-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KIeGNDde3jCqqrRqPq2lZ6J8/KGIgdPmcpioRsvgXbyWFw7Z8ntukGO2Z3a1u5uG wWuskrSmOonf3Jon+J2jDQ== 0000916641-01-000349.txt : 20010319 0000916641-01-000349.hdr.sgml : 20010319 ACCESSION NUMBER: 0000916641-01-000349 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010316 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VIRGINIA ELECTRIC & POWER CO CENTRAL INDEX KEY: 0000103682 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 540418825 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-02255 FILM NUMBER: 1570713 BUSINESS ADDRESS: STREET 1: 120 TREDEGAR ST CITY: RICHMOND STATE: VA ZIP: 23219 BUSINESS PHONE: 8047713000 MAIL ADDRESS: STREET 1: 120 TREDEGAR ST CITY: RICHMOND STATE: VA ZIP: 23219 10-K405 1 0001.txt FORM 10-K - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ---------------- FORM 10-K (Mark One) [X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 OR [_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission File Number 1-2255 ---------------- VIRGINIA ELECTRIC AND POWER COMPANY (Exact name of registrant as specified in its charter) Virginia 54-0418825 (I.R.S. Employer Identification Number) (State or other jurisdictionof incorporation or organization) 701 East Cary Street 23219-3932 Richmond, Virginia (Address of principal executive (Zip Code) offices) (804) 771-3000 (Registrant's telephone number, including area code) ---------------- Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange Title of Each Class on Which Registered ------------------- ----------------------- Preferred Stock (cumulative), $100 liquidation value, $5.00 dividend New York Stock Exchange Trust Preferred Securities, $25 liquidation value, 8.05% diviend New York Stock Exchange 7.15% Senior Notes, $25 redemption value New York Stock Exchange 6.70% Senior Notes, $25 redemption value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None ---------------- Indicate by check mark whether the 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 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] The aggregate market value of the voting stock held by non-affiliates of the registrant as of March 2, 2001, was zero. As of March 2, 2001, there were issued and outstanding 171,484 shares of the registrant's common stock, without par value, all of which were held, beneficially and of record, by Dominion Resources, Inc. DOCUMENTS INCORPORATED BY REFERENCE. None - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- VIRGINIA ELECTRIC AND POWER COMPANY
Item Page Number Number - ------ ------ PART I 1.Business.............................................................. 3 The Company........................................................... 3 Organizational Changes................................................ 4 Competition........................................................... 4 Regulation............................................................ 5 Rates................................................................. 10 Capital Requirement and Financing Program............................. 11 Sources of Power...................................................... 12 Sources of Energy Used, Fuel Costs and Operations..................... 13 Future Sources of Power............................................... 14 Interconnections...................................................... 14 Cautionary Factors That May Affect Future Results .................... 15 2.Properties............................................................ 15 3.Legal Proceedings..................................................... 15 4.Submission of Matters to a Vote of Security Holders................... 16 PART II 5.Market for the Registrant's Common Equity and Related Stockholder Matters................................................................ 17 6.Selected Financial Data............................................... 17 7.Management's Discussion and Analysis of Financial Condition and Results of Operations.................................................. 18 Business Segments..................................................... 18 Liquidity and Capital Resources....................................... 18 Capital Requirements.................................................. 19 Results of Operations................................................. 20 Energy Segment........................................................ 23 Delivery Segment...................................................... 24 Electric Industry Issues.............................................. 24 Rate Matters.......................................................... 29 Other Regulatory Matters.............................................. 29 Environmental Matters................................................. 29 Restructuring Costs................................................... 31 Recently Issued Accounting Standards.................................. 31 Market Risk Sensitive Instruments and Risk Management................. 32 7A.Quantitative and Qualitative Disclosures About Market Risk........... 34 8.Financial Statements and Supplementary Data........................... 35 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure................................................... 67 PART III 10.Directors and Executive Officers of the Registrant................... 68 11.Executive Compensation............................................... 71 12.Security Ownership of Certain Beneficial Owners and Management....... 77 13.Certain Relationships and Related Transactions....................... 77 PART IV 14.Exhibits, Financial Statement Schedules, and Reports on Form 8K...... 78
2 PART I ITEM 1. BUSINESS THE COMPANY Virginia Electric and Power Company was incorporated in 1909 as a Virginia public service corporation. Our principal office is located at 701 East Cary Street, Richmond, Virginia 23219-3932. The telephone number is (804) 771-3000. All of our common stock is held by Dominion Resources, Inc., a Virginia corporation (Dominion). Virginia Electric and Power Company (the Company) is a public utility engaged in the power generation and electric service delivery business within a 30,000 square-mile service territory in Virginia and northeastern North Carolina. We supply energy at retail to approximately two million customers. In addition, we sell electricity at wholesale to rural electric cooperatives, power marketers, municipalities and other utilities. Within this document, "the Company" refers to the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and all of our subsidiaries. In Virginia we trade under the name "Dominion Virginia Power." The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population. In North Carolina we trade under the name "Dominion North Carolina Power" and serve retail customers located in the northeastern region of the state, excluding certain municipalities. We also engage in off-system wholesale purchases and sales of electricity, purchases and sales of natural gas, and are developing trading relationships beyond the geographic limits of our retail service territory. The Federal Energy Regulatory Commission (FERC), the State Corporation Commission of Virginia (the Virginia Commission) and the North Carolina Utilities Commission (the North Carolina Commission) are the principal regulators of our electric operations. Various factors are currently affecting the electric utility industry, including increasing competition and related regulatory changes, costs to comply with environmental regulations, and the potential for new business opportunities outside of traditional rate-regulated operations. To meet the challenges of this new competitive environment, we continue to consider new business opportunities, particularly those which allow us to use the expertise and resources developed through our regulated utility experience. Over the past several years we have developed a broad array of "non-traditional" products and services, including wholesale power marketing. We also market our services to other utilities in areas such as nuclear consulting and management and power distribution (i.e., transmission, distribution, engineering and metering services). We continue to focus on new and existing programs to enhance customer satisfaction and energy efficiency. We manage our operations in a manner that requires disclosure of two business segments--Energy and Delivery. Our Energy segment includes our portfolio of generating facilities and power purchase contracts, trading and marketing activities, nuclear consulting services and energy services activities. Our Delivery segment includes bulk power transmission, distribution and metering services and customer service, and continues to be subject to cost-based regulation. The majority of our revenue is provided through bundled rate tariffs. Such revenue is allocated between the Energy and Delivery segments for internal reporting purposes and discussion in this document. Certain activities discussed in Liquidity and Capital Resources currently are not managed at the segment level; however, specific references to segments are made as appropriate. Our discussion of trends and variations generally applies to the Company as a whole. Notwithstanding our use of the business segments described above, we continue to own and operate all of the Company's assets. See Note 23 to the Consolidated Financial Statements for selected financial information about our business segments. 3 We had approximately 8,200 employees as of December 31, 2000. Approximately 3,700 of our employees are represented by the International Brotherhood of Electrical Workers under a contract extending to March 2002. ORGANIZATIONAL CHANGES On January 28, 2000, Dominion, our parent company, completed its acquisition of Consolidated Natural Gas Company (CNG). CNG and its subsidiaries became wholly-owned subsidiaries of Dominion and, as a result, Dominion has become a registered public utility holding company subject to regulation under the Public Utility Holding Company Act of 1935 (1935 Act). In connection with the acquisition, a number of organizational changes were implemented within the Company. Some of these changes were required as a result of Dominion's new status as a 1935 Act company and some were based on business decisions relating to the integration of the merged companies. As part of the acquisition of CNG, Dominion created a subsidiary service company, Dominion Resources Services, Inc. (Services), which provides certain services to Dominion's operating subsidiaries. During 2000, CNG also had a service company, CNG Services, Inc. Effective January 1, 2001, the two service companies were combined into one service company. We provided certain administrative and support services to Services under the Virginia Electric and Power Company Support Agreement between the Company and Services effective January 1, 2000. Since Services was established, we have transferred approximately 1,400 of our employees to Services. In July 2000, the Virginia Commission approved the transfer by the Company of all of its issued and outstanding common stock in VPS Communications, Inc. (VPSC) to Dominion. This transfer took place on August 1, 2000, resulting in VPSC becoming a direct subsidiary of Dominion. Subsequently, VPSC changed its name to Dominion Telecom, Inc. COMPETITION The structure of the electric industry in our service territory and throughout the United States has been relatively stable for many years. Recently, however, there have been both federal and state developments in restructuring regulation and increasing competition. Electric utilities are required to open up their transmission systems for non-discriminatory use by wholesale competitors. In addition, non-utility power marketers now compete with electric utilities in the wholesale generation market. At the federal level, retail competition is under consideration. Some states, including Virginia, have enacted legislation requiring retail competition. Historically, we have had the exclusive right to provide electricity at retail within our assigned service territories in Virginia and North Carolina. As a result, our Company was limited to competition for retail sales to the extent our business customers moved into another utility service territory, used other energy sources instead of electric power, or generated their own electricity. However, during 1998 and 1999, deregulation legislation was enacted in Virginia that established a plan to restructure Virginia's electric utility industry and provided for a phased-in transition to a fully competitive retail electric market during the period January 1, 2002 through January 1, 2004. Pursuant to this legislation, there is a retail choice pilot program now in place within our service territory. See Electric Industry Issues--Retail Access Pilot Program and Transition to Retail Competition under Management Discussion and Analysis of Financial Condition and Results of Operations (MD&A). 4 We continue to participate actively in both the legislative and regulatory processes relating to industry restructuring in an effort to ensure an orderly transition from a regulated environment. We have also responded to the trends toward competition by cutting costs, re-engineering our core business processes and pursuing innovative approaches to serving traditional and future markets. In addition, we are developing certain "non-traditional" products and services in an effort to provide growth in future earnings. For a more thorough review of our changing industry environment, see Electric Industry Issues under MD&A. REGULATION General Many aspects of our business are presently subject to regulation by the Virginia Commission, the North Carolina Commission, FERC, the Environmental Protection Agency (EPA), the Department of Energy (DOE), the Nuclear Regulatory Commission (NRC), the Army Corps of Engineers, the Securities and Exchange Commission (SEC), and other federal, state and local authorities. The Company holds certificates of public convenience and necessity issued by the Virginia Commission and the North Carolina Commission authorizing us to construct and operate the electric facilities now in operation for which certificates are required, and to sell electricity to retail customers. However, we may not construct, or incur financial commitments for construction of, any substantial generating facilities or large capacity transmission lines without the prior approval of various state and federal governmental agencies. The Virginia Commission and the North Carolina Commission regulate the bundled rates of our Energy and Delivery segments for retail electric sales and FERC approves our rates for electric sales to wholesale customers. The following sections discuss various regulatory proceedings in which we are or have recently been involved. Rate specific proceedings are discussed separately in the RATES section below. Virginia The Company is subject to the jurisdiction of the Virginia Commission, which has broad powers of supervision and regulation over public utilities, including rates, service regulations and sales of securities. The following is a description of recent Virginia proceedings. Regional Transmission Entities (RTE) Deregulation legislation requires that Virginia's incumbent electric utilities join or establish regional transmission entities (RTE) by January 1, 2001, and seek authorization from the Virginia Commission to transfer ownership or operational control of their transmission facilities to such RTEs. In July 2000, the Virginia Commission issued regulations governing the transfer of ownership or control of electric transmission assets to RTE. In October 2000, we filed an application with the Virginia Commission seeking authorization to transfer control of our electric transmission facilities to the Alliance Regional Transmission Organization (Alliance RTO). As discussed below, the formation of the Alliance RTO began in connection with FERC initiatives and we expect the RTO to satisfy the RTE requirements under Virginia legislation. 5 Retail Access Pilot Program In 1998, the Virginia Commission issued an Order also instructing the Company and American Electric Power-Virginia, a subsidiary of American Electric Power (AEP), each to design and file a retail access pilot program. In 2000, the Virginia Commission approved our retail access pilot program and issued a final order on the interim rules governing pilot programs. Our pilot program, Project Current Choice, began in September 2000. As of the end of December 2000, over 81,000 customers have volunteered for the pilot and over 20,000 have switched to a competitive service provider. In January 2001, the Virginia Commission established a proceeding to determine the permanent rules for retail access. Metering and Billing Services In July 2000, the Virginia Commission issued an order inviting comments regarding retail electric metering and billing services. As required by statute, the Virginia Commission presented a recommendation and draft plan for retail electric billing and metering services to the Virginia legislative transition task force in December 2000. The Virginia Commission's plan would provide for customer choice for billing services beginning January 1, 2002 subject up to a one year delay if determined necessary by the Virginia Commission. The plan also addressed which costs related to competitive billing services should be recoverable by incumbent utilities and the authority of the Virginia Commission to calculate such costs and determine the most appropriate method of cost recovery. In addition to approving the Virginia Commission's plan for retail electric billing services, the 200l General Assembly also approved a bill containing a provision that the Virginia Commission shall implement the provision of competitive metering services by licensed providers for large industrial and large commercial customers of investor-owned distributors on January 1, 2002, and may approve such services for residential and small business customers of investor-owned distributors on or after January 1, 2003. Separation of Electric Generation and Delivery Operations in Virginia In October 2000, the Virginia Commission issued its Final Order outlining regulations governing the functional separation of incumbent electric utilities' generation, transmission and distribution services. The Order adopted rules for how Virginia's existing monopoly electric utilities should organize themselves to participate in the competitive energy supply market, which begins a phase-in in 2002. The rules govern how utilities can divide themselves so that their generating plants can participate in the competitive market without raising anti-competitive and other concerns. State law requires the utilities to separate their various functions by January 1, 2002. In November 2000, as required by deregulation legislation, the Company filed with the Virginia Commission an application for approval of a functional separation plan. The plan includes: . transfer of generation assets into a separate legal entity, Dominion Generation Corporation; . transfer of rights and obligations under non-utility purchase power contracts to Dominion Generation Corporation; . retention of transmission and distribution assets and operations by Virginia Power, to be known as Dominion Virginia Power. . Dominion Generation Corporation to supply Dominion Virginia Power with electric power during and after the capped rate period under a power purchase agreement to ensure that adequate capacity and energy is available to meet Dominion's capped rate service and default supply obligations; . Planned allocation between Dominion Virginia Power and Dominion Generation Corporation of payment responsibility for existing Virginia Power debt with the objective that ratings on outstanding debt will remain unchanged. 6 The Virginia Commission has set a hearing date in October 2001 to consider the Company's functional separation plan. For additional details on functional separation, see Electric Industry Issues--Separation of Electric Generation and Delivery Operations in Virginia under MD&A. Other Proceedings In January 2000, we filed an application with the Virginia Commission to build and operate two 160 Mw combustion turbine units in Caroline County, Virginia for additional peaking capacity. In May 2000, a hearing was held on our application and the Virginia Commission approved the application in October 2000. We have reached an agreement to terminate three long-term power purchase contracts as part of our ongoing program, which seeks to achieve competitive cost structure at its power generating business. The Virginia Commission and FERC have approved this transaction. However, approval by the SEC is currently pending. For additional discussion on this matter, see SOURCES OF ENERGY USED, FUEL COSTS AND OPERATIONS--Purchases and Sales of Energy. Federal The Federal Power Act subjects the Company to regulation by FERC as a company engaged in the transmission or sale of wholesale electric energy in interstate commerce. The Energy Policy Act of 1992 and FERC's subsequent rulemaking activities allow FERC to order access for third parties to transmission facilities owned by another entity. This authority is limited, however, and does not permit FERC to issue orders requiring transmission access to retail customers. FERC has also issued a number of rules of general applicability for third-party transmission service including Orders 888 and 889. We sell electricity in the wholesale market under our market-based sales tariff authorized by FERC but have agreed not to make wholesale power sales under this tariff to loads located within our service territory. During 2000, we filed applications with FERC to make sales under our market-based sales tariff to loads within our service territory participating in our retail access pilot program and to amend our open-access transmission tariff to accommodate the Virginia retail access pilot program. FERC has accepted both applications. Until authorization is granted by FERC, any sales of wholesale power to loads located within our service territory, other than sales to loads participating in the retail access pilot program are to be at cost-based rates accepted by FERC. In February 2000, FERC finalized regulations (Order No. 2000) to advance the formation of Regional Transmission Organizations (RTO). The regulations require that each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce make certain filings with respect to forming and participating in RTO. The Company, together with AEP, Consumers Energy Company, The Detroit Edison Company and First Energy Corporation, on behalf of themselves and their public utility operating company subsidiaries (Alliance Companies), filed with FERC applications under Sections 205 and 203 of the Federal Power Act for approval of the proposed Alliance RTO. FERC approved most aspects of the Alliance RTO in January 2001. Dayton Power and Light Company, Commonwealth Edison Company, Commonwealth Edison Company of Indiana, Illinois Power Company, Ameren UE and Ameren CIPS have subsequently requested authority to join the Alliance RTO. The United States Congress may consider federal legislation in the near future authorizing or requiring retail competition or repealing the 1935 Act and/or the Public Utility Regulatory Policy Act of 1978. We cannot predict what, if any, definitive actions the Congress may take. North Carolina During 2000, a study commission, established by the North Carolina General Assembly to explore the future of electric service in North Carolina, developed a proposal to provide full retail competition to North 7 Carolina by January 1, 2006, with a phase-in beginning January 1, 2005 of up to 50 percent of each power supplier's customer load. These recommendations were part of a report given to the General Assembly in May 2000. The General Assembly subsequently passed legislation that extended the study commission through 2006 and added Dominion North Carolina Power's CEO, or his designee, to its membership. The study commission continues to meet and review its recommendations to the General Assembly as issues in other states have generated further discussion concerning retail competition. Environmental Both our Energy and Delivery segments face substantial regulation and compliance costs with respect to environmental matters. For discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, see Electric Industry Issues--Environmental Matters under MD&A. From time to time we may be identified as a potentially responsible party (PRP) with respect to a superfund site. EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs, but the parties can then bring contribution actions against each other and seek reimbursement from their insurance companies. As a result of the Superfund Act or other laws or regulations regarding the remediation of waste, we may be required to expend amounts on remedial investigations and actions. We do not believe that any currently identified sites will result in significant liabilities. For a discussion of certain remediation efforts in which we are involved, see Note 20 to Consolidated Financial Statements. In accordance with applicable Federal and state environmental laws, we have applied for or obtained the necessary environmental permits material to the operation of our generating stations. Many of these permits are subject to re- issuance and continuing review. During 2000,we received a Notice of Violation (NOV) from the EPA, alleging that we failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at our Mt. Storm Power Station in West Virginia. Also in 2000, the Attorney General of New York filed a suit alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. We also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. Violations of the Clean Air Act may result in substantial civil penalties and injunctive relief. Although we believe that we have obtained the permits necessary in connection with our generating facilities, we have reached an agreement in principle with the federal government and the state of New York to resolve the situation. This agreement in principle includes a 12 year, $1.2 billion capital investment program that will include the installation of state-of-the-art emissions-control equipment on its largest coal-fired generating units in Virginia and West Virginia. The highlights of the agreement, which includes several major environmental improvement efforts already under way are: . Installation of two scrubbers to be operational by 2002 that will remove up to 95 percent of all sulfur dioxide emissions at Mt. Storm Power Station in West Virginia. . Installation of equipment to reduce nitrogen oxide emissions on all three units at Mt. Storm. . Installation of two scrubbers at Chesterfield Power Station, near Richmond, Va. . Installation of NOx control equipment on three units at Chesterfield Power Station. . Installation of NOx control equipment on two units at Chesapeake Energy Center in Chesapeake, Va. . Conversion of two units at Possum Point Power Station near Washington, D.C., from coal-fired generation to natural gas-fired generation. The company filed with the Virginia Commission this past spring for permission to begin that conversion, which should be completed by 2003. 8 . Payment of a $5 million civil penalty to resolve issues at Mt. Storm. . Commitment of $14 million for major environmental programs or projects in cooperation with the states of Virginia, West Virginia, Connecticut, New Jersey, and New York. Under the agreement in principle, the Company will begin making major reductions in its nitrogen oxide emissions in 2004. In December 2000, EPA issued a decision that it would move forward in developing regulations to control the emissions of mercury from coal-fired electric generating units. EPA expects to issue a final ruling by December 2004, with implementation/compliance expected to be required by 2007. Depending upon the level of reduction required and the flexibility allowed to comply with the reduction requirements, these regulations could require the installation of control technology to reduce mercury emissions in the future. For additional information regarding environmental matters, see Item 3, LEGAL PROCEEDINGS and Electric Industry Issues--Environmental Matters under MD&A. Nuclear Generation All aspects of the operation and maintenance of our nuclear power stations, which are a part of our Energy segment, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires. From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining our nuclear generating units. One of the issues associated with the operation and decommissioning of nuclear facilities is disposal of spent nuclear fuel (SNF). The Nuclear Waste Policy Act of 1982 required the federal government to make available by January 31, 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel. Despite ongoing proceedings and investigations, the federal government has not made such a repository available. Most recently, we joined approximately 17 other electric utilities in a petition for review in the U.S. Court of Appeals for the 11th Circuit, challenging the DOE's action in allowing PECO Energy Company (PECO) to take credits against payments PECO would otherwise make into the Nuclear Waste Fund (NWF). The credits are part of a DOE settlement agreement with PECO for potential claims arising out of DOE's breach of its 1998 obligation to begin taking SNF for storage. The petition asserts that DOE violated the Nuclear Waste Policy Act (NWPA) by improperly depleting the NWF and releasing PECO from a portion of its NWF obligation. The petition seeks a declaration that credits against NWF payments to offset on-site SNF storage costs violate the NWPA, an injunction against DOE implementing the credit and fee reduction provisions of the settlement agreement, and an injunction against DOE entering into similar agreements. We initiated the license renewal process for our nuclear power plants in mid-1999 with expected submission to the NRC in 2001. If successful, NRC renewed licenses will extend the operation of our four nuclear units to 2032, 2033, 2038 and 2040 for Surry Units 1 and 2 and North Anna Units 1 and 2, respectively. When our nuclear units cease to operate, we will be obligated to decontaminate the facilities. This process is referred to as decommissioning, and we are required by the NRC to prepare for it financially. For information on our compliance with the NRC financial assurance requirements, see Note 8 to Consolidated Financial Statements. 9 RATES The majority of our revenue is provided through bundled rate tariffs. Accordingly, the following discussion applies to both our Energy and Delivery segments. Our 2000 electric service sales included 73 million megawatt-hours of retail sales and 4.3 million megawatt-hours of sales to wholesale requirements contract customers and were composed of the following:
2000 ------------------------------- Percent of Electric Service ------------------------------- Revenue Kwh Sales ------------- -------------- Virginia retail: Non-Governmental customers............ Virginia Commission 81% 77% Governmental customers............ Negotiated Agreements 10 13 North Carolina retail... North Carolina Commission 5 4 Wholesale*.............. FERC 4 6 ------------- ------------- 100% 100% ============= =============
- -------- * Excludes power marketing sales which are also subject to FERC regulation. Substantially all of our electric service sales are currently subject to recovery of changes in fuel costs through fuel adjustment factors. On November 27, 2000, the Company filed an application with the Virginia Commission to propose an alternative fuel recovery method for the period January 1, 2002-- July 1, 2007. The proposed method would utilize a portfolio of fuel indices, rather than actual incurred fuel costs, in the development of the Virginia fuel factor. Virginia Recent Virginia proceedings related to our rates include the following: The Company's base (non-fuel) rates in Virginia are currently capped until July 1, 2007, according to legislation passed in the 1998 session of the General Assembly. In December 2000, the Company filed an application with the Virginia Commission for approval of unbundled tariffs that reflect distribution rates and wires charges for the recovery of stranded costs. These proposed rates are requested to become effective for usage on and after January 1, 2002. In December 2000, the Company filed an application with the Virginia Commission to increase its Virginia fuel factor from 1.339c per kWh to 1.613c per kWh or an estimated annual increase of $158 million. These new rates went into effect on January 1, 2001, on an interim basis, for usage on and after January 1, 2001 pending a hearing scheduled for March 1, 2001. In July 2000, the Virginia Commission issued an order to modify our cogeneration and small power production rates under Schedule 19. The order sustained our proposed method to determine avoided costs, agreed with our position that off system sales should be excluded from the calculation of avoided costs, and that the cogeneration rate should be effective through 2001. In September 2000, we filed a revised Schedule 19 as required by the Virginia Commission's July 2000 Order, and in November 2000 the Virginia Commission accepted for filing our revised Schedule 19 Tariff. 10 North Carolina In support of Dominion's request for approval by the North Carolina Commission of its acquisition of CNG, the Company and Dominion reached an agreement with the North Carolina Commission whereby we agreed not to request an increase in North Carolina retail electric base rates for both our Energy and Delivery segments until after December 31, 2005, except for certain events that would have a significant financial impact on the Company. Such events could include any governmental action or an occurrence that is beyond our control and not attributable to our fault or negligence. However, fuel rates are still subject to change under the annual fuel cost adjustment proceedings. CAPITAL REQUIREMENTS AND FINANCING PROGRAM Capital And Nuclear Fuel Expenditures Our estimated capital and nuclear fuel expenditures for the three-year period 2001-2003 total $1.4 billion for the Energy segment and $1.1 billion for the Delivery segment. The estimated 2001 construction and nuclear fuel expenditures amount to $831 million consisting of $438 million for the Energy segment and $393 million for the Delivery segment. Financing Program We intend to finance the above expenditures through current operations and the issuance of additional securities as necessary. See Liquidity and Capital Resources section of MD&A for details about our financing program. 11 SOURCES OF POWER Generating Units
Summer Years Capability Installed Type Of Fuel MW --------- -------------- ---------- Name of Station, Units and Location ----------------------------------- Nuclear: Surry Units 1 & 2, Surry, Va............. 1972-73 Nuclear 1,625 North Anna Units 1 & 2, Mineral, Va...... 1978-80 Nuclear 1,842(a) ------ Total nuclear stations............... 3,467 ------ Fossil Fuel: Steam: Bremo Units 3 & 4, Bremo Bluff, Va....... 1950-58 Coal 227 Chesterfield Units 3-6, Chester, Va...... 1952-69 Coal 1,229 Clover Units 1 & 2, Clover, Va........... 1995-96 Coal 882(b) Mt. Storm Units 1-3, Mt. Storm, W. Va.... 1965-73 Coal 1,587 Chesapeake Units 1-4, Chesapeake, Va..... 1953-62 Coal 595 Possum Point Units 3 & 4, Dumfries, Va... 1955-62 Coal 322 Yorktown Units 1 & 2, Yorktown, Va....... 1957-59 Coal 326 Possum Point Units 1, 2, & 5, Dumfries, Va...................................... 1948-75 Oil 929 Yorktown Unit 3, Yorktown, Va............ 1974 Oil & Gas 818 North Branch Unit 1, Bayard, W. Va....... 1994 Waste Coal 74 Combustion Turbines: 39 units (9 locations)................... 1967-70 Oil & Gas 1,595(c) Combined Cycle: Bellmeade, Richmond, Va.................. 1991 Oil & Gas 230 Chesterfield Units 7 & 8, Chester, Va.... 1990-92 Oil & Gas 397 ------ Total fossil stations................ 9,211 ------ Hydroelectric: Gaston Units 1-4, Roanoke Rapids, N.C.... 1963 Conventional 225 Roanoke Rapids Units 1-4, Roanoke Rapids, N.C..................................... 1955 Conventional 99 Other.................................... 1930-87 Conventional 3 Bath County Units 1-6, Warm Springs, Va.. 1985 Pumped Storage 1,260(d) ------ Total hydro stations................. 1,587 ------ Total generating unit capability..... 14,265 Net Purchases.............................. 145 Non-Utility Generation (power purchase contracts)................................ 3,973 ------ Total Capability..................... 18,383 ======
- -------- (a) Includes an undivided interest of 11.6 percent (213.7 Mw) owned by Old Dominion Electric Cooperative (ODEC). (b) Includes an undivided interest of 50 percent (441 Mw) owned by ODEC. (c) Includes the four new Remington combustion turbine units that began operations in July 2000. (d) Reflects Virginia Power's 60 percent undivided ownership interest in the 2,100 Mw station. A 40 percent undivided interest in the facility is owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc. (AE). The Company's highest one-hour integrated service area summer and all-time peak demand was 16,216 Mw on July 6, 1999, and an all-time high one-hour integrated winter peak demand of 15,072 Mw was reached on January 28, 2000. 12 SOURCES OF ENERGY USED, FUEL COSTS AND OPERATIONS For information as to energy supply mix and the average fuel cost of energy supply, see Results of Operations under MD&A. Nuclear Operations and Fuel Supply In 2000, our four nuclear units achieved a combined capacity factor of 95.1 percent. We utilize both long-term contracts and spot purchases to support our needs for nuclear fuel. We continually evaluate worldwide market conditions in order to ensure a range of supply options at reasonable prices. Current agreements, inventories and spot market availability will support our current and planned fuel supply needs for fuel cycles into the early 2000's. Beyond that period, additional fuel will be purchased as required to ensure optimum cost and inventory levels. In March 1999, the Company, along with a consortium of companies, was awarded a contract by DOE for mixed oxide (MOx) fuel fabrication and reactor irradiation services. We have determined that MOX fuel can be used safely and can potentially lower fuel costs. Furthermore, this program will improve international security by reducing plutonium stockpiles. Certain plant and site/facility modifications must be implemented to receive and utilize MOx fuel. DOE will reimburse the Company for all plant and site/facility modifications as well as other MOx fuel implementation costs. We expect to provide irradiation services beginning September 2007. The DOE did not begin the acceptance of SNF in 1998 as specified in our contract with the DOE. However, on-site SNF pool and dry container storage at the Surry and North Anna Power Stations is expected to be adequate for our needs until the DOE begins accepting SNF. For details on the issues of decommissioning and nuclear insurance, see Note 8 to Consolidated Financial Statements. Fossil Fuel Supply The fuel mix utilized by our Energy segment fossil operations consists of coal, oil, and natural gas. During 2000, we burned approximately 14 million tons of coal. We utilize both long-term contracts and spot purchases to support our coal needs. We presently anticipate sufficient supplies of coal will be available at reasonable prices but market prices and price volatility will be higher. Coal producers, for the past two decades, have over-supplied the market. As a result, market prices in the past have remained relatively stable, even during periods when utility demand has spiked. However, coal markets have become more supply demand balanced and will likely lead to more price volatility in the future. Oil and oil-fired generation are used primarily to support heavier system generation loads during very cold or very hot weather periods. System requirements are purchased under both short term spot agreements and longer term contracts. A sufficient supply of oil is expected over the next five to ten year period. We use natural gas as needed throughout the year for our jurisdictional and non-jurisdictional facilities. Dominion has the capability to buy and store natural gas at summer prices, which will then be consumed at the facilities during the winter. Dominion's storage capability helps to provide a low fixed cost winter supply of natural gas to the facilities during a time that has traditionally shown upward price volatility. Firm natural gas transportation contracts (Capacity) exist that allow delivery of gas to our facilities. Dominion has positioned its Capacity portfolio in such a way that allows flexible natural gas deliveries to our gas turbine fleet, while minimizing costs. With natural gas being the preferred source of new electric generation, competition for existing gas capacity has increased. In order to ensure reliable delivery of natural gas, Dominion has acquired more natural gas capacity and has a rolling seven year capacity plan in place that will protect its fleet from any perceived or real capacity shortage in the market. 13 Purchases and Sales of Energy Our Energy segment purchases electricity under contracts with other suppliers to meet a portion of our own system capacity requirements and makes other wholesale electric power transactions in the eastern United States. In addition to wholesale electric power transactions, we actively participate in the purchase and sale of natural gas in the open market. From the mid-1980's until the start of the 1990's, we entered into a number of long-term purchase contracts for electricity now associated with our Energy segment. At the end of 1999, 900 Mw of these purchases from other utilities ended, and by the end of the first quarter of 2000, an additional 200 Mw of diversity exchange transactions will be suspended. As of December 31, 2000, we had 54 power purchase contracts with a combined dependable summer capacity of 3,973 Mw. For information on the financial obligations under these agreements, see Note 20 to Consolidated Financial Statements. The Company has reached an agreement, pending regulatory approvals, to terminate three long-term power purchase agreements. Dominion expects the transaction to be completed in the first quarter of 2001, resulting in a one- time, non-operating charge of approximately $135 million, after taxes. The transaction is part of an ongoing program which seeks to achieve competitive cost structures at its power generating business. FUTURE SOURCES OF POWER In January 2000, we filed an application with the Virginia Commission to build and operate two 160 Mw combustion turbine units in Caroline County, Virginia for additional peaking capacity. We have obtained the applicable zoning permits for the construction of the generators and have applied for other required environmental permits. The Virginia Commission approved the project in October 2000. The units are expected to be operational by the summer of 2001. In June 2000, we filed an application with the Virginia Commission to make a number of changes to the Possum Point Power Station designed to improve air quality and to meet existing and proposed air emission limitations in Northern Virginia. We have proposed the retirement of two coal-fired units; conversion of two other coal-fired units to gas and the addition of one combined cycle unit to be operational by May 2003. The Virginia Commission held a hearing on the matter in January 2001. INTERCONNECTIONS Our Delivery segment maintains major interconnections with Carolina Power and Light Company, AEP, AE and the utilities in the Pennsylvania-New Jersey- Maryland Power Pool. Through this major transmission network, we have arrangements with these utilities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy. In June 1999, the Company, together with AEP, Consumers Energy Company, The Detroit Edison Company and First Energy Corporation, on behalf of themselves and their public utility operating company subsidiaries, filed with FERC for the approval of an RTE. See REGULATION--Virginia and Federal above for a discussion of state and federal laws and proceedings relating to the establishment of RTE's and RTO's. 14 CAUTIONARY FACTORS THAT MAY AFFECT FUTURE RESULTS (Cautionary statements under the Private Securities Litigation Reform Act of 1995) Our disclosure and analysis in this report contain some "forward-looking statements." Forward-looking statements give our current expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. In particular, these include statements relating to future actions, a broad spectrum of regulatory approvals, future performance or results of current and anticipated generation capacity, growth in customer base, and the outcome of contingencies such as legal proceedings. From time to time, we also may provide oral or written forward-looking statements in other materials we release to the public. Any or all of our forward-looking statements in this report or in any other public statements that we make may turn out to be wrong. They can be affected by inaccurate assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in the discussion above - for example, government regulations, organizational and operations restructuring, competition, weather, trading risks - will be important in determining future results. Consequently, no forward-looking statement can be guaranteed. Actual future results may vary materially. We encourage you to read thoroughly Management's Discussion and Analysis of Financial Condition and Results of Operations and its Forward-Looking Statements. We undertake no obligation to publicly update forward-looking statements, whether as a result of new information, future events or otherwise. You are advised, however, to consult any further disclosures we make on related subjects in our 10-Q and 8-K reports to the SEC. ITEM 2. PROPERTIES We own our principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of our property is subject to the lien of a mortgage securing our First and Refunding Mortgage Bonds. In connection with our Delivery segment, right-of-way grants from the apparent owners of real estate have been obtained for most of our electric lines, but underlying titles have not been examined except for transmission lines of 69 Kv or more. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly owned property, as to which permission for use is generally revocable. Portions of our transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line if any exists. Our Energy segments and Delivery segments share certain leased buildings and equipment. See Generating Units-SOURCES OF POWER under Item 1. BUSINESS for a list of the principal facilities utilized by our Energy segment. ITEM 3. LEGAL PROCEEDINGS From time to time, we are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. From time to time, there may be pending administrative proceedings on these matters. In addition, in the normal course of 15 business, we are involved in various legal proceedings. We believe that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations. See REGULATION and RATES under Item 1. BUSINESS for information on various regulatory proceedings to which we are a party. Environmental Matters In 1999, we were notified by the Department of Justice of alleged noncompliance with the EPA's oil spill prevention, control and countermeasures (SPCC) plans and facility response plan (FRP) requirements at one of our power stations. If, in a legal proceeding, such instances of noncompliance are deemed to have occurred, we may be required to remedy any alleged deficiencies and pay civil penalties. Settlement of this matter is currently in negotiation and is not expected to have a material impact on our Company's financial condition or results of operations. We also identified matters at certain other power stations that the EPA might view as not in compliance with the SPCC and FRP requirements. We reported these matters to the EPA and our plan for correcting them. The EPA has not assessed any penalties against us, pending its review of the disclosure information. Future resolution of these matters is not expected to have a material impact on the Company's financial condition or results of operations. Clean Air Act Matters During 2000, we received a Notice of Violation (NOV) from the EPA alleging that we failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at our Mt. Storm Power Station in West Virginia. EPA alleges that each of these projects resulted in an increase in the emission of air pollutants beyond levels that require a New Source Review permit specified under the Clean Air Act. Also in 2000, the Attorney General of New York filed a suit alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. We also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. Violations of the Clean Air Act may result in the imposition of substantial civil penalties and injunctive relief. Although we believe that we have obtained the permits necessary in connection with our generating facilities, we have reached an agreement in principle with the federal government and the state of New York to resolve this situation. The agreement in principle includes payment of a $5 million civil penalty, a commitment of $14 million for major environmental projects in Virginia, West Virginia, Connecticut, New Jersey, and New York, and a 12-year, $1.2 billion capital investment program for environmental improvements at the Company's coal-fired generating stations in Virginia and West Virginia. Although we have reached an agreement in principle, the terms of a final binding settlement are still being negotiated. See Note 20 to the Consolidated Financial Statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None 16 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Dominion Resources, Inc. (Dominion) owns all of the Company's common stock. The Company paid quarterly cash dividends on its common stock as follows:
1st 2nd 3rd 4th --- --- ---- --- (Millions) 2000........................................................... $93 $94 $160 $61 1999........................................................... 99 95 92 97
ITEM 6. SELECTED FINANCIAL DATA
1997 1996 2000 1999 (/3/) 1998 (/2/) (/1/) (/1/) ------ ------ ------ ------ ------ (Millions) Operating revenue and income........ $4,791 $4,591 $4,280 $4,664 $4,382 Income from operations.............. 1,086 1,007 681 1,015 1,000 Income before extraordinary item and cumulative effect of a change in accounting principle............... 558 485 230 469 457 Extraordinary item (net of income taxes of $197)..................... 255 Cumulative effect of a change in accounting principle (net of income taxes of $11)...................... 21 Net income.......................... 579 230 230 469 457 Balance available for common stock.. 543 193 194 433 422 Total assets........................ 13,331 11,765 11,985 11,925 11,828 Long-term debt, noncurrent capital lease obligations, preferred stock subject to mandatory redemption and preferred securities of subsidiary trust.............................. 3,722 3,716 3,805 3,854 3,916
- -------- (/1/Revenue)for 1996 and the first eight months of 1997 includes revenue associated with power marketing and gas sales with related cost of sales of such operations recorded as a component of fuel, net. The Company experienced significant growth in its power marketing operations in 1997 relative to prior years. Beginning in September 1997, the Company recorded the results of its power marketing and gas sales operations, not subject to cost-based rate regulation, as a component of other revenue net of related cost of sales. (/2/Revenue)for 1998 reflects the Company's settlement of base rate proceedings which included a one-time rate refund of $150 million and a base rate reduction of $100 million beginning in March 1998. Net income for 1998 reflects the aforementioned base rate refund and rate reduction as well as an impairment charge of $159 million to write-off net regulatory assets no longer considered recoverable as a result of the rate settlement. See Note 6 to the Consolidated Financial Statements. (/3/In)1999, the Company discontinued the application of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, to its generation operations in connection with the deregulation of these operations in Virginia. The discontinuance of SFAS No. 71 for generation resulted in a $255 million after-tax charge. See Note 6 to the Consolidated Financial Statements. 17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This Management's Discussion and Analysis of Financial Condition and Results of Operations contains "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995, including (without limitation) discussions as to expectations, beliefs, plans, objectives and future financial performance, or assumptions underlying or concerning matters discussed in this document. These discussions, and any other discussions, including certain contingency matters (and their respective cautionary statements) discussed elsewhere in this report, that are not historical facts, are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Our business and financial condition are influenced by a number of factors including political and economic risks, market demand for energy, inflation, capital market conditions, governmental policies, legislative and regulatory actions (including those of FERC, EPA, DOE, NRC, SEC, Virginia Commission and North Carolina Commission), industry and rate structure and legal and administrative proceedings. Some other important factors that could cause actual results or outcomes to differ materially from those discussed in the forward-looking statements include changes in and compliance with environmental laws and policies, weather conditions and catastrophic weather-related damage, present or prospective wholesale and retail competition, electric deregulation, the restructuring of the organization, operations and financing of the Company's business to separate generation, transmission and distribution, competition for new energy development opportunities, pricing and transportation of commodities, operation of nuclear power facilities, acquisition and disposition of assets and facilities, nuclear decommissioning costs, exposure to changes in the fair value of commodity contracts, counter- party credit risk and unanticipated changes in operating expenses and capital expenditures. All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. See Item 1. CAUTIONARY FACTORS THAT MAY AFFECT FUTURE RESULTS for additional discussion of these matter. New factors emerge from time to time and it is not possible to predict all such factors, nor can we assess the impact of each such factor on the Company. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made. Business Segments We manage our operations in a manner that requires disclosure of two business segments--Energy and Delivery. Our Energy segment includes our portfolio of generating facilities and power purchase contracts, trading and marketing activities, nuclear consulting services, and energy services activities. Our Delivery segment includes bulk power transmission, distribution and metering services, and customer service. Currently, the majority of our revenue is provided through bundled rate tariffs. Such revenue is allocated between the Energy and Delivery segments for internal reporting purposes and discussion herein. Certain activities discussed in Liquidity and Capital Resources are currently not managed at the segment level; however, specific references to segments are made as appropriate. Our discussion of trends and variations generally applies to the Company as a whole. Liquidity And Capital Resources Internal Sources of Liquidity Cash flow from operating activities provided approximately $1.1 billion during each of the years 2000, 1999 and 1998. During each of the three years 1998 through 2000, cash flow from operating activities, after dividend payments, was sufficient to cover over 90 percent of our capital and nuclear fuel expenditures and, on average, approximately 73 percent of our total cash requirements. Cash requirements not met by the timing or amount of cash flow from operations are generally satisfied with proceeds from the sale of securities and short-term borrowings. 18 External Sources of Liquidity In 2000, we issued $220 million in aggregate principal of variable-rate medium-term notes maturing in 2002. We also entered into a swap agreement to synthetically convert $200 million of these variable rate notes to fixed rate debt. Under the swap agreement, we will pay a 7.27% fixed rate. Proceeds from the notes were used to retire outstanding debt and preferred stock. We retired $376 million of outstanding debt and preferred stock during 2000. Also in 2000, we issued through the Industrial Development Authority of the Town of Louisa, Virginia $30 million in aggregate principal amount of Tax- Exempt Pollution Control Revenue Bonds due September 2030. The net proceeds of the bonds were used to finance qualifying expenditures made during the construction of facilities at our North Anna Power Station. We have a commercial paper program supported by two credit facilities. We have a $300 million credit facility and also participate in a credit facility that supports the combined commercial paper programs of Dominion, the Company and Consolidated Natural Gas Company (CNG). This facility, established in June 2000, is for $1.75 billion and matures May 2001. Although we have access to the full amount of the $1.75 billion facility, we operate with an internal allocation that may vary depending upon the needs of participating entities. Net borrowings under the commercial paper program were $714 million at December 31, 2000, an increase of $336 million from amounts outstanding at December 31, 1999. Borrowings under these facilities are used primarily to fund working capital requirements and may vary significantly during the course of the year depending upon the timing and amount of cash requirements not satisfied by current cash provided from operations. In addition to commercial paper, we may also issue extendible commercial notes (ECNs) to meet working capital requirements. This program became effective in July 2000 and will allow us to issue up to $200 million aggregate outstanding principal of ECNs. ECNs are unsecured notes expected to be sold in private placements. Any ECNs we issue would have a stated maturity of 390 days from issuance and may be redeemed, at our option, within 90 days or less from issuance. As of December 31, 2000, we have available $1.62 billion of remaining principal amount under currently effective shelf registrations with the SEC to meet capital requirements. In February 2001, we issued through the Industrial Development Authority of the Town of Louisa, Virginia $50 million in aggregate principal amount of Tax- Exempt Pollution Control Revenue Bonds due September 2031. The net proceeds of the bonds were used to finance qualifying expenditures made during the construction of facilities at our North Anna Power Station. 2000 Capital Expenditures In 2000, our investing activities resulted in a net cash outflow of $770 million. These activities included capital expenditures of $652 million and nuclear fuel expenditures of $82 million. Generation-related projects totaled approximately $307 million and included construction of four combustion turbines, environmental upgrades, and routine capital improvements. We spent approximately $292 million on transmission and distribution-related projects reflecting routine capital improvements and expenditures associated with new connections. Remaining capital expenditures of $53 million included approximately $20 million of continued expansion of fiber optic network and $33 million other general and information technology projects. We conveyed our telecommunications subsidiary to Dominion in August 2000. Capital Requirements Capacity--We anticipate that peak demand will grow approximately 1 percent a year through 2003. We expect to complete construction of two 160 Mw combustion turbines in Caroline County, Virginia by midyear 19 2001. We anticipate spending an estimated $115 million on the project of which approximately $98 million has been incurred through December 31, 2000. We expect that any future additional capacity and energy requirements will be met through a combination of market purchases and Company-constructed generation. Plant and equipment--Our generation construction and nuclear fuel expenditures during 2001, 2002 and 2003 are expected to total $438 million, $488 million and $433 million, respectively. Our transmission and distribution expenditures during 2001, 2002, and 2003, are expected to total $393 million, $379 million and $371 million, respectively. The majority of these expenditures will primarily address funding for environmental projects, customer growth, as well as reliability initiatives and routine replacements. We are installing sulfur dioxide (SO\\2\\) emission control equipment at two coal-fired generating units with an expected completion date of early 2002. The total cost for this project is estimated to be $123 million of which $76 million has been incurred as of December 31, 2000. In response to Clean Air Act requirements, we are installing nitrogen oxide (NOx) reduction equipment on all of our coal-fired generating units at an estimated capital cost of $542 million of which $66 million has been incurred as of December 31, 2000. The installations are scheduled for completion by midyear 2004. We are also discontinuing the use of coal at our Possum Point station in Prince William County, Virginia. Over the next three years, two of the coal-fired units will be retired and the other two coal-fired units will be converted to gas, at an estimated capital cost of $15 million. No significant costs have been incurred on the conversion as of December 31, 2000. See Environmental Matters for additional discussion Clean Air Act matters. Maturities--We will require $241 million to meet maturities of securities in 2001. We expect to fund our capital requirements and maturities with cash flow from operations and a combination of sales of securities and short-term borrowings. Results Of Operations General This section provides a general discussion of factors that affect operating revenue and income of both our Energy and Delivery segments and a discussion of fluctuations in certain expenses, which are not allocated separately to the segments. Operating Revenue and Income Total operating revenue and income for fiscal years 2000, 1999, and 1998 was allocated to the Energy and Delivery segments as follows:
Year ended December 31, ----------------------- 2000 1999 1998 ------- ------- ------- (Millions) Energy............................................ $ 3,552 $ 3,393 $ 3,292 Delivery.......................................... 1,217 1,166 1,111 Other............................................. 22 32 (123) ------- ------- ------- Total operating revenue and income.............. $ 4,791 $ 4,591 $ 4,280 ======= ======= =======
Regulated electric sales consists primarily of sales to retail customers in our service territory at rates authorized by the Virginia Commission and North Carolina Commission, and sales to cooperatives and municipalities at wholesale rates authorized by FERC. Also included in regulated electric sales are amounts received from others for use of our transmission system to transport electric energy under tariffs authorized by FERC. The primary factors affecting regulated electric sales revenue in both fiscal years 2000 and 1999 were customer growth and changes in rates. 20 Other revenue includes sales of electricity beyond our service territory, sales of natural gas, and other revenue. The following factors contributed to the increase in operating revenue and income during 2000 and 1999:
2000 vs. 1999 1999 vs. 1998 ------------- ------------- (Millions) Increase (decrease) in regulated electric sales revenue due to: Retail customer growth...................... $ 76 $ 68 Weather..................................... 15 2 Base rate refund............................ 154 Base rates.................................. (9) (57) Fuel rates.................................. 117 24 Other retail, net(/1/)...................... 59 31 ---- ---- Total regulated retail electric sales revenue.................................. 258 222 Other regulated electric sales revenue.... 7 26 ---- ---- Total increase in regulated electric sales revenue.......................... 265 248 Total increase (decrease) in other revenue................................ (65) 63 ---- ---- Total increase in revenue............... $200 $311 ==== ====
- -------- (/1/Other)retail, net--this category reflects actual revenue variances not otherwise identified by the economic models used to prepare the revenue analysis. Items that give rise to these types of variances primarily relate to residential and commercial customer usage patterns not contemplated by economic assumptions in the models. Weather, seasonal rate differences, and overall economy contribute to customer usage patterns. 2000 as compared to 1999 Retail customer growth--Regulated electric sales revenue increased as we served, on average, approximately 39,000 more retail customers during 2000. Weather--Regulated electric sales revenue increased reflecting higher customer usage in response to colder fall and winter weather offset somewhat by lower customer usage resulting from milder summer weather. Heating and cooling degree-days were as follows:
2000 1999 Normal ----- ----- ------ Heating degree-days................................. 3,860 3,445 3,753 Percentage change from prior year................... 12.1% 7.8% Cooling degree-days................................. 1,297 1,475 1,565 Percentage change from prior year................... (12.1)% (10.1)%
Fuel rates--Currently, we recover the cost of fuel used in generating electricity through fuel rates approved by regulatory authorities. The increase in fuel rate revenue reflects higher fuel rates approved during the first quarter of 2000. Other regulated electric sales revenue increased primarily due to increased wholesale sales to cooperatives and municipalities under requirements contracts. Revenue from electric transmission services did not change significantly. Other revenue decreased reflecting lower net revenue associated with electricity and gas marketing and trading activities. The decrease reflects lower off-system electric sales resulting primarily from the expiration of two major long-term power purchase contracts in late 1999. 21 1999 as compared to 1998 Retail customer growth-- Regulated electric sales revenue increased as we served, on average, approximately 39,000 more retail customers in 1999. Weather--Weather typically has a significant impact on regulated electric sales revenue. However, for these comparative periods, weather did not have a significant impact. Base rate refund and base rate reduction--Regulated electric sales revenue increased reflecting the one-time base rate refund of $150 million recorded in 1998 as part of our settlement to resolve then outstanding rate proceedings. In addition, we agreed to a two-phased rate reduction, $100 million effective March 1, 1998 and an additional $50 million effective March 1, 1999. This two- phased rate reduction reduced regulated electric sales by $57 million. As a result of deregulation legislation, our Virginia jurisdictional base rates will remain unchanged until July 2007. See Note 6 to Consolidated Financial Statements. Fuel rates--The increase in fuel rate revenue reflects comparatively higher fuel rates as a result of an annual fuel case that became effective December 1998. Other regulated electric sales revenue increased due to increased revenue for electric transmission services. Other revenue increased reflecting higher net revenue associated with electricity and gas marketing and trading activities. The increase in net revenue associated with electricity and gas marketing and trading activities primarily reflects changes in the composition of and net mark-to-market gains in our portfolio of commodity contracts. Expenses Certain expenses, which are not allocated separately to the Energy and Delivery segments, changed as follows when compared to the respective prior years: 2000 as compared to 1999 Restructuring costs--During 2000, we incurred restructuring costs of $71 million in connection with the implementation of a plan to restructure the operations of Dominion subsidiaries following Dominion's acquisition of CNG. These charges related primarily to costs associated with workforce reduction activities. See Restructuring Costs and Note 5 to the Consolidated Financial Statements for further information. Cumulative effect of a change in accounting principle--As a result of its acquisition of CNG, Dominion adopted a new company-wide standard method of calculating the market related value of plan assets for all of its pension plans. The market related value of plan assets is used to determine the expected return on plan assets, a component of net periodic pension cost. The cumulative effect of this accounting change as of January 1, 2000 was $21 million (net of income taxes of $11 million). See Note 3 to the Consolidated Financial Statements. 1999 as compared to 1998 Impairment of regulatory assets--This charge in 1998 reflected the write down of regulatory assets as a result of our settlement of the Virginia rate proceeding. See Note 6 to the Consolidated Financial Statements. Interest expense--Interest expense decreased in part due to the interest cost associated with the one-time base rate refund paid in 1998 as part of the settlement of our Virginia rate proceeding. See Note 6 to the Consolidated Financial Statements. In addition, upon discontinuance of SFAS No. 71, we began capitalizing interest in accordance with SFAS No. 34, Capitalization of Interest Cost, as part of our generation-related construction projects. 22 Extraordinary item--The passage of legislation establishing a detailed plan to restructure the electric utility industry in Virginia, was an event that required discontinuation of SFAS No. 71 for our generation operations. Generation-related assets and liabilities not expected to be recovered through cost-based rates were written off in 1999, resulting in an after-tax charge of $255 million. See Note 6 to the Consolidated Financial Statements. Energy Segment Net income of our Energy segment increased $70 million in 2000 and $47 million in 1999. We have presented below those revenue and expense items contributing to the comparative fluctuations in segment results:
Year ended December 31, ----------------------- 2000 1999 1998 ------- ------- ------- (Millions) Operating revenue...................................... $ 3,552 $ 3,393 $ 3,292 Fuel, net.............................................. 1,104 986 953 Purchased power capacity, net.......................... 740 809 806 Operations and maintenance............................. 626 593 510 Depreciation and amortization.......................... 269 275 307 Other taxes............................................ 138 155 179 Other income........................................... 18 4 7 Net income............................................. 362 292 245
- -------- Note: certain 1999 and 1998 amounts have been reclassified to conform to 2000 classifications. 2000 as compared to 1999 Operating revenue--see General section for discussion of revenue on a consolidated basis. Fuel, net increased primarily due to higher overall production from our generating units, increased costs of fossil fuel, and increased energy purchases. System energy output by energy source and the average fuel cost for each are shown below. Fuel cost is presented in mills (one tenth of one cent) per kilowatt hour.
2000 1999 1998 ------------ ------------ ------------ Source Cost Source Cost Source Cost ------ ----- ------ ----- ------ ----- Nuclear(/1/)............................. 33% 4.48 35% 4.59 33% 4.71 Coal(/2/)................................ 42 14.04 38 13.73 42 13.21 Oil...................................... 3 35.89 4 20.47 3 22.52 Purchased power, net..................... 20 23.97 19 23.95 19 21.85 Other.................................... 2 44.58 4 28.98 3 27.27 --- --- --- Total.................................. 100% 100% 100% === === === Average fuel cost...................... 14.20 13.34 12.71
- -------- (/1/Excludes)Old Dominion Electric Cooperative's (ODEC) 11.6 percent ownership interest in the North Anna Power Station. (/2/Excludes)ODEC's 50 percent ownership interest in the Clover Power Station. Purchased power capacity, net decreased reflecting the expiration of two major long-term power purchase contracts as of December 31, 1999. Operations and maintenance increased reflecting primarily higher overall corporate and administrative costs. 23 Other taxes decreased due to the accrual in 2000 for a tax refund. Other income includes an accrual in 2000 for interest income to be received in connection with the favorable resolution of tax litigation. 1999 as compared to 1998 Operating revenue--see General section for discussion of revenue on a consolidated basis. Fuel, net increased primarily due to higher production from our generating units and increased energy purchases. See our presentation of system energy output by energy source and the average fuel cost for each in the chart presented in the 2000 as compared to 1999 section above. Operations and maintenance increased primarily as a result of: increased maintenance activities performed during planned outages at our fossil plants; adjustments to inventories related to the planned disposal of identified obsolete and excess materials and supplies; and the effect of certain accounting policy changes in 1999 that resulted from the discontinuance of SFAS No. 71, including the recognition of losses on retirement of equipment and related removal costs. Depreciation and amortization primarily reflect the amortization of certain terminated construction projects in 1998. The costs of these projects were completely amortized as of the end of the first quarter 1999. Other taxes decreased primarily due to changes in the provision for other taxes associated with our electricity and gas marketing and trading activities. Delivery Segment Net income of our Delivery segment increased $49 million in 2000 and $8 million in 1999. We have presented below those revenue and expense items contributing to the comparative fluctuations in segment results:
Year ended December 31, ----------------------- 2000 1999 1998 ------- ------- ------- (Millions) Operating revenue...................................... $ 1,217 $ 1,166 $ 1,111 Operations and maintenance............................. 379 403 372 Net income............................................. 242 193 185
- -------- Note: certain 1999 and 1998 amounts have been reclassified to conform to 2000 classifications. 2000 as compared to 1999 and 1999 as compared to 1998 Operating revenue--see General section for discussion of revenue on a consolidated basis. Operations and maintenance expenses were higher in 1999 as compared to fiscal years 2000 and 1998 as a result of significant service restoration costs associated with ice storm and hurricane damage. Electric Industry Issues Deregulation Legislation Virginia Historically, we have had the exclusive right to provide electricity at retail within our assigned service territories in Virginia and North Carolina. 24 However, during 1998 and 1999, deregulation legislation was enacted in Virginia that established plans to restructure Virginia's electric utility industry and provided for a phased-in transition to a fully competitive retail electric market during the period January 1, 2002 through January 1, 2004. In connection with the implementation of the phase-in of retail electric competition, the Commission Staff recommended transition schedules for each of Virginia's electric utilities. For the Company, the Commission Staff's plan recommended the phase-in of retail choice to be made available to all customers by January 1, 2003. We filed comments on the Commission Staff's recommended plan in February 2001. Under the deregulation legislation, the generation portion of our Virginia jurisdictional operations will no longer be subject to cost-based rate regulation beginning in 2002. Our base rates will remain unchanged until July 2007 and recovery of generation-related costs will continue to be provided through capped rates and a wires charge assessed to those customers opting for alternate suppliers. In addition, we may petition the Virginia Commission to terminate the capped rates after January 1, 2004, and such capped rates may be terminated if the Virginia Commission finds that an effectively competitive market for generation services exists within our service territory. As discussed further in sections below, this legislation also addressed divestiture, a retail access pilot program, separation of generation and delivery operations, regional transmission entities and other corporate relationships and established a task force to work with the Virginia Commission during the phase-in of competition. The task force's specific assignments include the monitoring of possible over or under-recovery of stranded costs by incumbent utilities. The 200l General Assembly approved a bill containing several technical amendments to the deregulation legislation. In addition, and consistent with the intent of the earlier legislation, the 2001 General Assembly clarified that generation rates for default service will be based on competitive market prices. North Carolina During 2000, a study commission, established by the North Carolina General Assembly to explore the future of electric service in North Carolina, developed a proposal to provide full retail competition to North Carolina by January 1, 2006, with a phase-in beginning January 1, 2005 of up to 50 percent of each power supplier's customer load. These recommendations are part of a report given to the General Assembly in May 2000. During the short session, legislation was passed that extended the study commission through 2006 and added Dominion North Carolina Power's CEO, or his designee, to its membership. The study commission continues to meet and review its recommendations to the General Assembly as issues in other states have generated further discussion concerning retail competition. Federal The United States Congress may consider federal legislation in the near future authorizing or requiring retail competition or repealing the 1935 Act and/or the Public Utility Regulatory Policy Act of 1978. Retail Access Pilot Program and Transition to Retail Competition In 1998, the Virginia Commission issued an order instructing the Company and AEP-Virginia as Virginia's two largest investor-owned utilities, each to design and file a retail access pilot program. During 1998 and 1999, we worked with the Commission Staff in developing the plans for the size and scope of the program and the market price methodology. In 2000, the Virginia Commission issued a final order on the interim rules governing pilot programs. In January 2001, the Virginia Commission established a proceeding to determine the permanent rules for retail access. A working group of interested parties worked with the Commission Staff to develop proposed rules, which were filed by the Commission Staff in March 2001. Comments on the proposed rules will be filed in April 2001. 25 Our pilot program, Project Current Choice, began in September 2000. As of the end of December 2000, over 81,000 customers have volunteered for the pilot and over 20,000 have switched to a competitive service provider. In Phase I of Project Current Choice, being conducted in Central Virginia, over 44,000 residential and small business customers have volunteered to participate. The small and intermediate-sized business portion of Phase I is currently fully subscribed, and we have stopped accepting enrollments. In October 2000, we implemented Phase II of Project Current Choice in Northern Virginia and began accepting enrollments in December 2000. Over 13,000 residential and small business customers have already switched to a competitive supplier in Northern Virginia. Project Current Choice also includes a separate plan under which nearly one-half of the approximately 2,000 large commercial and industrial customers throughout our service territory have volunteered for the pilot program. Fifty-eight of the large customers who volunteered were selected by a lottery and are eligible to participate and switch to a competitive supplier. So far, six large customers have selected an alternative supplier. In December 2000, we filed an application with the Virginia Commission to increase the wires charges in our retail access pilot program, consistent with the proposed Virginia fuel factor case, effective January 1, 2001. In January 2001, the Virginia Commission authorized the Company to increase its pilot program wires charges, on an interim basis, effective January 1, 2001, to incorporate revised fuel cost recovery. We filed comments on the proposed wires charge increases with the Virginia Commission in January 2001. A hearing on the matter is scheduled for April 2001. We do not expect the participation of customers in our Virginia service area in Project Current Choice to have a material impact on our results of operations. Separation of Electric Generation and Delivery Operations in Virginia The deregulation legislation requires functional separation of electric generation and delivery utility operations by January 1, 2002. In November 2000, we filed with the Virginia Commission an application for approval of a functional separation plan. The plan provides for the following: .transfer of generation assets into a separate legal entity, Dominion Generation Corporation; . transfer of rights and obligations under non-utility purchase power contracts to Dominion Generation Corporation; . retention of transmission and distribution assets and operations by the Company, to be known as Dominion Virginia Power; . collection of nuclear decommissioning funding costs and wires charges from retail customers by Dominion Virginia Power on behalf of Dominion Generation Corporation; . Dominion Virginia Power to be responsible for providing capped rate service until July 1, 2007 and default service obligations, if any; . Dominion Generation Corporation to supply Dominion Virginia Power with electric power during and after the capped rate period under a power purchase agreement to ensure that adequate capacity and energy is available to meet the Company's capped rate service and default supply obligations; . upon expiration of the capped rate period, any power purchases by Dominion Virginia Power from Dominion Generation Corporation to be at prevailing market prices; . an index-based fuel cost recovery mechanism based on the forecasted generation by fuel type and projected fuel price indices after January 1, 2002; . unbundled rates to reflect the separation and deregulation of generation; . a wires charge, effective January 1, 2002, and subject to annual adjustment to be paid by retail customers choosing an alternative generation supplier during the capped rate period; . proposed internal controls to prevent cross-subsidies between regulated and unregulated entities and to ensure that the regulated company does not give undue advantages to unregulated affiliated generation companies; 26 . planned reallocation between Dominion Virginia Power and Dominion Generation Corporation of payment responsibility for existing Company debt in a manner to be determined with investment banking assistance with the objective that ratings on outstanding debt will remain unchanged. In October 2000, the Virginia Commission issued its final order promulgating regulations governing the functional separation of incumbent electric utilities' generation, transmission, and distribution services. The order adopted rules for how Virginia's existing electric utilities should organize themselves to participate in the competitive energy supply market. The rules govern how utilities that generate, transmit and distribute electricity, can separate operations so their generating plants can participate in the competitive market without raising anti-competitive and other concerns. In 2001, the General Assembly provided additional clarification to the order and made amendments to deregulation legislation that provides for, after the termination or expiration of capped rate service, the generation price for default service provided by incumbent distribution utilities to be based on competitive market prices. The Virginia Commission has set a hearing date in October 2001 to consider the Company's functional separation plan. Regional Transmission Entities/Regional Transmission Organizations The deregulation legislation requires that Virginia's incumbent electric utilities join or establish regional transmission entities (RTE) by January 1, 2001, and seek authorization from the Virginia Commission to transfer ownership or operational control of their transmission facilities to such RTEs. In July 2000, the Virginia Commission issued regulations governing the transfer of ownership or control of electric transmission assets to an RTE. The regulations establish: (1) the elements of an RTE essential to the public interest to be applied by the Virginia Commission in determining whether to authorize transfer of control of electric transmission facilities to an RTE, (2) the filing requirements for entities seeking authorization to transfer the facilities, and (3) a schedule for such filings. In October 2000, we filed our application with the Virginia Commission pursuant to the RTE regulations seeking authorization to transfer control of our electric transmission facilities to the Alliance Regional Transmission Organization (Alliance RTO). As discussed below, the Alliance RTO was formed according to FERC initiatives but we expect it to satisfy the requirements to establish the RTE under Virginia legislation. In 1999, FERC issued regulations (Order No. 2000) to advance the formation of Regional Transmission Organizations (RTO). The regulations require each public utility that owns, operates, or controls electric transmission facilities in interstate commerce make certain filings with respect to running and participating in an RTO. The Company, together with AEP, Consumers Energy Company, The Detroit Edison Company and First Energy Corporation, on behalf of themselves and their public utility operating company subsidiaries (Alliance Companies), filed with FERC applications under Sections 205 and 203 of the Federal Power Act for approval of the proposed Alliance RTO. FERC approved the application subject to certain conditions and filing requirements. During 2000, the Alliance Companies filed a response complying with FERC's conditions and filing requirements. FERC approved most aspects of the Alliance RTO in January 2001. Dayton Power and Light Company, Commonwealth Edison Company, Commonwealth Edison Company of Indiana, Illinois Power Company, Ameren UE and Ameren CIPS subsequently requested to join the Alliance RTO. Wholesale Competition We sell electricity in the wholesale market under our market-based sales tariff authorized by FERC but have agreed not to make wholesale power sales under this tariff to loads located within our service territory. During 2000, we filed applications with FERC to make sales under our market-based sales tariff to loads within our service territory participating in our retail access pilot program and to amend our open-access transmission tariff to accommodate the Virginia retail access pilot program. FERC has accepted both applications. Until 27 authorization is granted by FERC, any sales of wholesale power to loads located within our service territory, other than sales to loads participating in the retail access pilot program, are to be at cost-based rates accepted by FERC. Metering and Billing Services In July 2000, the Virginia Commission issued an order inviting comments with regard to retail electric metering and billing services. As required by statute, the Virginia Commission presented a recommendation and draft plan for retail electric billing and metering services to the Virginia legislative transition task force in December 2000. The Virginia Commission's plan would provide for customer choice for billing services effective January 1, 2002 subject to a one year delay if determined necessary by the Virginia Commission. The plan also addressed which costs related to competitive billing services should be recoverable by incumbent utilities and the authority of the Virginia Commission to calculate such costs and determine the most appropriate method of cost recovery. In addition to approving the Virginia Commission's plan for retail electric billing services, the 2001 General Assembly approved a bill containing a provision that the Virginia Commission shall implement the provision of competitive metering services by licensed providers for large industrial and large commercial customers of investor-owned distributors on January 1, 2002, and may approve such services for residential and small business customers of investor-owned distributors on or after January 1, 2003. Exposure To Potentially Stranded Costs The most significant potential impact of transitioning from a regulated to a competitive environment is stranded costs. Stranded costs are those costs incurred or commitments made by utilities under cost-based regulation that may not be recovered in a competitive market. If no recovery mechanism is provided during the transition, the financial position of a utility could be materially adversely affected. At December 31, 2000, our exposure to potentially stranded costs was comprised of: long-term power purchase contracts that could ultimately be determined to be above market; generating plants that may become uneconomic in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements. We believe capped rates provided under the deregulation legislation present a reasonable opportunity to recover a substantial portion of our potentially stranded costs. In the absence of capped rates, at March 31, 1999, we would have otherwise been exposed, on a pre-tax basis, to an estimated $3.2 billion of potential losses related to long-term power purchase commitments. Recovery of our potentially stranded costs is subject to numerous risks including, those exposures listed above as well as, future environmental compliance requirements, changes in tax laws, decommissioning costs, inflation, and increased capital costs, among other items. See Notes 6, 8, 19, and 20 to the Consolidated Financial Statements. Restructuring of Contracts with Non-Utility Generating Facilities We have reached an agreement, pending regulatory approvals, to terminate three long-term power purchase contracts. We expect the transaction to be completed in the first quarter of 2001, resulting in a one-time, non-operating charge of approximately $135 million, after taxes. The transaction is part of an ongoing program which seeks to achieve competitive cost structures in our power generation business. Nuclear Re-licensing In June 2001, we plan to file applications with the NRC to renew the operating licenses for our Surry and North Anna nuclear stations. The technical work that is required to support a license renewal application was completed by December 31, 2000. The renewal of the license will extend the plants' working lives by 20 years. 28 Rate Matters In December 2000, we filed an application with the Virginia Commission to increase our Virginia fuel factor from 1.339c per kWh to 1.613c per kWh or an estimated annual increase of $158 million. These new rates went into effect, on an interim basis, for usage on and after January 1, 2001 pending a hearing scheduled for April 2001. In July 2000, the Virginia Commission issued an order to modify our cogeneration and small power production rates under Schedule 19. The order sustained our proposed method to determine avoided costs, agreed with our position that off system sales should be excluded from the calculation of avoided costs, and that the cogeneration rate should be effective through 2001. In September 2000, we filed a revised Schedule 19 as required by the Virginia Commission's July 2000 Order, and in November 2000 the Virginia Commission accepted for filing our revised Schedule 19 Tariff. In support of Dominion's request for approval by the North Carolina Commission of its acquisition of CNG, we and Dominion reached an agreement with the Public Staff of the North Carolina Commission whereby we agreed not to request any increase in our North Carolina retail electric base rates until after December 31, 2005, except for certain events that would have a significant financial impact on our Company. Such events could include any governmental action or an occurrence that is beyond our control and not attributable to our fault or negligence. However, fuel rates are still subject to change under the annual fuel cost adjustment proceedings. Other Regulatory Matters In June 2000, we filed an application with the Virginia Commission to make a number of changes to the Possum Point Power Station designed to provide environmental benefits. The proposed plan entails the retirement of two coal- fired units; conversion of two other coal fired units to gas and/or oil; and the addition of one combined cycle unit capable of running on gas or oil. This unit will be owned by a third-party and operated by the Company under an operating lease. The Virginia Commission held a hearing on the matter in January 2001. See Environmental Matters for further discussion of this issue. Environmental Matters We are subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. Historically, we recovered these costs from customers through utility rates. To the extent environmental costs are incurred through June 30, 2007, in excess of electric retail Virginia jurisdictional rates, the amounts will be reflected in our results of operations. After that date, we may seek recovery for only those environmental costs related to transmission and distribution operations through regulated utility rates. Environmental Protection And Monitoring Expenditures We incurred approximately $90 million, $78 million, and $72 million (including depreciation) of expenses during 2000, 1999, and 1998, respectively, in connection with environmental protection and monitoring activities, and we expect these expenses to be approximately $87 million in 2001. Capital expenditures related to environmental controls were approximately $207 million, $74 million, and $22 million for 2000, 1999, and 1998, respectively. The amount estimated for 2001 for these capital expenditures is approximately $171 million which includes certain expenditures for Clean Air Act improvements as discussed below. 29 Clean Air Act Compliance The Clean Air Act, as amended in 1990, requires the Company to reduce its emissions of SO\\2\\ and NOx which are gaseous by-products of fossil fuel combustion. The Clean Air Act also requires us to obtain operating permits for all major emissions-emitting facilities. Permit applications have been submitted for the Company's power stations. The Clean Air Act's SO\\2\\ reduction program is based on the issuance of a limited number of SO\\2\\ emission allowances, each of which may be used as a permit to emit one ton of SO\\2\\ into the atmosphere or may be sold to someone else. The EPA administers the program. Our compliance plans are reviewed periodically and may include switching to lower sulfur coal, purchasing emission allowances and installing of SO\\2\\ control equipment. In December 1998 we initiated a capital project to install SO\\2\\ control equipment on two units at our Mt. Storm power station at an estimated cost of $123 million. These SO\\2\\ controls are expected to be operational by January 2002. We began complying with Clean Air Act Phase I NOx limits at eight of our units in Virginia in 1997, three years earlier than otherwise required. As a result, the units will not be subject to more stringent Phase II limits until 2008. We have established a plan to comply with the Phase II limits at the remaining eight coal-fired units in Virginia subject to the Phase II limits. In September 1998, the EPA adopted a rule requiring 22 states, including Virginia, West Virginia and North Carolina, to reduce and cap ozone season (May-September) NOx emissions beginning in May 2003. A recent ruling by the U.S. District Court of Appeals in the DC Circuit has extended the compliance date to May 31, 2004. However, in December 1999, the EPA issued a finding in support of petitions filed by several Northeastern states seeking relief from long-range pollutant transport from utility and large industrial sources that essentially enforces the same NOx emission caps beginning in May 2003 for 12 of the 22 states, including Virginia, West Virginia and North Carolina. In response to these requirements, we plan to install NOx reduction equipment at our coal-fired generating facilities at an estimated capital cost of approximately $542 million over the next several years. Whether these costs are actually incurred is dependent on both the outcome of pending litigation of these rules and on the implementation plans adopted by the states in which we operate. The Virginia Department of Environmental Quality (DEQ) has issued a new air permit that imposes a plantwide ozone season NOx emission limit of 0.15 lb/mmBtu at the Possum Point Power Station beginning in May 2003 as part of a state implementation plan to address ozone levels in Northern Virginia, which is classified as a serious ozone non-attainment area. Given the age of the existing units at Possum Point and the high probability of additional control requirements in the future, we evaluated various options to optimize the ability to continue to operate these units in a cost-effective manner while providing the Northern Virginia area with a reliable source of electricity. Based on this evaluation, we recently announced the planned retirement of 143 Mw of existing oil-fired generation and conversion of 322 Mw of coal-fired generation to natural gas or No. 6 fuel oil at Possum Point. Additionally, a new, cleaner 540 Mw combined cycle gas unit will be constructed and owned by a third party and operated by the Company under an operating lease. This arrangement has been filed for approval with the Virginia Commission, and approval is expected in early 2001. Evaluation and planning of future projects to comply with SO\\2\\ and NOx reduction requirements are ongoing and will be influenced by changes in the regulatory environment, availability of SO\\2\\ allowances and emission control technology. During 2000, we received a Notice of Violation (NOV) from the EPA alleging that we failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at our Mt. Storm power station in West Virginia. Also in 2000, the Attorney General of New York filed a suit alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. We also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. 30 Violations of the Clean Air Act may result in the imposition of substantial civil penalties and injunctive relief. We believe that we have obtained the permits necessary in connection with our generating facilities. Currently, we have reached an agreement in principle with the federal government and the state of New York concerning the implementation of certain additional environmental controls at our coal-fired generating stations in connection with the resolution of various Clean Air Act matters. The agreement in principle includes payment of a $5 million civil penalty, a commitment of $14 million for major environmental projects in Virginia, West Virginia, Connecticut, New Jersey, and New York, and a 12-year, $1.2 billion capital investment program for environmental improvements at the Company's coal-fired generating stations in Virginia and West Virginia (including the SO\\2\\ and NOx emissions controls discussed above). Although we have reached an agreement in principle, the terms of a final binding settlement are still being negotiated. See Note 20 to the Consolidated Financial Statements. In December 2000, EPA issued a decision that it would move forward in developing regulations to control the emissions of mercury from coal-fired electric generating units. EPA expects to issue a final ruling by December 2004, with implementation/compliance expected to be required by 2007. Depending upon the level of reduction required and the flexibility allowed to comply with the reduction requirements, these regulations could require the installation of control technology to reduce mercury emissions in the future. Global Climate Change In 1993, the United Nation's Global Warming Treaty became effective. The objective of the treaty is the stabilization of greenhouse gas concentrations at a level that would prevent man-made emissions from interfering with the climate system. As a continuation of the effort to limit man-made greenhouse emissions, an international Protocol was formulated in December 1997, in Kyoto, Japan. This Protocol calls for the United States to reduce greenhouse emissions by 7 percent from 1990 baseline levels by the period 2008-2012. The Protocol has been signed by the United States but will not constitute a binding commitment unless submitted to and approved by the United States Senate. Emission reductions of the magnitude included in the Protocol, if adopted, would likely result in a substantial financial impact on companies that consume or produce fossil fuel-derived electric power, including the Company. Restructuring Costs Subsequent to Dominion's acquisition of CNG, Dominion and its subsidiaries developed and began the implementation of a plan to restructure the operations of the combined companies. Restructuring activities include workforce reductions and the consolidation of post-merger operations and information technology systems. During 2000, we recognized $71 million of restructuring costs as discussed below. Under the restructuring plan, a total of 174 employee positions were identified for elimination, resulting in $14 million of employee severance related costs. At December 31, 2000, a total of 168 positions had been eliminated, and $8 million of severance benefits had been paid. During 2000, approximately 400 employees elected to participate in the early retirement program, resulting in an expense approximating $51 million. Restructuring costs also included $6 million related to consolidation and integration of business operations and administrative functions. The planned workforce reductions should avoid future annualized operating costs of approximately $34 million that would have otherwise been incurred. See Note 5 to the Consolidated Financial Statements. Recently Issued Accounting Standards In June 2000, the Financial Accounting Standards Board (FASB) issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, which amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133 requires that all derivative instruments be recorded on the balance sheet at their fair value effective January 1, 2001. 31 In addition to contracts currently held for trading purposes and recorded at fair value, we have determined that certain other contracts will be subject to fair value accounting under SFAS No. 133. We use a substantial portion of these contracts in connection with the production and delivery of energy to our customers and in various hedging strategies. In addition to these commodity contracts, we use interest rate swaps to manage our cost of capital. We will record one-time, non-operating after-tax charges to net income of approximately $1 million and other comprehensive income of approximately $14 million in the first quarter of 2001 for the initial adoption of SFAS No. 133. These adjustments will be recognized as of January 1, 2001 as the cumulative effect of a change in accounting principle. The ongoing effects will depend on future market conditions, our hedging activities, and further interpretations of the standard. The Derivatives Implementation Group (DIG), a group sponsored by the FASB, continues to develop interpretive guidance. The DIG has not yet resolved certain issues that could ultimately impact the application of the standard. In September 2000, the FASB issued SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, which revises the standards for accounting and disclosure of securitizations and other transfers of financial assets and extinguishments of liabilities. With certain exceptions, the standard will be applied prospectively to transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001. We do not expect the adoption of this new standard to have a material impact on our financial condition or results of operations. Market Risk Sensitive Instruments and Risk Management We are exposed to market risk because we utilize financial instruments, derivative financial instruments and derivative commodity instruments. The market risks inherent in these instruments are represented by the potential loss due to adverse changes in commodity prices, equity security prices and interest rates as described below. Interest rate risk generally is related to our outstanding debt, preferred stock and trust-issued securities. We are exposed to equity price risk primarily as a result of equity securities held in nuclear decommissioning trusts. Commodity price risk is experienced in our power generation and commodity marketing and trading business due to the exposure to market shifts in the prices received and paid for electricity and natural gas. We are using sensitivity analysis to disclose quantitative information about our exposure to commodity price and interest rate risks. Our sensitivity analysis estimates the potential loss of future earnings that may result from market risk sensitive instruments over a selected time period due to hypothetical changes in interest rates and commodity prices. The tabular presentation methodology is used to disclose equity price risk. Commodity Price Risk As part of our strategy to market energy from our generation capacity and to manage related risks, we manage a portfolio of derivative commodity contracts held for trading purposes. These contracts are sensitive to changes in the prices of electricity and natural gas. We employ established policies and procedures to manage the risks associated with these price fluctuations and use various commodity instruments, such as futures, swaps and options, to reduce risk by creating offsetting market positions. In addition, we seek to use our generation capacity, when not needed to serve customers in our service territory, to satisfy commitments to sell energy. One of the techniques commonly used to measure risk in a commodity trading portfolio is sensitivity analysis, which determines a hypothetical change in the fair value of the portfolio which would result from an assumed change in the market prices of the related commodities. The fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, market value reflects our best estimates considering over-the- counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are marked to market based on closing exchange prices. 32 We have determined a hypothetical loss by calculating a hypothetical fair value for each contract assuming a 10% unfavorable change in the market prices of the related commodity and comparing it to the fair value of the contracts based on market prices at December 31, 2000 and 1999. This hypothetical 10% change in commodity prices would have resulted in a hypothetical loss of approximately $3 million and $5 million in the fair value of our commodity contracts as of December 31, 2000 and 1999, respectively. The sensitivity analysis does not include the price risks associated with utility operations, including those underlying utility fuel requirements. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks principally include credit risk, which is not reflected in the sensitivity analysis above. Interest Rate Risk We manage our exposure to interest rate risk by maintaining a portfolio of both fixed and variable-rate debt instruments. In addition, we participate in interest rate sensitive derivatives, such as interest rate swaps, to manage this risk. As part of our risk management policies, we may participate in similar types of derivatives in the future. Our sensitivity analysis estimates the impact of a hypothetical change in interest rates on our variable-rate long-term and short-term financial instruments and interest rate sensitive derivatives. For financial instruments outstanding at December 31, 2000, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $9 million. A similar hypothetical increase in market interest rates, as determined at December 31, 1999, resulted in a decrease in annual earnings of $8 million. Equity Price Risk The following table presents a description of marketable equity securities held at December 31, 2000 and 1999. In accordance with current accounting standards, these securities are reported on the balance sheet at fair value.
At December 31, --------------------- 2000 1999 ---------- ---------- Fair Fair Cost Value Cost Value ---- ----- ---- ----- (Millions) Nuclear decommissioning trust investments.............. $279 $549 $274 $565
Risk Management Policies These commodity contracts are sensitive to changes in the prices of electricity and natural gas. We have appropriate operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, we have established an independent function to monitor compliance with the price risk management policies of all subsidiaries. Our trading activities also expose us to credit risk. Credit risk represents the potential loss that we would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with respect to its counterparties that management believes minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of standardized agreements which facilitate the netting of cash flows associated with a single counterparty. We also monitor the financial condition of existing counterparties on an ongoing basis. Considering the system of internal controls in place and credit reserve levels at December 31, 2000, we believe it unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance. 33 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See Market Risk Sensitive Instruments and Risk Management under Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. 34 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No. ---- Report of Management..................................................... 38 Independent Auditors' Report ............................................ 39 Consolidated Statements of Income for the years ended December 31, 2000, 1999 and 1998........................................................... 40 Consolidated Balance Sheets at December 31, 2000 and 1999................ 42 Consolidated Statements of Retained Earnings for the years ended December 31, 2000, 1999 and 1998................................................. 44 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998..................................................... 45 Notes to Consolidated Financial Statements............................... 46
35 REPORT OF MANAGEMENT The Company's management is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the Company's annual report on Form 10-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with generally accepted accounting principles. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements. Management maintains a system of internal accounting controls designed to provide reasonable assurance, at a reasonable cost, that the Company's assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal accounting control and, therefore, cannot provide absolute assurance that the objectives of the established internal accounting controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. Management believes that during 2000 the system of internal control was adequate to accomplish the intended objective. The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by the Board of Directors. Their audits were conducted in accordance with auditing standards generally accepted in the United States of America and included a review of the Company's accounting systems, procedures and internal controls, and the performance of tests and other auditing procedures sufficient to provide reasonable assurance that the Consolidated Financial Statements are not materially misleading and do not contain material errors. The Audit Committee of the Board of Directors of Dominion Resources, Inc., composed entirely of directors who are not officers or employees of Dominion Resources, Inc. or its subsidiaries, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters of the Company and to ensure that each is properly discharging its responsibilities. Both the independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time. Management recognizes its responsibility for fostering a strong ethical climate so that the Company's affairs are conducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the Company's Code of Ethics, which is distributed throughout the Company. The Code of Ethics addresses, among other things, the importance of ensuring open communication within the Company; potential conflicts of interest; compliance with all domestic and foreign laws, including those relating to financial disclosure; the confidentiality of proprietary information; and full disclosure of public information. VIRGINIA ELECTRIC AND POWER COMPANY /s/ G. Scott Hetzer /s/ Steven A. Rogers Senior Vice President and Treasurer Vice President and Principal Accounting Officer 36 INDEPENDENT AUDITORS' REPORT To the Board of Directors of Virginia Electric and Power Company Richmond, Virginia We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the Company) as of December 31, 2000 and 1999, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting used to develop the market related value of pension plan assets in 2000. /s/ Deloitte & Touche LLP Richmond, Virginia January 25, 2001 37 VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME
For The Years Ended December 31, --------------------- 2000 1999 1998 ------ ------ ------ (Millions) Operating revenue and income: Regulated electric sales............................... $4,492 $4,227 $3,979 Other.................................................. 299 364 301 ------ ------ ------ Total................................................ 4,791 4,591 4,280 ------ ------ ------ Expenses: Fuel, net.............................................. 1,104 986 953 Purchased power capacity, net.......................... 740 809 806 Restructuring costs.................................... 71 Impairment of regulatory assets........................ 159 Operations and maintenance............................. 957 959 854 Depreciation and amortization.......................... 558 548 537 Other taxes............................................ 275 282 290 ------ ------ ------ Total................................................ 3,705 3,584 3,599 ------ ------ ------ Income from operations................................... 1,086 1,007 681 Other income............................................. 47 25 23 ------ ------ ------ Income before interest and income taxes.................. 1,133 1,032 704 ------ ------ ------ Interest and related charges: Interest expense....................................... 285 278 306 Distributions--preferred securities of subsidiary trust................................................. 11 11 11 ------ ------ ------ Total................................................ 296 289 317 ------ ------ ------ Income before income taxes, extraordinary item, and cumulative effect of a change in accounting principle... 837 743 387 Income tax expense....................................... 279 258 157 ------ ------ ------ Income before extraordinary item and cumulative effect of a change in accounting principle........................ 558 485 230 Extraordinary item (net of income taxes of $197)......... (255) Cumulative effect of a change in accounting principle (net of income taxes of $11)............................ 21 ------ ------ ------ Net income............................................... 579 230 230 Preferred dividends...................................... 36 37 36 ------ ------ ------ Balance available for common stock....................... $ 543 $ 193 $ 194 ====== ====== ======
The Company had no other comprehensive income reportable in accordance with Statement of Financial Accounting Standards (SFAS) No. 130, Reporting Comprehensive Income. The accompanying notes are an integral part of the Consolidated Financial Statements. 38 VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS
At December 31, --------------- 2000 1999 ------- ------- (Millions) ASSETS CURRENT ASSETS: Cash and cash equivalents.................................... $ 141 $ 62 Accounts receivable: Customers (less allowance for doubtful accounts of $16 in 2000 and $12 in 1999).............................................. 1,134 664 Other...................................................... 82 67 Receivable from affiliated companies......................... 34 Inventories (average cost method): Materials and supplies..................................... 129 124 Fossil fuel................................................ 102 111 Commodity contract assets.................................... 1,047 362 Other........................................................ 164 125 ------- ------- Total current assets....................................... 2,833 1,515 ------- ------- INVESTMENTS: Nuclear decommissioning trust funds.......................... 851 818 Other........................................................ 63 52 ------- ------- Total investments.......................................... 914 870 ------- ------- PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment................................ 16,190 15,688 Less accumulated depreciation................................ 7,165 6,746 ------- ------- 9,025 8,942 Nuclear fuel, net............................................ 140 137 ------- ------- Net property, plant and equipment.......................... 9,165 9,079 ------- ------- DEFERRED CHARGES AND OTHER ASSETS: Regulatory assets, net....................................... 235 221 Unamortized debt issuance costs.............................. 30 31 Commodity contract assets.................................... 79 3 Other........................................................ 75 46 ------- ------- Total deferred charges and other assets.................... 419 301 ------- ------- Total assets............................................... $13,331 $11,765 ======= =======
The accompanying notes are an integral part of the Consolidated Financial Statements. 39 VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS
At December 31, --------------- 2000 1999 ------- ------- (Millions) LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES: Securities due within one year............................... $ 241 $ 375 Short-term debt.............................................. 714 378 Accounts payable, trade...................................... 882 534 Payable to affiliated companies.............................. 122 Customer deposits............................................ 55 49 Accrued payroll.............................................. 88 88 Accrued interest............................................. 94 97 Accrued taxes................................................ 60 52 Commodity contract liabilities............................... 994 347 Other........................................................ 100 116 ------- ------- Total current liabilities.................................. 3,350 2,036 ------- ------- LONG-TERM DEBT................................................. 3,561 3,551 ------- ------- DEFERRED CREDITS AND OTHER LIABILITIES: Deferred income taxes........................................ 1,494 1,452 Deferred investment tax credits.............................. 130 146 Commodity contract liabilities............................... 87 5 Other........................................................ 216 188 ------- ------- Total deferred credits and other liabilities............... 1,927 1,791 ------- ------- COMMITMENTS AND CONTINGENCIES OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST(/1/)......................................... 135 135 ------- ------- PREFERRED STOCK: Preferred stock not subject to mandatory redemption.......... 509 509 ------- ------- COMMON STOCKHOLDER'S EQUITY: Common stock, no par, 300,000 shares authorized, 171,484 shares outstanding at December 31, 2000 and 1999............ 2,738 2,738 Other paid-in capital........................................ 16 17 Retained earnings............................................ 1,095 988 ------- ------- Total common stockholder's equity.......................... 3,849 3,743 ------- ------- Total liabilities and shareholder's equity................. $13,331 $11,765 ======= =======
- -------- (/1/As)described in Note 14 to Consolidated Financial Statements, the 8.05% Junior Subordinated Notes totaling $139 million principal amount constitute 100% of the Trust's assets. The accompanying notes are an integral part of the Consolidated Financial Statements. 40 VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For The Years Ended December 31, ---------------------- 2000 1999 1998 ------ ------ ------ (Millions) Balance at beginning of year.......................... $ 988 $1,178 $1,362 Net income............................................ 579 230 230 ------ ------ ------ Total............................................. 1,567 1,408 1,592 ------ ------ ------ Cash dividends: Preferred stock subject to mandatory redemption..... (7) (11) (11) Preferred stock not subject to mandatory redemption......................................... (29) (26) (25) Common stock........................................ (408) (383) (378) ------ ------ ------ Total dividends................................... (444) (420) (414) ------ ------ ------ Distribution of common stock of telecommunications subsidiary to parent................................. (30) Other................................................. 2 Balance at end of year................................ $1,095 $ 988 $1,178 ====== ====== ======
The accompanying notes are an integral part of the financial statements. 41 VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Years Ended December 31, ------------------- 2000 1999 1998 ----- ----- ----- (Millions) CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: Net income.............................................. $ 579 $ 230 $ 230 Adjustments to reconcile net income to net cash from operating activities: Cumulative effect of a change in accounting principle............................................ (21) Restructuring costs................................... 58 Extraordinary item, net of income taxes............... 255 Impairment of regulatory assets....................... 159 Depreciation and amortization......................... 637 629 613 Deferred income taxes................................. 27 38 (6) Deferred investment tax credits....................... (17) (17) (17) Deferred fuel expenses, net........................... (33) (35) (34) Deferred capacity expenses............................ (16) Changes in: Accounts receivable................................. (524) 123 (41) Inventories......................................... 4 2 (24) Accounts payable, trade............................. 487 (32) 91 Accrued expenses.................................... 5 16 18 Commodity contract assets and liabilities (including affiliates)........................................ (33) (92) 66 Other............................................... (64) (9) 55 ----- ----- ----- Net Cash Flows From Operating Activities.......... 1,105 1,108 1,094 ----- ----- ----- CASH FLOWS USED IN INVESTING ACTIVITIES: Plant construction and other property additions......... (652) (673) (451) Nuclear fuel............................................ (82) (64) (81) Nuclear decommissioning contributions................... (36) (35) (37) Other................................................... (3) (13) ----- ----- ----- Net Cash Flows Used in Investing Activities........... (770) (775) (582) ----- ----- ----- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: Issuance (repayment) of short-term debt, net............ 336 156 (4) Issuance of long-term debt.............................. 250 305 270 Repayment of long-term debt and preferred stock......... (376) (345) (334) Common stock dividend payments.......................... (408) (383) (378) Preferred stock dividend payments....................... (36) (37) (36) Distribution-preferred securities of subsidiary trust... (11) (11) (11) Other................................................... (11) (5) (6) ----- ----- ----- Net Cash Flows Used in Financing Activities........... (256) (320) (499) ----- ----- ----- Increase in cash and cash equivalents................... 79 13 13 Cash and cash equivalents at beginning of year.......... 62 49 36 ----- ----- ----- Cash and cash equivalents at end of year................ $ 141 $ 62 $ 49 ===== ===== ===== SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for: Interest (excluding amounts capitalized).............. $ 291 $ 278 $ 309 Income taxes.......................................... 331 232 184 Non-cash transactions from financing activities: Distribution of common stock of telecommunications subsidiary to parent, net of cash.................... 19
The accompanying notes are an integral part of the Consolidated Financial Statements. 42 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1. Nature of Operations Virginia Electric and Power Company, a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion), a Virginia corporation, is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy within a 30,000 square-mile area in Virginia and northeastern North Carolina. It sells electricity to retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population. The Company engages in off- system wholesale purchases and sales of electricity and purchases and sales of natural gas, and has developed trading relationships beyond the geographic limits of its retail service territory. Within this document, the term "Company" shall refer to the entirety of Virginia Electric and Power Company, including its Virginia and North Carolina operations, and all of its subsidiaries. The Company manages its operations along two primary business lines, Energy and Delivery. The Energy segment encompasses the Company's portfolio of generating facilities and power purchase contracts, trading and marketing activities, nuclear consulting services and energy services activities. The Delivery segment includes bulk power transmission, distribution and metering services, and customer service and continues to be subject to cost-based regulation. Note 2. Significant Accounting Policies Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate regulation may differ from accounting methods generally applied by nonregulated companies. When the accounting allocations prescribed by regulatory authorities are used for ratemaking, the economic effects thereof must be considered in the application of generally accepted accounting principles. See Note 9 for further discussion on regulatory assets. The consolidated financial statements reflect certain estimates and assumptions made by management that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses for the periods presented. Actual results could differ from those estimates. The consolidated financial statements represent the accounts of the Company after the elimination of intercompany transactions. Certain amounts in the 1999 and 1998 financial statements have been reclassified to conform to the 2000 presentation. Operating Revenue Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Revenue from trading activities includes realized commodity contract revenue, net of related cost of sales, amortization of option premiums and unrealized gains and losses resulting from marking to market those commodity contracts not yet settled. Fuel, Net Fuel, net represents fuel costs subject to rate regulation. It includes the cost of fossil fuel, nuclear fuel and purchased energy used to serve electric sales. It also includes the cost of purchased energy associated with power marketing sales subject to cost of service rate regulation. 43 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Approximately 95 percent of rate regulated fuel costs are subject to deferral accounting. Deferral accounting provides that the difference between reasonably incurred actual expenses and the level of expenses included in current rates is deferred and matched against future revenue. Fuel, net includes the effect of this deferral accounting and may therefore reflect expenses that are marginally higher or lower than the actual cost of fuel consumed during the period. Property, Plant and Equipment Property, plant and equipment is recorded at original cost, which includes labor, materials, services, capitalized interest and other indirect costs. The cost of maintenance and repairs is charged to the appropriate operating expense accounts. The cost of additions and replacements is charged to the appropriate utility plant account, except that the cost of minor additions and replacements is charged to maintenance expense. During 2000 and 1999, the Company capitalized interest costs for generation-related projects of $18 million and $13 million, respectively. Depreciation and Amortization Depreciation of property, plant, and equipment (other than nuclear fuel) is computed on the straight-line method based on projected useful service lives. The cost of depreciable transmission and distribution property retired and related cost of removal, less salvage, are charged to accumulated depreciation. For generation-related property, cost of removal is charged to expense as incurred. The Company records gains and losses upon retirement of generation- related property based upon the difference between proceeds received, if any, and the property's undepreciated basis at the retirement date. The general ranges of estimated useful lives for property, plant and equipment are as follows: generation 5-41 years, transmission 34 years, distribution 27 years, and other 8-25 years. Operating expenses include amortization of nuclear fuel, which is provided on a unit of production basis sufficient to fully amortize, over the estimated service life, the cost of the fuel plus permanent storage and disposal costs. Income Taxes The Company files a consolidated federal income tax return with Dominion. The Company is subject to a tax-sharing agreement with Dominion, pursuant to which taxes are allocated to the Company based upon taxable income, determined on a separate company basis. Deferred investment tax credits are being amortized over the service lives of the property giving rise to such credits. Amortization of Debt Issuance Costs The Company defers and amortizes expenses incurred in connection with the issuance of long-term debt, including premiums and discounts associated with such debt, over the lives of the respective issues. As permitted by appropriate regulatory jurisdictions, gains or losses resulting from the redemption of debt are deferred and amortized over the remaining lives of the redeemed issues. In the case of a refinancing, the Company amortizes such gains and losses over the lives of the new issues of long-term debt. Gains or losses resulting from the retirement or refinancing of debt allocable to generation-related operations are recorded in accordance with SFAS No. 4, Reporting Gains and Losses From Extinguishment of Debt. 44 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Cash and Cash Equivalents Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2000 and 1999, the Company's accounts payable included the net effect of checks outstanding but not yet presented for payment of $78 million and $52 million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand and temporary investments purchased with an initial maturity of three months or less. Commodity Contracts As part of the Company's strategy to market energy from its generation capacity and to manage the risks related thereto, the Company enters into contracts for the purchase and sale of energy commodities. The trading activities of the Company's Energy Clearinghouse include forward contracts and the purchase and sale of over-the-counter options that require physical delivery of the underlying commodity. Furthermore, in order to manage risk associated with energy requirements for utility operations, the Company uses physically and financially settled swap, future, forward, and option instruments negotiated both on the exchange and over-the-counter. All contracts initiated within the Energy Clearinghouse are shown at fair value on the Company's financial statements. The mark-to-market valuation method results in unrealized gains and losses on commodity contracts not yet settled. Unrealized gains and losses on contracts initiated for trading purposes are reported in earnings. Unrealized gains and losses on contracts designated as hedges for accounting purposes are shown as changes in assets and liabilities. Exchange-traded contracts are marked to market based on exchange closing prices. For instruments negotiated over-the-counter, fair value reflects management's best estimates considering exchange closing prices, industry publications, independent price quotations, time value, and volatility factors of the underlying commitments. Commodity contracts representing unrealized gain positions are reported as commodity contract assets; commodity contracts representing unrealized losses are reported as commodity contract liabilities. In addition, purchased options and options sold are reported as commodity contract assets and commodity contract liabilities, respectively, at estimated market value until exercise or expiration. Realized commodity contract revenue, net of related cost of sales, settlement of futures contracts, amortization of option premiums and unrealized gains and losses resulting from marking positions to market are included in other revenue. Cash flows from trading activities are reported as operating activities in the Consolidated Statements of Cash Flows. Interest Rate Swaps The net of amounts paid and amounts received under interest rate swaps is reported as interest expense on the Consolidated Statements of Income. Note 3. Accounting Change During 2000, Dominion and its subsidiaries, including the Company, adopted a new company-wide method of calculating the market related value of pension plan assets used to determine the expected return on plan assets, a component of net periodic pension cost. Prior to Dominion's acquisition of Consolidated Natural Gas Company (CNG), each company used different methods to determine the "calculated value" of market related value of plan assets. Dominion's previous method recognized interest income, dividends and realized gains and losses immediately and recognized unrealized gains and losses evenly over a five-year period. Under its new method, the market related value of plan assets would reflect the difference between actual investment returns and expected investment returns evenly over a four-year period. Dominion believes that the new method 45 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) is preferable to continuing to use either or both of the former methods as the new method enhances the predictability of expected return on plan assets, provides consistent treatment of all investment gains and losses, and results in calculated market related plan asset values that are generally closer to market value as compared to values calculated under the previous methods. As the primary participating employer in the Dominion Resources Retirement Plan, the Company recorded its proportionate share of the cumulative effect of the change in accounting principle, $21 million (net of income taxes of $11 million). Other than the impact of the cumulative effect of the change in accounting principle, the effect of the change on net income for 2000 was not material. Retroactive application of the new method, on a pro forma basis, would not have materially changed the Company's net income for 1999 or 1998. Note 4. Recently Issued Accounting Standards In 2000, the Financial Accounting Standards Board (FASB) issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, which amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133 requires that all derivative instruments be recorded on the balance sheet at their fair value beginning January 1, 2001. The Company holds certain commodity contracts for trading purposes that are already subject to fair value accounting under Emerging Issues Task Force (EITF) Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The Company determined that certain other contracts will be subject to fair value accounting under SFAS No. 133. A substantial portion of these contracts is used by the Company in its production and delivery of energy to its customers and involves various hedging strategies. In addition to these commodity contracts, the Company uses interest rate swaps to manage its cost of capital. Under SFAS No. 133, changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated and effective as part of a hedge strategy, and, if it is, whether such strategy represents a fair value or cash flow hedge. For fair value hedge strategies, where the Company is hedging the changes in fair value of assets, liabilities or firm commitments, changes in the fair value of the derivative instruments will generally be offset in the income statement by changes in the fair value of the hedged items. For cash flow hedge strategies, where the Company is hedging the variability of cash flows related to variable-priced assets, liabilities or forecasted transactions, including anticipated production, purchases or sales, changes in the fair value of the derivative instruments will be reported in other comprehensive income. Amounts reported in other comprehensive income will be adjusted for changes in fair value until reclassified to earnings. Such reclassification will generally occur when earnings are affected by the hedged transactions. As amounts are reclassified from other comprehensive income, the impact on earnings should generally be offset by the recognition of the hedged transactions. The Company will record after-tax charges to net income of approximately $1 million and other comprehensive income of approximately $14 million in the first quarter of 2001 for the initial adoption of SFAS No. 133. These adjustments will be recognized as of January 1, 2001 as the cumulative effect of a change in accounting principle. The Derivatives Implementation Group (DIG), a group sponsored by FASB, continues to develop interpretative guidance. The DIG has not yet concluded on certain issues that could ultimately impact the application of the standard. Also in 2000, the FASB issued SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, which revises the standards for accounting and disclosure of securitizations 46 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) and other transfers of financial assets and extinguishments of liabilities. With certain exceptions, the standard will be applied prospectively to transfers and servicing of financial assets and extinguishments of liabilities occurring after March 31, 2001. The Company does not expect the adoption of this new standard to have a material impact on its financial condition or results of operations. Note 5. Restructuring Costs Subsequent to the CNG acquisition on January 28, 2000, Dominion and its subsidiaries developed and began the implementation of a plan to restructure the operations of the combined companies. The restructuring plan includes the following components: . An involuntary severance program; . A voluntary early retirement program (the ERP); and . A transition plan to implement operational changes to provide efficiencies, including the consolidation of post-merger operations and the integration of information technology systems. Dominion and its subsidiaries established a comprehensive involuntary severance package for salaried employees whose positions will be eliminated. Severance payments are based on the individual's base salary and years of service at the time of termination. Under the restructuring plan, 174 positions at the Company and its subsidiaries were identified for elimination, resulting in $14 million of employee severance related costs. At December 31, 2000, a total of 168 positions had been eliminated, and $8 million of severance benefits had been paid. Salaried employees of the Company, excluding officers, who had attained age 52 and completed at least five years of service as of July 1, 2000 were eligible under the ERP. The early retirement option provides up to three additional years of age and three additional years of employee service, subject to age and service maximums, for benefit formula purposes under Dominion's pension and postretirement medical plans. Approximately 400 Company employees elected to participate in the ERP, resulting in an expense approximating $51 million. Some of the ERP participants will receive benefits under both the involuntary severance package and the ERP. Benefits under the involuntary severance package are subject to reduction as a result of coordination with the additional retirement plan benefits provided by the ERP. Restructuring costs also included $6 million related to consolidation and integration of business operations and administrative functions. Note 6. Extraordinary Item and 1998 Virginia Rate Settlement Extraordinary Item--Discontinuance of SFAS No. 71 In 1999, legislation was passed that established a detailed plan to restructure the electric utility industry in Virginia. The legislation's deregulation of generation is an event that required discontinuation of SFAS No. 71 for the Company's generation operations in 1999. The Company's transmission and distribution operations continue to meet the criteria for recognition of regulatory assets and liabilities as defined by SFAS No. 71. In addition, fuel continues to be subject to deferral accounting. In order to measure the amount of regulatory assets to be written off upon discontinuance of SFAS No. 71, the Company evaluated to what extent recovery of regulatory assets would be provided through the capped rates during the transition period ending July 2007. Generation-related assets and liabilities that will not be recovered through the capped rates were written off in 1999, resulting in an after-tax charge to earnings of $255 million. See Note 9 for discussion of net regulatory assets at December 31, 2000. The $255 million 47 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) charge also included 1) the write-off of approximately $38 million, after-tax, of deferred investment tax credits and 2) approximately $18 million, after-tax, of other generation-related assets. A corresponding regulatory asset of $23 million was established representing the amount expected to be recovered during the transition period related to these assets. The events that caused the discontinuance of SFAS No. 71 for generation- related assets and liabilities, also required a review of generation assets in accordance with the provisions of SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This review was based on estimates of possible future market prices, load growth, competition and many other assumptions and included the effects of nuclear decommissioning and other currently identified environmental expenditures. Based on those analyses which were highly dependent on the underlying assumptions, no plant write-downs were appropriate at that time. The Company also reviewed its long-term power purchase contracts for potential loss in accordance with SFAS No. 5, Accounting for Contingencies, and Accounting Research Bulletin No. 43, Chapter 4, Inventory Pricing. Based on projections of possible future market prices for wholesale electricity, the results of the analyses indicated no loss recognition was appropriate at that time. Other projections of possible future market prices indicated a possible loss of $500 million. In the absence of capped rates as provided by the legislation, at March 31, 1999, the potential loss exposure would have been approximately $3.2 billion. Significant estimates were required in recording the effect of the deregulation legislation, including the resulting impact on the fair value determination of generating facilities and estimated purchases under long-term power purchase contracts. Such projections are highly dependent on future customer load projections, generating unit availability, the timing and type of future capacity additions in the Company's market area and future market prices for fuel and electricity and are subject to future re-evaluation. Virginia Rate Settlement The Company's 1998 settlement of its outstanding base rate proceedings defined a new regulatory framework for the Company's transition to electric competition. The impact of the settlement provisions were largely recognized in 1998 and 1999 and included: 1) a $150 million base rate reduction phased-in during 1998 and 1999, 2) a $150 million one-time refund in 1998, and 3) the accrual of $159 million, when coupled with $65 million previously recorded in earlier years, for the write-off of $220 million of regulatory assets. 48 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 7. Income Taxes Details of income tax expense are as follows:
Year ended December 31, ---------------- 2000 1999 1998 ---- ---- ---- (Millions) Current expense: Federal..................................................... $262 $224 $167 State....................................................... 7 13 12 ---- ---- ---- 269 237 179 Deferred expense: Federal..................................................... 32 36 (3) State....................................................... (5) 2 (2) ---- ---- ---- 27 38 (5) Net deferred investment tax credits-amortization.............. (17) (17) (17) ---- ---- ---- Total income tax expense...................................... $279 $258 $157 ==== ==== ====
Total federal income tax expense differs from the amount computed by applying the statutory federal income tax rate to pretax income for the following reasons:
Year ended December 31, ---------------- 2000 1999 1998 ---- ---- ---- (Millions) Income before income taxes................................... $837 $743 $387 Federal income tax expense at federal statutory rate (35%)... 293 260 135 ---- ---- ---- Increases (decreases) resulting from: Plant and equipment differences............................ 4 3 26 Amortization of investment tax credits..................... (12) (15) (15) Terminated construction project costs...................... 1 5 State income tax, net of federal tax benefit............... 1 10 7 Other, net................................................. (7) (1) 1 ---- ---- ---- Total increase (decrease) from reconciling items........... (14) (2) 22 ---- ---- ---- Total income tax expense................................. $279 $258 $157 ==== ==== ==== Effective tax rate....................................... 33.3% 34.7% 40.6%
The Company's net accumulated deferred income taxes consist of the following:
At December 31 ------------- 2000 1999 ------ ------ (Millions) Deferred income tax assets: Investment tax credits........................................... $ 50 $ 52 ------ ------ Deferred income tax liabilities: Plant and equipment differences.................................. 1,502 1,466 Income taxes recoverable through future rates.................... 18 20 Other............................................................ 24 18 ------ ------ Total deferred income tax liabilities.......................... 1,544 1,504 ------ ------ Total net accumulated deferred income taxes.................... $1,494 $1,452 ====== ======
49 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 8. Nuclear Operations Decommissioning When the Company's nuclear units cease operations, the Company is obligated to decontaminate or remove radioactive contaminants so that the property will not require Nuclear Regulatory Commission (NRC) oversight. This phase of a nuclear power plant's life cycle is termed decommissioning. While the units are operating, amounts are currently being collected from ratepayers that, when combined with investment earnings, will be used to fund this future obligation. These dollars are deposited into external trusts through which the funds are invested. The amount being accrued for decommissioning is equal to the amount being collected from ratepayers and is included in Depreciation and Amortization Expense. The decommissioning collections were $36 million per year for the period 1998 through 2000. However, an additional $10 million was expensed in 1997 based on an expected increase in the decommissioning collections for 1997 as provided in the Company's rate case then pending before the Virginia Commission. Since the Virginia rate case settlement did not include such an increase, the 1998 expense provision was decreased by $10 million. Therefore, the expense levels were $36 million, $36 million, and $26 million in 2000, 1999, and 1998, respectively. Net earnings (losses) of the trust's investments are included in Other Income in the Company's Consolidated Statements of Income. In 2000, 1999 and 1998, net earnings were $20 million, $17 million, and $18 million, respectively. The accretion of the decommissioning obligation is equal to the trusts' net earnings and is also recorded in Other Income. The accumulated provision for decommissioning, which is included in Accumulated Depreciation in the Company's Consolidated Balance Sheets, includes the accrued expense and accretion described above and any unrealized gains and losses on the trusts' investments. At December 31, 2000, the net unrealized gains were $268 million, a decrease of $23 million over the December 31, 1999, amount of $291 million. The accumulated provision for decommissioning at December 31, 2000 and 1999, was $851 million and $818 million, respectively. The total estimated cost to decommission the Company's four nuclear units is $1.6 billion based upon a site-specific study that was completed in 1998. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. This method assumes that dismantlement and other decommissioning activities will begin shortly after cessation of operations, which under current operating licenses will begin in 2012 as detailed in the table below.
Surry North Anna Total All ----------- ----------- --------- Unit Unit Unit Unit 1 2 1 2 Units ----- ----- ----- ----- --------- (Millions) NRC license expiration year................. 2012 2013 2018 2020 Current cost estimate (1998 dollars)........ $ 411 $ 413 $ 401 $ 387 $1,612 Funds in external trusts at December 31, 2000....................................... 235 230 198 188 851 2000 contributions to external trusts....... 11 11 7 7 36
50 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of the nuclear facilities. The Company's 2000 NRC minimum financial assurance amount, aggregated for the four nuclear units, was $1.0 billion and will be satisfied by a combination of surety bonds and the funds being collected in the external trusts. FASB is reviewing the accounting for nuclear plant decommissioning. FASB has tentatively determined that the estimated cost of decommissioning should be reported as a liability rather than as accumulated depreciation and that a substantial portion of the decommissioning obligation should be recognized earlier in the operating life of the nuclear unit. During its deliberations, FASB expanded the scope of the project to include similar unavoidable obligations to perform closure and post-closure activities for other long-lived assets, possibly including non-nuclear power plants. Any forthcoming standard also may change regulated utility plant depreciation practices, the impact of which cannot be determined at this time. Insurance The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $9.5 billion for a single nuclear incident. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. The Company has purchased $200 million of coverage from the commercial insurance pools with the remainder provided through a mandatory industry risk sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, the Company could be assessed up to $88 million for each of its four licensed reactors not to exceed $10 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The Company's current level of property insurance coverage ($2.55 billion for North Anna and $2.55 billion for Surry) exceeds the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance are used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The Company's nuclear property insurance is provided by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $21 million. Based on the severity of the incident, the board of directors of the Company's nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. For any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination, the Company has the financial responsibility for these losses. The Company purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, the Company is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period's maximum assessment is $5 million. As part owner of the North Anna Power Station, the co-owner is responsible for its share of the nuclear decommissioning obligation and insurance premiums applicable to that station, including any retrospective premium assessments and any losses not covered by insurance. 51 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 9. Regulatory Assets Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. The Company's regulatory assets include the following:
At December 31, ----------- 2000 1999 ----- ----- (Millions) Income taxes recoverable through future rates...................... $ 55 $ 57 Cost of decommissioning DOE uranium enrichment facilities.......... 49 55 Deferred losses on reacquired debt, net............................ 9 15 Deferred fuel...................................................... 98 63 Other.............................................................. 24 31 ----- ----- Total ........................................................... $ 235 $2221 ===== =====
The incurred costs underlying these regulatory assets may represent expenditures by the Company or may represent the recognition of liabilities that ultimately will be settled at some time in the future. See Note 6 for information about the impairment of regulatory assets resulting from the 1999 Virginia deregulation legislation and the 1998 Virginia rate settlement. Where permitted by appropriate regulatory jurisdictions for the portion of the Company's operations that are subject to cost-based regulation, income taxes recoverable through future rates represent principally the tax effect of depreciation differences not normalized in earlier years for ratemaking purposes. These amounts are amortized as the related temporary differences reverse. Such amounts are net of related regulatory liabilities and $39 million associated with deferred income taxes which were established at rates in excess of the current Federal rate and are subject to Internal Revenue Code normalization requirements. The cost of decommissioning the Department of Energy's (DOE) uranium enrichment facilities represents the Company's required contributions to a fund for decommissioning and decontaminating the DOE's uranium enrichment facilities. The Company began making contributions in 1992 and are expected to continue over a 15-year period with escalation for inflation. These costs are currently being recovered in fuel rates. Where permitted by appropriate regulatory jurisdictions for the portion of the Company's operations that are subject to cost-based regulation, gains or losses on refinanced debt are deferred and amortized over the lives of the new debt issues. Gains or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues. Deferred fuel accounting provides that the difference between reasonably incurred actual expenses and the recovery for such costs included in current rates is deferred and matched against future revenue. 52 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 10. Property, Plant and Equipment Property, plant and equipment, other than nuclear fuel, consists of the following:
At December 31, --------------- 2000 1999 ------- ------- (Millions) Generation..................................................... $ 8,103 $ 7,758 Transmission................................................... 1,557 1,517 Distribution................................................... 5,070 4,835 Other.......................................................... 944 901 ------- ------- 15,674 15,011 Construction work in progress.................................. 516 677 ------- ------- Total ......................................................... $16,190 $15,688 ======= =======
Note 11. Jointly Owned Plants The following information relates to the Company's proportionate share of jointly owned plants at December 31, 2000:
Bath County North Pumped Anna Clover Storage Power Power Station Station Station ------- ------- ------- (Millions) Ownership interest.................................... 60.0% 88.4% 50.0% Plant in service...................................... $1,067 $1,875 $538 Accumulated depreciation.............................. 294 1,135 69 Nuclear fuel.......................................... 350 Accumulated amortization of nuclear fuel.............. 335 Construction work in progress......................... 2 33 3
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interest. The Company's share of operating costs is classified in the appropriate operating expense (fuel, operations and maintenance, depreciation, taxes, etc.) in the Consolidated Statements of Income. 53 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 12. Short-term Debt and Credit Agreements The Company has a commercial paper program supported by two credit facilities. The Company has a $300 million credit facility and also participate in a credit facility that supports the combined commercial paper programs of Dominion, the Company and Consolidated Natural Gas Company (CNG). This facility, established in June 2000, is for $1.75 billion and matures May 2001. Although the Company has access to the full amount of the $1.75 billion facility, it operates with an internal allocation that may vary depending upon the needs of participating entities. Net borrowings under the commercial paper program were $714 million at December 31, 2000 with a weighted average interest rate of 6.63 percent and $378 million at December 31, 1999 with a weighted average interest rate of 6.11 percent. 54 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 13. Long-term Debt Long-term debt includes the following:
At December 31, ------------- 2000 1999 ------ ------ (Millions) First and refunding mortgage bonds (/1/): 1993 Series C, 5.875%, due 2000................................ $ $ 135 1993 Series E, 6.000%, due 2001................................ 100 100 1992 Series E, 7.375%, due 2002................................ 155 155 1993 Series F, 6.000%, due 2002................................ 100 100 1993 Series B, 6.625%, due 2003................................ 200 200 1992 Series C, 8.000%, due 2004................................ 250 250 1992 Series D, 7.625%, due 2007................................ 215 215 1997 Series A, 6.75%, due 2007................................. 200 200 Various series, 6.75%-8.75%, due 2021-2025..................... 1,101 1,101 ------ ------ Total first and refunding mortgage bonds..................... 2,321 2,456 ------ ------ Other long-term debt: Term notes: Fixed interest rate notes, 5.73%-10.00%, due 1998-2008....... 581 422 1999 Series B, senior notes, 7.20%, due 2004................. 75 75 1999 Series A, senior notes, 6.70%, due 2009................. 150 150 1998 Series A, senior notes, 7.15%, due 2038................. 150 150 Tax exempt financings: Money market municipal securities due 2007-2027(/2/,/3/) .... 489 489 Convertible interest rate bonds, 4.9%--5.15%, due 2022-- 2030(/3/)................................................... 40 10 Fixed interest rate bonds, 5.45%, due 2024(/1/).............. 19 19 ------ ------ Total other long-term debt................................. 1,504 1,315 ------ ------ 3,825 3,771 ------ ------ Less amounts due within one year: First and refunding mortgage bonds........................... 100 135 Term notes................................................... 141 60 ------ ------ Total amount due within one year........................... 241 195 ------ ------ Less unamortized discount, net of premium........................ 23 25 ------ ------ Total long-term debt....................................... $3,561 $3,551 ====== ======
- -------- (/1/The)first and refunding mortgage bonds and the fixed interest rate, tax- exempt financings are secured by a mortgage lien on substantially all of the Company's property. (/2/Certain)pollution control facilities at the Company's generating facilities have been pledged or conveyed to secure these financings. (/3/Interest)rates vary based on short-term, tax-exempt market rates. For 2000 and 1999, the weighted average daily interest rates were approximately 3.3 percent. Although these bonds are re-marketed within a one year period, they are classified as long-term debt because the Company intends to maintain the debt, and they are supported by long-term bank commitments. The following amounts of debt will mature during the next five years: 2001-- $241 million; 2002 -- $535 million; 2003 -- $240 million; 2004 -- $325 million, and 2005 -- $0. In February 2001, the Company issued $50 million in aggregate principal amount of Tax-Exempt Pollution Control Revenue Bonds due 2031. 55 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 14. Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Virginia Power Capital Trust I (VP Capital Trust) was established as a subsidiary of the Company for the sole purpose of selling $135 million of preferred securities (5.4 million shares at $25 par) in 1995. The Company concurrently issued $139 million of its 1995 Series A, 8.05% Junior Subordinated Notes (the Notes) in exchange for the $135 million realized from the sale of the preferred securities and $4 million of common securities of VP Capital Trust. The preferred securities and the common securities represent the total beneficial ownership interest in the assets held by VP Capital Trust. The Notes are the sole assets of VP Capital Trust. The preferred securities are subject to mandatory redemption upon repayment of the Notes at a liquidation amount of $25 plus accrued and unpaid distributions, including interest. The Notes are due September 30, 2025. However, that date may be extended up to an additional ten years if certain conditions are satisfied. Note 15. Preferred Stock Subject to Mandatory Redemption The total number of authorized shares for all preferred stock (whether or not subject to mandatory redemption) is 10 million shares. Upon involuntary liquidation, dissolution or winding-up of the Company, all presently outstanding preferred stock is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative. At December 31, 1999, there were 1.8 million issued and outstanding shares of preferred stock subject to mandatory redemption ($180 million) and the Company classified these securities as Securities Due Within One Year. During 2000, the Company redeemed all 1.8 million issued and outstanding shares. Note 16. Preferred Stock Not Subject to Mandatory Redemption Shown below are the series of preferred stock not subject to mandatory redemption that were outstanding as of December 31, 2000.
Issued and Outstanding Entitled Per Dividend Share Upon Shares(/1/) Liquidiation ----------- ------------ $5.00............................................... 107 $112.50 4.04................................................ 13 102.27 4.20................................................ 15 102.50 4.12................................................ 32 103.73 4.80................................................ 73 101.00 7.05................................................ 500 105.00(/2/) 6.98................................................ 600 105.00(/3/) MMP 1/87(/1/)....................................... 500 100.00 MMP 6/87(/1/)....................................... 750 100.00 MMP 10/88(/1/)...................................... 750 100.00 MMP 6/89(/1/)....................................... 750 100.00 MMP 9/92, Series A (/4/)............................ 500 100.00 MMP 9/92, Series B (/4/)............................ 500 100.00 ----- Total............................................. 5,090 =====
- -------- (/1/Shares)are presented in thousands. (/2/Through)7/31/03; amounts decline in steps thereafter to $100.00 after 7/31/13. (/3/Through)8/31/03; amounts decline in steps thereafter to $100.00 after 8/31/13. (/4/Money)Market Preferred (MMP) dividend rates are variable and are set every 49 days via an auction process. The combined weighted average rates for these series in 2000, 1999 and 1998, including fees for broker/dealer agreements, were 5.71 percent, 4.82 percent, and 4.49 percent, respectively. 56 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 17. Common Stock There were no changes in the number of authorized and outstanding shares of the Company's common stock during the three years ended December 31, 2000. Note 18. Long-term Incentives During 1999, approximately two million Dominion common stock options were granted to certain officers and key employees of the Company under a stock- based compensation plan sponsored by Dominion. These options vested on January 1, 2000. No compensation expense was recognized under the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. Had compensation expense been measured based on the fair value of the options on the date of grant, calculated under the provisions of SFAS No. 123, Accounting for Stock Based Compensation, the Company's allocated share of such compensation expense would have reduced reported net income in 1999 by approximately $5 million. During 2000, all officers of the Company became employees of Dominion Resources Services, Inc. Stock options granted during 2000 to other key employees of the Company were not material. No compensation expense was recognized for these awards, and the pro forma impact on net income had the Company measured compensation expense under SFAS No. 123 would not be material. Note 19. Employee Benefit Plans The Company participates in the Dominion Resources, Inc. Retirement Plan, a defined benefit pension plan. Retirement benefits are based on years of service and average base compensation over the consecutive 60-month period in which pay is highest (Pension Benefits). In 1999 and 1998, the Company provided certain health care and life insurance benefit plans for retired employees (Other Benefits). Health care benefits are provided to retirees who complete at least 10 years of service after attaining age 45. Beginning in 2000, the Company participated in plans providing Other Benefits to multiple Dominion subsidiaries. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits. As the Company's level of participation in the benefit plans is significant, the following disclosures of net periodic benefits costs and funded status present plan totals for those pension and other benefit plans in which the Company participates as well as the benefit costs allocated to and/or incurred by the Company. 57 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The components of the provision for net periodic benefit cost were as follows:
Pension Benefits Other Benefits ----------------- ---------------- Year ending December 31, 2000 1999 1998 2000 1999 1998 ------------------------ ----- ---- ---- ---- ---- ---- (Millions) (Millions) Service cost.............................. $ 39 $ 40 $ 32 $ 19 $ 16 $ 12 Interest cost............................. 85 76 71 29 27 24 Expected return on plan assets............ (108) (93) (80) (25) (19) (16) Amortization of transition obligation..... (3) 12 12 12 Amortization of prior service cost........ 1 ERP benefit costs......................... 38 13 Net amortization and deferral............. (1) (2) (1) ----- ---- ---- ---- ---- ---- Net periodic benefit cost................. $ 52 23 $ 22 $ 46 $ 36 $ 31 ===== ==== ==== ==== ==== ==== Company allocated expense................. $ 50 $ 21 $ 21 $ 42 $ 36 $ 31
Subsequent to Dominion's acquisition of CNG, Dominion and its subsidiaries developed and began the implementation of a plan to restructure the operations of the combined companies. This plan included a voluntary early retirement program (ERP). Salaried employees of the Company, excluding officers, who had attained age 52 and completed at least five years of service as of July 1, 2000 were eligible under the ERP. The early retirement option provides up to three additional years of age and three additional years of employee service, subject to age and service maximums, for benefit formula purposes under Dominion's postretirement medical and pension plans. Expenses under the ERP associated with pension and other benefits were $38 million and $13 million, respectively. See Note 5 for further discussion of restructuring costs. 58 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The following table sets forth the funded status of the plans:
Pension Other Benefits Benefits -------------- ---------- 2000 1999 2000 1999 ------ ------ ---- ---- Change in plan assets: Fair value of plan assets at beginning of year.. $1,305 $1,094 $272 $212 Actual return on plan assets.................. (5) 232 (7) 45 Contributions................................. 15 22 11 16 Benefits paid from plan assets................ (49) (43) (1) (1) ------ ------ ---- ---- Fair value of plan assets at end of year.... 1,266 1,305 275 272 ------ ------ ---- ---- Change in benefit obligation Benefit obligation at beginning of year................................ 1,097 1,126 401 372 Actuarial (gain)/loss during prior period....... (13) 25 ------ ------ ---- ---- Actual benefit obligation at beginning of year.. 1,097 1,113 401 397 Service cost.................................. 39 40 19 16 Interest cost................................. 85 76 29 27 Special termination benefit cost.............. 38 13 Benefits paid................................. (49) (43) (21) (18) Plan amendments............................... (16) (22) Actuarial (gain)/loss during the year......... 47 (89) 17 (28) ------ ------ ---- ---- Expected benefit obligation at end of year.. 1,241 1,097 436 394 ------ ------ ---- ---- Reconciliation of funded status: Funded status................................... 25 208 (161) (122) Unrecognized net actuarial (gain)/loss........ 14 (177) (10) (46) Unamortized prior service cost................ (14) 3 (2) Unrecognized net transition (asset)/obligation........................... (8) (12) 126 156 ------ ------ ---- ---- Prepaid (accrued) benefit costs............. $ 17 $ 22 $(47) $(12) ====== ====== ==== ====
Significant assumptions used in determining net periodic pension cost, the projected benefit obligation, and postretirement benefit obligations were:
Pension Other Benefits Benefits ---------- ---------- 2000 1999 2000 1999 ---- ---- ---- ---- Discount rates.......................................... 7.50% 7.50% 7.50% 7.50% Expected return on plan assets.......................... 9.50% 9.50% 6.50% 9.00% Rate of increase for compensation income................ 5.00% 5.00% 5.00% 5.00% Medical cost trend rate................................. 9.00% 4.75%
The medical cost trend rate is assumed to gradually decrease to 4.75% by 2005 and for years thereafter. 59 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
One One Percentage Percentage Point Point Increase Decrease ---------- ---------- (Millions) Effect on total of service and interest cost components for 2000............................................... $ 7 $ (5) Effect on postretirement benefit obligation at December 31, 2000............................................... 54 (44)
The funds collected for other postretirement benefits in rates, in excess of benefits actually paid during the year, are contributed to external benefit trusts. See Note 20 for a discussion of the impact of deregulation legislation on the recoverability of potentially stranded costs. The Company also sponsors employee savings plans which cover substantially all employees. Employer matching contributions of $12 million, $11 million and $11 million were expensed in 2000, 1999 and 1998, respectively. Note 20. Commitments and Contingencies The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will not have a material adverse effect on the Company's operations, financial position, liquidity or results of operations. Utility Rate Regulation Under Virginia's electric utility industry deregulation legislation, the Company's base rates will remain unchanged until July 2007 and recovery of generation-related costs will be provided through these capped rates. The period of capped rates may terminate as early as January 1, 2004, if petitioned by the Company and approved by the Virginia Commission. As the industry transitions to a deregulated environment, especially during this period of capped rates, the Company remains exposed to numerous risks, including, among others, exposure to potentially stranded costs, future environmental compliance requirements, changes in tax laws, inflation and increased capital costs. At December 31, 2000, the Company's exposure to potentially stranded costs was comprised of: long-term power purchase contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomic in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements. See Notes 8 and 19. Retrospective Premium Assessments Under several of the Company's nuclear insurance policies, the Company is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to these insurance companies. For additional information, see Note 8. Construction Program The Company has made substantial commitments in connection with its construction program and nuclear fuel expenditures. Those expenditures are estimated to total approximately $831 million for 2001. The 60 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Company presently estimates that 2001 construction expenditures, including nuclear fuel, will be met through cash flow from operations and through a combination of sales of securities and short-term borrowing. Power Purchase Contracts The Company has entered into contracts for the long-term purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. The Company has 54 non-utility purchase contracts with a combined dependable summer capacity of 3,973 Mw. The table below reflects the Company's minimum commitments as of December 31, 2000, for power purchases from utility and non-utility suppliers.
Commitment -------------- Year Capacity Other - ---- -------- ----- (Millions) 2001............................................................. $ 727 $ 43 2002............................................................. 724 43 2003............................................................. 674 31 2004............................................................. 672 29 2005............................................................. 665 25 Later years...................................................... 6,683 169 ------- ---- Total.......................................................... $10,145 $340 ======= ==== Present value of the total....................................... $ 5,580 $193 ======= ====
In addition to the minimum purchase commitments in the table above, under some of these contracts, the Company may purchase, at its option, additional power as needed. Purchased power expenditures, subject to cost of service rate regulation, (including economy, emergency, limited term, short-term and long- term purchases) for the years 2000, 1999, and 1998 were $1.1 billion, $1.2 billion, and $1.1 billion, respectively. See Note 6 regarding the evaluation of the Company's potential exposure under its long-term purchased power commitments. Fuel Purchase Commitments The Company's estimated fuel purchase commitments for the next five years for system generation are as follows: 2001 -- $379 million; 2002 -- $193 million; 2003 -- $166 million; 2004 -- $153 million; and 2005-- $133 million. Lease Commitments Total future minimum lease payments under the Company's noncancellable capital leases and operating leases that have initial or remaining lease terms in excess of one year were $174 million at December 31, 2000. Expected future minimum lease payments under these leases over the next five years are as follows: 2001 -- $34 million; 2002 -- $26 million; 2003 -- $20 million; 2004 -- $16 million; 2005 -- $14 million and $64 million for the years thereafter. 61 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Sales of Power The Company enters into agreements with other utilities and with other parties to purchase and sell capacity and energy. These agreements may cover current and future periods. The volume of these transactions varies from day to day based on the market conditions, our current and anticipated load, and other factors. The combined amounts of sales and purchases range from 3,000 Mw to 15,000 Mw at various times during a given year. These operations are closely monitored from a risk management perspective. Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations of the Company. Historically, the Company recovered these costs from customers through utility rates. However, to the extent environmental costs are incurred during the period ending June 30, 2007, in excess of the level currently included in Virginia jurisdictional rates, the Company's results of operations will decrease. After that date, the Company may seek recovery from customers through utility rates of only those environmental costs related to transmission and distribution operations. In 1987, the Environmental Protection Agency (EPA) identified the Company and a number of other entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. Current cost studies estimate total remediation costs for the sites to range from $98 million to $156 million. The Company's proportionate share of the total cost is expected to be in the range of $2 million to $3 million, based upon allocation formulas and the volume of waste shipped to the sites. The Company has accrued a reserve of $2 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay the costs apportioned to them. The Company generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 2000, any pending or possible claims were not recognized as an asset or offset against such obligations of the Company. In 1999, the Company was notified by the Department of Justice of alleged noncompliance with the EPA's oil spill prevention, control and countermeasures (SPCC) plans and facility response plan (FRP) requirements at one of the Company's power stations. If, in a legal proceeding, such instances of noncompliance are deemed to have occurred, the Company may be required to remedy any alleged deficiencies and pay civil penalties. Settlement of this matter is currently in negotiation and is not expected to be material to the Company's financial condition or results of operations. The Company also identified matters at certain other power stations that the EPA might view as not in compliance with the SPCC and FRP requirements. The Company reported these matters to the EPA and its plan for correction thereof. Presently, the EPA has not assessed any penalties against the Company, pending its review of the Company's disclosure information. Future resolution of these matters is not expected to have a material impact on the Company's financial condition or results of operations. During 2000, the Company received a Notice of Violation (NOV) from the EPA alleging that the Company is operating its Mt. Storm Power Station in West Virginia in violation of the Clean Air Act. The NOV alleges that the Company failed to obtain New Source Review permits prior to undertaking specified construction projects at the station. Violations of the Clean Air Act may result in the imposition of substantial 62 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) civil penalties and injunctive relief. Also in 2000, the Attorney General of New York filed a suit against the Company alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. The Company has also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit against the Company for similar violations. Currently, the Company has reached an agreement in principle with the federal government and the state of New York with the resolution of various Clean Air Act matters. The agreement in principle includes payment of a $5 million civil penalty, a commitment of $14 million for major environmental projects in Virginia, West Virginia, Connecticut, New Jersey and New York, and a 12-year, $1.2 billion capital investment program for environmental improvements at the Company's coal-fired generating stations in Virginia and West Virginia. The Company has already committed to a substantial portion of the $1.2 billion expeditures for SO\\2\\ and NOx emissions controls in response to other Clean Air Act requirements. Although the Company and EPA have reached an agreement in principle, the terms of a final binding settlement are still being negotiated. As of December 31, 2000, the Company has recorded, on a discounted basis, a $17 million liability for the civil penalty and environmental projects. Note 21. Fair Value of Financial Instruments The Company used available market information and appropriate valuation methodologies to estimate the fair value of each class of financial instrument for which it is practicable to estimate fair value. These estimates are not necessarily indicative of the amounts the Company could realize in a market exchange. In addition, the use of different market assumptions may have a material effect on the estimated fair value amounts.
Year ended December 31, 2000 1999 - ----------------------- --------------- --------------- Carrying Fair Carrying Fair Amount Value Amount Value -------- ------ -------- ------ (Millions) Assets: Cash and cash equivalents (/1/)............. $ 141 $ 141 $ 62 $ 62 Nuclear decommissioning trust funds (/2/)... 851 851 818 818 Commodity-based swaps (/3/)................. 281 281 25 25 Commodity-based options (/3/)............... 29 29 6 6 Liabilities and capitalization: Short-term debt (/1/)....................... 714 714 378 378 Commodity-based swaps (/3/)................. 325 325 24 24 Commodity-based options (/3/)............... 56 56 6 6 Long-term debt: First and refunding mortgage bonds (/4/).. 2,321 2,310 2,456 2,370 Medium-term notes and senior unsecured notes (/4/).............................. 956 954 797 750 Money market municipal tax-exempt securities (/5/)......................... 489 489 489 489 Convertible and fixed interest rate tax- exempt bonds (/6/)....................... 59 60 29 28 Preferred stock subject to mandatory redemption (/6/)........................... 180 181 Preferred securities of subsidiary trust (/4/)...................................... 135 133 135 117 Unrecognized financial instruments: Interest rate swap agreements (/7/)......... 3 (11)
- -------- (/1/The)carrying amount of cash and cash equivalents approximates fair value because of their short maturity. (/2/Fair)value is based on available market information and generally is the average of bid and asked price. (/3/Fair)value reflects the Company's best estimates considering over-the- counter quotations, time value and volatility factors of the underlying commitments. 63 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (/4/Fair)value is based on market quotations. (/5/The)interest rates for these notes vary so that fair value approximates carrying value. (/6/The)fair value is based on market quotations or is estimated by discounting the dividend and principal payments for a representative issue of each series over the average remaining life of the series. (/7/Fair)value was determined by the respective counterparties to the agreements and is based upon the present value of all estimated net future cashflows. Commodity Contracts Held for Trading Purposes As part of the Company's strategy to market energy from its generation capacity and to manage related risks, the Company manages a portfolio of commodity contracts held for trading purposes. These contracts are reported at fair value on the Consolidated Balance Sheet. Commodity contract assets totaled $1.1 billion and $365 million at December 31, 2000 and 1999, respectively. Commodity contract liabilities totaled $1.1 billion and $352 million at December 31, 2000 and 1999, respectively. As disclosed in the table above, included in these amounts were commodity-based derivative financial instruments consisting of swaps and options. Net gains associated with the Company's trading and activities is reported net of related cost of sales in Other Revenue and totaled $94 million and $65 million for 2000 and 1999, respectively. See Note 2 for further discussion of our accounting policies associated with commodity contracts. These commodity contracts are sensitive to changes in the prices of electricity and natural gas. The Company has appropriate operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, the Company has established an independent function to monitor compliance with the price risk management policies of all subsidiaries. These trading activities also expose the Company to credit risk. Credit risk represents the potential loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company maintains credit policies with respect to its counterparties that management believes minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of standardized agreements which facilitate the netting of cash flows associated with a single counterparty. The Company also monitors the financial condition of existing counterparties on an ongoing basis. Considering the system of internal controls in place and credit reserve levels at December 31, 2000, the Company believes it unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance. Note 22. Related Party Transactions Subsequent to Dominion's acquisition of CNG, the Company engaged in the exchange of certain quantities of natural gas with affiliates at index prices, in the ordinary course of business. During the period from January 28, 2000 through December 31, 2000, an unregulated subsidiary of the Company purchased approximately $60 million of natural gas from affiliates and sold approximately $33 million of natural gas to affiliates. Effective February 1, 2000, Dominion created a subsidiary service company, Dominion Resources Services, Inc. (Services), which provides certain services to the Company. In connection with the formation of Services, certain of the Company's employees became employees of Services. The cost of services charged by Services to Virginia Power during the period February 1, 2000 through December 31, 2000 was approximately $202 million. In addition, prior to February 1, 2000, certain employees of Dominion provided services to the Company. The cost of these services was $2 million, $9 million and $5 million during the period from January 1, 2000 through January 31, 2000 and during the years ended December 31, 1999 and 1998, respectively. The Company also charged affiliates for certain costs incurred on their behalf, including facility 64 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) and equipment expenses and personnel costs. The cost of services charged by Virginia Power to affiliates was $15 million and $2 million in 2000 and 1999, respectively. The cost of such services in 1998 was insignificant. The Company leases its principal office building from Dominion under an agreement approved by the Virginia Commission that expires in 2006. This agreement is accounted for as a capital lease. The capitalized cost of the property under that lease, net of accumulated amortization, was approximately $19 million and $21 million at December 31, 2000 and 1999, respectively. The rental payments for this lease were $3 million in each of the years ended December 31, 2000, 1999 and 1998. In July 2000, the Virginia Commission approved the transfer by Virginia Power of all of its issued and outstanding common stock in VPS Communications, Inc. (VPS Communications) to Dominion. This transfer took place on August 1, 2000, resulting in VPS Communications becoming a direct subsidiary of Dominion. The transfer was made at VPS Communications' book value of approximately $30 million and, accordingly, no gain or loss was recorded on the transfer. In connection with the transfer, VPS Communications was renamed Dominion Telecom, Inc. (Dominion Telecom). Dominion Telecom leases fiber optic capacity from Virginia Power at rates subject to the approval of the Virginia Commission. In December 2000, the Company acquired additional fiber optic capacity for lease to Dominion Telecom for approximately $10 million. Payments received by the Company in connection with Dominion Telecom's lease of fiber optic equipment, and related fiber optic support and maintenance services, during the period August 1, 2000 through December 31, 2000 were approximately $1 million. The Company had a net outstanding payable balance of approximately $105 million to affiliates and a net outstanding receivable balance of approximately $1 million from affiliates as of December 31, 2000 and 1999, respectively. Balances due to or from affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. See Notes 2, 18 and 19 for discussion of the inclusion of the Company in Dominion's consolidated federal income tax return and the Company's participation in certain Dominion employee incentive and benefit plans. Note 23. Business Segments The Company manages its operations along two primary business lines, Energy and Delivery. The majority of the Company's revenue is provided through bundled rate tariffs. Generally, such revenues are allocated between the two business lines for management reporting based on prior cost of service studies. Amounts in Other include: (1) Corporate operations and assets (2) transactions not allocated to the segments for internal reporting purposes (including 2000 restructuring costs, 2000 cumulative effect of a change in accounting principle, and the 1999 extraordinary item); (3) adjustments to reconcile internal financial statement groupings to those used to prepare the externally reported consolidated financial statements; and (4) intersegment eliminations, where applicable. 65 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Consolidated Description Energy Delivery Other Total - ----------- ------ -------- ----- ------------ (Millions) Year ended December 31, 2000 Operating revenue and income................. $3,552 $1,217 $ 22 $4,791 Depreciation and amortization........... 269 251 38 558 Income before interest and income taxes....... 682 529 (78) 1,133 Interest and related charges................ 146 156 (6) 296 Income tax expense...... 174 131 (26) 279 Net income.............. 362 242 (25) 579 Total assets............ 8,189 4,779 363 13,331 Capital expenditures.... 312 329 11 652 Year ended December 31, 1999 Operating revenue and income................. $3,393 $1,166 $ 32 $4,591 Depreciation and amortization........... 275 246 27 548 Income before interest and income taxes....... 580 449 3 1,032 Interest and related charges................ 139 147 3 289 Income tax expense...... 149 109 258 Net income.............. 292 193 (255) 230 Total assets............ 6,751 4,633 381 11,765 Capital expenditures.... 333 317 23 673 Year ended December 31, 1998 Operating revenue and income................. $3,292 $1,111 $(123) $4,280 Depreciation and amortization........... 307 237 (7) 537 Income before interest and income taxes....... 545 440 (281) 704 Interest and related charges................ 156 150 11 317 Income tax expense...... 143 104 (90) 157 Net income.............. 245 185 (200) 230
66 VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Note 24. Quarterly Financial Data (unaudited) The following amounts reflect all adjustments, consisting of only normal recurring accruals (except as discussed below), necessary in the opinion of management for a fair statement of the results for the interim periods.
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter ----------- ----------- ----------- ----------- 2000 - ---- Operating revenue and income... $1,126 $1,147 $1,378 $1,140 Income from operations......... 259 220 444 163 Income before extraordinary item and cumulative effect of a change in accounting principle..................... 130 Net income..................... 151 97 263 68 Balance available for common stock......................... 141 88 254 60 1999 - ---- Operating revenue and income... $1,089 $1,087 $1,440 $ 975 Income from operations......... 246 214 430 117 Income before extraordinary item and cumulative effect of a change in accounting principle..................... 114 Net income (loss).............. (141) 99 236 36 Balance available for common stock......................... (149) 90 227 25
Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors. The following accruals and adjustments recorded in 2000 and 1999 were of an extraordinary, unusual, or infrequent nature: Restructuring Costs --During 2000, the Company incurred restructuring costs of $71 million in connection with the implementation of a plan to restructure the operations of Dominion subsidiaries following Dominion's acquisition of CNG. These charges related primarily to costs associated with work-force reduction activities. See Note 5. Cumulative effect of a change in accounting principle--In 2000, as a result of its acquisition of CNG, Dominion adopted a new company-wide standard method of calculating the market related value of plan assets for all pension plans of Dominion and its subsidiaries. The market related value of plan assets is used to determine the expected return on plan assets, a component of net periodic pension cost. The cumulative effect of this accounting change as of January 1, 2000 was $21 million (net of income taxes of $11 million). See Note 3. Extraordinary item--The passing of legislation establishing a detailed plan to restructure the electric utility industry in Virginia, was an event that required discontinuation of SFAS No. 71 for our generation operations. Generation-related assets and liabilities not expected to be recovered through cost-based rates were written off in 1999, resulting in an after-tax charge of $255 million. See Note 6. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 67 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (a) Information concerning directors of Virginia Electric and Power Company is as follows:
Year First Principal Occupation For Last 5 Years, Elected A Name And Age Directorships in Public Corporations Director ------------ -------------------------------------- ---------- Thos. E. Capps (65)..... Chairman of the Board of Virginia Electric and 1986 Power Company from September 12, 1997 to date; Chairman of the Board of Directors, President and Chief Executive Officer of Dominion Resources, Inc. from August 1, 2000 to date; Vice Chairman of the Board of Directors, President and Chief Executive Officer of Dominion Resources, Inc. from January 28, 2000 to August 1, 2000; Chairman of the Board of Directors, President and Chief Executive Officer from September 1, 1995 to January 28, 2000 of Dominion Resources, Inc.; Chairman of the Board of Directors and Chief Executive Officer prior to September 1, 1995. Thomas F. Farrell, II Executive Vice President of Dominion Resources, 1999 (46)................... Inc. from March 1, 2000 to date and Chief Executive Officer of Virginia Electric and Power Company and Dominion Energy, Inc. from May 1, 1999 to date; Executive Vice President of Consolidated Natural Gas Company from January 28, 2000 to date; Senior Vice President-- Corporate Affairs and General Counsel of Dominion Resources, Inc. and Executive Vice President, General Counsel and Corporate Secretary of Virginia Electric and Power Company from July 1, 1998 to May 1, 1999; Executive Vice President and General Counsel of Virginia Electric and Power Company from April 17, 1998 to June 30, 1998; Senior Vice President-- Corporate Affairs and General Counsel of Dominion Resources, Inc. from January 1, 1997 to March 1, 1999; Vice President and General Counsel of Dominion Resources, Inc. from July 1, 1995 to January 1, 1997; Partner in law firm of McGuire, Woods, Battle & Boothe LLP prior to July 1, 1995. Edgar M. Roach, Jr. Chief Executive Officer of Virginia Electric and 1999 (52)................... Power Company from May 1, 1999 to date and Executive Vice President of Dominion Resources, Inc. from September 15, 1997 to date; Executive Vice President of Consolidated Natural Gas Company from January 28, 2000 to date; Senior Vice President--Finance, Regulation and General Counsel of Virginia Electric and Power Company from January 1, 1996 to September 15, 1997; Vice President--Regulation and General Counsel, prior to January 1, 1996.
68 (b) Information concerning the executive officers of Virginia Electric and Power Company is as follows:
Name And Age Business Experience Past Five Years ------------ ----------------------------------- Thomas F. Farrell, II Executive Vice President of Dominion Resources, Inc. and (46)................... Chief Executive Officer of Virginia Electric and Power Company and Dominion Energy, Inc. from May 1, 1999 to date; Executive Vice President of Consolidated Natural Gas Company from January 28, 2000 to date; Senior Vice President-- Corporate Affairs of Dominion Resources, Inc. and Executive Vice President, General Counsel and Corporate Secretary of Virginia Electric and Power Company from July 1, 1998 to May 1, 1999; Executive Vice President and General Counsel of Virginia Electric and Power Company from April 17, 1998 to June 30, 1998; Senior Vice President--Corporate Affairs and General Counsel of Dominion Resources, Inc. from January 1, 1997 to March 1, 1999; Vice President and General Counsel of Dominion Resources, Inc. from July 1, 1995 to January 1, 1997; Partner in law firm of McGuire, Woods, Battle & Boothe LLP prior to July 1, 1995. Edgar M. Roach, Jr. Chief Executive Officer of Virginia Electric and Power (52)................... Company from May 1, 1999 to date and Executive Vice President of Dominion Resources, Inc. from September 15, 1997 to date; Executive Vice President of Consolidated Natural Gas Company from January 28, 2000 to date; Senior Vice President--Finance, Regulation and General Counsel of Virginia Electric and Power Company from January 1, 1996 to September 15, 1997; Vice President--Regulation and General Counsel, prior to January 1, 1996. James P. O'Hanlon (57).. President and Chief Operating Officer of Virginia Electric and Power Company and Dominion Generation, Inc., and Executive Vice President of Dominion Resources, Inc. from May 1, 1999 to date; Chief Nuclear Officer of Virginia Electric and Power Company from May 1, 1999 to April 28, 2000; Senior Vice President--Nuclear, prior to May 1, 1999. Robert E. Rigsby (51)... President and Chief Operating Officer of Virginia Electric and Power Company and Executive Vice President of Dominion Resources, Inc. from May 1, 1999 to date; Executive Vice President of Virginia Electric and Power Company from January 1, 1996 to April 30, 1999; Senior Vice President-- Finance and Controller of Virginia Electric and Power Company prior to January 1, 1996. M. Stuart Bolton, Jr. Senior Vice President--Financial Management from January 28, (47)................... 2000 to date; Vice President and Controller from January 1, 1999 to January 27, 2000; Controller, prior to January 1, 1999. David A. Christian Senior Vice President--Nuclear Operations and Chief Nuclear (46)................... Officer from April 28, 2000 to date; Vice President--Nuclear Operations from July 1, 1998 to April 28, 2000; Vice President--Nuclear Operations from July 1, 1998 to April 28, 2000; Site Vice President--Surry from March 1, 1998 to June 30, 1998. James T. Earwood, Jr. Senior Vice President--Bulk Power Delivery, January 28, 2000 (57)................... to date; Vice President--Bulk Power Delivery and General Manager from April 30, 1999 to January 28, 2000; Vice President-- Bulk Power Delivery, January 1, 1997 to April 30, 1999; Vice President--Energy Efficiency and Division Services, January 1, 1996 to January 1, 1997; Vice President-- Division Services prior to January 1, 1996.
69
Name And Age Business Experience Past Five Years ------------ ----------------------------------- G. Scott Hetzer (44).... Senior Vice President and Treasurer of Virginia Electric and Power Company from January 28, 2000 to date; Senior Vice President and Treasurer of Dominion Resources, Inc. from May 1, 1999 to date; Vice President and Treasurer of Dominion Resources, Inc. from October 1, 1997 to May 1, 1999; Managing Director of Wheat First Butcher Singer prior to October 1, 1997. E. Paul Hilton (57)..... Senior Vice President--Bulk Sales from January 28, 2000 to date; Vice President-Regulation, September 1, 1997 to January 27, 2000; Manager, Rates and Regulation, February 20, 1996 to October 1, 1997. Paul D. Koonce (41)..... Senior Vice President--Portfolio Management of Virginia Electric and Power Company from January 28, 2000 to date; Senior Vice President Commercial Operations of Consolidated Natural Gas Company from January 1999 to date; Executive Vice President- Sonat Power Systems from August 1997 to January 1999; Executive Vice President-Sonat Marketing Company and Senior Vice President-Sonat Energy Services prior to August 1997. Margaret E. McDermid Senior Vice President--Information Technology and Chief (52)................... Information Officer from January 1, 2001 to date; Vice President - Information Technology and Chief Information Officer from October 1, 1998 to January 1, 2001. Mark F. McGettrick Senior Vice President--Customer Service and Metering from (43)................... January 28, 2000 to date; Vice President--Customer Service and Marketing from January 1, 1997 to January 28, 2000. Edward J. Rivas (56).... Senior Vice President--Fossil & Hydro from September 1, 1999 to date; Vice President--Fossil & Hydro Operations from January 1, 1998 to August 31, 1999. John A. Shaw (53) ...... Senior Vice President--Financial Management from January 28, 2000 to date; Senior Vice President and Chief Financial Officer from July 1, 1998 to January 28, 2000; Senior Vice President and Chief Financial Officer from March 16, 1998 to July 1, 1998; Vice President Financial Services for ARCO Chemical Company, Philadelphia, Pennsylvania, prior to March 16, 1998. Prior to March 16, 1998 Vice President-- Treasurer and Vice President--Controller of ARCO Chemical. Jimmy D. Staton (40).... Senior Vice President--Electric Distribution from October 1, 2000 to date; Senior Vice President--Gas Distribution and Regulatory from January 28, 2000 to October 1, 2000; James L. Trueheart Group Vice President of Virginia Electric and Power Company (48)................... since April 28, 2000 to date; Group Vice President and Chief Administrative Officer of Dominion Resources, Inc. from June 1, 2000 to date; Group Vice President, Controller, and Chief Administrative Officer of Dominion Resources, Inc. from January 28, 2000 to June 1,2000; Senior Vice President and Controller from November 1, 1998 to January 28, 2000; Vice President and Controller prior to November 1, 1998. Steven A. Rogers (39)... Vice President, Controller and Principal Accounting Officer of Dominion and Consolidated Natural Gas Company and Vice President and Principal Accounting Officer of Virginia Electric and Power Company from June 1, 2000 to date; Controller of Virginia Electric and Power Company from January 28, 2000 to May 31, 2000; Controller of Dominion Energy, Inc. from September 1, 1998 to June 1, 2000; Vice President and Controller of Optacor Financial Services Company from February 17, 1997 through September 1, 1998; Manager--Internal Audit of Dominion prior to February 17, 1997.
There is no family relationship between any of the persons named in response to Item 10. 70 ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The Summary Table below includes compensation paid by the Company for services rendered in 2000, 1999 and 1998 for the Chief Executive Officer(s) and the four other most highly compensated executive officers (as of December 31, 2000) as determined under the SEC executive compensation disclosure rules. Summary Compensation Table(/8/)
Long Term Compensation Awards ----------------------- Annual Compensation Securities Payouts ---------------------------------------- Restricted Underlying ------------------------------ Name & Principal Other Annual Stock Options/SAR LTIP All Other Position Year Salary(/1/) Bonus(/2/) Compensation(/3/) Awards(/4/) Grants(/5/) Pay Out(/6/) Compensation(/7/) ---------------- ---- ----------- ---------- ----------------- ----------- ----------- ------------ ----------------- ($) ($) ($) ($) (#) ($) ($) Thomas F. Farrell, II................ 2000 $ 324,638 $ 409,214 $ 71,002 0 79,765 $ 275,441 $ 155,914 Chief Executive Officer 1999 $ 123,299 $ 48,628 $ 0 0 112,500 $ 113,126 $ 3,486 1998 $ 236,971 $ 161,951 $ 0 0 0 $ 33,444 $ 4,800 Edgar M. Roach, Jr................ 2000 $ 251,732 $ 314,424 $ 71,914 0 61,289 $ 211,638 $ 125,795 Chief Executive Officer 1999 $ 98,000 $ 79,380 $ 0 0 220,500 $ 205,917 $ 3,383 1998 $ 201,667 $ 138,104 $ 0 0 0 $ 70,687 $ 4,800 James P. O'Hanlon.. 2000 $ 268,570 $ 305,690 $ 56,667 0 64,926 $ 221,045 $ 127,595 President and Chief 1999 $ 243,400 $ 100,637 $ 0 0 192,500 $ 115,951 $ 355,800 Operating Officer 1998 $ 334,667 $ 180,232 $ 0 0 0 $ 86,512 $ 4,679 Robert E. Rigsby... 2000 $ 220,077 $ 165,163 $ 14,244 0 16,320 $ 175,845 $ 33,936 President and Chief 1999 $ 231,727 $ 161,841 $ 0 0 262,500 $ 229,352 $ 4,800 Operating Officer 1998 $ 279,414 $ 226,553 $ 0 0 0 $ 133,691 $ 4,769 Edward J. Rivas.... 2000 $ 208,634 $ 191,836 $ 34,912 0 40,000 $ 102,264 $ 81,475 Senior Vice 1999 $ 128,067 $ 67,796 $ 0 0 81,833 $ 38,619 $ 3,842 President-- Fossil & Hydro 1998 $ 112,720 $ 68,093 $ 0 0 0 $ 10,920 $ 3,317 Mark F. McGettrick........ 2000 $ 190,000 $ 152,648 $ 26,184 0 30,000 $ 93,370 $ 62,382 Senior Vice President-- 1999 $ 147,083 $ 91,802 $ 0 0 56,000 $ 35,868 $ 4,413 Customer Service 1998 $ 125,825 $ 107,296 $ 0 0 0 $ 30,761 $ 3,775 and Metering
- -------- (1) Salary. Amounts shown may include vacation sold back to the Company. (2) Bonus. Amounts in this column represent cash awards made under the annual incentive plan (described on page 73) as well as annual cash bonus and bonus shares granted under the Executive Stock Purchase and Loan Program (described on page 76). (3) Other Annual Compensation. None of the named executive officers received perquisites or other personal benefits in excess of $50,000 or 10% of their total cash compensation. The amounts listed in this column for 2000 are tax payments made on behalf of the executive. 71 (4) Restricted Stock Award. The number and value of each executive's restricted stock holding at year-end, based on a December 31, 2000 closing price of $67.00 per share, were as follows:
Number of Officer Restricted Shares/1/ Value Thomas F. Farrell, II/2.............../.. 2,655 $ 177,885 Edgar M. Roach, Jr./2................./.. 2,275 $ 152,425 James P. O'Hanlon/2.................../.. 2,133 $ 142,911 Robert E. Rigsby/2..................../.. 3,282 $ 219,894 Edward J. Rivas/2...................../.. 409 $ 27,403 Mark F. McGettrick/2................../.. 914 $ 61,238 -------- 1. Dividends are paid on restricted shares. 2. These shares vest two years from the date of grant.
(5) Securities Underlying Options. Options granted in 2000 were granted and simultaneously exercised by the named executive to purchase shares under the Executive Stock Purchase and Loan Program. (6) LTIP Payouts. Amounts in this column represent cash awards under the 1998-- 2000 Long-term Incentive Plan as described on page 73. (7) All Other Compensation. The amounts listed for 2000 are (1) Matching contributions on Employee Savings Plan accounts for named executives and (2) a quarterly interest subsidy paid under the Executive Stock Purchase and Loan Program. (8) The executive officers included in the table may perform services for more than one company. Therefore, compensation for the individuals listed in the table reflects only that portion which is attributable to the Company. Option/SAR Grants in Last Fiscal Year(/3/)
Potential Realizable Value at Percent of Assumed Total Annual Rates Number of Options/SARs of Securities Granted to Exercise Stock Price Underlying Employees in of Base Appreciation Options/SARs Fiscal Price Expiration for Option Name Granted (#)/1/ Year/2/ ($/Sh) Date Term - ---- ------------ ------------ -------- ---------- ------------- 5% 10% ------ ------ Thomas F. Farrell, II... 79,765 4.4% $41.22 2/1/00 $ 0 $ 0 Edgar M. Roach, Jr...... 61,289 3.4% $41.22 2/1/00 $ 0 $ 0 James P. O'Hanlon....... 64,926 3.6% $41.22 2/1/00 $ 0 $ 0 Robert E. Rigsby........ 16,320 0.9% $41.22 2/1/00 $ 0 $ 0 Edward J. Rivas......... 40,000 2.2% $41.22 2/1/00 $ 0 $ 0 Mark F. McGettrick...... 30,000 1.7% $41.22 2/1/00 $ 0 $ 0
- -------- 1. Nonstatutory stock options were granted on February 1, 2000 to the named executives at an exercise price of $41.21875 per share. One-hundred percent of the options vested and were exercised on the date of grant. 2. The total number of options granted in 2000 to Company employees was 1,795,416. 3. The executive officers included in the table may perform services for more than one company. Therefore, compensation for the individuals listed in the table reflects only that portion which is attributable to the Company. 72 Aggregated Option/SAR Exercises in Last Fiscal Year And FY-End Option/SAR Values(/3/)
Number of Securities Shares Underlying Unexercised Value of Unexercised In-the- Acquired on Value Options/SARs Money Options/SARs Name Exercise/1/ Realized At FY-End At FY-End - ---- ----------- -------- ------------------------- ---------------------------- Exercisable Unexercisable Exercisable/2/ Unexercisable ----------- ------------- -------------- ------------- (#) ($) (#) (#) ($) ($) --- --- -- -- --- --- Thomas F. Farrell, II... 79,765 $ 0 318,600 0 $8,203,950 $ 0 Edgar M. Roach, Jr...... 61,289 $ 0 244,800 0 $6,303,600 $ 0 James P. O'Hanlon....... 64,926 $ 0 248,850 0 $6,407,888 $ 0 Robert E. Rigsby........ 16,320 $ 0 190,400 0 $4,902,800 $ 0 Edward J. Rivas......... 40,000 $ 0 81,833 0 $1,969,962 $ 0 Mark F. McGettrick...... 30,000 $ 0 56,000 18,082 $1,442,000 $501,776
- -------- 1. Options granted under the Dominion Executive Stock Purchase and Loan Program were exercised on the same day they were granted. 2. Spread between the market value at year-end minus the exercise price. Year- end stock price was $67.00 per share. 3. The executive officers included in the table may perform services for more than one company. Therefore, compensation for the individuals listed in the table reflects only that portion which is attributable to the Company. Annual Incentives Under the annual incentive program, in place for the Company's executive officers, if goals are achieved or exceeded, the executive's total cash compensation for the year may be more than the median total cash compensation for similar positions at companies in our executive labor market. Under this program, "target awards" are established for each executive officer. These target awards are expressed as a percentage of the individual executive's base salary (for example, 40% x base salary). The target award is the amount of cash that will be paid, at year-end, if the executive achieves 100% of the goals established at the beginning of the year. A "threshold" or minimum acceptable level of financial performance is also established. If this threshold is not met, no executive receives an annual bonus. Actual bonuses, if any, are based on a pre-established formula and may exceed 100% of the target award. 2000 earnings per share was used as the performance measure under the annual incentive plan. Each executive's goals were weighted heavily toward the earnings per share contribution of the business unit for which they were responsible, but also included operating goals and a consolidated earnings-per- share goal. Goals were established and approved at the beginning of 2000. At year-end, the Company's actual financial performance was compared with the consolidated and business unit earnings per share goals. For 2000, these goals were surpassed. Annual bonuses paid to the named executives are detailed in the Summary Compensation Table. Long-Term Incentives We believe the long-term incentive programs we approve play a critical part in our compensation practices and philosophy. Historically, at least half of the long-term incentive component was paid in company stock--a long-term investment. We believe this form of payout underscores commitment to the Company while 73 rewarding performance. In May 1999, executives were granted stock options to represent the 1999-2001 long-term plan cycle, as well as to replace the restricted stock portion of the 1998-2000 long-term plan cycle. Given the current labor market environment and to provide balance in our long-term incentive program, the sole use of options has been reassessed and it has been determined that an award of restricted stock would be appropriate for the 2001-2003 long-term plan cycle. Goals were established at the start of the 1998-2000 performance cycle. The performance measure used for the executive officers was cumulative net income for the three-year cycle weighted 50% on consolidated net income and 50% on the net income of the business unit for which the executive was responsible. Following the significant reorganization of Dominion and its operating subsidiaries in 2000, the weightings were revised to 100% consolidated net income for the three-year cycle. Based on 2000 year-end results, which exceeded the performance goal, the executives were awarded cash (see the LTIP Payout column of the Summary Compensation Table). As stated above, stock options were granted to executives in 1999. These options became exercisable on January 1, 2000 and will remain exercisable until May 17, 2009. Stock Ownership Guidelines In February 2000, Dominion stock ownership guidelines were established for our executive officers. We believe these guidelines place an emphasis on stock ownership that aligns management with the interests of Dominion's shareholders. Officers have up to five years to meet the guidelines outlined below. Dominion Resources, Inc. Stock Ownership Guidelines
Positions Share Ownership --------- --------------- Executive Vice President and CEO--Operating Companies.... 35,000 Senior Vice President.................................... 20,000 Vice President........................................... 10,000
Retirement Plans The table below shows the estimated annual straight life benefit that the Company would pay to an employee at normal retirement (age 65) under the benefit formula of the Retirement Plan. The calculations have been prepared using the retirement benefit plan formula that became effective January 1, 2001. Estimated Annual Benefits Payable Upon Retirement
Credited Years Of Service ------------------------------- Final Average Earnings 15 20 25 30 - ---------------------- ------- ------- ------- ------- $185,000........................................ $45,803 $61,070 $76,338 $91,606 $200,000........................................ 49,853 66,470 83,088 99,706 $250,000........................................ 63,353 84,470 105,588 126,706 $300,000........................................ 76,853 102,470 128,088 153,706 $350,000........................................ 90,353 120,470 150,588 180,706 $400,000........................................ 103,853 138,470 173,088 207,706
74 Retirement Plan Benefits under the Retirement Plan are based on: . average base salary over a five-year period when base pay is highest; . years of credited service; . age at retirement; and . the offset of Social Security benefits. In addition, certain officers, if they reach a specified age while still employed, will be credited with additional years of service. For the executives named in the Summary Compensation Table, credited years of service at age 60 would be 30 years. Other retirement agreements and arrangements for the named executives are described herein. Benefit Restoration Plan The Retirement Plan pays a benefit that is calculated on average base salary over a five-year period. In some years our executives' base salaries were set below the competitive market median in order to more closely link annual pay to company performance through the incentive programs. Under this Restoration Plan, we calculate a "market-based adjustment" to base salary in those years when base salary was below the market median. The difference between the benefit calculated on the market-based salary and the benefit provided by the Retirement Plan is paid to the executive under the Restoration Plan. In 2000, a market-based adjustment to executive base salaries was not necessary. Also, the Internal Revenue Code imposes certain limits related to Retirement Plan benefits. Any resulting reductions in an executive's Retirement Plan benefit will be compensated for under the Restoration Plan. Executive Supplemental Retirement Plan The Supplemental Plan provides an annual retirement benefit equal to 25 percent of a participant's final cash compensation (base pay plus target annual bonus). To retire with full benefits under the Supplemental Plan, an executive must be 55 years old and have been employed by the Company for at least five years. Benefits under the plan are provided either as a lump sum cash payment at retirement or as a monthly annuity paid out, typically, over 10 years. Certain executive officers receive this benefit for their lifetime. Based on 2000 cash compensation, we have estimated that portion of the annual benefit under this plan which is attributable to the Company for certain executives named in the Summary Compensation Table as follows: Mr. Farrell-$142,927, Mr. Roach-$109,820, Mr. O'Hanlon-$109,494, Mr. Rigsby-$83,776, Mr. Rivas-$71,621, Mr. McGettrick-$68,875. Employment Agreements Mr. McGettrick has an employment agreement with the Company for a three year period ending August 1, 2002. During employment, Mr. McGettrick will continue to receive a salary at least equal to his salary on the date of the agreement and will be eligible for bonuses and all employee benefits provided to senior management. The agreement also provides Mr. McGettrick with enhanced retirement benefits. If Mr. McGettrick's employment is terminated without cause or if his salary, incentives or benefits are reduced or not paid, or he is demoted to a position that is not a senior management position, the executive will (subject to notice and remedy provisions): (1) receive a lump sum payment equal to the present value of salary and cash bonus for the balance of the contract period, (2) vest in his outstanding restricted stock and (3) receive age and service credit and continued benefit plan coverage through the end of the contract period. The agreement also provides benefits in the event of death or disability. In the case of a change in control, the executive will not receive pay under this agreement as a result of his termination of employment for any reason if he receives payment under his employment continuity agreement. Messrs. Farrell and Roach each had an employment agreement that expired September 12, 2000. These executives, as well as Mr. McGettrick, Mr. O'Hanlon and Mr. Rigsby, each have enhanced retirement benefits, as well as employment continuity agreements, as described below. 75 Special Arrangements The Company has entered into employment continuity agreements with executives named in the Summary Compensation Table, which provide benefits in the event of a change in control. Each agreement has a three-year term and is automatically extended for an additional year, unless cancelled by the Company. The agreements provide for the continuation of salary and benefits for a maximum period of three years after either (1) a change in control, (2) termination without cause following a change in control, or (3) a reduction of responsibilities, salary and incentives following a change in control (if the executive gives 60 days notice). Payment of this benefit will be made in either a lump sum or installments over three years. In addition, the agreements indemnify the executives for potential penalties related to the Internal Revenue Code and fees associated with the enforcement of the agreements. If an executive is terminated for cause, the agreements are not effective. For purposes of the continuity agreements discussed above, a change of control shall be deemed to have occurred if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, a merger or other business combination, sale of assets, or contested election, the Directors constituting the Dominion Board before any such transactions cease to represent a majority of Dominion or its successor's Board within two years after the last of such transactions Executive Deferred Compensation Plan Under this plan, executives may defer any portion of their cash compensation. Deferrals are credited at the executive's discretion, for bookkeeping purposes, with earnings and losses as if they were invested in any of several mutual fund options, or Dominion common stock. Distributions are made at the direction of the executive. Also, under this Plan, executives may defer gains received as a result of a stock option exercise. Stock option gain deferrals must be invested in Dominion common stock. Under this Plan, the Company also credits the accounts of eligible executives are credited with the amount of "lost" company matching contributions under the Employee Savings Plan as a result of Internal Revenue Code Section 401(a)(17). Executive Stock Purchase and Loan Program At the end of 1999, Dominion's Board approved target levels of stock ownership for executives (See Ownership Guidelines above). The Board also approved a Stock Purchase and Loan Program intended to encourage and facilitate executives' ownership of common stock through the availability of loans guaranteed by Dominion. Under the Program, loans must be used to purchase Dominion common stock. An executive may borrow up to ten times his or her base salary, subject to credit approval, with a term of five years. Executives who meet their target ownership level through their participation in the Program receive "bonus shares" equal to five percent of the number of shares purchased under the Program. The dividends on the stock purchased through the program are used to pay the interest on the loan. The interest payments are subsidized to the extent that the current dividend rate does not fully cover the payments. The subsidy of the loan will end if it is pre-paid or if the stock is sold. Dominion executives have borrowed in aggregate $87.4 million, for which they are personally liable and which Dominion has guaranteed. Compensation of Directors All of the Directors, who are also employees of the Company, do not receive any compensation for services they provide as directors. 76 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The table below sets forth as of March 2, 2001, except as noted, the number of shares of Dominion common stock owned by Directors and the executive officers named on the Summary Compensation Table.
Shares of Common Beneficially Name Owned - ---- ------------ Thos. E. Capps.................................................... 1,571,918 Thomas F. Farrell, II............................................. 603,474 Edgar M. Roach, Jr................................................ 602,627 James P. O'Hanlon................................................. 462,212 Robert E. Rigsby.................................................. 413,031 Edward J. Rivas................................................... 133,528 Mark F. McGettrick................................................ 116,037 All Directors and Executive Officers as a Group (19 persons)...... 5,079,323
- -------- (1) Amounts include exercisable stock options as follows: Mr. Capps, 1,233,000 shares; Mr. Farrell and Mr. Roach each has 450,000 shares; Mr. O'Hanlon and Mr. Rigsby each has 350,000 shares; Mr. Rivas, 81,883 shares; Mr. McGettrick, 74,082 shares; and all directors and officers as a group, 5,079,323 shares. (2) Amounts include restricted stock as follows: Mr. Capps, 46,919 shares; Mr. Farrell, 14,558 shares; Mr. O'Hanlon, 10,655 shares; Mr. Rigsby, 11,893 shares; Mr. Rivas, 5,584 shares; Mr. Roach, 14,550 shares; Mr. McGettrick, 5,914 shares; and all directors and officers as a group, 175,191 shares. (3) Beneficial ownership is disclaimed as follows: Mr. Capps, 158 shares, and Mr. Farrell, 399 shares, for a total of 557 shares. (4) All current directors and executives as a group own 2.1 percent of the number of shares outstanding. Of these shares, 20 percent were purchases under the Executive Stock Loan Program with $41.0 million of loans, for which executive officers are personally liable. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS See Item 11. EXECUTIVE COMPENSATION--Executive Stock Purchase and Loan Program, for information concerning certain transactions with executive officers under the Executive Stock Purchase and Loan Program. 77 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this Form 10-K: 1. Financial Statements See Index on page 35. 2. Financial Statement Schedules
Page ---- Independent Auditors' Report on Financial Statement Schedule............ 81 Schedule II--Valuation and Qualifying Accounts.......................... 82
All other schedules are omitted because they are not applicable, or the required information is shown in the financial statements or the notes thereto. 3. Exhibits 3.1 -- Restated Articles of Incorporation, as amended, as in effect on May 6, 1999 (Exhibit 3.1), Form 10-Q for the period ended March 31, 1999, File No. 1-2255, incorporated by reference). 3.2 -- Bylaws, as amended, as in effect on April 28, 2000 (Exhibit 3, Form 10- Q for the period ended March 31, 2000, File No. 1-2255, incorporated by reference). 4.1 -- See Exhibit 3 (i) above. 4.2 -- Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference); Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1- 2255, incorporated by reference and Seventieth Supplemental Indenture (Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i)) and Seventy-Second Supplemental Indenture (Exhibit 4(ii), Form 8-K, dated July 7, 1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture (Exhibit 4(i), Form 8- K, dated August 6, 1992, File No. 1-2255, incorporated by reference); Seventy-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 6, 1993, File No. 1-2255, incorporated by reference); Seventy- Sixth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 21, 1993, File No. 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated June 8, 1993, File No. 1-2255, incorporated by reference); Seventy-Eighth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Ninth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1- 2255, incorporated by reference); Eightieth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 12, 1993, File No. 1- 2255, incorporated by reference); Eighty-First Supplemental Indenture (Exhibit 4(iii), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Eighty-Second Supplemental Indenture (Exhibit 4(i), Form 8-K, dated January 18, 1994, File No. 1- 2255, incorporated by reference); Eighty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference); Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 22, 1995, File No. 1-2255, incorporated by reference; and Eighty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by reference). 4.3 -- Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and The Chase Manhattan Bank (formerly Chemical Bank) (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference). 78 4.4 -- Indenture, dated April 1, 1988, between Virginia Electric and Power Company and The Chase Manhattan Bank (formerly Chemical Bank), as supplemented and modified by a First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form S-3, dated April 13, 1999, File No. 333-76155, incorporated by reference). 4.5 -- Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and Power Company and The Chase Manhattan Bank (formerly Chemical Bank), as Trustee, as supplemented (Exhibit 4(a), Form S-3 Registration Statement File No. 333-20561 as filed on January 28, 1997, incorporated by reference). 4.6 -- Form of Senior Indenture, dated as of June 1, 1998 as supplemented by the First Supplemental Indenture (Exhibit 4.2 to Form 8-K dated June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2 to Form 8-K dated June 3, 1999, File No. 1-2255, incorporated by reference) and Third Supplemental Indenture (Exhibit 4.2, Form 8-K, dated October 27, 1999, File No. 1- 2255, incorporated by reference). 4.7 -- Virginia Electric and Power Company agrees to furnish to the Commission upon request any other instrument with respect to long- term debt as to which the total amount of securities authorized thereunder does not exceed 10 percent of Virginia Electric and Power Company's total assets. 10.1 -- Amended and Restated Interconnection and Operating Agreement, dated as of July 29, 1997 between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit 10.3, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255 incorporated by reference). 10.2 -- Credit Agreement dated June 7, 1996, between The Chase Manhattan Bank (formerly Chemical Bank) and Virginia Electric and Power Company (Exhibit 10(i), Form 10-Q for the period ended June 30, 1996, File No. 1-2255, incorporated by reference) Credit Agreement dated June 7, 1996, between The Chase Manhattan Bank and Virginia Electric and Power Company and as amended and restated as of June 4, 1999 (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference). 10.3* -- Description of arrangements with certain officers regarding additional credited years of service for retirement purposes (Exhibit 10 (xii), Form 10-K for the fiscal year ended December 31, 1992, File No. 1- 2255, incorporated by reference). 10.4* -- Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective January 1, 1981 as amended and restated September 1, 1996 with first amendment dated June 20, 1997 and second amendment dated March 3, 1998 (Exhibit 10.14, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255, incorporated by reference) 10.5* -- Dominion Resources, Inc.'s Cash Incentive Plan as adopted December 20, 1991 (Exhibit 10 xxv), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference). 10.6* -- Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as amended and restated September 1, 1996 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255, incorporated by reference). 10.7* -- Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective January 1, 1991 as amended and restated September 1, 1996 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255, incorporated by reference). 10.8* -- Dominion Resources, Inc. Executives' Deferred Compensation Plan, effective January 1, 1994, as amended and restated on January 1, 1997 (Exhibit 10 (xix), Form 10-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference). 10.9* -- Employment Agreement dated September 15, 1995 between Virginia Power and Robert E. Rigsby (Exhibit 10 (xxii), Form 10-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference). 79 10.10* -- Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997 (Exhibit 10.23 Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255, incorporated by reference) and as amended and restated effective April 16, 1999 (Exhibit 10.1, Form 10-Q for the period ended June 30, 1999 File No. 1-2255, incorporated by reference). 10.11* -- Form of an Employment Agreement dated March 16, 1998 between Virginia Power and certain executive officers (Exhibit 10.1, Form 10-Q for the period ended March 31, 1998, File No. 1-2255, incorporated by reference). [The only material respect in which the particular employment agreements differ is the base salary set forth therein.] 10.12* -- Employment Agreement dated September 12, 1997 between Dominion and Thomas F. Farrell, II (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 1998, File No. 1-2255, incorporated by reference). 10.13* -- Form of Employment Continuity Agreement for certain officers of the Company including Thomas F. Farrell, II, Edgar M. Roach, Jr., and James P. O'Hanlon, (Exhibit 10.2, Form 10-Q for the period ended June 30, 1999, File No. 1-2255, incorporated by reference). 10.14* -- Form of Amendment to Employment Agreement for certain officers including Robert E. Rigsby and James P. O'Hanlon (Exhibit 10.3, Form 10-Q for the period ended June 30, 1999, File No. 1-2255, incorporated by reference). 10.15* -- Employment Agreement dated September 12, 1997, between Dominion and Edgar M. Roach, Jr. (Exhibit 10(xxxiv) Form 10-K for fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference). 10.16 -- Services Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company dated January 1, 2000 (Exhibit 10.19, Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference). 10.17 -- Support Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company effective January 1, 2000 (Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference). 10.18 -- Alliance Agreement Establishing the Alliance Independent Transmission System Operator, Inc., Alliance Transmission Company, Inc., and Alliance Transmission Company, LLC Dated May 27, 1999 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 1999, File No. 1- 2255, incorporated by reference). 10.19* -- Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000 (Exhibit 10(ii), Form 10-Q for the quarter ended June 30, 2000, File No. 1-8489, incorporated by reference). 10.20*-- Employment Agreement dated August 1, 1999 between Virginia Electric and Power Company (filed herewith). 18 -- Letter re change in accounting principles (Exhibit 18, Form 10-Q for the period ended September 30, 2000, File No. 1-2255, incorporated by reference). 23.1 -- Consent of McGuire Woods Battle & Boothe LLP (filed herewith). 23.2 -- Consent of Jackson & Kelly (filed herewith). 23.3 -- Consent of Deloitte & Touche LLP (filed herewith). * Indicates management contract or compensatory plan or arrangement (b) Reports on Form 8-K The Company filed a report on Form 8-K, dated November 16, 2000 relating to the agreement in principle with the Environmental Protection Agency for environmental improvements at the Company's coal-fired generating stations in Virginia and West Virginia. 80 INDEPENDENT AUDITORS' REPORT To the Board of Directors of Virginia Electric and Power Company Richmond, Virginia We have audited the consolidated financial statements of Virginia Electric and Power Company (a wholly owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the Company) as of December 31, 2000 and 1999, and for each of the three years in the period ended December 31, 2000, and have issued our report thereon dated January 25, 200l; such report is included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company, listed in Item 14. This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. /s/ DELOITTE & TOUCHE LLP Richmond, Virginia January 25, 200l 81 Virginia Electric and Power Company Schedule II-Valuation and Qualifying Accounts
Column A Column B Column C Column D Column E -------- ---------- -------------------------- ---------- ---------- Additions ---- ---------- -------------------------- ---------- ---------- Balance at Balance at beginning Charged Charged to end of Description of period to expense other accounts Deductions period ----------- ---------- ---------- -------------- ---------- ---------- (millions) Valuation and qualifying accounts which are deducted in the balance sheet from the assets to which they apply: Allowance for doubtful accounts... 1998 $ 2 $13 $10(a) $ 5 1999 5 19 12(a) 12 2000 12 18 14(a) 16 Valuation allowance for commodity contracts........................ 1998 13 13 1999 13 9 (b) 22 2000 22 (3)(b) 19 Reserves: Liabilities for pre-2000 workforce reductions....................... 1998 30 2 16(c) 16 1999 16 12(c) 4 2000 4 4(c) Liabilities for restructuring activities....................... 1998 1999 2000 14 8(c) 6
- -------- (a) Represents net amounts charged off as uncollectible. (b) Amounts are net of adjustments to allowances reflecting changes in estimates. (c) Represents payments for workforce reductions and restructuring activities. 82 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Virginia Electric and Power Company /s/ Thos. E. Capps By:__________________________________ (Thos. E. Capps., Chairman of the Board Of Directors) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the day of March 16, 2001.
Signature Title Date --------- ----- ---- /s/ Thos. E. Capps Chairman of the Board of March 16, 2001 ______________________________________ Directors and Director Thos. E. Capps /s/ Thomas F. Farrell, II Chief Executive Officer March 16, 2001 ______________________________________ and Director Thomas F. Farrell, II /s/ Edgar M. Roach Chief Executive Officer March 16, 2001 ______________________________________ and Director Edgar M. Roach /s/ G. Scott Hetzer Senior Vice President and March 16, 2001 ______________________________________ Treasurer C. Scott Hetzer /s/ Steven A. Rogers Vice President and March 16, 2001 ______________________________________ Principal Accounting Steven A. Rogers Officer
83 EX-10.20 2 0002.txt EMPLOYMENT AGREEMENT DATED AUGUST 1, 1999 Exhibit 10.20 EMPLOYMENT AGREEMENT -------------------- This EMPLOYMENT AGREEMENT (the "Agreement") is made as of August 1, 1999, between Virginia Electric and Power Company (the "Company") and Mark F. McGettrick (the "Executive"). RECITALS: -------- The Board of Directors of the Company (the "Board of Directors") recognizes that outstanding management of the Company is essential to advancing the best interests of the Company, its shareholders and its subsidiaries. The Board of Directors believes that it is particularly important to have stable, excellent management at the present time. The Board of Directors believes that this objective may be achieved by giving key management employees assurances of financial security for a period of time, so that they will not be distracted by personal risks and will continue to devote their full time and best efforts to the performance of their duties. The Company's Board of Directors has approved entering into employment agreements with the Company's key management executives in order to achieve the foregoing objectives. The Executive is a key management executive of the Company and is a valuable member of the Company's management team. The Company acknowledges that the Executive's contributions to the growth and success of the Company will be substantial. The Company and the Executive are entering into this Agreement to induce the 1 Executive to serve as an employee of the Company and to devote his/her full energy to the Company's affairs. The Executive has agreed to be employed by the Company under the terms and conditions hereinafter set forth. NOW, THEREFORE, in consideration of the foregoing and the mutual undertakings contained in this Agreement, the parties agree as follows: 1. Employment. The Company will employ the Executive, and the Executive will be employed by the Company, as an executive of the Company, for the period beginning August 1, 1999 (the "Effective Date") and ending on the third anniversary of such date, subject to the further provisions of this Section 1 (the "Term of this Agreement"). 2. Duties. The Company and the Executive agree that, during the Term of this Agreement, the Executive will serve in a senior management position with the Company. The Executive (i) will devote his/her knowledge, skill and best efforts on a full-time basis to performing his duties and obligations to the Company (with the exception of absences on account of illness or vacation in accordance with the Company's policies and civic and charitable commitments not involving a conflict with the Company's business), and (ii) will comply with the directions and orders of the Board of Directors and Chief Executive Officer of the Company with respect to the performance of his duties. 2 3. Effect on Other Agreements. (a) The Board of Directors recognizes that the Executive has entered or may enter into an Employment Continuity Agreement with the Company, which provides benefits under certain circumstances in the event of a change in control of the Company. Notwithstanding anything in this Agreement to the contrary, if the Executive's employment terminates for any reason after a change in control and payments are to be made to the Executive under the Executive's Employment Continuity Agreement: (i) the Executive will not receive payments under this Agreement as a result of his termination of employment for any reason, (ii) after payment of any amounts otherwise due the Executive under this Agreement, this Agreement will terminate without liability on the part of the Company, and (iii) if and to the extent that any payments made under this Agreement are considered "parachute payments" for purposes of Section 280G of the Internal Revenue Code of 1986, as amended (the "Code"), the payments will be taken into account in determining the amount to be grossed up to the Executive under Article 6 of the Employment Continuity Agreement, If a change of control occurs and the Executive is not entitled to receive payments under the Executive's Employment Continuity Agreement, this Agreement will continue in effect according to its terms. (b) Except as provided above, this Agreement sets forth the entire understanding of the parties with respect to the Executive's employment with the Company. The Executive and the 3 Company agree that, effective as of the execution of this Agreement, any prior employment agreements between the Executive and the Company (other than the Executive's Employment Continuity Agreement) are null and void. The term "employment agreement" as used in the preceding sentence does not include any retirement, incentive or benefit plan or program in which the Executive participates or any credited service agreement under which the Executive receives years of service credit for retirement plan purposes. 4. Affiliates. For purposes of this Agreement, the term "Affiliate" means the subsidiaries of Dominion Resources, Inc. and other entities under common control with Dominion Resources, Inc. 5. Compensation and Benefits. (a) During the Term of this Agreement, while the Executive is employed by the Company, the Company will pay to the Executive the following salary and incentive awards for services rendered to the Company: (i) The Company will pay to the Executive an annual salary in an amount not less than the base salary in effect for the Executive as of the date on which this Agreement is executed. The Board of Directors will evaluate the Executive's performance at least annually and will consider annual increases in the Executive's salary based on the Executive's performance. 4 (ii) The Executive will be entitled to receive incentive awards if and to the extent that the Board of Directors determines that the Executive's performance merits payment of an award. The Board of Directors will make its determination consistent with the methodology used by the Company for compensating its senior management employees. (b) During the Term of this Agreement, while the Executive is employed by the Company, the Executive will be eligible to participate in a similar manner as other senior executives of the Company in retirement plans, cash and stock incentive plans, fringe benefit plans and other employee benefit plans and programs provided by the Company for its senior management employees from time to time. (c) If the Executive serves as an officer until his/her fiftieth(50th) birthday, Executive will be eligible, at retirement, for five (5) additional years of credited age and five (5) additional years of credited service to be added for pension and other retirement benefits, including but not limited to the DRI Executive Supplemental Retirement Plan, the DRI Retirement Benefit Restoration Plan, medical coverage and life insurance. Any minimum age requirements shall be waived. Any supplemental benefit to be provided under this subsection (c) or subsection (d) below will be provided as a supplemental benefit under this Agreement and will not be provided directly from the Retirement Plan. The provisions of this subsection (c) 5 and subsection (d) below shall survive the termination of this Agreement. (d) If Executive is terminated, other than for Cause (as defined in Section 8 below), prior to age 50, Executive will be credited at termination with: (i) the number of years of age credit needed to give Executive 55 years of credited age; and (ii) the number of additional years of service credit needed to give Executive the same number of years of service that would have been earned had the Executive remained employed by Company until age 55. These age and service credits will be added for pension and other retirement benefits, including but not limited to the DRI Executive Supplemental Retirement Plan, the DRI Retirement Benefit Funding Plan, medical coverage and life insurance. Any minimum age requirements shall be waived. 6. Termination of Employment. (a) If the Company terminates the Executive's employment, other than for Cause, during the Term of this Agreement, the Company will pay the Executive a lump sum payment equal to the present value of the Executive's annual base salary and annual cash incentive awards (computed as described below) for the balance of the Term of this Agreement. The lump sum payment will be computed as follows: (i) For purposes of this calculation, the Executive's annual base salary for the balance of the Term of the Agreement will be calculated at the highest 6 annual base salary rate in effect for the Executive during the three- year period preceding his termination of employment. For purposes of this calculation, the Executive's annual cash incentive awards for the balance of the Term of the Agreement will be calculated at a rate equal to the highest annual cash incentive award paid to the Executive during the three-year period preceding his termination of employment. Salary and bonus that the Executive elected to defer will be taken into account for purposes of this Agreement without regard to the deferral. (ii) The salary and incentive award for any partial year in the Term of this Agreement will be a pro-rated portion of the annual amount. (iii) If the Executive has not yet received an annual cash incentive award for the year in which his employment terminates, the lump sum payment will be increased to include a pro-rated award for the portion of the year preceding the Executive's termination of employment. If the Executive has not yet received payment of his annual cash incentive award for the year preceding his termination of employment, the lump sum payment will be increased to include an award for the year preceding the Executive's termination of employment. The incentive award for the year or portion of the year preceding the Executive's 7 termination of employment will be determined according to clause (i) above, unless the Board of Directors made a good faith final determination of the amount of the applicable incentive award pursuant to Section 5(a)(ii) before the Executive's termination of employment. If the Board of Directors made such a determination, the applicable incentive award will be computed according to the Board of Directors' determination. (iv) Present value will be computed by the Company as of the date of the Executive's termination of employment, based on a discount rate equal to the applicable Federal short-term rate, as determined under Section 1274(d) of the Code, compounded monthly, in effect on the date as of which the present value is determined. (v) The lump sum payment will be paid within 30 days after the Executive's termination of employment. (b) If the Company terminates the Executive's employment, other than for Cause, during the Term of this Agreement, the Executive will be entitled to receive the following additional benefits determined as of the date of his termination of employment: (i) Any outstanding restricted stock that would become vested (that is, transferable and nonforfeitable) if the Executive remained an employee through the Term of this Agreement will become vested 8 as of the date of the Executive's termination of employment (or as of the date described in the next sentence, if applicable). In addition, if the Company has agreed to award the Executive restricted stock at the end of a performance period, subject to the Company's achievement of performance goals, and the date as of which the restricted stock is to become vested falls within the Term of this Agreement, the stock will be awarded and become vested at the end of the performance period if and to the extent that the performance goals are met. The Executive must satisfy the tax withholding requirements described in Section 10 with respect to the restricted stock. (ii) The Executive shall become fully vested in any and all stock options granted to the Executive under any Company plan which have not become exercisable as of the Executive's termination of employment. All of the Executive's stock options (including options vested as outlined in the preceding sentence) shall remain exercisable until the applicable option expiration date. (c) If the Executive voluntarily terminates employment with the Company during the Term of this Agreement under circumstances described in this subsection (c), the Executive will be entitled to 9 receive the benefits described in subsections (a) and (b) above as if the Company had terminated the Executive's employment other than for Cause. Subject to the provisions of this subsection (c), these benefits will be provided if the Executive voluntarily terminates employment after (i) the Company reduces the Executive's base salary, (ii) the Executive is not in good faith considered for incentive awards as described in Section 5(a)(ii), (iii) the Company fails to provide benefits as required by Section 5(b) and 5(c), or (iv) the Company demotes the Executive to a position that has significantly lesser authority and/or significantly decreased duties than those being performed by Executive at the time of the signing of this Agreement(other than on account of the Executive's disability, as defined in Section 7 below). In order for this subsection (c) to be effective: (1) the Executive must give written notice to the Company indicating that the Executive intends to terminate employment under this subsection (c), (2) the Executive's voluntary termination under this subsection must occur within 60 days after the Executive knows or reasonably should know of an event described in clause (i), (ii), (iii) or (iv) above, or within 60 days after the last in a series of such events, and (3) the Company must have failed to remedy the event described 10 in clause (i), (ii), (iii) or (iv), as the case may be, within 30 days after receiving the Executive's written notice. If the Company remedies the event described in clause (i), (ii), (iii) or (iv), as the case may be, within 30 days after receiving the Executive's written notice, the Executive may not terminate employment under this subsection (c) on account of the event specified in the Executive's notice. (d) The amounts under this Agreement will be paid in lieu of severance benefits under any severance plan or program maintained by the Company (subject to Section 3 above). The amounts payable under this Agreement will not be reduced by any amounts earned by the Executive from a subsequent employer or otherwise. If the Executive's employment is terminated by the Company for Cause or if the Executive voluntarily terminates employment for a reason not described in subsection (c) above or Section 7 below, this Agreement will immediately terminate without liability on the part of the Company. 7. Disability or Death. If the Executive becomes disabled (as defined below) during the Term of this Agreement while he is employed by the Company, the Executive shall be entitled to receive the benefits described in Section 6(b)(i) of this Agreement as of the date on which he is determined by the Company to be disabled. If the Executive dies during the Term of this Agreement while he is employed by the Company, the benefits described in Section 6(b)(i) will be provided to the personal 11 representative of the Executive's estate. The foregoing benefits will be provided in addition to any death, disability and other benefits provided under Company benefit plans in which the Executive participates. Upon the Executive's death or disability, the provisions of Sections 1, 2, 5, and 6 of this Agreement will terminate. The term "disability" means a condition, resulting from bodily injury or disease, that renders, and for a six consecutive month period has rendered, the Executive unable to perform substantially the duties pertaining to his employment with the Company. A return to work of less than 14 consecutive days will not be considered an interruption in the Executive's six consecutive months of disability. Disability will be determined by the Company on the basis of medical evidence satisfactory to the Company. 8. Cause. For purposes of this Agreement, the term "Cause" means (i) fraud or material misappropriation with respect to the business or assets of the Company, (ii) persistent refusal or willful failure of the Executive to perform substantially his duties and responsibilities to the Company, which continues after the Executive receives notice of such refusal or failure, (iii) conviction of a felony or crime involving moral turpitude, or (iv) the use of drugs or alcohol that interferes materially with the Executive's performance of his duties. 9. Indemnification. The Company will pay all reasonable fees and expenses, if any, (including, without limitation, legal fees and expenses) that are incurred by the Executive to enforce 12 this Agreement and that result from a breach of this Agreement by the Company. 10. Payment of Compensation and Taxes. All amounts payable under this Agreement (other than restricted stock and stock options, which will be governed by the terms of their respective plans) will be paid in cash, subject to required income and payroll tax withholdings. No unrestricted stock will be issued to the Executive with respect to the vesting of restricted stock until the Executive has paid to the Company the amount that must be withheld for applicable income and employment taxes or the Executive has made provisions satisfactory to the Company for the payment of such taxes. 11. Administration. The senior executive of Human Resources will be responsible for the administration and interpretation of this Agreement on behalf of the Company. If for any reason a benefit under this Agreement is not paid when due, the Executive may file a written claim with the senior executive of Human Resources. If the claim is denied or no response is received within 90 days after the filing (in which case the claim is deemed to be denied), the Executive may appeal the denial to the Board of Directors within 60 days of the denial. The Executive may request that the Board of Directors review the denial, the Executive may review pertinent documents, and the Executive may submit issues and comments in writing. A decision on appeal will be made within 60 days after the appeal is made, unless special circumstances require that the Board of 13 Directors extend the period for another 60 days. If the Company defaults in an obligation under this Agreement, the Executive makes a written claim pursuant to the claims procedure described above, and the Company fails to remedy the default within the claims procedure period, then all amounts payable to the Executive under this Agreement will become immediately due and owing. 12. Assignment. The rights and obligations of the Company under this Agreement will inure to the benefit of and will be binding upon the successors and assigns of the Company. If the Company is consolidated or merged with or into another corporation, or if another entity purchases all or substantially all of the Company's assets, the surviving or acquiring corporation will succeed to the Company's rights and obligations under this Agreement. The Executive's rights under this Agreement may not be assigned or transferred in whole or in part, except that the personal representative of the Executive's estate will receive any amounts payable under this Agreement after the death of the Executive. 13. Rights Under the Agreement. The right to receive benefits under the Agreement will not give the Executive any proprietary interest in the Company or any of its assets. Benefits under the Agreement will be payable from the general assets of the Company, and there will be no required funding of amounts that may become payable under the Agreement. The Executive will for all purposes be a general creditor of the 14 Company. The interest of the Executive under the Agreement cannot be assigned, anticipated, sold, encumbered or pledged and will not be subject to the claims of the Executive's creditors. 14. Notice. For purposes of this Agreement, notices and all other communications must be in writing and are effective when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to the Executive or his personal representative at his last known address. All notices to the Company must be directed to the attention of the senior executive of Human Resources. Such other addresses may be used as either party may have furnished to the other in writing. Notices of change of address are effective only upon receipt. 15 15. Miscellaneous. This instrument contains the entire agreement of the parties. To the extent not governed by federal law, this Agreement will be construed in accordance with the laws of the Commonwealth of Virginia, without reference to its conflict of laws rules. No provisions of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and the writing is signed by the Executive and the Company. A waiver of any breach of or compliance with any provision or condition of this Agreement is not a waiver of similar or dissimilar provisions or conditions. The invalidity or unenforceability of any provision of this Agreement will not affect the validity or enforceability of any other provision of this Agreement, which will remain in full force and effect. This Agreement may be executed in one or more counterparts, all of which will be considered one and the same agreement. WITNESS the following signatures. Virginia Electric and Power Company By:__________________________ Edgar M. Roach, Jr. Chief Executive Officer Dated:___________________ _____________________________ Mark F. McGettrick Dated:___________________ 16 EX-23.1 3 0003.txt CONSENT OF MCGUIRE WOODS BATTLE & BOOTHE Exhibit 23.1 March 16, 2001 Virginia Electric and Power Company 701 East Cary Street Richmond, VA 23219-3932 Ladies and Gentlemen: We consent to the incorporation by reference into the statements made in regard to our firm in the Registration Statements and related prospectuses of Virginia Electric and Power Company on Form S-3 (File Nos. 333-38510 and 333-76155) of the legal conclusions that relate to the Company's franchises and title to properties included in this Annual Report on Form 10-K. Sincerely, /s/ McGuireWoods LLP EX-23.2 4 0004.txt CONSENT OF JACKSON & KELLY Exhibit 23.2 Virginia Electric and Power Company Richmond, Virginia 23261 Re: Virginia Electric and Power Company Form 10-K Gentlemen: We consent to the incorporation by reference into the registration statements of Virginia Electric and Power Company on Form S-3 (File No. 333- 76155 and File No. 333-38510) of the statements, included in this Annual Report on Form 10-K, made in regard to our firm that are governed by the laws of West Virginia and that relate to franchises, title to properties, limitations upon the issuance of bonds and preferred stock, rate and other regulatory matters, and litigation. Sincerely yours, JACKSON & KELLY PLLC EX-23.3 5 0005.txt CONSENT OF DELOITTE & TOUCHE LLP Exhibit 23.3 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 333- 38510 and 333-76155 of Virginia Electric and Power Company on Form S-3 of our reports dated January 25, 2001, appearing in this Annual Report on Form 10-K of Virginia Electric and Power Company for the year ended December 31, 2000. DELOITTE & TOUCHE LLP Richmond, Virginia March 16, 2001 -----END PRIVACY-ENHANCED MESSAGE-----