dated as of March 1, 1985, October 15, 1985, and December 1, 1985, between NYSEG
and NYSERDA relating to Annual Tender Pollution Control Revenue Bonds (1985 Series A), (1985 Series B), and (1985 Series D), respectively, a copy of the Participation Agreements dated as of February 1, 1993, February 1, 1994, June 1, 1994, October 1, 1994, and December 1, 1994, between NYSEG and NYSERDA relating to Pollution Control Refunding Revenue Bonds (1994 Series A), (1994 Series B), (1994 Series C), (1994 Series D), and (1994 Series E), respectively; a copy of the Participation Agreement dated as of December 1, 1993, between NYSEG and NYSERDA relating to Solid Waste Disposal Revenue Bonds (1993 Series A); 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); and a copy of certain supplemental indentures to the First Mortgage dated as of July 1, 1921, as supplemented. The total amount of securities authorized under each of such agreements does no t 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); and a copy of the Participation Agreement dated as of August 1, 1997, between RG&E and New York State Energy Research and Development Authority (NYSERDA) relating to Pollution Control Revenue Bonds, Rochester Gas and Electric Corporation Project (1997 Series A) (1997 Series B), (1997 Series C) and (1998 Series A); and a copy of certain supplemental indentures to the General Mortgage dated September 1, 1918, as supplemented.The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of RG&E.
(b) Reports on Form 8-K
Energy East, CMP, NYSEG and RG&E each filed a report on Form 8-K dated October 24, 2002, to report certain information under Item 5, "Other Events."
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| ENERGY EAST CORPORATION |
| CENTRAL MAINE POWER COMPANY |
| NEW YORK STATE ELECTRIC & GAS CORPORATION |
| ROCHESTER GAS AND ELECTRIC CORPORATION |
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 | |
| PRINCIPAL EXECUTIVE OFFICER |
| PRINCIPAL FINANCIAL OFFICER |
| PRINCIPAL ACCOUNTING OFFICER |
Signatures (Cont'd)
ENERGY EAST CORPORATION, cont'd | |
Date: February 27, 2003 | By /s/Richard Aurelio |
Date: February 27, 2003 | By /s/James A. Carrigg |
Date: February 27, 2003 | By /s/Joseph J. Castiglia |
Date: February 27, 2003 | By /s/Lois B. DeFleur |
Date: February 27, 2003 | By /s/G. Jean Howard |
Date: February 27, 2003 | By /s/David M. Jagger |
Date: February 27, 2003 | By /s/John M. Keeler |
Date: February 27, 2003 | By /s/Ben E. Lynch |
Date: February 27, 2003 | By /s/Peter J. Moynihan |
Date: February 27, 2003 | By /s/Walter G. Rich |
Signatures (Cont'd)
CENTRAL MAINE POWER COMPANY | |
| PRINCIPAL EXECUTIVE OFFICER |
| PRINCIPAL FINANCIAL OFFICER AND |
Date: February 27, 2003 | By /s/Kenneth M. Jasinski |
Date: February 27, 2003 | By /s/Wesley W. von Schack |
Signatures (Cont'd)
NEW YORK STATE ELECTRIC & GAS CORPORATION | |
| PRINCIPAL EXECUTIVE OFFICER |
| PRINCIPAL FINANCIAL OFFICER AND |
Date: February 27, 2003 | By /s/Kenneth M. Jasinski |
Date: February 27, 2003 | By /s/Wesley W. von Schack |
Signatures (Cont'd)
ROCHESTER GAS AND ELECTRIC CORPORATION | |
| PRINCIPAL EXECUTIVE OFFICER |
| PRINCIPAL FINANCIAL OFFICER |
| PRINCIPAL ACCOUNTING OFFICER |
Date: February 27, 2003 | By /s/Kenneth M. Jasinski |
Date: February 27, 2003 | By /s/Wesley W. von Schack |
Certifications
I, Wesley W. von Schack, certify that:
1. I have reviewed this annual report on Form 10-K of Energy East Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 27, 2003 | /s/ Wesley W. von Schack |
Certifications (Cont'd)
I, Kenneth M. Jasinski, certify that:
1. I have reviewed this annual report on Form 10-K of Energy East Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 27, 2003 | /s/ Kenneth M. Jasinski |
Certifications (Cont'd)
I, Sara J. Burns, certify that:
1. I have reviewed this annual report on Form 10-K of Central Maine Power Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 27, 2003 | /s/ Sara J. Burns |
Certifications (Cont'd)
I, Curtis I. Call, certify that:
1. I have reviewed this annual report on Form 10-K of Central Maine Power Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 27, 2003 | /s/ Curtis I. Call |
Certifications (Cont'd)
I, Ralph R. Tedesco, certify that:
1. I have reviewed this annual report on Form 10-K of New York State Electric & Gas Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 27, 2003 | /s/ Ralph R. Tedesco |
Certifications (Cont'd)
I, Sherwood J. Rafferty, certify that:
1. I have reviewed this annual report on Form 10-K of New York State Electric & Gas Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 27, 2003 | /s/ Sherwood J. Rafferty |
Certifications (Cont'd)
I, Paul C. Wilkens, certify that:
1. I have reviewed this annual report on Form 10-K of Rochester Gas and Electric Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 27, 2003 | /s/ Paul C. Wilkens |
Certifications (Cont'd)
I, Joseph Syta, certify that:
1. I have reviewed this annual report on Form 10-K of Rochester Gas and Electric Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 27, 2003 | /s/ Joseph Syta |
EXHIBIT INDEX
Registrant | Exhibit No. | Description |
Energy East Corporation | *2-1 - | Agreement and Plan of Merger, dated as of February 16, 2001, by and among RGS Energy Group, Inc., the Company and Eagle Merger Corp. |
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. |
Energy East Corporation | *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. |
Energy East Corporation | *3-3 - | By-Laws of the Company as amended April 12, 2001. |
Energy East Corporation | *4-1 - | Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of August 31, 2000. |
Energy East Corporation | *4-2 - | Second 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. |
Energy East Corporation | *4-3 - | 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. |
Energy East Corporation | *4-4 - | 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. |
Energy East Corporation | *4-5 - | Fifth Supplemental Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of April 8, 2002 related to the Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of August 31, 2000. |
Energy East Corporation | *4-6 - | 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. |
Energy East Corporation | *4-7 - | Subordinated Indenture between the Company and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, dated as of July 24, 2001. |
Energy East Corporation | *4-8 - | 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. |
Energy East Corporation | *(A)10-1 - | Deferred Compensation Plan for Directors. |
Energy East Corporation | *(A)10-2 - | Amended and Restated Director Share Plan. |
Energy East Corporation | *(A)10-3 - | Deferred Compensation Plan - Director Share Plan. |
Energy East Corporation | *(A)10-4 - | Supplemental Executive Retirement Plan. |
Energy East Corporation | *(A)10-5 - | Supplemental Executive Retirement Plan Amendment No. 1. |
Energy East Corporation | *(A)10-6 - | Annual Executive Incentive Plan. |
Energy East Corporation | *(A)10-7 - | Annual Executive Incentive Plan Amendment No. 1. |
EXHIBIT INDEX (Cont'd)
Registrant | Exhibit No. | Description |
Energy East Corporation | *(A)10-8 - | Annual Executive Incentive Plan Amendment No. 2. |
Energy East Corporation | *(A)10-9 - | Long-Term Executive Incentive Share Plan. |
Energy East Corporation | *(A)10-10 - | Long-Term Executive Incentive Share Plan Amendment |
Energy East Corporation | *(A)10-11 - | Deferred Compensation Plan - Salaried Employees. |
Energy East Corporation | *(A)10-12 - | Employment Agreement dated February 8, 2002, for |
Energy East Corporation | *(A)10-13 - | Employment Agreement dated February 8, 2002, for |
Energy East Corporation | *(A)10-14 - | Employment Agreement dated March 1, 2002, for |
Energy East Corporation | *(A)10-15 - | Restricted Stock Plan. |
Energy East Corporation | (A)10-16 - | Restricted Stock Plan Amendment No. 1. |
Energy East Corporation | (A)10-17 - | Form of Restricted Stock Award Grant. |
Energy East Corporation | *(A)10-18 - | 2000 Stock Option Plan. |
Energy East Corporation | *(A)10-19 - | 2000 Stock Option Plan Amendment No. 1. |
Energy East Corporation | *(A)10-20 - | Award Agreement under the 2000 Stock Option Plan. |
Energy East Corporation | *(A)10-21 - | Award Agreement (February 2001) under the 2000 Stock Option Plan. |
Energy East Corporation | *(A)10-22 - | Energy East Management Corporation Form of Change In Control Agreement. |
Energy East Corporation | *(A)10-23 - | Energy East Management Corporation Form of Employee Invention and Confidentiality Agreement. |
Energy East Corporation | 21 - | Subsidiaries. |
Energy East Corporation | 23 - | Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements. |
Central Maine Power Company | *3-1 - | Articles of Incorporation, as amended. |
Central Maine Power Company | *3-2 - | Articles of Amendment to the Articles of Incorporation. |
Central Maine Power Company | *3-3 - | Amended and Restated By-Laws. |
Central Maine Power Company | *4-1 - | Indenture, dated as of August 1, 1989, between the Company and The Bank of New York, as Trustee, relating to the Medium-Term Notes. |
Central Maine Power Company | *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. |
Central Maine Power Company | *10-1 - | Stockholder Agreement dated as of May 20, 1968 among the Company and the other stockholders of Maine Yankee Atomic Power Company. |
Central Maine Power Company | *10-2 - | Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company. |
Central Maine Power Company | *10-3 - | Amendment No. 1 dated as of March 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company. |
Central Maine Power Company | *10-4 - | Amendment No. 2 dated as of January 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company. |
Central Maine Power Company | *10-5 - | Amendment No. 3 dated as of October 1, 1984 to Power Contract dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company. |
Central Maine Power Company | *10-6 - | Additional Power Contract between the Company and Maine Yankee Atomic Power Company dated as of February 1, 1984. |
EXHIBIT INDEX (Cont'd)
Registrant | Exhibit No. | Description |
Central Maine Power Company | *10-7 - | Capital Funds Agreement dated as of May 20, 1968 between the Company and Maine Yankee Atomic Power Company. |
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. |
Central Maine Power Company | *10-9 - | Amendatory Agreement between the Company and Maine Yankee Atomic Power Company dated as of August 6, 1997, amending Company Exhibits 10-2 and 10-6. |
Central Maine Power Company | *(A)10-10 - | Energy East Corporation's Supplemental Executive Retirement Plan. |
Central Maine Power Company | *(A)10-11 - | Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1. |
Central Maine Power Company | *(A)10-12 - | Energy East Corporation's Annual Executive Incentive Plan. |
Central Maine Power Company | *(A)10-13 - | Energy East Corporation's Annual Executive Incentive Plan Amendment No. 1. |
Central Maine Power Company | *(A)10-14 - | Energy East Corporation's Annual Executive Incentive Plan Amendment No. 2. |
Central Maine Power Company | *(A)10-15 - | Energy East Corporation's Restricted Stock Plan. |
Central Maine Power Company | *(A)10-16 - | Energy East Corporation's Restricted Stock Plan Amendment No. 1. |
Central Maine Power Company | *(A)10-17 - | Energy East Corporation's Form of Restricted Stock Award Grant. |
Central Maine Power Company | *(A)10-18 - | Energy East Corporation's 2000 Stock Option Plan. |
Central Maine Power Company | *(A)10-19 - | Energy East Corporation's 2000 Stock Option Plan Amendment No. 1. |
Central Maine Power Company | *(A)10-20 - | Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan. |
Central Maine Power Company | *(A)10-21 - | Amended and Restated Employment Agreement between the Company, Energy East Corporation and Sara J. Burns dated June 14, 1999. |
Central Maine Power Company | *(A)10-22 - | Employment Agreement between the Company and Curtis I. Call dated June 30, 1997. |
Central Maine Power Company | *(A)10-23 - | First Amendment dated as of March 18, 1999 to the Employment Agreement between the Company and Curtis I. Call dated June 30, 1997. |
Central Maine Power Company | (A)10-24 - | Employment Agreement between the Company and Kathleen A. Case dated May 12, 1999. |
Central Maine Power Company | 21 - | Subsidiaries. |
Central Maine Power Company | 23 - | Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements. |
Central Maine Power Company | 99-1 - | Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, and security ownership of management. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
EXHIBIT INDEX (Cont'd)
Registrant | Exhibit No. | Description |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *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. |
New York State Electric | *3-16 - | By-Laws of the Company as amended June 28, 2002. |
New York State Electric | *4-1 - | First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (JPMorgan Chase Bank is Successor Trustee). |
New York State Electric & Gas Corporation Supplemental Indentures to First Mortgage dated as of
July 1, 1921:
*4-2 - | No. 37 |
*4-3 - | No. 39 |
*4-4 - | No. 43 |
*4-5 - | No. 51 |
*4-6 - | No. 75 |
EXHIBIT INDEX (Cont'd)
Registrant | Exhibit No. | Description | ||||
New York State Electric | 4-7 - | Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002. | ||||
New York State Electric | 4-8 - | First Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002. | ||||
New York State Electric | 4-9 - | Second Supplemental Indenture between the Company and JPMorgan Chase Bank, as Trustee, dated as of November 18, 2002. | ||||
New York State Electric | *10-1 - | Agreement between New York Independent System Operator and Transmission Owners, dated as of December 2, 1999. | ||||
New York State Electric | *10-2 - | Independent System Operator Agreement, dated as of December 2, 1999. | ||||
New York State Electric | *10-3 - | Asset Purchase Agreement by and among Niagara Mohawk Power Corporation, the Company, Rochester Gas and Electric Corporation, Central Hudson Gas & Electric Corporation and Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000. | ||||
New York State Electric | *(A)10-4 - | Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001. | ||||
New York State Electric | *(A)10-5 - | Amendment No. 1 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001. | ||||
New York State Electric | *(A)10-6 - | Amendment No. 2 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001. | ||||
New York State Electric | *(A)10-7 - | Amendment No. 3 to Supplemental Executive Retirement Plan, amended and restated effective August 1, 2001. | ||||
New York State Electric | *(A)10-8 - | Energy East Corporation's Supplemental Executive | ||||
New York State Electric | *(A)10-9 - | Energy East Corporation's Supplemental Executive | ||||
New York State Electric | *(A)10-10 - | Energy East Corporation's Annual Executive Incentive Plan. | ||||
New York State Electric | *(A)10-11 - | Energy East Corporation's Annual Executive Incentive Plan Amendment No. 1. | ||||
New York State Electric | *(A)10-12 - | Energy East Corporation's Annual Executive Incentive Plan Amendment No. 2. | ||||
New York State Electric | *(A)10-13 - | Energy East Corporation's Long-Term Executive Incentive Share Plan. | ||||
New York State Electric | *(A)10-14 - | Energy East Corporation's Long-Term Executive Incentive Share Plan Amendment No. 1. | ||||
New York State Electric | *(A)10-15 - | Long-Term Executive Incentive Share Plan Deferred Compensation Agreement. | ||||
New York State Electric | *(A)10-16 - | Form of Severance Agreement for Senior Vice Presidents. | ||||
New York State Electric | *(A)10-17 - | Form of Severance Agreement for Senior Vice Presidents Amendment No. 1. | ||||
New York State Electric | *(A)10-18 - | Form of Severance Agreement for Senior Vice Presidents Amendment No. 2. | ||||
New York State Electric | *(A)10-19 - | Form of Severance Agreement for Senior Vice Presidents Amendment No. 3. | ||||
New York State Electric | *(A)10-20 - | Form of Severance Agreement for Vice Presidents. | ||||
New York State Electric | *(A)10-21 - | Form of Severance Agreement for Vice Presidents Amendment No. 1. | ||||
New York State Electric | *(A)10-22 - | Form of Severance Agreement for Vice Presidents Amendment No. 2. |
EXHIBIT INDEX (Cont'd)
Registrant | Exhibit No. | Description | ||||
New York State Electric | *(A)10-23 - | Form of Severance Agreement for Vice Presidents Amendment No. 3. | ||||
New York State Electric | *(A)10-24 - | Form of Amendment to the Company's Severance Agreements. | ||||
New York State Electric | *(A)10-25 - | Employee Invention and Confidentiality Agreement | ||||
New York State Electric | *(A)10-26 - | Employee Invention and Confidentiality Agreement (Existing Executive) Amendment No. 1. | ||||
New York State Electric | *(A)10-27 - | Deferred Compensation Plan for Salaried Employees. | ||||
New York State Electric | *(A)10-28 - | Energy East Corporation's Restricted Stock Plan. | ||||
New York State Electric | *(A)10-29 - | Energy East Corporation's Restricted Stock Plan Amendment No. 1. | ||||
New York State Electric | *(A)10-30 - | Energy East Corporation's Form of Restricted Stock Award Grant. | ||||
New York State Electric | *(A)10-31 - | Energy East Corporation's 2000 Stock Option Plan. | ||||
New York State Electric | *(A)10-32 - | Energy East Corporation's 2000 Stock Option Plan Amendment No. 1. | ||||
New York State Electric | *(A)10-33 - | Energy East Corporation's Award Agreement under the 2000 Stock Option Plan. | ||||
New York State Electric | *(A)10-34 - | Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan. | ||||
New York State Electric | 23 - | Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements. | ||||
New York State Electric | 99-1 - | Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, and security ownership of management. | ||||
Rochester Gas and Electric | *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. | ||||
Rochester Gas and Electric | *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. | ||||
Rochester Gas and Electric | *3-3 - | By-Laws of the Company as amended June 28, 2002. | ||||
Rochester Gas and Electric | *4-1 - | General Mortgage to Bankers Trust Company, as Trustee, dated September 11, 1918, and supplements thereto, | ||||
Rochester Gas and Electric | *4-2 - | Supplemental Indenture, dated as of March 1, 1983, between the Company and Bankers Trust Company, as Trustee. | ||||
Rochester Gas and Electric | *10-1 - | Agreement dated February 5, 1980 between the Company and the Power Authority of the State of New York. | ||||
Rochester Gas and Electric | *10-2 - | Agreement dated March 9, 1990 between the Company and Mellon Bank, N.A. | ||||
Rochester Gas and Electric | *10-3 - | Agreement between New York Independent System Operator and Transmission Owners, dated as of December 2, 1999. | ||||
Rochester Gas and Electric | *10-4 - | Independent System Operator Agreement, dated as of December 2, 1999. |
EXHIBIT INDEX (Cont'd)
Registrant | Exhibit No. | Description | ||
Rochester Gas and Electric | *10-5 - | Revenue Sharing Agreement regarding the sale of the Company's interest in Nine Mile Point 2 Nuclear Plant to Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000. | ||
Rochester Gas and Electric | *10-6 - | Power Purchase Agreement regarding the sale of the Company's interest in Nine Mile Point 2 Nuclear Plant to Constellation Energy Group, Inc. and Constellation Nuclear, LLC dated as of December 11, 2000. | ||
Rochester Gas and Electric | *(A)10-7 - | Unfunded Retirement Income Plan Restatement as of July 1, 1995. | ||
Rochester Gas and Electric | *(A)10-8 - | Employment Agreement, dated June 28, 2002, for Paul C. Wilkens. | ||
Rochester Gas and Electric | *(A)10-9 - | Supplemental Executive Retirement Program effective January 1, 1999. | ||
Rochester Gas and Electric | *(A)10-10 - | Supplemental Executive Retirement Program Amendment No. 1, effective November 1, 2001. | ||
Rochester Gas and Electric | *(A)10-11 - | Supplemental Executive Retirement Program Amendment No. 2, effective May 1, 2002. | ||
Rochester Gas and Electric | *(A)10-12 - | Supplemental Executive Retirement Benefit Program effective July 1, 1999. | ||
Rochester Gas and Electric | *(A)10-13 - | Supplemental Executive Retirement Benefit Program Amendment No. 1, effective November 1, 2001. | ||
Rochester Gas and Electric | *(A)10-14 - | Supplemental Executive Retirement Benefit Program Amendment No. 2, effective May 1, 2002. | ||
Rochester Gas and Electric | *(A)10-15 - | Energy East Corporation's Restricted Stock Plan. | ||
New York State Electric | *(A)10-16 - | Energy East Corporation's Restricted Stock Plan Amendment No. 1. | ||
New York State Electric | *(A)10-17 - | Energy East Corporation's Form of Restricted Stock Award Grant. | ||
Rochester Gas and Electric | *(A)10-18 - | Energy East Corporation's 2000 Stock Option Plan. | ||
Rochester Gas and Electric | *(A)10-19 - | Energy East Corporation's 2000 Stock Option Plan Amendment No. 1. | ||
Rochester Gas and Electric | *(A)10-20 - | Energy East Corporation's Award Agreement (February 2001) under the 2000 Stock Option Plan. | ||
Rochester Gas and Electric | (A)10-21 - | Form of Severance Agreement, as amended. | ||
Rochester Gas and Electric | *(A)10-22 - | Separation Agreement and General Release between T.S. Richards, Energy East Corporation and RGS Energy Group, Inc. dated June 28, 2002. | ||
Rochester Gas and Electric | 23 - | Consent of PricewaterhouseCoopers LLP to incorporation by reference into certain registration statements. | ||
Rochester Gas and Electric | 99-1 - | Information regarding directors, Section 16(a) compliance, executive compensation, employment, change in control and other arrangements, and security ownership of management. |
____________________________
* Incorporated by reference.
(A) Management contract or compensatory plan or arrangement.