-----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, Wr+l3JQAWtjrFdnHysGy8Aib4gn/K5Zf+sLjhTWHzOL1Q8Tkb2/oqS6sirB9FFVR 31U9osr2+Z9BC7Vy4s5kTQ== 0000916641-01-000361.txt : 20010321 0000916641-01-000361.hdr.sgml : 20010321 ACCESSION NUMBER: 0000916641-01-000361 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010320 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DOMINION RESOURCES INC /VA/ CENTRAL INDEX KEY: 0000715957 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 541229715 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-08489 FILM NUMBER: 1572390 BUSINESS ADDRESS: STREET 1: 120 TREDEGAR STREET STREET 2: P O BOX 26532 CITY: RICHMOND STATE: VA ZIP: 23219 BUSINESS PHONE: 8048192000 MAIL ADDRESS: STREET 1: P O BOX 26532 STREET 2: 901 EAST BYRD STREET CITY: RICHMOND STATE: VA ZIP: 23261 10-K405 1 0001.txt FORM 10-K405 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 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 1-8489 ---------------- DOMINION RESOURCES, INC. (Exact name of registrant as specified in its charter) Virginia 54-1229715 (I.R.S. Employer Identification Number) (State or other jurisdictionof incorporation or organization) 120 Tredegar Street 23219 Richmond, Virginia (Address of principal executive (Zip Code) offices) (804) 819-2000 (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 ------------------- ----------------------- Common Stock, no par value New York Stock Exchange Corporate Premium Income Equity Securities New York Stock Exchange 8.4% Trust Preferred Securities 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 was over $16.0 billion based on the closing price of our Common Stock on March 2, 2001, as reported on the composite tape by the Wall Street Journal. Indicate the number of shares outstanding of each registrant's class of common stock, as of the latest practicable date.
Outstanding at Class March 2, 2001 ----- -------------- Common Stock, no par value 246,420,761
DOCUMENTS INCORPORATED BY REFERENCE. (a) Portions of the 2000 Annual Report to Shareholders for the fiscal year ended December 31, 2000 are incorporated by reference in Parts I, II and IV hereof. (b) Portions of the 2001 Proxy Statement, dated March 16, 2001, are incorporated by reference in Part III hereof. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- DOMINION RESOURCES, INC.
Item Page Number Number - ------ ------ PART I 1. Business........................................................ 3 The Company...................................................... 3 Legal Structure and Principal Legal Subsidiaries............... 3 Organizational Changes......................................... 4 Competition...................................................... 4 Electric Industry.............................................. 4 Gas Industry................................................... 5 Regulations...................................................... 7 Separation of Electric Generation and Delivery Operations in Virginia...................................................... 7 Regional Transmission Entities/Regional Transmission Organizations................................................. 8 Retail Access Pilot Program.................................... 8 Wholesale Markets.............................................. 8 Environmental Matters.......................................... 9 Nuclear Generation............................................. 9 Rates............................................................ 10 Electric....................................................... 10 Gas............................................................ 11 Financial Information about Segments and Geographic Areas........ 11 Sources of Energy................................................ 11 Sources of Energy--Electricity................................. 11 Sources of Energy--Gas......................................... 14 Future Sources of Energy......................................... 15 Cautionary Factors That May Affect Future Results................ 16 2. Properties...................................................... 16 3. Legal Proceedings............................................... 19 4. Submission of Matters to a Vote of Security Holders............. 21 Executive Officers of the Registrant............................. 21 PART II 5. Market for the Registrant's Common Equity and Related Stockholder Matters............................................... 23 6. Selected Financial Data......................................... 23 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................. 23 7A. Quantitative and Qualitative Disclosures About Market Risk..... 23 8. Financial Statements and Supplementary Data..................... 23 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.............................................. 23 PART III 10. Directors and Executive Officers of the Registrant............. 24 11. Executive Compensation......................................... 24 12. Security Ownership of Certain Beneficial Owners and Management........................................................ 24 13. Certain Relationships and Related Transactions................. 24 PART IV 14. Exhibits, Financial Statement Schedules, and Reports on Form 8- K................................................................. 25
2 PART I ITEM 1. BUSINESS THE COMPANY Dominion Resources, Inc. (Dominion or the Company) is a fully integrated gas and electric holding company headquartered in Richmond, Virginia. Our principal assets are located in the Northeast quadrant of the United States, which is an area we call MAIN to Maine. In the power industry, "MAIN" means the Middle American Interconnected Network, which comprises the states of Missouri, Illinois, Wisconsin, Michigan and Indiana. The MAIN to Maine region is home to approximately 40% of the nation's demand for energy. It also has some of the nation's highest energy prices and, as a result, is rapidly moving toward industry deregulation and restructuring. Our acquisition of Consolidated Natural Gas Company (CNG), completed in early 2000, substantially increased our concentration of assets and customers in this region. As a result of our acquisition of CNG, Dominion is a registered public utility holding company subject to the provisions of the Public Utility Holding Company Act of 1935 (the 1935 Act). CNG also continues to be a registered holding company under the 1935 Act. With the acquisition of CNG, Dominion began managing its business through three principal segments that integrate its electric and gas services, streamline operations, and position Dominion for long-term growth in the competitive marketplace. . Dominion Energy--Dominion Energy manages our 19,000-megawatt generation portfolio, our 7,600 miles of gas transmission pipeline, and a 959 billion cubic foot natural gas storage network. It also guides our generation growth strategy and our commodity trading, marketing, and risk management activities. We currently operate generation facilities in Virginia, West Virginia, North Carolina and Illinois. Dominion Energy will also include the 1,954-megawatt Millstone Nuclear Power Station, which we expect to acquire this year. . Dominion Delivery--Dominion Delivery manages our local electric and gas distribution systems serving nearly 3.8 million customers, our 6,000 miles of electric transmission lines and our customer service operations. We currently operate transmission and distribution systems in Virginia, West Virginia, North Carolina, Pennsylvania and Ohio. Dominion Delivery also includes our interest in Dominion Telecom with its 3,600 route-mile fiber optic network and related telecommunications and advanced data services. . Dominion Exploration & Production--Dominion Exploration & Production (Dominion E&P) manages our onshore and offshore oil and gas exploration and production activities. With approximately 2.8 trillion cubic feet of natural gas equivalent reserves and an annual production capacity exceeding 300 billion cubic feet, Dominion E&P is one of the nation's largest independent oil and gas operators. We operate on the outer continental shelf and deepwater areas of the Gulf of Mexico, western Canada, the Appalachian Basin and other selected regions in the continental United States. While Dominion manages its daily operations as described above, its assets remain wholly-owned by its legal subsidiaries, which are described below in Legal Structure and Principal Legal Subsidiaries. For additional financial information on business segments, see Note 27 to the Consolidated Financial Statements on page 68 of the 2000 Annual Report. Legal Structure and Principal Legal Subsidiaries Dominion was incorporated in 1983 as a Virginia corporation. Dominion and its subsidiaries had approximately 15,600 full-time employees as of December 31, 2000. Our principal office is located at 120 Tredegar Street, Richmond, Virginia 23219, telephone (804) 819-2000. Dominion's principal direct legal 3 subsidiaries are Virginia Electric and Power Company (Virginia Power) a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy in Virginia and northeastern North Carolina and Consolidated Natural Gas Company (CNG), a producer, transporter, distributor and retail marketer of natural gas, serving customers in Pennsylvania, Ohio, Virginia, West Virginia, New York and other cities focused in the Northeast and Mid-Atlantic regions of the United States. Our other major subsidiaries are Dominion Energy, Inc. (DEI), Dominion's independent power and natural gas subsidiary, and Dominion Capital, Inc. (DCI), our diversified financial services company. Our legal structure is not currently the same as the operating segments we use to manage our business. The functional separation of Virginia Power's regulated and unregulated businesses described elsewhere in this report may, with regulatory approval, provide us with the opportunity to realign our legal structure with our operating segments. Organizational Changes On January 28, 2000, Dominion completed its acquisition of CNG. The combination with CNG, based in Pittsburgh, Pennsylvania, creates a fully integrated electric and natural gas utility in the Midwest, Northeast and Mid- Atlantic regions of the United States. As a result of the acquisition of CNG, we became a registered public utility holding company under the 1935 Act. The 1935 Act imposes a number of restrictions on the operations of registered holding company systems, one of which limits our ability to engage in activities unrelated to our utility operations or other energy related businesses. As part of the Securities and Exchange Commission (SEC) order approving the acquisition under the 1935 Act, Dominion must divest itself of DCI within three years. During the approval process, Dominion and CNG also agreed to divest Virginia Natural Gas, Inc. (VNG), CNG's gas distribution subsidiary located in Virginia Beach, Virginia. In October 2000, Dominion completed the sale of VNG to AGL Resources Inc. As we build our geographically focused business, we are also divesting our assets outside of the targeted MAIN to Maine region. We have divested all of our Latin American assets, including the Argentine assets of CNG. We completed our exit from the United Kingdom during 2000 with the sale of our 80% interest in the Corby Power Station, and we are actively exploring the sale of CNG's remaining international operations in Australia. 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. For additional information regarding the acquisition of CNG and our exit strategy for certain DCI businesses, see Notes 5 and 6 to Consolidated Financial Statements on pages 46 through 49 of the 2000 Annual Report. COMPETITION Our Dominion Energy and Dominion Delivery segments are each affected by the increasing momentum towards deregulation in both the electric and gas industries. In addition to the restructuring of the gas industry, the emerging unbundling of services provided by electric utilities is leading toward the convergence of the two industries to create one overall, highly competitive marketplace for a customer's total energy needs. Electric Industry 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 4 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. Although progress varies, pro-competition electric legislation is under consideration in many states. In Virginia, legislation was passed in 1999 which will phase in customer choice between 2002 and 2004. In Ohio, legislation was enacted in 1999 which allowed consumers to choose their electric supplier beginning January 1, 2001. In Pennsylvania, all consumers may now choose their electric supplier. Regulators and legislators in West Virginia and North Carolina are also debating issues related to electric industry restructuring. Because competition has not yet been fully phased-in and electric services have not been unbundled in Virginia, competition issues affect both our Dominion Energy and Dominion Delivery segments as a whole and do not lend themselves to discussion on a segment basis. The following discussion relates to competition as it affects our electricity operations in Virginia and North Carolina. Historically, our electric utility subsidiary has had the exclusive right to provide electricity at retail within its assigned service territories in Virginia and North Carolina. As a result, our Company's exposure to competition for retail electric sales was limited to the extent our 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, legislation was passed 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 (deregulation legislation). Complying with this deregulation legislation, we established a retail choice pilot program that is currently in place for sales of electricity within our Virginia service territory. 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. See Deregulation Legislation--Electric Industry under Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) on page 35 of the 2000 Annual Report. Gas Industry Dominion Delivery Dominion has taken steps to offer choices to its gas customers in Pennsylvania. As early as 1984, large industrial customers in Pennsylvania began to buy natural gas supplies from third parties, rather than directly from local utilities; the local distributors transported these third-party gas supplies to the industrial facilities. Since that time, nearly all of our Pennsylvania industrial and large commercial customers have changed from being utility sales customers to transportation services customers, buying the natural gas commodity from unregulated suppliers and transporting it on our gas delivery network. In 1997, Dominion's Pennsylvania gas utility subsidiary voluntarily launched an Energy Choice program for all of its retail consumers in Pennsylvania--whether industrial, commercial, or residential. Subsequently, in 1999, Pennsylvania enacted legislation to mandate supplier choice for residential and small commercial customers. At December 31, 2000, approximately 106,000 customers had opted for Energy Choice in our Company's Pennsylvania service area. Large industrial customers in Ohio began to source their own natural gas supplies in the mid-1980's, as interstate pipeline transportation services became more widely available. However, to date, Ohio has not enacted legislation to require supplier choice for residential and commercial natural gas consumers. Dominion has made significant progress in offering Energy Choice to customers on its own initiative, in cooperation with The Public Utilities Commission of Ohio. In 1997, Dominion's Ohio gas utility subsidiary launched a pilot 5 program, designed to make gas transportation service available to residential and small commercial customers, and to the suppliers that market gas to these customer classes. In 2000, the Energy Choice program was expanded to all 1.2 million customers in Dominion's Ohio service area. At December 31, 2000, approximately 175,000 of Dominion's Ohio customers were participating in this open-access program. At this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. In this smaller, more rural market area, Dominion has not voluntarily initiated an Energy Choice program. However, the West Virginia Public Service Commission recently issued regulations to govern pooling services; these services are one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future. Dominion Energy Dominion has taken advantage of selected market expansion opportunities, concentrating its efforts primarily in the Northeast and along the East Coast. Dominion's large underground storage capacity and the location of its gridlike pipeline system as a link between the country's major gas pipelines and large markets on the East Coast have been key factors in the success of these expansion efforts. The Company's pipelines are part of an interconnected gas transmission system which will continue to enable retail end users to take advantage of the accessibility of supplies nationwide as gas utilities unbundle services at the retail level. Dominion competes with domestic as well as Canadian pipeline companies and gas marketers seeking to provide or arrange transportation, storage and other services for customers. Also, certain end users have the ability to switch to fuel oil or coal if desired. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain longline pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enables Dominion to tailor its services to meet the individual needs of customers. Dominion Exploration & Production Exploration and production operations are conducted by the Company in several major gas and oil producing basins in the United States, both onshore and offshore, and Canada. In this highly competitive business, the Company competes with a large number of entities ranging in size from large international oil companies with extensive financial resources to small, cash flow driven independent producers. Dominion faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since Dominion is the operator of a number of properties, it also faces competition in securing drilling equipment and supplies for exploration and development. From the production perspective, the marketing of gas and oil is highly competitive with price being the most significant factor. Gas producers throughout the industry, including Dominion, face a diverse and active market with purchasers seeking to balance the advantage of flexible spot market supplies with the security of longer-term contracts. The growth of gas and energy marketing firms has added to the competition for Dominion. When the economics warrant, the Company attempts to sell its gas production under long- term contracts to customers such as electric power generators and others that require a secure source of supply. However, these arrangements represent only a portion of the Company's gas production. Further, the deliverability of gas produced is influenced by competition for downstream pipeline transportation capacity. The Company continues to develop marketing strategies, contracts and arrangements to address customer needs for intermediate and long-term gas supplies as well as swing, peaking and other energy services. In addition, in the ordinary course of business, Dominion participates in price risk management activities to manage exposure to price risk in connection with the production and sale of natural gas and oil. 6 REGULATION General Many aspects of our business are presently subject to regulation by the SEC, the Federal Energy Regulatory Commission (FERC), the Environmental Protection Agency (EPA), Department of Energy (DOE), the Nuclear Regulatory Commission (NRC), the Army Corps of Engineers, and other federal, state and local authorities. The Virginia State Corporation Commission (Virginia Commission) and the North Carolina Utilities Commission (the North Carolina Commission) regulate our bundled rates for retail electric sales in those states and FERC approves our rates for electric sales to wholesale customers. While our electric utility subsidiary holds certificates of public convenience and necessity authorizing it to construct and operate its electric facilities now in operation and to sell electricity to customers, it 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 government agencies. As discussed above in COMPETITION--Electric Industry, deregulation legislation has been enacted in Virginia. Under the deregulation legislation, Dominion's electric utility subsidiary is required to join or establish a regional transmission entity, establish a retail access pilot program and submit to the Virginia Commission a plan for separating its generation and and delivery operations. Certain subsidiaries of CNG are subject to the Natural Gas Act of 1938, as amended. Our interstate gas transportation and storage activities are regulated under such Act and are conducted in accordance with certificates, tariffs and service agreements on file with FERC. Other CNG subsidiaries are subject to various provisions of the five statutes that are referred to as the National Energy Act of 1978. One of these statutes, the National Energy Conservation Policy Act, requires utilities to offer home energy audits and other assistance to residential customers. We are also subject to the Natural Gas Pipeline Safety Act of 1968, which authorizes the establishment and enforcement of federal pipeline safety standards and places jurisdiction of these standards with the Department of Transportation. Intrastate facilities remain within the safety jurisdiction of the state regulatory agencies, presuming compliance by such agencies with certain prerequisites contained in such Act. Our gas distribution business subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate -- Pennsylvania, Ohio, and West Virginia. In 1999, Pennsylvania enacted legislation which mandates supplier choice for residential and small commercial customers. For additional information on deregulation in the gas industry, see COMPETITION--Gas Industry. The following sections discuss various regulatory proceedings in which the Company is or has recently been involved. See COMPETITION and RATES for information on additional proceedings. 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 electric deregulation legislation, the Company's electric subsidiary filed with the Virginia Commission an application for approval of a functional separation plan for its regulated utility operations. The plan provides in part for the following: . transfer of generation assets into a separate legal entity, Dominion Generation Corporation; 7 . transfer of rights and obligations under non-utility power purchase 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 Virginia Power'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. For additional details on functional separation, see Electric and Gas Industry Issues--Separation of Electric Generation and Delivery Operations in Virginia under MD&A on page 36 of the 2000 Annual Report. Regional Transmission Entities/Regional Transmission Organizations 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, Dominion's electric utility subsidiary filed an application with the Virginia Commission seeking authorization to transfer control of its 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 Dominion expects the RTO to satisfy the requirements to establish the RTE under Virginia legislation. 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 an RTO. Dominion, together with American Electric Power (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 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. Retail Access Pilot Program In 1998, the Virginia Commission issued an Order instructing the Company's electric utility subsidiary and American Electric Power-Virginia, a subsidiary of AEP, as Virginia's two largest investor-owned utilities, each to design and file a retail access pilot program relating to electric distribution in Virginia. 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 program 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. Wholesale Markets Dominion's electric utility subsidiary sells electricity in the wholesale market under its market based-sales tariff authorized by FERC but has agreed not to make wholesale power sales under this tariff to loads located 8 within its service territory. During 2000, our electric utility subsidiary filed applications with FERC to make sales under its market-based sales tariff to loads within its service territory participating in its retail access pilot program and to amend its 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 electric service territory, other than sales to loads participating in the electric retail access pilot program, are to be at cost- based rates accepted by FERC. Dominion's sales of oil and natural gas in wholesale markets are not regulated by FERC. The deregulation of gas sales began through a multi-year schedule established under the Natural Gas Policy Act (NGPA) of 1978 and was completed under the Natural Gas Wellhead Decontrol Act of 1989. Environmental Matters Each segment of our business faces 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 and Gas Industry Issues-- Environmental Matters, Environmental Protection and Monitoring Expenditures, Clean Air Act Compliance, and Global Climate Change under MD&A on pages 37 and 38 of the 2000 Annual Report. From time to time we may be identified as a potentially responsible party with respect to a superfund site. The 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, we may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. We do not believe that any currently identified sites will result in significant liabilities. The Company has determined that it is associated with 20 former manufactured gas plant sites, eight of which are currently owned by subsidiaries. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 20 former sites with which the Company is associated is under investigation by any state or federal environmental agency, and no investigation or action is currently anticipated. At this time it is not known if, or to what degree, these sites may contain environmental contamination. Therefore, the Company is not able to estimate the cost, if any, that may be required for the possible remediation of these sites. 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 electric generating stations. Many of these permits are subject to re-issuance and continuing review. For additional information regarding environmental matters, see Item 3. LEGAL PROCEEDINGS on page 20 and Electric and Gas Industry Issues-- Environmental Matters under MD&A on page 37 and Note 22 to the Consolidated Financial Statements on page 60 of the 2000 Annual Report. Nuclear Generation All aspects of the operation and maintenance of our nuclear power stations, which are a part of our Dominion 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. 9 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 yet 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 14 to Consolidated Financial Statements on page 53 of the 2000 Annual Report. RATES Electric The majority of our electric revenue is provided through bundled rate tariffs. In 2000, electric service sales by our electric utility subsidiary 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 -------------------------------- Revenues 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 the electric service sales made by our electric utility subsidiary are currently subject to recovery of changes in fuel costs through fuel adjustment factors. On November 27, 2000, an application was filed 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. 10 Recent Virginia proceedings related to our rates include the following: The Virginia base (non-fuel) rates of our electric utility subsidiary are currently capped until July 1, 2007, according to legislation passed in the 1998 session of the General Assembly. In December 2000, our electric utility subsidiary 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. Our electric utility subsidiary also 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, our electric utility subsidiary 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 connection with the approval by the North Carolina Commission of its acquisition of CNG, the Company agreed not to request an increase in North Carolina retail electric base rates for both the Dominion Energy and Dominion Delivery segments until after December 31, 2005, except for certain events that would have a significant financial impact on the Company. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings. Gas Dominion's regulated gas subsidiaries continue to seek general rate increases with regard to their regulated gathering, transmission, storage and gas distribution services. Such rate changes are requested on a timely basis to recover increased operating costs and to ensure that rates of return are compatible with the cost of raising capital. In addition to general rate increases, certain of our gas distribution subsidiaries make separate filings with their respective regulatory commissions to reflect changes in the costs of purchased gas. Dominion Transmission, Inc. (Dominion Transmission), an interstate gas transmission subsidiary, has pending rate cases before FERC, which are intended: (1) to unbundle gathering and products extraction rates from those for interstate transportation, and (2) to recover the costs of certain gas used as fuel for system operations. Otherwise, Dominion's regulated gas subsidiaries filed no new general rate cases during 2000, nor were there any outstanding cases requiring settlement. In March 2001, Dominion's West Virginia gas utility subsidiary filed a rate case with the Public Service Commission of West Virginia with a proposed effective date for new rates as of January 1, 2002. No procedural schedule has been established at this time. The proposed new rates are to provide for the increased cost of gas supplies as well as increased operating costs. FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHIC AREAS See Note 27 to the Consolidated Financial Statements on page 68 of the 2000 Annual Report. SOURCES OF ENERGY Sources of Energy--Electricity Dominion Energy provides electricity for use on a wholesale and a retail level. We can supply electricity demand either through generation from our generation facilities in Virginia, West Virginia, North Carolina and Illinois or through power purchase contracts when needed. The following table outlines our generating units and capability. 11 Generating Units
Summer Years Capability Name of Station, Units and Location Installed Type of Fuel Mw ----------------------------------- --------- -------------- ---------- 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(e) ------ 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 ------ Non-regulated Units: Kincaid, Springfield, IL................. 1967-1968 Coal 1,158 Elwood, Elwood, IL....................... 1999 Gas 307 Morgantown, Morgantown, WV............... 1992 Waste Coal 33 Others................................... 1988-1990 Various 39 ------ Total non-regulated generating units............................... 1,537 ------ Net Purchases.............................. 145 Non-Utility Generation (power purchase contracts)................................ 3,973 ------ Total Capability..................... 19,920 ======
- -------- (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). (e) In 2000, our four nuclear units achieved a combined capacity factor of 95.1 percent. 12 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. Power Purchase Contracts Dominion Energy purchases electricity under contracts with other suppliers to meet a portion of our own system capacity requirements. 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 Dominion 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 was suspended. As of December 31, 2000, we have 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 22 to Consolidated Financial Statements on page 60 of 2000 Annual Report. 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. Fuel for Electric Generation We use a variety of fuels to power our electric generation. These include a mix of both nuclear fuel and fossil fuel as described further below. Nuclear Fuel Supply 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 are expected to support our current and planned fuel supply needs for fuel cycles into the early 2000's. Beyond that period, we expect to purchase additional fuel 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 are expected to be adequate for our needs until the DOE begins accepting SNF. See REGULATION--Nuclear Generation for additional information regarding SNF. Fossil Fuel Supply The fuel mix utilized by Dominion Energy's 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 13 to support our coal needs. We presently anticipate sufficient supplies of coal will continue to 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. Coal markets have become more supply-demand balanced which 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 to be available over the next five to ten year period. Dominion Energy uses natural gas as needed throughout the year for our jurisdictional and non-jurisdictional facilities. The Company's gas supply is obtained from various sources including: purchases from major and independent producers in the Southwest and Midwest regions; purchases from local producers in the Appalachian area; purchases from gas marketers; production from Company- owned wells in the Appalachian area, the Southwest, Midwest and offshore; and withdrawals from the Company's and third party underground storage fields. Dominion has the capability to buy and store natural gas at summer prices, which will then be consumed at the facilities during the winter. 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. Sources of Energy--Gas Gas Supply Dominion Energy is also engaged in the sale and storage of natural gas through its operating subsidiaries. Sources of gas supplies for sale to customers are the same as those described in Fossil Fuel Supply above. The Company has continued to purchase volumes from the array of accessible producing basins using its firm capacity resources. These purchased supplies include Appalachian resources in Ohio, Pennsylvania and West Virginia, and production from the Gulf Coast, Mid-Continent and offshore areas. Upon FERC's restructuring of the interstate pipeline business in 1992-93, pipelines no longer sell the delivered natural gas commodity; rather, customers provide their own gas supply for wholesale storage and/or delivery by the pipelines. Much of the supply is purchased by local distributors, energy marketing companies or end users, under seasonal or spot purchase agreements. While the average term of the Company's gas purchase agreements has declined, the reliability of supply has been adequate. The availability of supplies and heightened competition has forged a viable market, which has proven capable of satisfying the firm delivery requirement for supplies to the Company's markets in a highly reliable manner. Purchased gas volumes were 422 billion cubic feet (Bcf) or about 60% of the total 2000 supply. Spot market and short-term purchases were 398 Bcf, or about 56% of the total 2000 supply. Considering the Company's large storage capacity, the volumes obtainable under its firm interstate pipeline capacity and gas supply contracts, Company- owned gas reserves, and assuming the future availability of spot market gas, the Company believes that supplies will be available to meet sales requirements for at least the next several years. Gas Storage--Transmission The Company's underground storage facilities play an important part in balancing gas supply with sales demand and are essential to servicing the Company's large volume of space-heating business. In addition, 14 storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity. The Company operates 26 underground gas storage fields located in Ohio, Pennsylvania, West Virginia and New York. The Company owns 20 of these storage fields and has joint-ownership with other companies in six of the fields. The total designed capacity of the storage fields, including native gas, is approximately 959 Bcf. The Company's share of the total capacity is about 717 Bcf. About one-half of the total capacity is base gas which remains in the reservoirs at all times to provide the primary pressure which enables the balance of the gas to be withdrawn as needed. Dominion Transmission operates 756 Bcf of the total designed storage capacity and owns 514 Bcf of the Company's capacity. Dominion Transmission utilizes a large portion of its turnable capacity to provide approximately 275 Bcf of gas storage service for others. This service is provided principally to local distributors, end users, and other customers serving the Northeast. Two of Dominion's gas distribution subsidiaries, Dominion East Ohio and Dominion Peoples, own and operate the remaining 203 Bcf of storage capacity. In addition to owning their own storage, these companies, as well as several of the other subsidiaries, have access to a portion of the storage capacity operated by Dominion Transmission. The distribution subsidiaries also have capacity available in storage fields owned by others. The Company controls other acreage in the Appalachian area suitable for the development of additional storage facilities which would enable further expansion of capacity to meet possible future storage needs. FUTURE SOURCES OF ENERGY 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. Dominion has reached an agreement to acquire the Millstone Nuclear Power Station located in Waterford, Connecticut from subsidiaries of Northeast Utilities and other owners for approximately $1.3 billion. The acquisition includes 100% ownership in Unit 1 and Unit 2, and 93.47% ownership interest in Unit 3, for a total of 1,954 Mw of generating capacity. See Note 5 of the Consolidated Financial Statements on page 47 of the 2000 Annual Report for additional information on the Millstone Nuclear Power Station acquisition. Dominion has also sited four new generation plants with combined capacity of approximately 2,000 Mw along Dominion's gas pipelines in Ohio, Pennsylvania and West Virginia. Additional anticipated capacity expansion of 4,000 Mw is also planned, including capacity expansions at our Elwood facility in Illinois. The Company has planned a $400 million addition to its natural gas transmission system to help meet demand growth. The 200-mile Greenbrier Pipeline will extend from West Virginia to North Carolina. During 2000, Dominion acquired 167 billion cubic feet equivalent of gas reserves and additional acreage for exploratory and development drilling through a number of purchase transactions. Significant acquisitions during the year included the purchase of additional interests in two deepwater Gulf of Mexico properties and various South Texas gas fields. In January 2000, Dominion acquired an additional 12.5 percent interest in Popeye, a deepwater gas producing property, increasing its interest to 50 percent. Dominion also doubled its interest in the Devil's Tower deepwater discovery to 60 percent. In August 2000, Dominion acquired the operating interests of Suemaur Exploration & Production, LLC and several partners in three Texas Gulf Coast natural gas fields. 15 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 and in our 2000 Annual Report to shareholders 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, future performance or results of the development and expansion of the telecommunications segment, growth in customer base, financial results of asset divestitures, 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, in the 2000 Annual Report and 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 Dominion's assets consist primarily of its investments in its subsidiaries, the principal properties of which are described below. Our Dominion Energy segment utilizes the electric generation facilities listed under the heading Sources of Power--Generating Units in Item 1. BUSINESS. Additionally, in connection with gas transmission and storage operations, Dominion Energy's storage operation consists of 26 storage fields, 342,605 acres of operated leaseholds, 2,069 storage wells and 822 miles of pipe. A significant portion of our investment in gas transmission facilities is for 6,428 miles of pipe required to move large volumes of gas throughout the Company's operating area. Our Dominion Energy segment also includes 99 compressor stations with 492,040 installed compressor horsepower located in Ohio, West Virginia, Pennsylvania and New York. Some of the stations are used interchangeably for several functions. Our Dominion Delivery segment utilizes 3,600 miles of electric transmission lines. Right-of-way grants from the apparent owners of real estate have been obtained for most 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. Dominion Delivery's investment in its gas distribution network is located in the states of Ohio, Pennsylvania and West Virginia. The gas distribution network includes 27,060 miles of pipe, exclusive of service pipe. 16 The Company's investment in its natural gas system is considered suitable to do all things necessary to bring gas to the consumer. The Company's properties provided the capacity to meet a record system peak day sendout, including transportation service, of 11.4 Bcf on February 6, 1995. The system peak day sendout in 2000 was 8.6 Bcf on January 27. Information detailing Dominion Exploration & Production's oil and gas investments is as follows: Company-Owned Reserves Estimated net quantities of proved gas and oil reserves at December 31 were as follows:
2000 1999 1998 ---------------- ---------------- ---------------- Proved Total Proved Total Proved Total Developed Proved Developed Proved Developed Proved --------- ------ --------- ------ --------- ------ Gas reserves (Bcf) United States.............. 1,593 1,858 600 600 473 473 Canada..................... 361 479 405 514 118 118 ------ ------ ----- ------ ----- ----- Total gas reserves....... 1,954 2,337 1,005 1,114 591 591 ====== ====== ===== ====== ===== ===== Oil reserves (000 Bbls) United States.............. 21,709 51,072 659 659 2,661 2,661 Canada..................... 14,527 24,270 5,443 20,149 1,543 1,543 ------ ------ ----- ------ ----- ----- Total oil reserves....... 36,236 75,342 6,102 20,808 4,204 4,204 ====== ====== ===== ====== ===== =====
Dominion E&P and Dominion Transmission file Form EIA-23 with the DOE. The reserves reported on Form EIA-23 at December 31, 2000, as well as those which will be reported at December 31, 2001, are not reconcilable with Company-owned reserves because they are calculated on an operated basis and include working interest reserves of all parties. Quantities of Gas and Oil Produced Quantities of gas and oil produced during each of the last three years ending December 31 follow:
2000 1999 1998 ----- ----- ----- Gas production (Bcf) United States............................................... 222 60 50 Canada...................................................... 47 37 13 ----- ----- ----- Total gas production...................................... 269 97 63 ===== ===== ===== Oil production (000 Bbls) United States............................................... 6,436 595 751 Canada...................................................... 1,258 1,462 274 ----- ----- ----- Total oil production...................................... 7,694 2,057 1,025 ===== ===== =====
The average sales price (including transfers to other operations as determined under Financial Accounting Standards Board rules) per Mcf of non- cost-of-service gas produced during the years 2000, 1999 and 1998 was $3.10, $2.06 and $2.07, respectively. The respective average sales prices for oil were $22.88, $13.55 and $11.94 per barrel. The average production (lifting) cost per Mcf equivalent of gas and oil produced during the years 2000, 1999 and 1998 was $.49, $.71 and $.63, respectively. 17 Productive Wells The number of productive gas and oil wells in which the Company's subsidiaries had an interest at December 31, 2000, follow:
Gross Net ------ ----- Gas wells United States.................................................... 11,048 8,864 Canada........................................................... 815 490 ------ ----- Total gas wells................................................ 11,863 9,354 ====== ===== Oil wells United States.................................................... 342 247 Canada........................................................... 705 214 ------ ----- Total oil wells................................................ 1,047 461 ====== =====
Includes 82 gross (23 net) multiple completion gas wells and 21 gross (8 net) multiple completion oil wells. Net Wells Drilled in the Calendar Year The number of net wells completed during each of the last three years follows:
Years Ended December 31 ------------------------- 2000 1999 1998 ------- ------- ------- Exploratory: United States Productive........................................ 5 Dry............................................... 9 ------- ------- ------- Total exploratory............................... 14 ------- ------- ------- Development: United States Productive........................................ 253 90 134 Dry............................................... 2 ------- ------- ------- Total United States............................. 255 90 134 ------- ------- ------- Canada Productive........................................ 52 18 14 Dry............................................... 26 3 7 ------- ------- ------- Total Canda..................................... 78 21 21 ------- ------- ------- Total development............................... 333 111 155 ------- ------- ------- Total wells drilled........................... 347 111 155 ======= ======= =======
As of December 31, 2000, 36 gross (21 net) wells were in process of drilling, including wells temporarily suspended. 18 Acreage The following table sets forth the gross and net developed and undeveloped acreage of the Company's subsidiaries at December 31, 2000:
Developed Acreage Undeveloped Acreage ------------------- ------------------- Gross Net Gross Net* --------- --------- --------- --------- United States*.......................... 2,453,889 1,784,475 1,034,933 611,114 Canada.................................. 1,281,477 716,673 1,130,216 732,678 --------- --------- --------- --------- Total................................. 3,735,366 2,501,148 2,165,149 1,343,792 ========= ========= ========= =========
- -------- * Developed acreage includes 212,055 gross and net cost-of-service acres. ITEM 3. LEGAL PROCEEDINGS From time to time, Dominion and its subsidiaries 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 administrative proceedings on these matters pending. In addition, in the normal course of business, Dominion and its subsidiaries are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on the Company's 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. In April 1999, Virginia Power 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 our power stations. If, in a legal proceeding, such instances of noncompliance are deemed to have occurred, Virginia Power 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. In August 1999, Virginia Power identified matters at certain other power stations that the EPA might view as not in compliance with the SPCC and FRP requirements. Virginia Power reported these matters to the EPA and our plan for correcting them. The EPA has not assessed any penalties, 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. In August 1990, Dominion Transmission entered into a Consent Order and Agreement with the Commonwealth of Pennsylvania Department of Environmental Protection (DEP) in which Dominion Transmission agreed with the DEP's determination of certain violations of the Pennsylvania Solid Waste Management Act, the Pennsylvania Clean Streams Law and the rules and regulations promulgated thereunder. No civil penalties have been assessed. According to the Order and Agreement, Dominion Transmission continues to perform sampling, testing and analysis, and conducts a program of remediation at some of its Pennsylvania facilities. Dominion Transmission has recognized an estimated liability amounting to $6 million at December 31, 2000, for future costs expected to be incurred to remediate or mitigate hazardous substances at these sites and at facilities covered by the Order and Agreement. During 2000, Dominion Transmission paid a total of $380,000 related to a hydrocarbon spill in February 1998 at one of its facilities in Aliquippa, Beaver County, Pennsylvania. Dominion Transmission settled the matter by contributing $200,000 to the Penn's Corner Conservancy Charitable Trust and $80,000 to the Beaver County Conservation District, and paying $100,000 to the DEP for response costs. 19 During 2000, Virginia Power 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. Virginia Power also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. Virginia Power has 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 Virginia Power reached an agreement in principle, the terms of a final binding settlement are still being negotiated. See Note 22 to the Consolidated Financial Statements on page 61 of the 2000 Annual Report. Following the announcement of the merger, in April 1999, CNG and its directors were served with a Class Action Complaint, which sought, among other things, to compel CNG to sell the company for the highest value to CNG shareholders. Several additional Class Action Complaints, seeking essentially the same relief, have been combined with this action. CNG moved to dismiss, and on February 15, 2000, the plaintiffs took action for dismissal. A qui tam action (one in which the plaintiff sues for the government as well as for itself, and gets to keep part of the recovery) was brought by Jack Grynberg, an oil and gas entrepreneur, against a major part of the gas industry, including CNG and several of its subsidiaries. The complaint, which was filed on July 2, 1997, was under seal pending Department of Justice review. The Department of Justice declined to intervene and the seal was lifted in May 1999. CNG was served in the Western District of Louisiana on May 1, 1999. The suit alleges fraudulent mismeasurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. The cases have been removed to the Eastern District of Wyoming, where a motion to dismiss will be filed by the Company. A class action was filed by Quinque Operating Co. and others against approximately 300 defendants, including CNG and several of its subsidiaries, in Stevens County, Kansas. The complaint, which was served on CNG and its subsidiaries on September 24, 1999, alleged fraud, misrepresentation, conversion and assorted other claims, in the measurement and payment of gas royalties from privately held gas leases. The case has been remanded to Kansas state court by the federal judge overseeing the Grynberg case. The plaintiffs will seek class certification and expedited discovery in Kansas. The defendants in the case have filed a motion to keep the case in federal court. 20 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. EXECUTIVE OFFICERS OF THE REGISTRANT
Name and Age Business Experience Past Five Years ------------ ----------------------------------- Thos. E. Capps (65)......... Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from August 1, 2000 to date; Vice Chairman of the Board of Directors, President and Chief Executive Officer of Dominion 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; Chairman of the Board of Directors and Chief Executive Officer prior to September 1, 1995. Thomas N. Chewning (55)..... Executive Vice President and Chief Financial Officer of Dominion from May 1, 1999 to date; Chief Executive Officer of Dominion Energy from May 1, 1999 to January 28, 2000; Executive Vice President and Chief Financial Officer of Consolidated Natural Gas Company from January 28, 2000 to date; President and Chief Executive Officer of Dominion Energy from October 1, 1994 to May 1, 1999; Senior Vice President of Dominion prior to January 1, 1997. Thomas F. Farrell, II (46).. Executive Vice President of Dominion from March 1, 1999 to date; 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 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 and General Counsel of Dominion from January 1, 1997 to March 1, 1999; Vice President and General Counsel of Dominion from July 1, 1995 to January 1, 1997; Partner in the law firm of McGuire, Woods, Battle & Boothe LLP prior to July 1, 1995. James P. O'Hanlon (57)...... Executive Vice President of Dominion and President and Chief Operating Officer of Virginia Electric and Power Company from May 1, 1999 to date; Executive Vice President of Consolidated Natural Gas Company from January 28, 2000 to date; Chief Nuclear Officer of Virginia Electric and Power Company from May 1, 1999 to April 28, 2000; Senior Vice President-Nuclear of Virginia Electric and Power Company 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.
21
Name and Age Business Experience Past Five Years ------------ ----------------------------------- H. Patrick Riley (63)..... Executive Vice President of Dominion from January 28, 2000 to date; Executive Vice President of Consolidated Natural Gas Company from January 28, 2000 to date; President and Chief Executive Officer of Dominion Exploration and Production, Inc. from January 28, 2000 to date; President of CNG Producing Company prior to January 28, 2000. Edgar M. Roach, Jr. (52).. Executive Vice President of Dominion from September 15, 1997 to date and Chief Executive Officer of Virginia Electric and Power Company from May 1, 1999 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 L. Trueheart (49)... Group Vice President and Chief Administrative Officer of Dominion and Consolidated Natural Gas Company from June 1, 2000 to date; Group Vice President, Chief Administrative Officer, and Controller 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. Eva Teig Hardy (56)....... Senior Vice President-External Affairs & Corporate Communications of Dominion from May 1, 1999 to date; Senior Vice President-External Affairs & Corporate Communications of Virginia Electric and Power Company, September 1, 1997 to April 28, 2000; Vice President-External Affairs and Corporate Communications, June 1, 1997 to September 1, 1997; Vice President-Public Affairs of Virginia Electric and Power Company prior to June 1, 1997. G. Scott Hetzer (44)...... Senior Vice President and Treasurer of Dominion from May 1, 1999 to date; Senior Vice President and Treasurer of Virginia Electric and Power Company from January 28, 2000 to date; Senior Vice President and Treasurer of Consolidated Natural Gas Company from January 28, 2000 to date; Vice President and Treasurer of Dominion from October 1, 1997 to May 1, 1999; Managing Director of Wheat First Butcher Singer prior to October 1, 1997. James L. Sanderlin (59)... Senior Vice President-Law of Dominion from September 15, 1999 to date; Senior Vice President- Law of Consolidated Natural Gas Company from January 28, 2000 to date. Partner in the law firm of McGuire, Woods, Battle & Boothe LLP prior to September 15, 1999. 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.
22 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Dominion Resources common stock is listed on the New York Stock Exchange and at December 31, 2000 there were 188,737 common shareholders of record. Quarterly information concerning stock prices and dividends contained in Note 26 to the Consolidated Financial Statements on page 67 of the 2000 Annual Report for the fiscal year ended December 31, 2000, filed herein as Exhibit 13, is hereby incorporated herein by reference. ITEM 6. SELECTED FINANCIAL DATA This information contained under the caption "Selected Consolidated Financial Data" on page 69 of the 2000 Annual Report for the fiscal year ended December 31, 2000, filed herein as Exhibit 13, is hereby incorporated herein by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This information contained under the caption Management's Discussion and Analysis of Financial Condition and Results of Operations on pages 30 through 40 of the 2000 Annual Report for the fiscal year ended December 31, 2000, filed herein as Exhibit 13, is hereby incorporated herein by reference. In addition, see Schedule I--Condensed Financial Information to Registrant under Part IV, Item 14 for the separate, condensed financial statements and related notes for Dominion Resources, Inc. which contain information on certain restrictions in affect at December 31, 2000 on CNG's ability to make dividend payments. These restrictions did not affect the Company's ability to meet its cash obligations. Further as set out in Schedule I, this restriction has been eliminated. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK This information contained under the following captions: Market Rate Sensitive Instruments and Risk Management Interest Rate Risk Commodity Price Risk--Non-Trading Activities Commodity Price Risk--Trading Activities Equity Price Risk Risk Management Policies under Management's Discussion and Analysis of Financial Condition and Results of Operations on pages 39 and 40 of the 2000 Annual Report for the fiscal year ended December 31, 2000, filed herein as Exhibit 13, is hereby incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA This information contained in the Consolidated Financial Statements on pages 25 through 69 and related report thereon of Deloitte & Touche LLP, independent auditors, appearing on page 70 of the 2000 Annual Report for the fiscal year ended December 31, 2000, filed herein as Exhibit 13, is hereby incorporated herein by reference. In addition, see Schedule I--Condensed Financial Information of Registrant under Part IV, Item 14 for the separate, condensed financial statements and related notes, for Dominion Resources, Inc. which contain information on certain restrictions in affect at December 31, 2000 on CNG's ability to make dividend payments. These restrictions did not affect the Company's ability to meet its cash obligations. Further as set out in Schedule I, this restriction has been eliminated. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 23 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding the directors of Dominion contained in the 2001 Proxy Statement, under the heading The Board, File No. 1-8489, dated March 16, 2001 (the 2001 Proxy Statement), is incorporated herein by reference. The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the caption EXECUTIVE OFFICERS OF THE REGISTRANT. ITEM 11. EXECUTIVE COMPENSATION The information regarding executive compensation contained under the heading Executive Compensation and the information regarding director compensation contained under the heading The Board--Compensation and Other Programs in the 2001 Proxy Statement, is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information concerning stock ownership by directors and executive officers is contained under the heading The Board--Share Ownership Table in the 2001 Proxy Statement, is hereby incorporated herein by reference. There is no person known by Dominion to be the beneficial owner of more than five percent of Dominion common stock. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information concerning certain transactions with executive officers under the Stock Purchase and Loan Program contained under the heading Executive Compensation in the 2001 Proxy Statement is incorporated herein by reference. 24 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Certain documents are filed as part of this Form 10-K and are incorporated herein by reference and found on the pages noted. 1. Financial Statements
2000 Annual Report to Shareholders (Page) ------------ Consolidated Statements of Income for the years ended December 31, 2000, 1999 and 1998............................ 25 Consolidated Balance Sheets at December 31, 2000 and 1999.... 26-27 Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Comprehensive Income for the years ended December 31, 2000, 1999 and 1998................ 28 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998............................ 29 Notes to Consolidated Financial Statements................... 41-69 Independent Auditors' Report................................. 70 Report of Management's Responsibilities...................... 70 2. Financial Statement Schedules Page ------------ Independent Auditors' Report................................. 32 Schedule I--Condensed Financial Information of Registrant.... 33 Schedule II--Valuation and Qualifying Accounts............... 38
All other schedules are omitted because they are not applicable, or the required information is shown in the financial statements or the related notes. 3. Exhibits 2(i) -- Agreement, dated June 26, 1998, relating to the sale and purchase of East Midlands Electricity plc by PowerGen plc (Exhibit 2, Form 10-Q for the quarter ended June 30, 1998, File No. 1-8489, incorporated by reference). 2(ii) -- Amended and Restated Agreement and Plan of Merger, dated May 11, 1999 (Exhibit 2, Form S-4, Registration Statement, File No. 333-75699, as filed on May 20, 1999, incorporated by reference) and the Joinder Agreement, dated January 28, 2000 (Exhibit 1.2, Form 8-K, dated February 1, 2000, File No. 1-8489, incorporated by reference). 3(i) -- Articles of Incorporation as in effect August 9, 1999 (Exhibit 3(i), Form 10-Q for the quarter ended June 30, 1999, File No. 1-8489, incorporated by reference). 3(ii) -- Articles of Amendment establishing Series A Preferred Stock, effective March 12, 2001 (filed herewith). 3(iii) -- Bylaws as in effect on October 20, 2000 (Exhibit 3, Form 10-Q for the quarter ended September 30, 2000, File No. 1-8489, incorporated by reference). 4(i) -- See Exhibit 3(i) above.
25 4(ii) -- Indenture of Mortgage of Virginia Electric and Power 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); 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 23, 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(iii) -- 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). 4(iv) -- 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, dated May 1, 1999 (Exhibit 4.2, Form S-3, Registration Statement, File No. 333-7615, as filed on April 13, 1999, incorporated by reference). 4(v) -- 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(vi) -- Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and The Chase Manhattan Bank as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, 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).
26 4(vii) -- Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Chase Manhattan Bank as supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement, File No. 333-50653, as filed on April 21, 1998, incorporated by reference); Second and Third Supplemental Indentures, dated January 1, 2001, (Exhibits 4.6 and 4.13, Form 8-K, dated January 9, 2001, incorporated by reference). 4(viii) -- Consolidated Natural Gas Company Indentures, Supplemental Indentures and Securities Resolutions are listed below and incorporated by reference: The Chase Manhattan Bank (formerly Manufacturers Hanover Trust Company) Indenture dated as of May 1, 1971 (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012) Fifteenth Supplemental Indenture dated as of October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651) Seventeenth Supplemental Indenture dated as of August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167) Eighteenth Supplemental Indenture dated as of December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167) Nineteenth Supplemental Indenture dated as of January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference). Twentieth Supplemental Indenture dated as of March 19, 2001 (filed herewith). United States Trust Company of New York Indenture dated as of April 1, 1995 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8107) First Supplemental Indenture dated January 28, 2000 (Exhibit (4 A)(ii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference). Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2 to Form 8-A filed April 21, 1995 under File No. 1- 3196 and relating to the 7 3/8% Debentures Due April 1, 2005) Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2 to Form 8-A filed October 18, 1996 under file No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2026) Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2 to Form 8-A filed December 12, 1996 under file No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008) Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2 to Form 8-A filed December 12, 1997 under file No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027) Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2 to Form 8-A filed October 22, 1998 under file No. 1-3196 and relating to the 6% Debentures Due October 15, 2010) Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004).
27 4(ix) -- Senior Indenture, dated June 1, 2000, between Dominion and The Chase Manhattan Bank, as Trustee (Exhibit 4 (iii), Form S-3, Registration Statement, File No. 333-93187, incorporated by reference); First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K, dated June 21, 2000, File No. 1-8489, incorporated by reference); Second Supplemental Indenture, dated July 1, 2000 (Exhibit 4.2, Form 8-K, dated July 11, 2000, File No. 1-8489, incorporated by reference); Third Supplemental Indenture, dated July 1, 2000 (Exhibit 4.3, Form 8-K dated July 11, 2000, incorporated by reference); Fourth Supplemental Indenture and Fifth Supplemental Indenture dated September 1, 2000 (Exhibit 4.2, Form 8-K, dated September 8, 2000, incorporated by reference); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K, dated September 8, 2000, incorporated by reference); and Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K, dated October 11, 2000, incorporated by reference). Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K, dated January 23, 2001, incorporated by reference). 4(x) -- Dominion Resources 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% of Dominion Resources' total assets. 10(i) -- 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(v), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference). 10(ii) -- Credit Agreements, dated as of June 7, 1996, between The Chase Manhattan Bank (formerly Chemical Bank) and Virginia Electric and Power Company (Exhibit 10(i) and Exhibit 10(ii), Form 10-Q for the period ended June 30, 1996. File No. 1-2255, incorporated by reference) 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(iii) -- Inter-Company Credit Agreement, dated December 20, 1985, as modified on August 21, 1987, between Dominion Resources and Dominion Capital, Inc. (Exhibit 10(vi), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-8489, incorporated by reference). 10(iv) -- Inter-Company Credit Agreement, dated October 1, 1987 as amended and restated as of May 1, 1988 between Dominion Resources and Dominion Energy, Inc. (Exhibit 10(vii), Form 10- K for the fiscal year ended December 31, 1993, File No. 1- 8489, incorporated by reference). 10(v) -- Form of Amended and Restated Articles of Partnership in Commendam of Catalyst Old River Hydroelectric Limited Partnership, by and between Catalyst Vidalia Corporation and Dominion Capital, Inc. effective as of August 24, 1990 (Exhibit 10(xii) Form 10-K for the fiscal year ended December 31, 1990, File No. 1-8489, incorporated by reference). 10(vi) -- First Amendment of Trust Agreement of Dominion Resources Black Warrior Trust, dated June 27, 1994, among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and Nationsbank of Texas, N.A. (Exhibit 10(ii), Form 10-Q for the quarter ended June 30, 1994, File No. 1-8489, incorporated by reference).
28 10(vii) -- DRI Services Agreement, dated January 28, 2000, by and between Dominion Resources, Inc., Dominion Resources Services, Inc. and Consolidated Natural Gas Service Company, Inc. (Exhibit 10(viii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-8489, incorporated by reference). 10(viii) -- 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(ix) -- Support Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company dated 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(x) -- 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(xi)* -- Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective January 1, 1981 as amended and restated September 1, 1996 (Exhibit 10(iv), Form 10-Q for the quarter ended June 30, 1997, File No. 1-8489, incorporated by reference) and as amended June 20, 1997 and as amended March 3, 1998 (Exhibit 10(xxi), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference). 10(xii)* -- Arrangements with certain executive officers regarding additional credited years of service for retirement and retirement life insurance purposes (Exhibit 10(xxii), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference). 10(xiii)* -- Dominion Resources, Inc.'s Cash Incentive Plan as adopted December 20, 1991 (Exhibit 10(xxii), Form 10-K for the fiscal year ended December 31, 1991, File No. 1-8489, incorporated by reference). 10(xiv)* -- Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997 (Exhibit 99, Form S-8 Registration Statement, File No 333-25587, incorporated by reference) and as restated effective April 28, 2000 (Exhibit 99, Form S-8, Registration Statement, File No. 333-38396, incorporated by reference). 10(xv)* -- Form of Employment Continuity Agreement for certain officers of Dominion Resources (Exhibit 10(i), Form 10-Q for the quarter ended June 30, 1999, File No. 1-8489, incorporated by reference). 10(xvi)* -- Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as amended and restated September 1, 1996 (Exhibit 10(iii), Form 10-Q for the quarter ended June 30, 1997, File No. 1-8489, incorporated by reference). 10(xvii)* -- Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective January 1, 1991 as amended and restated September 1, 1996 (Exhibit 10(ii), Form 10-Q for the quarter ended June 30, 1997, File No. 1-8489, incorporated by reference). 10(xviii)* -- Dominion Resources, Inc. Executives' Deferred Compensation Plan, effective January 1, 1994 and as amended and restated January 1, 2001 (filed herewith).
29 10(xix)* -- Employment Agreement dated April 16, 1999 between Dominion Resources and Thos. E. Capps (Exhibit 10(ii), Form 10-Q for the quarter ended March 31, 1999, File No. 1-8489, incorporated by reference) and Form of Amendment (Exhibit 10(iii), Form 10-Q for the quarter ended June 30, 1999, File No. 1-8489, incorporated by reference). 10(xx)* -- Form of Employment Agreement between Dominion Resources certain executive officers including Thomas N. Chewning (Exhibit 10 (xxx), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference and Exhibit 10(ii), Form 10-Q for the quarter ended March 31, 1998, File No. 1-8489, incorporated by reference) and Form of Amendment for Thomas N. Chewning (Exhibit 10(iii), Form 10-Q for the quarter ended June 30, 1999, File No. 1-8489, incorporated by reference). 10(xxi)* -- Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, effective April 23, 1996 (Exhibit 10, Form 10-Q for the quarter ended March 31, 1996, File No. 1-8489, incorporated by reference). 10(xxii)* -- Dominion Resources, Inc. Directors Stock Compensation Plan, effective April 9, 1998 (Exhibit 99, Form S-8 Registration Statement, File No. 333-49725, incorporated by reference). 10(xxiii)* -- Dominion Resources, Inc. Directors Deferred Cash Compensation Plan, effective December 21, 1998 (Exhibit 99, Form S-8 Registration Statement, File No. 333-69305, incorporated by reference). 10(xxiv)* -- Employment Agreement, dated September 12, 1997 between Dominion Resources and Edgar M. Roach, Jr. (Exhibit 10(xxxiv), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference). 10(xxv)* -- Employment Agreement dated September 12, 1997 between Dominion Resources and Thomas F. Farrell, II (Exhibit 10(xxxiii), Form 10-K for the fiscal year ended December 31, 1998, File No. 1-8489, incorporated by reference) and Form of Amendment (Exhibit 10 (iii), Form 10-Q for the quarter ended June 30, 1999, File No. 1-8489, incorporated by reference). 10(xxvi)* -- Form of Reimbursement Agreement between certain executive officers and Dominion Resources (Exhibit 10(xxvii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference). 10(xxvii)* -- 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(xxviii) -- Purchase and Sale Agreement, dated August 7, 2000, by and among Northeast Nuclear Energy Company, et al and Dominion Resources, Inc. (Exhibit 10(iii), Form 10-Q for the quarter ended June 30, 2000, File No. 1-8489, incorporated by reference). 10(xxix) -- Stock Purchase Agreement, dated May 8, 2000, By and Between AGL Resources, Inc. as Buyer and Consolidated Natural Gas Company, as Seller of Virginia Natural Gas, Inc. (Exhibit 10(iii), Form 10-Q for the quarter ended June 30, 2000, File No. 1-8489, incorporated by reference).
30 11 -- Computation of Earnings Per Share of Common Stock Assuming Full Dilution (filed herewith). 13 -- Portions of the 2000 Annual Report to Shareholders for the fiscal year ended December 31, 2000 (filed herewith). 18(i) -- Letter re: Change in Accounting Principles (Exhibit 18, Form 10-Q for the quarter ended March 31, 2000, File No. 1-8489, incorporated by reference). 18(ii) -- Letter re: Change in Accounting Principles (Exhibit 18, Form 10-Q for the quarter ended September 30, 2000, File No. 1-8489, incorporated by reference). 21 -- Subsidiaries of the Registrant (filed herewith). 23 -- Consent of Deloitte & Touche LLP (filed herewith).
- -------- * Indicates management contract or compensatory plan or arrangement. (b) Reports on Form 8-K 1. Dominion filed a report on Form 8-K, dated November 16, 2000, relating to Dominion's agreement in principle with the Environmental Protection Agency regarding environmental improvements at coal-fired generating stations in Virginia and West Virginia. 2. Dominion filed a report on Form 8-K, dated November 22, 2000, relating to the Dominion's Purchase Agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated (Merrill Lynch and Co.) to sell 6,000,000 shares of common stock to Merrill Lynch & Co. 3. Dominion filed a report on Form 8-K, dated January 9, 2001, relating to (i) the Dominion and Dominion Resources Capital Trust III underwriting agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. for the sale of 250,000 8.4% Capital Securities and (ii) the Dominion and Dominion Resources Capital Trust II underwriting agreement with Merrill Lynch for the sale of 12,000,000 8.4% Trust Preferred Securities. 4. Dominion filed a report on Form 8-K, dated January 23, 2001, relating to the Dominion's underwriting agreement with Lehman Brothers Inc. for the sale of $1,000,000,000 2001 Series A 6% Senior Notes Due 2003. 31 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Dominion Resources, Inc. Richmond, Virginia We have audited the consolidated financial statements of Dominion Resources, Inc. and subsidiaries 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, 2001; such consolidated financial statements and report are included in your 2000 Annual Report to Shareholders and are incorporated herein by reference. Our audits also included the consolidated financial statement schedules of Dominion Resources, Inc. and subsidiaries, listed in Item 14. These consolidated financial statement schedules are 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 schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. /s/ DELOITTE & TOUCHE LLP Richmond, Virginia January 25, 2001 32 DOMINION RESOURCES, INC. Schedule I--Condensed Financial Information of Registrant Condensed Statements of Income
Years Ended December 31, ---------------- 2000 1999 1998 ---- ---- ---- (millions) Operating revenue and income.................................. $ 3 $ $ Operating expenses............................................ 31 37 36 ---- ---- ---- Loss from operations.......................................... (28) (37) (36) ---- ---- ---- Other income.................................................. 47 47 35 ---- ---- ---- Income (loss) before interest and income taxes................ 19 10 (1) Interest charges.............................................. 350 44 35 ---- ---- ---- Loss before income taxes...................................... (331) (34) (36) Income tax benefit (expense).................................. 129 17 (16) Equity in undistributed earnings of subsidiaries.............. 638 314 600 ---- ---- ---- Net income $436 $297 $548 ==== ==== ====
The accompanying notes are an integral part of the Condensed Financial Statements. 33 DOMINION RESOURCES, INC. Schedule I--Condensed Financial Information of Registrant Condensed Balance Sheets
At December 31, At December 31, 2000 1999 --------------- --------------- (millions) Assets Current assets: Cash and cash equivalents..................... $ 51 $ 28 Accounts receivable........................... 7 36 Other......................................... 33 15 ------- ------ Total current assets.......................... 91 79 ------- ------ Investments: Investment in subsidiaries.................... 10,881 5,115 Advances to affiliates........................ 951 340 Other 3 17 ------- ------ 11,835 5,472 ------- ------ Property, plant and equipment: Nonutility property........................... 35 42 Accumulated depreciation and amortization..... (13) (16) ------- ------ 22 26 ------- ------ Deferred charges and other assets.............. 3 37 ------- ------ Total assets.................................... $11,951 $5,614 ======= ====== Liabilities and Stockholders' Equity Current liabilities: Short-term debt............................... $ 1,306 $ 197 Accounts payable.............................. 6 9 Accrued interest.............................. 63 2 Accrued taxes................................. 71 20 Other......................................... 27 24 ------- ------ Total current liabilities..................... 1,473 252 ------- ------ Long-term debt................................. 3,438 576 ------- ------ Deferred credits and other liabilities......... 48 12 ------- ------ Stockholders' equity: Common stock.................................. 5,979 3,561 Other paid-in capital......................... 16 16 Accumulated other comprehensive income........ (31) (15) Retained earnings............................. 1,028 1,212 ------- ------ 6,992 4,774 ------- ------ Total liabilities and stockholders' equity..... $11,951 $5,614 ======= ======
The accompanying notes are an integral part of the Condensed Financial Statements. 34 DOMINION RESOURCES, INC. Schedule I--Condensed Financial Information of Registrant Condensed Statements of Cash Flows
Years Ended December 31, ---------------------------- 2000 1999 1998 --------- -------- -------- (millions) Net cash flows to operating activities........... $ (30) $ (66) $ (30) Cash flows from(to) financing activities: Issuance of common stock........................ 532 354 Repurchase of common stock...................... (1,641) (372) (99) (Repayment) issuance of long-term debt.......... 2,863 493 (401) (Repayment) issuance of short-term debt......... 1,108 Dividend payments............................... (615) (493) (503) Other........................................... 1 4 --------- ------- -------- Net cash flows from(to) financing activities.... 2,247 (371) (645) Cash flows from(to) investing activities: Purchase of Consolidated Natural Gas Company.... (2,869) Investment in affiliates........................ (71) (216) (413) Inter-company advances.......................... (611) 107 (114) Dividends received from subsidiaries............ 1,340 519 1,213 Other........................................... 17 (16) 38 --------- ------- -------- Net cash flows from(to) investing activities.... (2,194) 394 724 Increase (decrease) in cash and cash equivalents..................................... 23 (43) 49 Cash and cash equivalents at beginning of year... 28 71 22 --------- ------- -------- Cash and cash equivalents at end of year......... $ 51 $ 28 $ 71 ========= ======= ======== Supplemental cash flow information: Non-cash transaction from investing and financing activities: Common stock issuance--acquisition of Consolidated Natural Gas Company............... $ 3,527
The accompanying notes are an integral part of the Condensed Financial Statements. 35 DOMINION RESOURCES, INC. Schedule I--Condensed Financial Information of Registrant Notes to Condensed Financial Statements Note 1. Basis of Presentation Pursuant to rules and regulations of the Securities and Exchange Commission, the unconsolidated condensed financial statements of Dominion Resources, Inc. (the Company) do not reflect all of the information and notes normally included with financial statements prepared in accordance with generally accepted accounting principles. Therefore these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the fiscal 2000 Annual Report to Shareholders (2000 Annual Report) as referenced in Form 10-K, Part II, Item 8. Accounting for subsidiaries--The Company has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements. Income Taxes--The unconsolidated income tax expense or benefit computed for the Company in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, reflects the tax assets and liabilities of the Company on a stand alone basis and the effect of filing a consolidated U.S. tax return with its subsidiaries. Note 2. Long-term debt
At December 31, ----------------------------------------- 2000 1999 -------------------- -------------------- Interest Interest Balance Rate(/3/) Balance Rate(/3/) ---------- --------- ---------- --------- (millions) (millions) Senior notes: 2000 Series C, due 2003............ $ 400 7.6 2000 Series B, due 2005............ 700 7.6 2000 Various series, due 2010- 2014.............................. 1,400 7.2-8.1 Mandatory convertibles, convert 2004............................... 412 8.1 Commercial paper(/1/)............... 250 $300 Junior subordinated debentures, due 2027............................... 258 7.8 258 7.8 Bank loans, due 2004-2008(/2/)...... 18 7.3 18 5.8 ------ ------- ---- --- Total long-term debt................ $3,438 $576 ====== ====
- -------- (/1/)The weighted average interest rate for the years 2000 and 1999 were 6.5% and 5.4%, respectively. (/2/)Real estate at the Company is pledged as collateral. (/3/)Interest rates are rounded to the nearest one-tenth of one-percent and consist of weighted average interest rates for variable rate debt. Maturities (including sinking fund obligations) through 2005 are as follows (millions): 2003-$400; 2004-$431; 2005-$700. In January 2001, the Company issued $1.0 billion of 2-year fixed rate 6% notes, $309 million in aggregate principal of 8.4% junior subordinated debentures due 2041 and $258 million in aggregate principal of 8.4% junior subordinated debentures due 2031. See Notes 16 and 17 to the 2000 Annual Report. 36 Note 3. Guarantees The Company has issued guarantees to various third parties in relation to the payment of obligations by certain of its subsidiaries and officers. At December 31, 2000, the Company had issued $1.8 billion of guarantees, and the subsidiaries' debt subject to such guarantees totaled $1.2 billion. Note 4. Dividends received from consolidated subsidiaries The Company received dividends from its consolidated subsidiaries in the amounts of $1.3 billion, $519 million and $1.2 billion for the years 2000, 1999, and 1998, respectively. Cash dividends in 2000 included approximately $770 million reflecting proceeds from divestitures at certain of the Company's subsidiaries (see Note 5 to the 2000 Annual Report). Cash dividends in 1998 included approximately $720 million reflecting a portion of the proceeds from the sale of East Midlands Electricity plc by a subsidiary. Consolidated Natural Gas Company (CNG), a consolidated subsidiary of the Company, has indentures related to its long-term debt, one of which contained restrictions on dividend payments at December 31, 2000. As of that date, $19 million of CNG's consolidated retained earnings were free from such restriction. In March 2001, CNG requested and obtained the consent of debt holders to amend the indenture to eliminate certain provisions of the indenture, including such restriction. CNG received an order from the Securities and Exchange Commission on March 19, 2001, approving the amendment of the indenture. 37 DOMINION RESOURCES, INC. Schedule II--Valuation and Qualifying Accounts
Column A Column B Column C Column D Column E -------- ---------- ------------------ ---------- ---------- Additions ------------------ Balance at Charged Charged Balance at beginning to to other end of Description of period expense 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 36 (d) 71 $ 1 39 (a) 67 Allowance for loan losses................. 1998 18 30 1 (a) 47 1999 47 11 11 (a) 47 2000 47 35 21 (a) 61 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 12 (d) 9 (c) 3 Liabilities for restructuring actvities ....................... 1998 1999 2000 92 55 (c) 37
- -------- (a) Represents net amounts charged off as uncollectible. (b) Amounts are net of adjustments to allowance reflecting changes in estimates. (c) Represents payments for workforce reductions and/or restructuring liabilities. (d) Includes balance of acquired company at date of acquisition. 38 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. Dominion Resources, Inc. /s/ Thomas E. Capps By: _________________________________ (Thos E. Capps, Chairman of the Board of Directors, President and Chief Executive Officer) Date: March 20, 2001 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 and on the 20th day of March, 2001.
Signature Title --------- ----- /s/ Thos. E. Capps Chairman of the Board of Directors, ________________________________________________ President and Chief Executive Thos. E. Capps Officer /s/ William S. Barrack, Jr. Director ________________________________________________ William S. Barrack, Jr. /s/ George A. Davidson, Jr. Director, Former Chairman of the ________________________________________________ Board of Directors George A. Davidson, Jr. /s/ Raymond E. Galvin Director ________________________________________________ Raymond E. Galvin /s/ John W. Harris Director ________________________________________________ John W. Harris /s/ Benjamin J. Lambert, III Director ________________________________________________ Benjamin J. Lambert, III /s/ Richard L. Leatherwood Director ________________________________________________ Richard L. Leatherwood /s/ Paul E. Lego Director ________________________________________________ Paul E. Lego /s/ Margaret A. McKenna Director ________________________________________________ Margaret A. McKenna
39
Signature Title --------- ----- /s/ Steven A. Minter Director ________________________________________________ Steven A. Minter /s/ K. A. Randall Director ________________________________________________ K. A. Randall /s/ Frank S. Royal Director ________________________________________________ Frank S. Royal /s/ S. Dallas Simmons Director ________________________________________________ S. Dallas Simmons /s/ Robert H. Spilman Director ________________________________________________ Robert H. Spilman /s/ David A. Wollard Director ________________________________________________ David A. Wollard /s/ Thomas N. Chewning Executive Vice President ________________________________________________ and Chief Financial Thomas N. Chewning Officer /s/ Steven A. Rogers Vice President, Controller ________________________________________________ and Principal Accounting Steven A. Rogers Officer
40 DOMINION RESOURCES, INC. PORTIONS OF THE 2000 ANNUAL REPORT TO SHAREHOLDERS (Incorporated by Reference) 41 EX-4.8 2 0002.txt TWENTIETH SUPPLEMENTAL INDENTURE TWENTIETH SUPPLEMENTAL INDENTURE (the "Twentieth Supplemental Indenture"), dated as of March 19, 2001 between Consolidated Natural Gas Company, a Delaware corporation (including its predecessors by merger, the "Company"), and The Chase Manhattan Bank, a New York banking corporation, formerly known as Chemical Bank, successor by merger to Manufacturers Hanover Trust Company, as Trustee (the "Trustee"), to the Indenture between the Company and the Trustee, dated as of May 1, 1971, as amended or supplemented from time to time (the "Indenture"). WITNESSETH: WHEREAS, the Company has requested the Trustee to enter into this Twentieth Supplemental Indenture for the purpose of amending and modifying the Indenture in accordance with Section 14.02 of the Indenture; and WHEREAS, consents of the requisite holders of the Debentures to the execution of this Twentieth Supplemental Indenture, together with an officers' certificate and opinion of counsel, all in accordance with Section 14.03 of the Indenture, have been delivered to the Trustee. NOW, THEREFORE, intending to be legally bound hereby, the parties hereto agree as follows: ARTICLE I AMENDMENTS TO THE INDENTURE Section 1.1. Sections 6.05, 6.06, 6.07, 6.08, 6.09 and 6.10 of the Indenture are deleted and shall have no further force and effect. Section 1.2 Section 4.01 of each of the Seventeenth and Eighteenth Supplemental Indentures is deleted and shall have no further force and effect. Section 1.3. A new Section 6.15 is added to the Indenture, reading as follows: SECTION 6.15. The Company shall perform, observe and comply with all the covenants and restrictions of the Indenture, dated as of April 1, 1995, between the Company and United States Trust Company of New York, as Trustee, as amended and supplemented from time to time (the "1995 Indenture"); provided, that no amendment requiring consent of the holders of debt securities under the 1995 Indenture shall apply to the Indenture unless such amendment shall have been approved and consented to in accordance with the procedures set forth in Article Fourteen of this Indenture. Section 1.4. No additional Debentures may be issued under the Indenture. ARTICLE II EFFECTIVE TIME Section 2.1 This Twentieth Supplemental Indenture shall become effective immediately upon its execution by the parties hereto and without any further action by any person as of the date hereof. ARTICLE III MISCELLANEOUS PROVISIONS Section 3.1 The Indenture, as amended and modified by this Twentieth Supplemental Indenture, is in all respects ratified and confirmed; this Twentieth Supplemental Indenture shall be deemed part of the Indenture in the manner and to the extent herein and therein provided; and all the terms, conditions, and provisions of the Indenture shall remain in full force and effect, as amended and modified hereby. Section 3.2 This Twentieth Supplemental Indenture shall be deemed to be a contract made under the laws of the State of New York, and for all purposes shall be construed in accordance therewith. Section 3.3 The recitals herein contained are made by the Company and not by the Trustee, and the Trustee assumes no responsibility for the correctness thereof. The Trustee makes no representation as to the validity or sufficiency of this Twentieth Supplemental Indenture. Section 3.4 This Twentieth Supplemental Indenture may be executed in any number of counterparts and by different parties thereto on separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute but one and the same agreement. Section 3.5 Capitalized terms used herein without definition have the meanings assigned such terms in the Indenture. IN WITNESS WHEREOF, the parties hereto have caused this Twentieth Supplemental Indenture to be duly executed and their respective corporate seals to be hereunto affixed and attested, all as of the date hereof. CONSOLIDATED NATURAL GAS COMPANY By: /s/ G. Scott Hetzer -------------------------------------------- Name: G. Scott Hetzer Title: Senior Vice President and Treasurer Attest: By: /s/ J. P. Carney -------------------------------- Name: J. P. Carney Title: Assistant Treasurer THE CHASE MANHATTAN BANK, as Trustee By: /s/ Natalia Rodriguez ------------------------------------------ Name: Natalia Rodriguez Title: Assistant Vice President Attest: By: /s/ Diane Darconte --------------------- Name: Diane Darconte Title: Trust Officer EX-10.18 3 0003.txt EXECUTIVE DEFERRED COMPENSATION PLAN Exhibit 10(xviii) DOMINION RESOURCES, INC. EXECUTIVES' DEFERRED COMPENSATION PLAN AMENDED AND RESTATED Effective January 1, 2001 For the Executives of: Dominion Resources, Inc. And Affiliates TABLE OF CONTENTS
Section Page - ------- ---- 1. DEFINITIONS............................................................ 1 2. PURPOSE................................................................ 4 3. PARTICIPATION.......................................................... 4 4. DEFERRAL ELECTION...................................................... 5 5. EFFECT OF NO ELECTION.................................................. 6 6. FORMER CNG PLANS....................................................... 6 7. DEFERRED STOCK OPTION BENEFIT.......................................... 7 8. MATCH CONTRIBUTIONS.................................................... 7 9. INVESTMENT FUNDS....................................................... 8 10. DISTRIBUTIONS.......................................................... 9 11. HARDSHIP DISTRIBUTIONS................................................. 10 12. COMPANY'S OBLIGATION................................................... 11 13. CONTROL BY PARTICIPANT................................................. 12 14. CLAIMS AGAINST PARTICIPANT'S BENEFIT................................... 12 15. AMENDMENT OR TERMINATION............................................... 12 16. ADMINISTRATION......................................................... 12 17. NOTICES................................................................ 13 18. WAIVER................................................................. 13 19. CONSTRUCTION........................................................... 13
i DOMINION RESOURCES, INC. EXECUTIVES' DEFERRED COMPENSATION PLAN 1. DEFINITIONS. The following definitions apply to this Plan and to any ----------- related documents. (a) Accounts means, collectively, a Participant's Deferral Account, Match -------- Account, and Deferred Stock Option Account, if any. (b) Administrator means Dominion Resources Services, Inc. ------------- (c) Beneficiary or Beneficiaries means a person or persons or other entity that ----------- ------------- a Participant designates on a Beneficiary Designation Form to receive Benefit payments pursuant to Plan Section 9(i). If a Participant does not execute a valid Beneficiary Designation Form, or if the designated Beneficiary or Beneficiaries fail to survive the Participant or otherwise fail to take the Benefit, the Participant's Beneficiary or Beneficiaries shall be the first of the following persons who survive the Participant: a Participant's spouse (the person legally married to the Participant when the Participant dies); the Participant's children in equal shares. If none of these persons survive the Participant, the Beneficiary shall be the Participant's estate. (d) Beneficiary Designation Form means the form that a Participant uses to name ---------------------------- the Participant's Beneficiary or Beneficiaries. (e) Benefit means collectively, a Participant's Deferred Benefit, Match ------- Benefit, and Deferred Stock Option Benefit, if any. (f) Board means the Board of Directors of DRI. ----- (g) Change of Control means the occurrence of any of the following events: ----------------- (i) any person, including a "group" as defined in Section 13(d)(3) of Securities Exchange Act of 1934, as amended, becomes the owner or beneficial owner of DRI securities having 20% or more of the combined voting power of the then outstanding DRI securities that may be cast for the election of DRI's directors (other than as a result of an issuance of securities initiated by DRI, or open market purchases approved by the Board, as long as the majority of the Board approving the purchases is also the majority at the time the purchases are made); (ii) as the direct or indirect result of, or in connection with, a cash tender or exchange offer, a merger or other business combination, a sale of assets, a contested election, or any combination of these transactions, the persons who were directors of DRI before such transactions cease to constitute a majority of 1 the Board, or any successor's board, within two years of the last of such transactions; or (iii) with respect to a particular Participant, an event occurs with respect to the Participant's employer such that, after the event, the Participant's employer is no longer a Dominion Company. (h) Code means the Internal Revenue Code of 1986, as amended. ---- (i) Committee means the Organization, Compensation and Nominating Committee of --------- the Board. (j) Company means DRI and any Dominion Company that is designated by the ------- Administrator as covered by this Plan, and any successor business by merger, purchase, or otherwise that maintains the Plan. (k) Compensation means a Participant's base salary, cash incentive pay and ------------ other cash compensation from the Company, including annual bonuses, pre- scheduled one-time performance-based payments, and gains from stock option grants. Compensation does not include stock, stock options or spot awards. The Administrator may determine whether to include or exclude an item of income from Compensation. (l) Deferral means the amount of Compensation that a Participant has elected to -------- defer under a Deferral Election Form. (m) Deferral Account means a bookkeeping record established for each ---------------- Participant who is eligible to receive a Deferred Benefit. A Deferral Account shall be established only for purposes of measuring a Deferred Benefit and not to segregate assets or to identify assets that may be used to satisfy a Deferred Benefit. A Deferral Account shall be credited with that amount of a Participant's Compensation deferred according to a Participant's Deferral Election Form. A Deferral Account also shall be credited periodically with deemed investment gain or loss under Plan Section 8. (n) Deferral Election Form means the form that a Participant uses to elect to ---------------------- defer Compensation pursuant to Plan Section 4. (o) Deferred Benefit means the benefit available to a Participant who has ---------------- executed a valid Deferral Election Form. (p) Deferred Stock Option Account means a bookkeeping record established for ----------------------------- each Participant who has made an election to defer the DRI Stock to be received under an exercise of a nonstatutory stock option granted under the Dominion Resources, Inc. Incentive Compensation Plan and the Dominion Resources, Inc. Leadership Stock Option Plan. The account shall be charged or credited with net earnings, gains, losses and expenses, as well as any appreciation or depreciation 2 in market value during each Plan Year for the deemed investment in the DRI Stock. The Administrator may charge or credit such earnings, gains, losses, appreciation and depreciation based on the actual investment performance of the DRI Stock that it has deposited into the trust. (q) Deferred Stock Option Benefit means the portion of a Participant's Benefit ----------------------------- from the Participant's Deferred Stock Option Account. (r) Disability or Disabled means, with respect to a Participant, that the ---------- -------- Participant is entitled to benefits under the long-term disability plan of the Company. (s) Distribution Election Form means a form that a Participant uses to -------------------------- establish the duration of the deferral of Compensation and the frequency of payments of a Benefit. If a Participant does not execute a valid Distribution Election Form, the distribution of a Benefit shall be governed by Plan Section 9. (t) Dominion Company means Consolidated Natural Gas, Inc., Virginia Power, ---------------- Dominion Capital, Inc., Dominion Energy, Inc., Dominion Resources Services, Inc., or another corporation in which DRI owns stock possessing at least 50 % of the combined voting power of all classes of stock or which is in a chain of corporations with DRI in which stock possessing at least 50% of the combined voting power of all classes of stock is owned by one or more other corporations in the chain. (u) DRI means Dominion Resources, Inc. --- (v) DRI Stock means the common stock, no par value, of DRI. --------- (w) DRI Stock Fund means an Investment Fund in which the deemed investment is -------------- DRI Stock. (x) Election Date means the date by which an Executive must submit a valid ------------- Deferral Election Form for regular Compensation. For each Plan Year, the Election Date shall be January 1 unless the Administrator sets an earlier Election Date or as provided in Plan Section 4(b) or 4(c). (y) Executive means an individual who is employed by the Company and who (i) is --------- an executive in salary grades A through G, (ii) has Compensation in excess of the dollar limit for the Plan Year under Code section 401(a)(17), or (iii) has reached the age of 50 and who has a base salary of at least $100,000. (z) Investment Fund means one or more deemed investment alternatives offered to --------------- Participants from time to time. The Company may compute deemed investment gain or loss under the Investment Funds based on the actual investment performance of assets that it has deposited in a grantor trust (as described in Plan Section 11). The DRI Stock Fund shall be one of the Investment Funds. 3 (aa) Match Account means an Account that holds the matching contributions made ------------- by the Company under Plan Section 8. (bb) Match Benefit means the portion of a Participant's Benefit from the ------------- Participant's Match Account. (cc) Participant means an individual presently or formerly employed by the ----------- Company who meets one or more of the requirements of Plan Section 3(a). (dd) Plan means the Dominion Resources, Inc. Executives' Deferred Compensation ---- Plan. (ee) Plan Year means a calendar year. --------- (ff) Terminate or Termination, with respect to a Participant, means the --------- ----------- cessation of the Participant's employment with the Company on account of death, Disability, severance or any other reason. 2. PURPOSE. The Plan is intended to benefit a "select group of management or ------- highly compensated employees," as that term is used under Title I of the Employee Retirement Income Security Act of 1974, as amended. The Plan is intended to permit Executives to defer their Compensation, and for related purposes. 3. PARTICIPATION. ------------- (a) An individual presently or formerly employed by the Company is a Participant if he or she is: (i) With respect to any Plan Year, an Executive who executes a valid Deferral Election Form for that Plan Year as provided in Plan Section 3(b); (ii) An individual who has a Deferred Stock Option Account due to an election to defer DRI Stock; (iii) An individual who is eligible for a Match under Plan Section 8; (iv) An individual who had a benefit entitlement under Section 4.1.(b) of the CNG ERISA Excess Plan as of December 31, 2000; or (v) An individual who had a benefit entitlement under Section 5 of the Consolidated Natural Gas Company Executive Incentive Deferral Plan as of December 31, 2000. (b) An Executive may become a Participant for any Plan Year by filing a valid Deferral Election Form according to Plan Section 4 on or before the Election Date for that Plan Year, or by filing an election to defer DRI Stock pursuant to the Dominion Resources, Inc. Incentive Compensation Plan, the Dominion 4 Resources, Inc. Leadership Stock Option Plan or any other plan designated by the Administrator. (c) An individual remains a Participant as long as the Participant is entitled to a Benefit under the Plan. An individual who is a Participant under Section 3(a)(iv) or (v) and who is not an Executive may direct deemed investments pursuant to Section 9 but may not make a Deferral election under Section 4. 4. DEFERRAL ELECTION. An Executive may elect on or before the Election Date to ----------------- defer receipt of a portion of the Executive's Compensation for the Plan Year. Except as provided in Plan Section 4(a), an Executive may elect a deferral for any Plan Year only if he or she is an Executive on the Election Date for that Plan Year. The following provisions apply to deferral elections: (a) A Participant may defer up to 50% of the Participant's base salary and up to 80% of the Participant's annual cash incentive award, long-term cash incentive payments and pre-scheduled one-time cash payments. Compensation for deferrals under the Dominion Resources, Inc. Employee Savings Plan shall be based on a Participant's Compensation after any deferrals made under this Plan. (b) A Participant may defer up to 90% of the Participant's gains on stock acquired by exercise of an option under the Dominion Resources, Inc. Incentive Compensation Plan or the Dominion Resources, Inc. Leadership Stock Option Plan. For purposes of deferral of stock option gains, the Election Date shall be the date that is six months before the Participant exercises the option. Procedures for deferring stock option gains shall be established under the Dominion Resources, Inc. Incentive Compensation Plan and the Dominion Resources, Inc. Leadership Stock Option Plan. (c) Before each Plan Year's Election Date, each Executive shall be provided with a Deferral Election Form. Except as provided below, a deferral election shall be valid only when the Deferral Election Form is completed, signed by the electing Executive, and received by the Administrator on or before the Election Date for that Plan Year. In the year in which an Executive is first promoted to a salary grade between A through G, the Executive may make a deferral election by completing a Deferral Election Form within 30 days of the promotion. The deferral election will be effective for periods after the Administrator receives it. (d) An Executive must complete an Investment Election Form for all amounts in the Executive's Deferral Account. The Compensation deferred under a Deferral Election Form shall be allocated among available Investment Funds in percentages as specified on the investment election form. (e) An Executive must complete a Distribution Election Form for the distribution of the Executive's Deferral Account. 5 (f) The Administrator may reject any Deferral Election Form or any Distribution Election Form or both that does not conform to the provisions of the Plan. The Administrator may modify any Distribution Election Form at any time to the extent necessary to comply with any federal securities laws or regulations. The Administrator's rejection or modification must be made on a uniform basis with respect to similarly situated Executives. If the Administrator rejects a Deferral Election Form, the Executive shall be paid the amounts the Executive would have been entitled to receive if the Executive had not submitted the rejected Deferral Election Form. (g) An Executive may not revoke a Deferral Election Form after the Plan Year begins, except that an Executive may revoke a Deferral Election Form within 30 days following a Change of Control. Any revocation before the beginning of the Plan Year or within 30 days following a Change of Control has the same effect as a failure to submit a Deferral Election Form. Any writing signed by an Executive expressing an intention to revoke the Executive's Deferral Election Form and delivered to the Administrator before the close of business on the relevant Election Date shall be a revocation. (h) Subject to the distribution restrictions of Plan Section 9, an Executive may revoke an existing Distribution Election Form at any time by submitting a new Distribution Election Form. 5. EFFECT OF NO ELECTION. Except as provided in Plan Section 4(c), an Executive --------------------- who has not submitted a valid Deferral Election Form to the Administrator on or before the relevant Election Date may not defer any part of the Executive's Compensation for the Plan Year. The Deferred Benefit of an Executive who submits a valid Deferral Election Form but fails to submit a valid Distribution Election Form (either as to the form or commencement of payment) before the relevant Election Date shall be distributed in a lump sum on or before the February 28 following the calendar year of the Executive's Termination. 6. FORMER CNG PLANS. ---------------- (a) The Plan has assumed a portion of the obligations and liabilities of the Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural Gas Company and its Participating Subsidiaries Who are Not Represented by a Recognized Union ("CNG ERISA Excess Plan") with respect to Participants in the Plan. The portion assumed by the Plan is the liabilities related to "Matching Contributions" under the "Thrift Plan" (as those terms are defined in the CNG ERISA Excess Plan) and related gains and losses as of December 31, 2000. A Participant's Benefit as of January 1, 2001 shall include the Participant's account under the CNG ERISA Excess Plan as of December 31, 2000. The payment of a Participant's Benefit from this Plan shall be in complete satisfaction of the Participant's benefits under Section 4.1.(b) of the CNG ERISA Excess Plan. A Participant's Investment Election Form, Distribution Election Form and 6 Beneficiary Election Form shall apply to the portion of the Participant's Benefit from the CNG ERISA Excess Plan. (b) The Plan has assumed all of the obligations and liabilities of the Consolidated Natural Gas Company Executive Incentive Deferral Plan ("CNG Deferral Plan") with respect to Participants in the Plan. The liabilities assumed by the Plan are the liabilities of the CNG Deferral Plan as of December 31, 2000 equal to the sum of all Participants' balances as of December 31, 2000 in the CNG Deferral Plan. The Participant's balance in the CNG Deferral Plan shall be part of the Participant's Benefit as of January 1, 2001. A Participant's Benefit as of January 1, 2001 shall include the Participant's account under the CNG Deferral Plan as of December 31, 2000. The payment of a Participant's Benefit from this Plan shall be in complete satisfaction of the Participant's benefits under Section 5 of the CNG Deferral Plan. A Participant's Investment Election Form, Distribution Election Form and Beneficiary Election Form shall apply to the portion of the Participant's Benefit from the CNG Deferral Plan. 7. DEFERRED STOCK OPTION BENEFIT. A Participant's Deferred Stock Option Benefit ----------------------------- shall remain deemed invested in DRI Stock until distribution. Such Participant's Distribution Election Form and Beneficiary Election Form shall apply to the Participant's Deferred Stock Option Benefit. If the Company has delivered shares of DRI Stock to a trust to satisfy the Deferred Stock Option Benefit, payment of the Deferred Stock Option Benefit shall be tracked as stock and made in shares of DRI Stock from the trust. If the Company has not delivered shares of DRI Stock to a trust, the Company shall make payment of the Deferred Stock Option Benefit in DRI Stock through the Dominion Resources, Inc. Incentive Compensation Plan and the Dominion Resources, Inc. Leadership Stock Option Plan. 8. MATCH CONTRIBUTIONS. ------------------- (a) With respect to each Plan Year, the Company shall credit a Match (as defined below) to the Match Account of each eligible Participant. To be eligible for a Match, a Participant must meet all of the following criteria: (i) be employed on December 31 or have Terminated during the Plan Year due to retirement or early retirement (as defined by the Dominion Savings Plan), death or Disability; (ii) have made salary deferrals to the Dominion Savings Plan for the Plan Year; and (iii) have base salary for the Plan Year in excess of the dollar limit for the Plan Year under Code section 401(a)(17). (b) The amount of the Match will be determined under the following formula: Excess Compensation times Deferral Percentage times Match Percentage. The ----- ----- terms in the formula have the following meanings. 7 (i) Excess Compensation is the amount of the Participant's base salary ------------------- for the Plan Year in excess of the dollar limit for the Plan Year under Code section 401(a)(17). (ii) Deferral Percentage is the total of the Participant's salary ------------------- deferrals to the Dominion Savings Plan for the Plan Year divided by the lesser of (i) the dollar limit for the Plan Year under Code section 401(a)(17), or (ii) the Participant's base salary for the Plan Year reduced by deferrals under this Plan and the Dominion Savings Plan. The Deferral Percentage may not exceed the maximum percentage of compensation on which the Participant would be eligible to receive a match by making a deferral under the Dominion Savings Plan for the Plan Year. (iii) Match Percentage is the percentage of company match made with respect ---------------- to the Participant's salary deferral to the Dominion Savings Plan. (c) A Participant's Match Account will be vested to the same extent that the Participant's match account in the Dominion Savings Plan is vested. If a Participant Terminates employment when the Match Account is not vested, the Match Account will be forfeited. (d) A Participant will not be required to invest any portion of the Match Account in the DRI Stock Fund. The Administrator may establish further procedures for the administration of the Match Account. 9. INVESTMENT FUNDS. ---------------- (a) Each Participant shall have the right to direct the deemed investment of the Participant's Deferral Account and the Match Account among the Investment Funds. The Administrator shall determine the number and type of Investment Funds that will be available for investment in any Plan Year. (b) Deferrals shall be credited to an Investment Fund as of the date on which the deferred Compensation would have been paid to the Participant. A separate bookkeeping account shall be established for each Participant who has directed a deemed investment in an Investment Fund. Deemed transfers between Investment Funds in the Participant's Deferral Account and Match Account shall be charged and credited as the case may be to each Investment Fund account. The Investment Fund account shall be charged or credited with net earnings, gains, losses and expenses, as well as any appreciation or depreciation in market value during each Plan Year for the deemed investment in the Investment Fund. The Administrator may charge or credit such earnings, gains, losses, appreciation and depreciation based on the actual investment performance of assets that it has deposited in a grantor trust (as described in Plan Section 11). 8 (c) Pursuant to procedures established by the Administrator uniformly applied, Participants may direct the transfer of deemed investments among Investment Funds at least once in each Plan Year. 10. DISTRIBUTIONS. ------------- (a) All Benefits, less withholding for applicable income and employment taxes, shall be paid in cash by the Company or its designee, except that payment from a Participant's Deferred Stock Option Account shall be made in the form of DRI Stock. A Participant may elect to receive a distribution of all or a portion of the Participant's Benefits subject to the provisions of this Section. Payment of each distribution of Benefits shall be made in one lump sum or in installments as provided in this Section. Except in the event of Termination for reasons other than death, retirement or Disability, or as provided in subsection 10(f), a Participant may receive a distribution from the Participant's Deferral Account only on a date that is at least six months after the date on which the Participant's most recent Deferral Election Form is effective. (i) Unless otherwise provided herein or specified in a Participant's Distribution Election Form, any lump sum payment shall be paid, or installment payments shall begin, on or before February 28 of the calendar year after the Participant's Termination. The Participant may elect on the Participant's Distribution Election Form to begin payments (A) on or before the February 28 of the calendar year following the calendar year of the Participant's Termination; (B) on or before the February 28 of the calendar year following the calendar year of the Participant's Termination but no sooner than February 28 of a specified calendar year; or (C) even if the Participant does not Terminate, on or before the February 28 of a specified calendar year. (ii) Installment payments will be made in approximately equal amounts during each year of the installment period. For a Benefit payable in installments, the unpaid balance of a Participant's Deferral Account and Match Account, if any, shall continue to be maintained in Investment Funds. The unpaid balance of a Participant's Deferred Stock Option Account shall remain invested in DRI Stock. (b) Benefits paid on account of Termination for retirement shall be paid in a lump sum unless the Participant's Distribution Election Form specifies annual installment payments over a period of up to five (5) years. (c) Benefits paid on account of a Participant's death shall be paid in a lump sum in accordance with the provisions of Plan Section 9(i). (d) Benefits paid on account of Termination due to Disability shall begin to be paid as soon as administratively practicable following the Participant's Termination. The Benefits shall be paid in the method designated on the Participant's Distribution Election Form, or in annual installment payments over a period of five (5) years if the Participant made no election on the Participant's Distribution Election Form. 9 If a Disabled Participant begins to receive Benefits and thereafter recovers and returns to employment before the balance of the Participant's Accounts is fully paid, distributions shall cease and any remaining Benefits under the Plan shall be governed by this Plan Section 9 and the Participant's Distribution Election Form. (e) Benefits paid on account of Termination due to other than death, Disability or retirement shall be paid in a lump sum as soon as practicable following the Termination. (f) A Participant may elect to receive payment of Benefits prior to Termination. If payment is made pursuant to a Distribution Election Form that was effective less than six months before the date of such payment, the Participant's Deferred Benefit shall be reduced by 10%. Such payment shall be paid in a lump sum. (g) Notwithstanding any other provision of this Plan or a Participant's Distribution Election Form, the Committee in its sole discretion may postpone the distribution of all or part of a Benefit to the extent that the payment would not be deductible under Section 162(m) of the Internal Revenue Code of 1986, as amended (the Code) or any successor thereto. A Benefit distribution that is postponed pursuant to the preceding sentence shall be paid as soon as it is possible to do so within the deduction limitations of Section 162(m) of the Code. (h) A Participant or Beneficiary may not assign Benefits. A Participant may use only one Beneficiary Designation Form to designate one or more Beneficiaries for all of the Participant's Benefits under the Plan. Such designations are revocable. Each Beneficiary shall receive the Beneficiary's portion of the Participant's Accounts on or before February 28 of the year following the Participant's death. However, the Administrator, in its discretion, may approve a Beneficiary's request for accelerated payment under Plan Section 10. The Administrator may require that multiple Beneficiaries agree upon a single distribution method. 11. HARDSHIP DISTRIBUTIONS. ---------------------- (a) At its sole discretion and at the request of a Participant before or after the Participant's Termination, or at the request of any of the Participant's Beneficiaries after the Participant's death, the Administrator may accelerate and pay all or part of any amount attributable to a Participant's Benefits. The Administrator may accelerate distributions only in the event of Hardship as defined in subsection (b). An accelerated distribution under this Section shall be limited to the amount necessary to satisfy the Hardship. (b) Hardship is a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant or of a dependent of the Participant, loss of the Participant's property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. The circumstances that will constitute a Hardship will depend upon the facts of each case, but, in any case, payment will 10 not be made to the extent that the Hardship is or may be relieved: (i) through reimbursement or compensation by insurance or otherwise, (ii) by liquidation of the Participant's assets, to the extent that the liquidation of such assets would not itself cause severe financial hardship, or (iii) by cessation of deferrals under the Plan. (c) Distributions under this Section 10 shall be made in one lump sum payment in cash except that in the case of a Participant's Deferred Stock Option Benefit, distributions shall be made in DRI Stock. Distributions shall be made proportionately from all of the Investment Funds in the Participant's Accounts first, and, with respect to Deferred Benefits, shall be limited to amounts attributable to Compensation deferred under a Deferral Election Form that was effective at least six months before the distribution. The Investment Funds in the Participant's Accounts shall be valued as of the last business day prior to the distribution, or as of such other date as may be determined in the discretion of the Administrator. (d) A distribution under this Section 10 shall be in lieu of that portion of a Participant's Benefit that would have been paid otherwise. A Benefit shall be adjusted by reducing the balance of the Participant's Accounts by the amount of the distribution. 12. COMPANY'S OBLIGATION. -------------------- (a) The Plan shall be unfunded. DRI shall not be required to segregate any assets that at any time may represent a Benefit. DRI shall establish a grantor trust (within the meaning of Sections 671 through 679 of the Code) for Participants and Beneficiaries and shall deposit Participants' Match Benefits with the trustee of such trust. DRI may deposit funds with the trustee of such trust to provide the Deferred Benefits or Deferred Stock Option Benefits to which Participants and Beneficiaries may be entitled under the Plan. The funds deposited with the trustee or trustees of such trust, and the earnings thereon, will be dedicated to the payment of Benefits under the Plan but shall remain subject to the claims of the general creditors of the Company. Any liability of DRI to a Participant or Beneficiary under this Plan shall be based solely on any contractual obligations that may be created pursuant to this Plan. No such obligation of DRI shall be deemed to be secured by any pledge of, or other encumbrance on, any property of DRI. (b) Notwithstanding the foregoing, in the event of a Change of Control, DRI shall, immediately prior to a Change of Control, make an irrevocable contribution to the trust so that the amount held in trust is equal to 105% of the amount that is sufficient to pay each Participant or Beneficiary the Benefit to which they would be entitled, and for which DRI and each other Dominion Company is liable, pursuant to the terms of the Plan as in effect on the date on which the Change of Control occurred. The amount of such contribution exceeding the amount required to pay Benefits under the Plan shall be used to pay administrative costs of the trust and reimburse any Participant who incurs legal fees as a result of an attempt to enforce the terms of the Plan against an acquirer of DRI. 11 Additionally, the trustee of the trust as of the date of the Change of Control may not be removed as trustee of the trust before the fifth anniversary of the date of the Change of Control. 13. CONTROL BY PARTICIPANT. A Participant shall have no control over the ---------------------- Participant's Benefit except according to the Participant's Deferral Election Forms, Distribution Election Forms, Investment Election Form and Beneficiary Designation Form. 14. CLAIMS AGAINST PARTICIPANT'S BENEFIT. An Account shall not be subject in any ------------------------------------ manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, or charge, and any attempt to do so shall be void. A Benefit shall not be subject to attachment or legal process for a Participant's debts or other obligations. Nothing contained in this Plan shall give any Participant any interest, lien, or claim against any specific asset of the Company. A Participant or the Participant's Beneficiary shall have no rights other than as a general creditor of DRI. 15. AMENDMENT OR TERMINATION. Except as otherwise provided, this Plan may be ------------------------ altered, amended, suspended, or terminated at any time by the Committee. The Committee may not alter, amend, suspend, or terminate this Plan without the consent of that Participant if such action would result in (i) a distribution of the Participant's Benefit in any manner not provided in the Plan or (ii) immediate taxation of a Benefit to a Participant. 16. ADMINISTRATION. -------------- (a) This Plan shall be administered by the Administrator. The Administrator shall interpret the Plan, establish regulations to further the purposes of the Plan and take any other action necessary to the proper operation of the Plan. Prior to paying a Benefit under the Plan, the Administrator may require the Participant, former Participant or Beneficiary to provide such information or material as the Administrator, in its sole discretion, shall deem necessary to make any determination it may be required to make under the Plan. The Administrator may withhold payment of a Benefit under the Plan until it receives all such information and material and is reasonably satisfied of its correctness and genuineness. The Administrator may delegate all or any of its responsibilities and powers to any persons selected by it, including designated officers of employees of the Company. (b) If for any reason a Benefit payable under this Plan is not paid when due, the Participant or Beneficiary may file a written claim with a committee appointed by the Administrator to review claims for benefits under the Plan (the "Claims Committee"). If the claim is denied or no response is received within forty-five (45) days after the date on which the claim was filed with the Claims Committee (in which case the claim will be to have been denied), the Participant or Beneficiary may appeal the denial to the Committee within sixty (60) days of receipt of written notification of the denial or the end of the forty-five day period, 12 whichever occurs first. In pursuing an appeal, the Participant or Beneficiary may request that the Committee review the denial, may review pertinent documents, and may submit issues and documents in writing to the Committee. A decision on appeal will be made within sixty (60) days after the appeal is made, unless special circumstances require the Committee to extend the period for another sixty (60) days. 17. NOTICES. All notices or election required under the Plan must be in ------- writing. A notice or election shall be deemed delivered if it is delivered personally or sent registered or certified mail to the person at the person's last known business address. 18. WAIVER. The waiver of a breach of any provision in this Plan does not ------ operate as and may not be construed as a waiver of any later breach. 19. CONSTRUCTION. This Plan shall be adopted and maintained according to the ------------ laws of the Commonwealth of Virginia (except its choice-of-law rules and except to the extent that such laws are preempted by applicable federal law). Headings and captions are only for convenience; they do not have substantive meaning. If a provision of this Plan is not valid or enforceable, the validity or enforceability of any other provision shall not be affected. Use of one gender includes all, and the singular and plural include each other. IN WITNESS WHEREOF, this instrument has been executed this ____ day of _____________, 2000. DOMINION RESOURCES, INC. By__________________________________ James L. Trueheart Group Vice President and Chief Administrative Officer 13 EX-11 4 0004.txt COMPUTATION OF EARNINGS PER SHARE EXHIBIT 11 DOMINION RESOURCES, INC. COMPUTATION OF EARNINGS PER SHARE OF COMMON STOCK ASSUMING FULL DILUTION
(Million, Except Per Share Amounts) 2000 1999 1998 ---- ---- ---- Basic earnings per common share: Consolidated net income (1) $ 436 $ 297 $ 548 ====== ====== ====== Adjustment to average common shares: Shares of common stock - average shares outstanding 235.2 191.4 194.9 Plus: Additional shares assuming conversion of installments received on stock purchase plan at average market value (2) 0.0 0.0 0.0 ------ ------ ------ Adjusted average common shares 235.2 191.4 194.9 ====== ====== ====== Basic earnings per common share $ 1.85 $ 1.55 $ 2.81 ====== ====== ====== Diluted earnings per common share: Consolidated net income $ 436 $ 285 $ 548 ====== ====== ====== Adjustment to average common shares: Shares of common stock - average shares outstanding 235.9 191.4 194.9 Plus: Additional shares assuming conversion of installments received on stock purchase plan at average market value (2) 0.0 0.0 0.0 ------ ------ ------ Adjusted average common shares 235.9 191.4 194.9 ====== ====== ====== Diluted earnings per common share $ 1.85 $ 1.48 $ 2.81 ====== ====== ====== Notes: (1) See the Consolidated Statements of Income. (2) Based on the following data: 2000 1999 1998 ---- ---- ---- Installments received on stock purchase plan at year-end $ 0.3 $ 0.2 $ 0.4 Average market per common share $48.53 $43.46 $43.38
EX-13 5 0005.txt SELECTED FINANCIALS | Consolidated Statements of Income
For The Year Ended December 31, ------------------------------- (millions, except per share amounts) 2000 1999 1998 ================================================================================================================================ Operating revenue and income: Regulated sales Electric $ 4,492 $ 4,227 $ 3,979 Gas 1,374 Nonregulated sales Electric 97 180 190 Gas 593 Gas transportation and storage 486 Oil and gas production 856 218 141 East Midlands 1,010 Other 1,362 895 761 - -------------------------------------------------------------------------------------------------------------------------------- Total 9,260 5,520 6,081 - -------------------------------------------------------------------------------------------------------------------------------- Expenses: Fuel, net 1,106 996 961 Purchased power capacity, net 741 809 806 Purchased gas, net 1,453 Liquids, capacity and other products purchased 299 Supply and distribution-- East Midlands 655 Restructuring and other acquisition-related costs 460 Impairment of regulatory assets 159 Other operation and maintenance 2,011 1,376 1,357 Depreciation, depletion and amortization 1,176 707 733 Other taxes 485 304 306 - -------------------------------------------------------------------------------------------------------------------------------- Total 7,731 4,192 4,977 - -------------------------------------------------------------------------------------------------------------------------------- Income from operations 1,529 1,328 1,104 - -------------------------------------------------------------------------------------------------------------------------------- Other income: Gain on sale-- East Midlands 332 Other 95 75 99 - -------------------------------------------------------------------------------------------------------------------------------- Total 95 75 431 - -------------------------------------------------------------------------------------------------------------------------------- Income before interest and income taxes 1,624 1,403 1,535 - -------------------------------------------------------------------------------------------------------------------------------- Interest and related charges: Interest charges 958 507 583 Preferred dividends and distributions of subsidiary trusts 66 67 65 - -------------------------------------------------------------------------------------------------------------------------------- Total 1,024 574 648 - -------------------------------------------------------------------------------------------------------------------------------- Income before income taxes, minority interests, extraordinary item and cumulative effect of a change in accounting principle 600 829 887 Income taxes 183 259 312 Minority interests 2 18 27 - -------------------------------------------------------------------------------------------------------------------------------- Income before extraordinary item and cumulative effect of a change in accounting principle 415 552 548 - -------------------------------------------------------------------------------------------------------------------------------- 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 $ 436 $ 297 $ 548 ================================================================================================================================ Average shares of common stock-- basic 235.2 191.4 194.9 - -------------------------------------------------------------------------------------------------------------------------------- Basic earnings per common share: Income before extraordinary item and cumulative effect of a change in accounting principle $ 1.76 $ 2.88 $ 2.81 Extraordinary item (1.33) Cumulative effect of a change in accounting principle 0.09 - -------------------------------------------------------------------------------------------------------------------------------- Net income $ 1.85 $ 1.55 $ 2.81 ================================================================================================================================ Average shares of common stock-- diluted 235.9 191.4 194.9 - -------------------------------------------------------------------------------------------------------------------------------- Diluted earnings per share: Income before extraordinary item and cumulative effect of a change in accounting principle $ 1.76 $ 2.81 $ 2.81 Extraordinary item (1.33) Cumulative effect of a change in accounting principle 0.09 - -------------------------------------------------------------------------------------------------------------------------------- Net income $ 1.85 $ 1.48 $ 2.81 ================================================================================================================================ Dividends paid per common share $ 2.58 $ 2.58 $ 2.58 ================================================================================================================================
The accompanying notes are an integral part of the Consolidated Financial Statements. ___ 25 | Consolidated Balance Sheets | Assets
At December 31, --------------------------- (millions) 2000 1999 =========================================================================================================================== Current assets: Cash and cash equivalents $ 360 $ 280 Accounts receivable: Customers (less allowance for doubtful accounts of $67 in 2000 and $12 in 1999) 1,872 664 Other 486 269 Inventories: Materials and supplies (average cost method) 150 143 Fossil fuel (average cost method) 102 111 Gas stored-- current portion 75 Investment securities -- trading 275 2 Mortgage loans held for sale 104 119 Commodity contract assets 1,058 363 Unrecovered gas costs 263 Broker margin deposits 267 36 Prepayments 173 154 Net assets held for sale 73 Other 608 37 - ----------------------------------------------------------------------------------------------------------------------------- Total current assets 5,866 2,178 - ----------------------------------------------------------------------------------------------------------------------------- Investments: Loans receivable, net 676 2,049 Investments in affiliates 392 433 Available for sale securities 292 512 Nuclear decommissioning trust funds 851 818 Investments in real estate 65 86 Other 326 334 - ----------------------------------------------------------------------------------------------------------------------------- Total net investments 2,602 4,232 - ----------------------------------------------------------------------------------------------------------------------------- Property, plant and equipment 28,011 18,703 Less accumulated depreciation, depletion and amortization 13,162 7,906 - ----------------------------------------------------------------------------------------------------------------------------- Property, plant and equipment, net 14,849 10,797 - ----------------------------------------------------------------------------------------------------------------------------- Deferred charges and other assets: Goodwill, net 3,502 132 Regulatory assets, net 516 221 Prepaid pension costs 1,455 22 Other, net 558 200 - ----------------------------------------------------------------------------------------------------------------------------- Total deferred charges and other assets 6,031 575 - ----------------------------------------------------------------------------------------------------------------------------- Total assets $ 29,348 $17,782 =============================================================================================================================
___ 26 | Liabilities and Shareholders' Equity
At December 31, ------------------ (millions) 2000 1999 =================================================================================================== Current liabilities: Securities due within one year $ 336 $ 536 Short-term debt 3,237 870 Accounts payable, trade 1,736 711 Accrued interest 195 121 Accrued payroll 127 93 Accrued taxes 316 89 Commodity contract liabilities 1,021 348 Other 624 232 - --------------------------------------------------------------------------------------------------- Total current liabilities 7,592 3,000 - --------------------------------------------------------------------------------------------------- Long-term debt 10,101 6,936 - --------------------------------------------------------------------------------------------------- Deferred credits and other liabilities: Deferred income taxes 2,820 1,710 Deferred investment tax credits 147 146 Other 801 223 - --------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 3,768 2,079 - --------------------------------------------------------------------------------------------------- Total liabilities 21,461 12,015 - --------------------------------------------------------------------------------------------------- Minority interest 1 99 - --------------------------------------------------------------------------------------------------- Commitments and contingencies (see Note 22) Obligated mandatorily redeemable preferred securities of subsidiary trusts* 385 385 - --------------------------------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption 509 509 - --------------------------------------------------------------------------------------------------- Common shareholders' equity: Common stock -- no par; authorized -- 500.0 shares; outstanding -- 245.8 shares at 2000 and 186.3 shares at 1999 5,979 3,561 Other paid-in capital 16 16 Accumulated other comprehensive income (31) (15) Retained earnings 1,028 1,212 - --------------------------------------------------------------------------------------------------- Total common shareholders' equity 6,992 4,774 - --------------------------------------------------------------------------------------------------- Total liabilities and shareholders' equity $ 29,348 $ 17,782 ===================================================================================================
* As described in Note 17, the 7.83% and 8.05% Junior Subordinated Notes totaling $258 million and $139 million principal amounts, respectively, constitute 100% of the trusts' assets. The accompanying notes are an integral part of the Consolidated Financial Statements. ___ 27 Consolidated Statements of Common Shareholders' Equity
Accumulated Common Stock Other Other ------------------ Retained Comprehensive Paid-In (millions) Shares Amount Earnings Income Capital Total ================================================================================================================================= Balance at January 1, 1998 188 $ 3,674 $ 1,363 $ (3) $ 16 $ 5,050 Issuance of stock through public offering 7 268 268 Issuance of stock through employee and direct stock purchase plans 2 86 86 Stock repurchase and retirement (2) (99) (99) Other common stock activity 4 4 Comprehensive income 548 (17) 531 Dividends and other adjustments (503) (503) - --------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1998 195 3,933 1,408 (20) 16 5,337 Stock repurchase and retirement (9) (372) (372) Comprehensive income 297 5 302 Dividends and other adjustments (493) (493) - --------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 186 3,561 1,212 (15) 16 4,774 Issuance of stock--CNG acquisition 87 3,527 3,527 Issuance of stock through public offering 6 354 354 Issuance of stock through employee, executive loan and direct stock purchase plans 4 195 195 Stock repurchase and retirement (37) (1,641) (1,641) Premium income equity securities (21) (21) Other common stock activity 4 4 Comprehensive income 436 (16) 420 Dividends and other adjustments (620) (620) - --------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 246 $ 5,979 $ 1,028 $ (31) $ 16 $ 6,992 =================================================================================================================================
Consolidated Statements of Comprehensive Income
For The Year Ended December 31, ----------------------------------------- (millions) 2000 1999 1998 ================================================================================================================================= Net income $ 436 $ 297 $ 548 Other comprehensive income, net of tax: Unrealized holding gains (losses) on investment securities 9 (14) (3) Less: reclassification adjustment for gains (losses) realized in net income (3) 3 3 - --------------------------------------------------------------------------------------------------------------------------------- Unrealized gains (losses) on investment securities 12 (17) (6) Foreign currency translation adjustment (4) 22 (11) Minimum pension liability adjustment (24) - --------------------------------------------------------------------------------------------------------------------------------- Other comprehensive income (loss) (16) 5 (17) - --------------------------------------------------------------------------------------------------------------------------------- Comprehensive income $ 420 $ 302 $ 531 =================================================================================================================================
The accompanying notes are an integral part of the Consolidated Financial Statements. __ 28 | Consolidated Statements of Comprehensive Income
For The Year Ended December 31, ------------------------------------- (millions) 2000 1999 1998 ================================================================================================================================ Cash flows from (used in) operating activities: Net income $ 436 $ 297 $ 548 Adjustments to reconcile net income to net cash from operating activities: Cumulative effect of a change in accounting principle (21) Restructuring and other acquisition related costs 124 DCI impairment losses 292 Extraordinary item, net of income taxes 255 Impairment of regulatory assets 159 Gains on sales of subsidiaries (23) (332) Depreciation and amortization 1,268 798 814 Deferred income taxes 22 64 22 Deferred fuel expense (33) (35) (34) Changes in current assets and liabilities: Accounts receivable (842) 81 (90) Inventories (62) (6) (24) Unrecovered gas costs (217) Purchase and origination of mortgages (4,281) (2,575) (2,503) Proceeds from sale and principal collections of mortgages 4,295 2,597 2,450 Accounts payable, trade 674 (24) 65 Accrued interest and taxes 139 (48) 100 Commodity contract assets and liabilities (32) (92) 66 Net assets held for sale (24) Other (372) (57) (16) - -------------------------------------------------------------------------------------------------------------------------------- Net cash flows from operating activities 1,343 1,255 1,225 - -------------------------------------------------------------------------------------------------------------------------------- Cash flow from (used in) investing activities: Plant construction and other property additions (1,385) (871) (739) Acquisition of exploration and production assets (353) (90) (96) Loan originations (2,911) (2,581) (2,580) Repayments of loan originations 4,255 2,238 1,778 Sale of businesses, including East Midlands 836 180 1,462 Sale of marketable securities 137 35 70 Purchase of debt securities (235) (53) (120) Acquisitions of businesses (2,779) (167) (338) Other investments (140) (152) (75) Other (22) (81) (30) - -------------------------------------------------------------------------------------------------------------------------------- Net cash flow used in investing activities (2,597) (1,542) (668) - -------------------------------------------------------------------------------------------------------------------------------- Cash flow from (used in) financing activities: Issuance of common stock 532 354 Repurchase of common stock (1,641) (372) (99) Issuance (repayment) of short-term debt 1,820 394 65 Issuance of long-term debt 8,108 6,446 4,027 Repayment of long-term debt (6,813) (5,790) (4,207) Common dividend payments (615) (493) (503) Other (57) (44) (90) - -------------------------------------------------------------------------------------------------------------------------------- Net cash flow from (used in) financing activities 1,334 141 (453) - -------------------------------------------------------------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents 80 (146) 104 Cash and cash equivalents at beginning of the year 280 426 322 - -------------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of the year $ 360 $ 280 $ 426 ================================================================================================================================ Supplemental cash flow information: Cash paid during the year for: Interest, excluding capitalized amounts $ 988 $ 522 $ 474 Income taxes 240 199 202 Non-cash transactions from investing and financing activities: Common stock issuance-- CNG acquisition 3,527 Note received in sale of business 260 26 Exchange of securities 57 ================================================================================================================================
The accompanying notes are an integral part of the Consolidated Financial Statements. 29 [LOGO] Management's Discussion and Analysis of Financial Condition and Results of Operations (unaudited) Forward-Looking Information This annual report includes certain information which 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. The business and financial condition of Dominion Resources, Inc. and its subsidiaries (Dominion or the Company) are influenced by a number of factors including political and economic risks, market demand for energy, inflation, capital market conditions, and other general and specific economic conditions in the Company's service areas, governmental policies, legislative and regulatory actions (including those of the Federal Energy Regulatory Commission [FERC], the Securities and Exchange Commission [SEC], the Environmental Protection Agency [EPA], the Department of Energy, the Nuclear Regulatory Commission [NRC] and various state regulatory commissions), 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 and gas deregulation, the restructuring of the organization, operations and financing of Dominion's electric power business to separate generation, transmission and distribution, competition for new energy development opportunities, pricing and transportation of commodities, operation of nuclear power facilities, competition in the telecommunications industry, successful implementation of the Company's telecommunications strategy, effects and risks associated with the Company's acquisition, generation growth and divestiture strategies, recovery of potentially stranded costs, including nuclear decommissioning costs, exposure to risks associated with Dominion's portfolio of derivative 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 the control of Dominion. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of each such factor on Dominion. Any forward-looking statement speaks only as of the date on which such statement is made, and Dominion undertakes no obligation to update any forward- looking statement to reflect events or circumstances after the date on which such statement is made. Introduction Management's Discussion and Analysis of Financial Condition and Results of Operations explain the general financial condition and the results of operations for Dominion. "Dominion" or the "Company" is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one of Dominion's consolidated subsidiaries, or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries. Dominion is a holding company headquartered in Richmond, Virginia. Its principal subsidiaries are Virginia Electric and Power Company (Virginia Power) and Consolidated Natural Gas Company (CNG), which was acquired on January 28, 2000. Dominion is subject to the Public Utility Holding Company Act of 1935 (1935 Act). Virginia Power 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. Virginia Power sells electricity to approximately 2.1 million retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. Virginia Power also engages in off-system wholesale purchases and sales of electricity and purchases and sales of natural gas beyond the geographic limits of its retail service territory. CNG operates in all phases of the natural gas industry in the United States, including exploration for and production of oil and natural gas and natural gas transmission, storage and distribution. Its regulated retail gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Its interstate gas transmission pipeline system services each of its distribution subsidiaries, non-affiliated utilities and end use customers in the Midwest, the Mid-Atlantic and the Northeast states. CNG's exploration and production operations are conducted in several of the major gas and oil producing basins in the United States, both onshore and offshore, and in Canada. The Company's other major subsidiaries are Dominion Energy, Inc. (DEI) and Dominion Capital, Inc. (DCI). DEI is engaged in independent power production and the acquisition and production of natural gas and oil reserves. In Canada, DEI is engaged in natural gas exploration, production and storage. DCI is Dominion's financial services subsidiary. DCI's primary business is financial services which includes commercial lending and residential mortgage lending. See Note 6 to the Consolidated Financial Statements for a discussion of management's strategy to exit and windup DCI's businesses as ordered by the SEC under the 1935 Act. Under the 1935 Act, 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. Effective January 1, 2001, the two service companies were combined into one service company. 30 On March 3, 2000, Dominion announced a new business structure that integrates CNG's businesses, streamlines operations, and positions Dominion for long-term growth in the competitive marketplace. Under the structure, Dominion operates three principal business segments -- Dominion Energy, Dominion Delivery and Dominion Exploration & Production. In addition, Dominion reviews the financial services business of DCI and Corporate Operations as segments. Items for which the operating segments are not held accountable, as well as inter-segment eliminations, are included in Corporate Operations. See Note 27 to the Consolidated Financial Statements. While Dominion manages its daily operations as described above, assets remain wholly owned by its legal subsidiaries. For more information on business segments, see Note 27 to the Consolidated Financial Statements. Results of Operations Overview Dominion achieved net income of $436 million in 2000, or $1.85 per diluted share, compared with net income of $297 million in 1999, or $1.48 per share. Since its acquisition, CNG's various businesses have had a significant impact on Dominion's current year operations. Consequently, the primary reason for the increase in operating results when comparing 2000 to 1999 is the contributions of CNG's operations. CNG's various businesses contributed $157 million, or $0.67 per share, to Dominion's net income in 2000. Net income for the comparative periods was impacted by an extraordinary item for the write-off of certain generation-related assets and liabilities in 1999 and the following factors in 2000: . a change in the method of accounting for pensions (see Note 3 to the Consolidated Financial Statements); . the increased earnings contributions by Dominion Energy, Dominion Delivery and Dominion Exploration & Production; . the gain on the sale of Dominion's interest in Corby Power Station (see Note 5 to the Consolidated Financial Statements); . the charges for restructuring and other acquisition-related costs and the charges resulting from the impairment and revaluation of DCI's assets (see Note 6 to the Consolidated Financial Statements); . the amortization of the goodwill associated with the purchase of CNG (see Note 5 to the Consolidated Financial Statements); . an increase in interest charges primarily due to debt incurred to finance the acquisition of CNG and the interest expense of DCI; . a decrease in income tax expense primarily due to restructuring and other acquisition-related charges and the impairment and revaluation of DCI's assets. Net income decreased $251 million in 1999 as compared to 1998 and was impacted by the following: . the write-off of generation-related assets and liabilities in 1999, resulting in an after-tax charge to earnings of $255 million (see Note 7 to the Consolidated Financial Statements); . the loss recorded by Dominion Energy in 1999 related to its interests in Latin American power generation; . the sale of East Midlands which resulted in a gain in 1998 and the absence of East Midlands' contribution to earnings in 1999; . the increased contribution from Dominion Energy's energy marketing business during 1999; . the impairment of regulatory assets and one-time base rate refund resulting from the settlement of 1998 Virginia jurisdictional rate proceedings; . lower interest charges primarily due to the retirement of debt upon the sale of East Midlands, the capitalization of interest on utility generation construction beginning in 1999 and the interest portion of the 1998 Virginia jurisdictional rate refund. These factors were offset, in part, by interest charges from debt issued to fund the acquisition of Kincaid Power Station and Dominion Energy Canada, Ltd. in 1998 and increased funding for loan originations at Dominion's financial services businesses; and . a decrease in income tax expense due to taxes on the gain on the East Midlands sale recorded in 1998. A comparison of net income and earnings per share contributions by segment follows:
Year ended December 31, 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- (millions, except per Net Net Net share amounts) Income EPS Income EPS Income EPS - --------------------------------------------------------------------------------------------------------------------- Dominion Delivery $ 339 $ 1.44 $ 175 $ 0.91 $ 168 $ 0.86 Dominion Energy 478 2.03 271 1.42 262 1.35 Dominion E&P 270 1.14 44 0.23 34 0.17 DCI 11 0.05 78 0.41 59 0.30 East Midlands 26 0.14 - --------------------------------------------------------------------------------------------------------------------- 1,098 4.66 568 2.97 549 2.82 Corporate Operations (662) (2.81) (271) (1.42) (1) (0.01) - --------------------------------------------------------------------------------------------------------------------- Consolidated $ 436 $ 1.85 $ 297 $ 1.48/(1)/ $ 548 $ 2.81 - --------------------------------------------------------------------------------------------------------------------- Average shares -- diluted 235.9 191.4 $194.9 =====================================================================================================================
(1) Diluted earnings per share calculation includes the effect of the total return equity swap. For more information, see Note 19 to the Consolidated Financial Statements. Regulated Sales Revenue Regulated sales -- electric consist primarily of sales to retail customers in Dominion's electric service territory at rates authorized by the Virginia and North Carolina regulatory commissions and sales to cooperatives and municipalities at wholesale rates authorized by FERC. Also, included in this revenue are amounts received from others for use of Dominion's transmission system to transport electric energy under tariffs authorized by FERC. Regulated sales -- electric for fiscal years 2000, 1999 and 1998 were allocated to the electric utility operations of the Dominion Energy and Dominion Delivery businesses as follows: (millions) Year ended December 31, 2000 1999 1998 - ----------------------------------------------------------------------------- Revenue: Dominion Energy $ 3,341 $ 3,122 $ 3,069 Dominion Delivery 1,151 1,109 1,063 Corporate Operations (4) (153) - ----------------------------------------------------------------------------- Total revenue $ 4,492 $ 4,227 $ 3,979 ============================================================================= 31 Management's Discussion and Analysis of Financial Condition and Results of Operations (continued) Weather typically has a significant impact on retail electric sales revenue. However, for the comparative periods presented, weather did not have a significant impact. The primary factors affecting the increase in regulated sales -- electric in both fiscal years 2000 and 1999 were customer growth and changes in rates. Dominion's electric retail customer base increased, on average, approximately 39,000 in both 2000 and 1999 over the respective prior year periods. These additional customers increased electric regulated sales by an estimated $76 million in 2000 compared to 1999 and an estimated $68 million in 1999 compared to 1998. Fuel revenue increased $117 million in 2000 as compared to 1999 reflecting higher fuel rates approved in the first quarter of 2000. In addition, regulated sales -- electric in 1999 were higher as a result of a one-time $150 million base rate refund in 1998, the effect of which is reported in Corporate Operations along with other intersegment eliminations. For the period January 28, 2000 through December 31, 2000, regulated sales--gas were $ 1.4 billion. The revenue in 2000 reflects the cold weather experienced in the Company's retail gas service areas in the fourth quarter of 2000. Average sales rates for all customer groups increased sharply during the year, reflecting the pass through of higher purchased gas costs. Dominion Energy Dominion Energy includes Dominion's 19,000-megawatt generation portfolio, consisting of generating units and power purchase agreements. It also manages the Company's generation growth strategy; energy trading, marketing, hedging and arbitrage activities; and gas pipeline and storage operations. Selected financial information relevant to Dominion Energy is as follows: Year ended December 31, 2000 1999 1998 - --------------------------------------------------------------------------- All (millions) Total CNG Other - --------------------------------------------------------------------------- Regulated sales revenue: Electric $3,341 $3,341 $3,122 $3,069 Nonregulated sales revenue: Electric 97 97 180 190 Gas 518 $494 24 Gas transportation and storage 291 291 Other revenue 517 287 230 291 251 Operating expenses 3,830 857 2,973 2,970 2,895 Operating income 934 215 719 623 615 =========================================================================== 2000 Compared to 1999; 1999 Compared to 1998 Regulated sales-- electric increased, reflecting growth in the number of retail customers and an increase in Virginia jurisdictional fuel rates. The decrease in nonregulated electric sales is primarily attributable to the sale of Dominion Energy's interests in its Latin American power generation in 1999 and early 2000. Nonregulated gas sales to marketers and end users were $518 million. Nonregulated gas sales to other Dominion segments, included in Other revenue, were $122 million. Gas transportation volumes in 2000 were 425 Bcf, reflecting the cold weather experienced late in the year. Operating expenses in 2000 included purchased gas costs of $602 million associated with nonregulated gas sales. There were no significant variations in revenue, operating expenses or operating income for 1999 as compared to 1998. Dominion Delivery Dominion Delivery consists primarily of Dominion's electric transmission and distribution system and local gas distribution systems. Selected financial information relevant to Dominion Delivery is as follows: Year ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------- All (millions) Total CNG Other - ------------------------------------------------------------------------- Regulated sales revenue: Electric $1,151 $1,151 $1,109 $1,063 Gas 1,374 $1,374 Gas transportation and storage 197 197 Operating expenses 2,117 1,398 719 735 687 Operating income 707 205 502 431 424 ========================================================================= 2000 Compared to 1999; 1999 Compared to 1998 Regulated sales -- electric increased, reflecting growth in the number of retail customers. Regulated sales -- gas reflects the cold weather experienced in the Company's retail service areas during the fourth quarter of 2000. Gas sales and transportation volumes were 187 Bcf. Operating expenses increased due to the inclusion of CNG's other operations and maintenance expenses. The increase was mitigated by lower electric service restoration costs associated with storm damage, pension credits (see Note 3 to the Consolidated Financial Statements) and the effect of staffing reductions attributable to restructuring initiatives. There were no significant variations in revenue, operating expenses or operating income for 1999 as compared to 1998. Dominion Exploration & Production Dominion Exploration & Production consists of the gas and oil exploration, development and production operations of DEI and CNG. The CNG acquisition added 1.5 trillion cubic feet equivalent (Tcfe) of gas reserves located primarily in the Gulf of Mexico, Gulf Coast and Appalachian and Rocky Mountain regions of the United States. Production from these reserves added nearly 475 million cubic feet of gas and 20,000 barrels of oil per day to Dominion's existing production. Dominion now owns 2.8 Tcfe reserves. Acquisition activity in early 2000 included the purchase of additional interests in two deepwater Gulf of Mexico fields and various South 32 Texas gas fields. Selected financial information relevant to Dominion Exploration & Production is as follows: Year ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------- All (millions) Total CNG Other - ------------------------------------------------------------------------- Operating revenue $1,369 $998 $371 $256 $164 Operating expenses 931 670 261 212 135 Operating income 438 328 110 44 29 ========================================================================= 2000 Compared to 1999 Operating revenue and income were higher as a result of increased production and higher oil and gas prices. The 2000 results of operations reflect the addition of CNG's operations and new property acquisitions, as well as increased production from existing properties . CNG's exploration and production operations acquired in early 2000 contributed $998 million to the segment's total Operating revenue and income, including brokered gas and oil sales of $306 million. Natural gas production from operations other than CNG rose to 115 Bcfe in 2000, compared to 109 Bcfe in 1999. The increase was primarily due to a full year of operations from properties acquired by Dominion during 1999. Property additions in 1999 included the purchase of Remington Energy Ltd. (Remington), a natural gas exploration and production company headquartered in Calgary, Alberta, Canada and gas producing properties in the San Juan Basin of New Mexico. Operating expenses increased primarily due to the addition of CNG's operations and a full year of Remington's operations. Operating expenses attributable to CNG's operations also included $296 million for the cost of gas and oil purchased for brokered sales. 1999 Compared to 1998 Oil and gas production revenues increased primarily due to increased natural gas production. Natural gas production rose to 109 Bcfe in 1999, compared to 69 Bcfe in 1998. At December 31, 1999, proved reserves totaled 1,234 Bcfe, an increase of 618 Bcfe over 1998. The 1999 increase in production and reserves resulted primarily from the development of existing acreage, a full year's operations at Dominion Energy Canada, Ltd. and the acquisition of Remington and gas producing properties in the San Juan Basin of New Mexico. Operating expenses increased primarily due to increased natural gas operations. Dominion Capital Selected financial information relevant to DCI is as follows: (millions) Year ended December 31, 2000 1999 1998 - ------------------------------------------------------------------ Other revenue $433 $473 $409 Operating expenses 218 208 199 Operating income 215 265 210 ================================================================== 2000 Compared to 1999 Operating income decreased primarily due to decreased contributions from financial services businesses. Mortgage volumes were $2.1 billion in 2000, down from $2.4 billion in 1999. As a result of the sale and restructuring of loans, the commercial finance operations portfolio decreased to $676 million at the end of 2000 compared to $2.0 billion at the end of 1999. For additional information, see Note 6 to the Consolidated Financial Statements. 1999 Compared to 1998 Operating income increased primarily due to increased contributions from financial services businesses. Mortgage lending volumes were $2.4 billion, up from $2.1 billion in 1998. The commercial finance operations portfolio increased to $2.0 billion compared to $1.7 billion at the end of 1998. Liquidity and Capital Resources Internal Sources of Liquidity Cash flow from operating activities provided approximately $ 1.3 billion during 2000 and $1.2 billion in 1999 and 1998. Cash requirements not met by the timing or amount of cash flow from operations are generally satisfied with proceeds from the short-term borrowings, sales of securities in the case of major acquisitions and additional long-term debt financings. External Sources of Liquidity During 2000, Dominion issued a combination of common stock and short-term and long-term debt, totaling $10.5 billion. As discussed below, these issuances were used primarily to finance the acquisition of CNG and the pending acquisition of Millstone Nuclear Power Station (Millstone), support financial services operations and for other general corporate purposes including the repayment of approximately $7.0 billion of long-term debt and preferred securities. See Notes 15 and 16 to the Consolidated Financial Statements for information on Dominion's short-term borrowings and long-term debt as of December 31, 2000. CNG Acquisition and Related Financing On January 28, 2000, Dominion acquired the outstanding shares of CNG's common stock for $6.4 billion, consisting of approximately 87 million shares of Dominion common stock and approximately $2.9 billion in cash. In addition, in connection with the acquisition, Dominion shareholders exchanged approximately 33 million shares of Dominion common stock for $1.4 billion. Dominion initially financed the CNG acquisition with bridge financing consisting of a $3.5 billion commercial paper program backed by a short-term credit facility and $1 billion of short-term, privately placed money market notes. During 2000, Dominion issued the following securities whose proceeds were used primarily to refinance a portion of the bridge financing: . $700 million of 10-year fixed rate 8.125% notes; . $700 million of 5-year fixed rate 7.625% notes; 33 Management's Discussion and Analysis of Financial Condition and Results of Operations (continued) . $400 million of 3-year fixed rate 7.60% notes; . $200 million of 12-years fixed rate 7.40% remarketable notes; . $250 million of 14-year fixed rate 7.82% remarketable notes; . $250 million of 12-year variable rate remarketable notes; and . $413 million of Premium Income Equity Securities (registered trademark of Lehman Brothers, Inc.). Also during 2000, Dominion used net proceeds from the sales of non-core assets to pay down a portion of the bridge financing. In January 2001, Dominion issued $250 million of 8.4% Capital Securities due in January 2031 and $1 billion of 2-year fixed rate 6% notes to refinance the remaining bridge financing. For additional information on the capital securities, see Note 17 to the Consolidated Financial Statements. Millstone Nuclear Power Station Acquisition and Related Financing Dominion has reached an agreement to acquire Millstone, located in Waterford, Connecticut, for a total purchase price of approximately $1.3 billion. The acquisition is expected to close by the end of April 2001, following regulatory approvals. See Note 5 to the Consolidated Financial Statements. During 2000, Dominion issued 6 million shares of common stock generating proceeds of $354 million to pre-finance a portion of the Millstone acquisition. Also in January 2001, Dominion issued $300 million of 8.4% Trust Preferred Securities due in January 2041 in anticipation of the Millstone purchase. For additional information on the preferred securities, see Note 17 to the Consolidated Financial Statements. Dominion plans to finance the remainder of the Millstone acquisition with bridge financing or through the issuance of long-term debt. Short-Term Borrowings In addition to the bridge financing discussed above, Dominion has three separate commercial paper programs with an aggregate limit of $2.85 billion supported by various credit facilities. One facility is a $1.75 billion 364-day revolving credit facility that matures May 31, 2001. Two of the facilities, aggregating $500 million, are accessible by CNG only and will terminate by March 31, 2001. The other facilities are multi-year, one of which matures in June 2001. Net borrowings under the commercial paper program were $2.7 billion at December 31, 2000, an increase of $1.5 billion from amounts outstanding at December 31, 1999. Commercial paper borrowings are used primarily to fund working capital requirements and bridge financing of acquisitions, and therefore may vary significantly during the course of the year depending upon the timing and amount of cash requirements not satisfied by cash provided by operations. In addition to commercial paper, Dominion may also issue extendible commercial notes (ECNs) to meet working capital requirements. This program became effective in July 2000 and will allow Dominion to issue up to $200 million aggregate outstanding principal of ECNs. ECNs are unsecured notes expected to be sold in private placements. Any ECNs Dominion issues would have a stated maturity of 390 days from issuance and may be redeemed, at Dominion's option, within 90 days or less from issuance. Equity Plans In 2000, Dominion raised $195 million from the sale of common stock through Dominion Direct (a dividend reinvestment open enrollment direct stock purchase plan) and employee savings plans. Beginning in August 2000, Dominion began using newly issued shares rather than shares purchased on the open market for these plans. Other Securities Issuances and Repayments In 2000, Dominion issued the following securities: . $220 million of variable-rate medium-term notes maturing in 2002; and . $30 million of Tax-Exempt Pollution Control Revenue Bonds due September 1, 2030. The proceeds from the issuances were used for general corporate purposes, including the scheduled retirement of outstanding debt and preferred stock. In 2000, Dominion repaid approximately $867 million of scheduled maturities of its long-term debt and preferred stock, excluding debt repaid in connection with financial services operations, and retired $45 million of debt securities through sinking fund provisions and open market purchases. In February 2001, Dominion 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 2031. The net proceeds of the bonds were used to finance qualifying expenditures made during the construction of facilities at the North Anna Power Station. Dominion Capital Financing Activities In connection with purchases and originations of loans and sales and collections of loans during 2000, the Company repaid $237 million of short-term commercial paper and issued and repaid long-term debt of $5.0 billion and $6.1 billion, respectively. Amounts Available under Shelf Registrations As of December 31, 2000, Dominion had available $5.0 billion of remaining principal amount under currently effective shelf registrations with the SEC to meet capital requirements. Financing activities in January 2001 reduced this amount by $1.55 billion. Investing Activities In 2000, investing activities resulted in a net cash outflow of $2.6 billion reflecting the following primary investing activities: . Dominion's cash payment of approximately $2.9 billion in connection with the CNG acquisition; . plant and nuclear fuel expenditures of $1.4 billion that included construction and expansion of generation facilities, environmental upgrades, purchase of nuclear-fuel, and construction and improvements of gas and electric transmission and distribution assets; 34 . exploration and production expenditures of $353 million that included the purchase of gas and oil producing properties, drilling and equipment costs and undeveloped lease acquisitions; . proceeds from the sales of non-core businesses of $836 million; and . repayments of loans (net of new originations) associated with DCI of $1.3 billion. Capital Requirements Capital Expenditures Dominion's planned capital expenditures during 2001, 2002 and 2003 are expected to total $2.0 billion, $3.0 billion and $2.8 billion, respectively. These expenditures include construction and expansion of generation facilities, environmental upgrades, purchase of nuclear fuel, construction improvements of gas and electric transmission and distribution assets, and expenditures for natural gas and oil producing properties. Maturities Dominion will require $336 million to meet current maturities of long-term securities in 2001. Dominion expects to fund its capital requirements and debt maturities with cash flow from operations and a combination of sales of securities and short- term borrowings. Electric and Gas Industry Issues Deregulation Legislation -- Electric Industry Virginia Historically, Dominion has had the exclusive right to provide electricity at retail within its assigned service areas in Virginia and North Carolina. 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. In connection with the implementation of the phase-in of retail electric competition, the Virginia Commission Staff recommended transition schedules for each of Virginia's electric utilities. For Dominion, the Virginia Commission Staff's plan recommended the phase-in of retail choice for all customers by January 1, 2003. Dominion filed comments on the Commission Staff's recommended plan in February 2001. Under the deregulation legislation, the generation portion of Dominion's Virginia jurisdictional operations will no longer be subject to cost-based rate regulation beginning in 2002. 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, under the deregulation legislation, Dominion may petition the Virginia Commission to terminate the capped rates after January 1, 2004. The capped rates may be terminated if the Virginia Commission finds that a competitive market for generation services exists within Dominion's service area. As discussed further in sections below, the deregulation legislation addressed divestiture, functional separation, regional transmission entities and other corporate relationships. It also 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. Technical amendments to the deregulation legislation were approved by the 2001 General Assembly. North Carolina The North Carolina General Assembly is exploring the future of electric service in North Carolina, including 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 the Public Utility Regulatory Policy Act of 1978. Deregulation Legislation -- Gas Industry Each of the three states in which Dominion has gas distribution operations has enacted or considered legislation regarding deregulation of natural gas sales at the retail level. Pennsylvania As early as 1984, large industrial customers in Pennsylvania began to buy natural gas supplies from third parties, rather than directly from local utilities. Local distributors transported these third-party gas supplies to the industrial facilities. Since that time, nearly all Pennsylvania industrial and large commercial customers have started buying natural gas from unregulated suppliers. In 1997, Dominion's Pennsylvania gas utility voluntarily launched an Energy Choice program for all of its retail consumers in Pennsylvania. Subsequently, in 1999, Pennsylvania enacted legislation mandating supplier choice for residential and small commercial customers. At December 31, 2000, approximately 106,000 customers had opted for Energy Choice in the Company's Pennsylvania service area. Ohio Large industrial customers in Ohio also began to source their own natural gas supplies in the mid-1980s, as interstate pipeline transportation services became more widely available. However, to date Ohio has not enacted legislation requiring supplier choice for residential and commercial natural gas consumers. Dominion has made significant progress in offering Energy Choice to customers on its own initiative, in cooperation with the Public Utilities Commission of Ohio. In 1997, Dominion's Ohio gas utility launched a pilot program, designed to make gas transportation service available to residential and small commercial customers, and to the suppliers that market gas to these customer classes. In 2000, the Energy Choice program was expanded to all 1.2 million customers in Dominion's Ohio service area. At December 31, 2000, approximately 35 Management's Discussion and Analysis of Financial Condition and Results of Operations (continued) 175,000 of Dominion's Ohio customers were participating in this open-access program. West Virginia At this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. The West Virginia Public Service Commission recently issued regulations to govern pooling services; these services are one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future. Virginia Retail Access Pilot Program In 1998, the Virginia Commission issued an order instructing Dominion and AEP- Virginia, Virginia's two largest investor-owned utilities, each to design and file a retail access pilot program relating to electric distribution in Virginia. During 1998 and 1999, Dominion worked with the Virginia Commission Staff to develop the plans for the size and scope of the program and the market price methodology. In 2000, the Virginia Commission approved Dominion's retail access pilot program and issued a final order on the interim rules governing pilot programs. Dominion began its pilot program in September 2000. In January 2001, the Virginia Commission established a proceeding to determine the permanent rules for retail access. 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, Dominion filed with the Virginia Commission an application for approval of a functional separation plan for its regulated electric utility operations. 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 power purchase contracts to Dominion Generation Corporation; . retention of Dominion's electric transmission and distribution assets and operations, 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 Dominion'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; and 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. 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, which begins a two-year phase in period in 2002. The rules govern how utilities which 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. Regional Transmission Entities/ Regional Transmission Organizations The deregulation legislation required 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 a RTE. In October 2000, Dominion filed its application with the Virginia Commission pursuant to the RTE regulations seeking authorization to transfer control of its electric transmission facilities to the Alliance Regional Transmission Organization (Alliance RTO). As discussed below, the formation of the Alliance RTO began according to FERC initiatives, but Dominion expects it to satisfy the RTE requirements under the Virginia deregulation legislation. In 1999, FERC issued 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 operating and participating in a RTO. Dominion, 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, Illinois Power, Commonwealth Edison Company of 36 Indiana, Commonwealth Edison Company, Ameren UE and Ameren CIPS subsequently requested FERC approval to join the Alliance RTO. Competition -- Wholesale Market Dominion sells electricity in the wholesale market under its market based sales tariff authorized by FERC but has agreed not to make wholesale power sales under this tariff to loads located within its service territory. During 2000, Dominion filed applications with FERC to make sales under its market-based sales tariff to loads within its Virginia service territory participating in its retail access pilot program and to amend its 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 Dominion's Virginia service territory, other than sales to loads participating in the retail access pilot program, are to be at cost-based rates accepted by FERC. Dominion's sales of oil and natural gas in wholesale markets are not regulated by the FERC. The deregulation of gas sales began through a multi-year schedule established under the Natural Gas Policy Act (NGPA) of 1978 and was completed under the Natural Gas Wellhead Decontrol Act of 1989. 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 reasonably expected to 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, Dominion's exposure to potentially stranded costs was comprised of: long-term purchased power 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. Dominion believes capped electric retail rates provided under the Virginia deregulation legislation present a reasonable opportunity to recover a substantial portion of its potentially stranded costs. In the absence of capped rates, at March 31, 1999, Dominion 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 Dominion's potentially stranded costs is subject to numerous risks including, among others, exposure to long- term power purchase commitment losses, future environmental compliance requirements, changes in tax laws, nuclear decommissioning costs, inflation, increased capital costs, and recovery of certain other items. See Notes 14, 21 and 22 to the Consolidated Financial Statements. Environmental Matters Dominion 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 and can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. To the extent environmental costs are incurred through June 30, 2007, in excess of the level currently included in electric retail Virginia jurisdictional rates, the amounts will be reflected in Dominion's results of operations. After that date, recovery through regulated rates may be sought for only those environmental costs related to regulated electric transmission and distribution operations. Dominion may seek recovery through regulated rates for environmental expenditures related to regulated gas transmission and distribution operations. Environmental Protection and Monitoring Expenditures Dominion incurred approximately $94 million, $78 million, and $72 million of expenses (including depreciation) during 2000, 1999, and 1998, respectively, in connection with the use of environmental protection and monitoring activities, and expects these expenses to be approximately $91 million in 2001. In addition, capital expenditures related to environmental controls were $214 million, $84 million, and $22 million for 2000, 1999, and 1998, respectively. The amount estimated for 2001 for these expenditures is $200 million. Clean Air Act Compliance The Clean Air Act requires Dominion to reduce its emissions of SO\\2\\ and NO\\X\\, which are gaseous by-products of fossil fuel combustion. The Clean Air Act also requires Dominion to obtain operating permits for all major emissions- emitting facilities. Permit applications have been submitted for Dominion'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 a third party. In September 1998, the EPA adopted a rule requiring 22 states, including Virginia, West Virginia, Illinois and North Carolina, to reduce and cap ozone- season NO\\X\\ emissions beginning in May 2003. A recent court ruling has extended the compliance date to May 31, 2004. In response to these requirements, Dominion plans to install NO\\X\\ reduction equipment at its coal-fired generating facilities at an estimated capital cost of approximately $635 million over the next several years. Whether these costs are actually incurred is dependent on the outcome of pending litigation of these rules, the implementation plans adopted by the states in which Dominion operates and Dominion's agreement in principle with the federal government as discussed below. Evaluation and planning of future projects to comply with SO\\2\\ and NO\\X\\ reduction requirements are ongoing and will be influenced by changes in the regulatory environment, availability of SO\\2\\ allowances, and emission control technology. 37 Management's Discussion and Analysis of Financial Condition and Results of Operations (continued) During 2000, Dominion received a Notice of Violation from the EPA alleging that it failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at the Mt. Storm Power Station in West Virginia. Management believes that Dominion has obtained the permits necessary in connection with its generating facilities. Dominion has reached an agreement in principle with the federal government and the state of New York concerning the implementation of certain additional environmental controls at its 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 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 Dominion's coal-fired generating stations in Virginia and West Virginia. Dominion had already committed to a substantial portion of the $1.2 billion expenditures for SO\2\ and NO\X\ emissions controls as discussed above. Although Dominion has reached an agreement in principle, the terms of a final binding settlement are still under negotiation. See Note 22 to the Consolidated Financial Statements. 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 Dominion. Recently Issued Accounting Standards In June 2000, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 Company's balance sheet at their fair value effective January 1, 2001. Dominion has determined that certain contracts used in its operations will be subject to fair value accounting under SFAS No. 133. A substantial portion of these contracts is used by Dominion in its production and delivery of energy to its customers and the contracts involve various hedging strategies. In addition to these commodity contracts, Dominion uses interest rate swaps to manage its cost of capital. The Company will record one-time, non-operating after-tax charges to net income of approximately $1 million and other comprehensive income of approximately $180 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, the Company's 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. Restructuring and Other Acquisition-Related Charges Subsequent to its acquisition of CNG, Dominion 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. For the year ended December 31, 2000, the Company recognized $460 million of restructuring costs and other acquisition-related costs. See Note 6 to the Consolidated Financial Statements. The 2000 workforce reductions and other restructuring actions should reduce future annualized operating costs by approximately $102 million that would otherwise have been incurred. Business Opportunities and Other Operations Because Dominion's industry is rapidly changing, there are many opportunities for acquisitions of assets and business combinations. Dominion investigates any opportunity that may increase shareholder value and build on existing businesses. Dominion has participated in the past, and its security holders may assume that at any time Dominion may be participating, in bidding or other negotiating processes for such transactions. Such participation may or may not result in a transaction for Dominion. However, any such transaction that does take place may involve consideration in the form of cash, debt or equity securities and may involve payment of a premium over book or market values. Such transactions or payments could affect the market prices and rates for Dominion's securities. Exploration and Production Operations Dominion continues to focus on maintaining and increasing earnings from oil and gas properties primarily through development and acquisition activities and operating efficiencies. Dominion will continue to seek opportunities to optimize the value of its reserves through the convergence of its gas and electric products and maximization of its gas storage facilities. In addition, sharing past experiences and sound business practices developed over time in oil and gas operations should help improve operational efficiencies and minimize finding, developing and lifting costs. Additional efficiencies are being achieved by elimination of duplicate administrative functions. 38 Due to unprecedented supply and demand factors, natural gas prices are now at levels not seen in years. While increased prices can benefit Dominion, where over 80 percent of reserves are natural gas, higher prices also will impact the future cost of acquiring, finding, developing and producing reserves. Higher oil and gas prices have impacted both the availability and cost of oilfield equipment and materials, such as rigs, boats and drill pipe. Independent Power Production Operations Dominion's future focus in its power generation business is to acquire and develop additional power generation in the MAIN to Maine region. The region begins at the Mid-America Interconnected Network (MAIN) and extends northeastward through Maine. MAIN includes electric service territories of the upper Midwest. Dominion is benefiting from the CNG acquisition as it plans to develop natural gas-fired power generation facilities along its natural gas pipeline system. Dominion has identified a number of potential development sites in Ohio, Pennsylvania, New York, West Virginia and Virginia. Telecommunications Operations The Company plans to expand its telecommunications operations as a competitive provider of telecommunications service, including the development of a facilities-based high-bandwidth capacity telecommunications network throughout the eastern United States. Initially, Dominion will build its network through the acquisition of dark fiber capacity on existing third-party networks. It expects future growth of its network to occur through joint development projects on third-party rights of way. The Company anticipates financing these expansion plans through a financing structure that will allow Dominion to deconsolidate its telecommunications business, while maintaining management flexibility for future growth. Dominion expects to close the approximately $700 million financing plan in early 2001 and will use the proceeds to fund telecommunications expansion. Divestitures Under the SEC's order approving the CNG acquisition, Dominion must divest itself of DCI within three years. No formal plan of divestiture has been adopted. However, Dominion has sold certain portions of its financial services businesses. Until DCI is sold, Dominion will continue to operate these financial service activities and be subject to their risks. Restructuring of Contracts with Non-Utility Generating Facilities 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. Nuclear Relicensing In June 2001, Dominion plans to file applications with the NRC to renew the operating licenses for its Surry and North Anna nuclear stations. The technical work required to support a license renewal application was completed in 2000. The renewal of the license will extend the plants' useful lives by 20 years. See Note 14 to the Consolidated Financial Statements. Effect of Changes in Natural Gas and Oil Prices Dominion's operations are impacted by changes in energy commodity prices. To the extent energy commodities are sold by one of Dominion's cost-of-service rate regulated utilities, the cost of such commodities are generally recovered through rates. For sales of Dominion's production of natural gas and oil and for sales of energy commodities through nonregulated subsidiaries, price changes impact Dominion's sales revenue. However, Dominion has established an enterprise risk management function to manage such price risk exposures. Market Rate Sensitive Instruments and Risk Management Dominion is exposed to market risk because it utilizes 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 interest rates, commodity prices and equity security prices as described below. Interest rate risk generally is related to Dominion's outstanding debt as well as its commercial, consumer, and mortgage lending activities. Commodity price risk is experienced in Dominion's electric operations, gas production and procurement operations, and energy marketing and trading operations due to the exposure to market shifts for prices received and paid for natural gas and electricity. Dominion uses derivative commodity instruments to hedge price exposures for these operations. Dominion is exposed to equity price risk through various portfolios of equity securities. Dominion uses the sensitivity analysis methodology to disclose the quantitative information for interest rate and commodity price risks. The sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in interest rates and commodity prices. 39 Management's Discussion and Analysis of Financial Condition and Results of Operations (continued) Interest Rate Risk Dominion manages its interest rate risk exposure by maintaining a mix of fixed and variable rate debt. In addition, Dominion enters into interest rate sensitive derivatives. Examples of these derivatives are swaps, forwards and futures contracts. In addition, Dominion, through subsidiaries, retains ownership in mortgage investments, including subordinated bonds and interest- only residual assets retained at securitization of mortgage loans originated and purchased. For financial instruments outstanding at December 31, 2000, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $40 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 1999, would have resulted in a decrease in annual earnings of $31 million. Commodity Price Risk -- Non-Trading Activities Dominion manages the price risk associated with purchases and sales of natural gas and oil by selecting derivative commodity instruments including futures, forwards, options, swaps, and collars. For sensitivity analysis purposes, the fair value of Dominion's oil and natural gas derivative financial contracts are determined from models which take into account the market prices of oil and natural gas in future periods, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange. Dominion has determined a hypothetical change in fair value for its oil and natural gas derivative financial contracts assuming a 10% unfavorable change in market prices. This hypothetical 10% change in market prices would have resulted in a decrease in fair value of approximately $56 million and $20 million as of December 31, 2000 and December 31, 1999, respectively. The impact of a change in oil and natural gas commodity prices on Dominion's oil and natural gas derivative financial contracts at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from oil and natural gas financial derivative contracts used for hedging purposes, to the extent realized, should generally be offset by recognition of the hedged transaction. Commodity Price Risk -- Trading Activities As part of its strategy to market energy from its generation capacity and to manage related risks, Dominion manages a portfolio of derivative commodity contracts held for trading purposes. These contracts are sensitive to changes in the prices of natural gas and electricity. Dominion employs established policies and procedures to manage the risks associated with these price fluctuations and uses various commodity instruments, such as futures, swaps and options, to reduce risk by creating offsetting market positions. In addition, Dominion seeks to use its generation capacity, when not needed to serve customers in its service territory, to satisfy commitments to sell energy. A 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 its commodity contracts, held for trading purposes, as of December 31, 2000 and 1999, respectively. Equity Price Risk Dominion is subject to equity price risk due to marketable securities held as investments and in trust funds. In accordance with current accounting standards, the marketable securities are reported on the balance sheet at fair value. The following table presents descriptions of the equity securities held by Dominion at December 31, 2000 and 1999.
2000 1999 - ---------------------------------------------------------------------------------- Fair Fair (millions) Cost Value Cost Value - ---------------------------------------------------------------------------------- Trading: Short-term marketable securities $275 $275 $ 1 $ 2 Other than trading: Marketable securities 134 118 134 126 Nuclear decommissioning trust investments 279 549 274 565 ==================================================================================
Risk Management Policies Dominion has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the price risk management policies of all subsidiaries. Dominion maintains credit policies that 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. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Dominion 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. 40 [LOGO] Notes to Consolidated Financial Statements Note 1 | Nature of Operations General Organization and Legal Description Dominion Resources, Inc. (Dominion or the Company) is a holding company headquartered in Richmond, Virginia. Its principal subsidiaries are Virginia Electric and Power Company (Virginia Power) and, with the completion of the acquisition on January 28, 2000, Consolidated Natural Gas Company (CNG). Dominion is subject to the Public Utility Holding Company Act of 1935 (1935 Act). Virginia Power 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. Virginia Power sells electricity to approximately 2.1 million retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. Virginia Power engages in off-system wholesale purchases and sales of electricity and purchases and sales of natural gas beyond the geographic limits of its retail service territory. CNG operates in all phases of the natural gas industry, including exploration for and production of oil and natural gas in the United States. Its regulated retail gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Its interstate gas transmission pipeline system services each of its distribution subsidiaries, non-affiliated utilities and end use customers in the Midwest, the Mid-Atlantic and the Northeast states. CNG's exploration and production operations are conducted in several of the major gas and oil producing basins in the United States, both onshore and offshore. CNG also holds equity investments in energy activities in Australia, which are held for sale. The Company's other major subsidiaries are Dominion Energy, Inc. (DEI) and Dominion Capital, Inc. (DCI). DEI is engaged in independent power production and the acquisition and production of natural gas and oil reserves. In Canada, DEI is engaged in natural gas exploration, production and storage. DCI is Dominion's financial services subsidiary. DCI's primary business is financial services which includes commercial lending and residential mortgage lending. See Note 6 for a discussion of management's strategy to exit and windup DCI's businesses as ordered by the Securities and Exchange Commission (SEC) under the 1935 Act. In mid-1998 Dominion sold East Midlands Electricity, plc (East Midlands), an electricity distribution and supply company in the United Kingdom. Dominion created a subsidiary service company under the 1935 Act, Dominion Resources Services, Inc. (Services), which provided certain services to Dominion's operating subsidiaries. During 2000, CNG also had a service company. Effective January 1, 2001, the two service companies were combined into one service company. Dominion manages its operations based on the following operating segments: Dominion Energy, Dominion Delivery and Dominion Exploration & Production. In addition, Dominion also reviews the financial services business of DCI and Corporate Operations as segments. While Dominion manages its daily operations as described above, assets remain wholly owned by its legal subsidiaries. For more information on business segments, see Note 27. "Dominion" or the "Company" is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one of Dominion's consolidated subsidiaries or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries. Note 2 | Significant Accounting Policies General The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. The consolidated financial statements represent the accounts of the Company after the elimination of intercompany transactions. The Company follows the equity method of accounting for investments in partnerships and corporate joint ventures when the company is able to influence the financial and operating policies of the investee. For all other investments, the cost method is applied. Accounting for the utility businesses conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by federal agencies and the commissions of the states in which the utility business operates. Revenue Revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and include amounts yet to be billed to customers. Revenue from trading activities include 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. Dividend income on securities owned is recognized on the ex-dividend date. 41 Notes to Consolidated Financial Statements (continued) Fuel, Net Fuel, net includes the cost of fossil fuel and nuclear fuel used in electric generation 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. Practically all of Dominion's electric service 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 revenues. Fuel, net includes the effect of this deferral accounting and may therefore show expenses that are marginally higher or lower than the actual cost of fuel consumed during the period. Unrecovered Gas Costs Where permitted by regulatory authorities, the Company defers the difference between the cost of gas (including certain related costs) and the amount of such costs included in current customer rates. The differences are accounted for as either unrecovered gas costs or amounts payable to customers. Unrecovered amounts are recognized as purchased gas expenses in future periods when the costs are recovered through adjusted rates. Goodwill, Net Goodwill is the excess of the cost of net identifiable assets acquired in business combinations over their fair value. It is amortized on a straight-line basis over periods up to 40 years. Utility and Other Plant Property, plant and equipment are stated at cost. Additions and betterments are charged to the property accounts at cost. Maintenance, repairs and related costs are charged principally to expense as incurred. Impairment of Long-Lived Assets Whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets, including goodwill, may not be recoverable, an evaluation for impairment is performed. Such evaluations may consider various analyses, including undiscounted future cash flows attributable to the assets. Exploration and Production Properties Effective with the acquisition of CNG on January 28, 2000, Dominion changed its method of accounting for its oil and gas exploration and production activities to the full cost method of accounting. Previously, the Company had accounted for these activities, which were primarily directed toward development and extraction rather than exploration, using the successful efforts method of accounting. Prior periods have been restated. The effect of restatement on 1999 and 1998 was not material. For more information on the accounting change, see Note 3. Under the full cost method, all costs directly associated with property acquisition, exploration, and development activities are capitalized, with the principal limitation that such amounts not exceed the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves (the "ceiling test"). If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. The ceiling test is performed separately for each cost center, with cost centers established on a country-by-country basis. Depreciation, Depletion and Amortization Depreciation and amortization are recorded over the estimated service lives of plant assets by application of the straight-line method or, in the case of gas and oil producing properties, the unit-of-production method. The cost of depreciable gas utility and electric 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. Owned nuclear fuel is amortized on a unit-of-production basis sufficient to amortize fully, over the estimated service life, the cost of the fuel plus permanent storage and disposal costs. Estimated useful lives of the Company's property, plant and equipment are as follows: production 10-66 years, transmission 10-77 years, distribution 10-66 years, storage 10-69 years, and other 5-50 years. Under the full cost method of accounting, amortization is also accrued on estimated future costs to be incurred in developing proved gas and oil reserves, and on estimated dismantlement and abandonment costs net of projected salvage values. However, the costs of investments in unproved properties and major development projects are excluded from amortization until it is determined whether or not proved reserves are attributable to such properties. Capitalized Interest Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part of the asset and is depreciated over the asset's estimated useful life. In 2000, 1999 and 1998, $22 million, $30 million and $10 million of interest cost was capitalized, respectively. Income Taxes Dominion and its subsidiaries file a consolidated federal income tax return. Deferred income taxes are provided for all significant temporary differences between the financial and tax basis of assets and liabilities. The regulatory treatment of temporary differences can differ from the requirements of Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. Accordingly, a regulatory asset has been recognized if it is probable 42 that future revenues will be provided for the payment of deferred tax liabilities. Dominion accounts for investment tax credits related to utility plant subject to cost-based regulation under the "deferral method," which provides for the amortization of these credits over the service lives of the property giving rise to the credits. Regulatory Assets and Liabilities Generally, Dominion uses the same accounting policies and practices used by nonregulated companies for financial reporting under generally accepted accounting principles. However, regulatory authorities may order an accounting treatment different from that used by nonregulated companies to determine the rates charged to customers. When this occurs, certain utility income and expenses are deferred as regulatory assets and liabilities. See Notes 7 and 12 for additional information on regulatory assets and liabilities and the impact of legislation on continued application of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Foreign Currency Translation Dominion translates foreign currency financial statements by adjusting balance sheet accounts using the exchange rate at the balance sheet date and income statement accounts using the average exchange rate for the year. Translation gains and losses are recorded in shareholders' equity as a component of accumulated other comprehensive income. Gains and losses resulting from the settlement of transactions in a currency other than the functional currency are reflected in income. Amortization of Debt Issuance Costs Dominion defers and amortizes the expenses incurred in the issuance of long-term debt, together with premiums and discounts associated with such debt, over the lives of the respective issues. Any gains or losses resulting from the refinancing of debt allocable to utility operations that are subject to cost- based regulation are also deferred and amortized over the lives of the new issues of long-term debt as permitted by regulatory commissions. In addition, gains or losses resulting from the redemption of debt allocable to utility operations that are subject to cost-based regulation without refinancing are amortized over the remaining lives of the redeemed issues. Investment Securities Dominion accounts for and classifies investments in equity securities that have readily determinable fair values and for all investments in debt securities based on management's intent. The investments are classified into three categories. Debt securities which are intended to be held to maturity are classified as held-to-maturity securities and reported at amortized cost. Debt and equity securities purchased and held with the intent of selling them in the current period are classified as trading securities and are reported at fair value with unrealized gains and losses included in earnings. Debt and equity securities that are neither held-to-maturity nor trading are classified as available-for-sale securities. These are reported at fair value with unrealized gains and losses reported in shareholders' equity, as a component of accumulated other comprehensive income, net of tax. For a discussion of the treatment for securities held in nuclear decommissioning trusts and classified as available- for-sale, see Note 14. Mortgage Loans Held for Sale Mortgage loans held for sale consist of mortgage loans secured by single family residential properties. Any price premiums or discounts on mortgage loans, including any capitalized costs or deferred fees on originated loans, are deferred as an adjustment to the cost of the loans and are therefore included in the determination of any gains or losses on sales of the related loans. Mortgage loans held for sale are carried at the lower of cost or market value. Loans Receivable, Net and Finance Receivables Held for Sale Loans receivable and finance receivables held for sale are stated at their outstanding principal balance, net of the allowance for credit losses and any deferred fees or costs. Origination fees, net of certain direct origination costs, are deferred and recognized as an adjustment of the yield of the related loans receivable. The allowance for credit losses is established through provisions for credit losses charged against income. Loans and finance receivables deemed to be uncollectible are charged against the allowance for credit losses, and subsequent recoveries, if any, are credited to the allowance. At December 31, 2000 and 1999, the allowance for credit losses for loans receivable, net was $61 million and $47 million, respectively. Gain on Sale of Loans Gain on sale of loans represents the present value of amounts based on the difference between the interest rate to be received on the mortgage loans sold and the interest rate to be paid to investors participating in securitizations, after considering estimated prepayments, credit losses, servicing costs, and non-refundable fees and premiums. Securitizations involve selling mortgage loans to an unconsolidated special purpose trust in exchange for cash proceeds and an interest in the loans securitized (residual assets). Gains on the sale of loans are recognized on the settlement date. Residual assets may include interest-only strips and servicing rights. Interest-only residual assets are recorded based on the net present value of the projected cash flows, using management's best estimates of the key assumptions, including credit losses, prepayment speeds, forward yield curves, and discount rates commensurate with the risks involved. Loan Servicing Rights Dominion recognizes as separate assets its rights to service mortgage loans. Mortgage servicing rights are recorded when purchased or when mortgage loans are originated and subsequently sold or securitized with the servicing rights retained. Servicing rights are recorded based on the relative fair value of the mortgage loans and the servicing rights. The fair value of the servicing rights 43 Notes to Consolidated Financial Statements (continued) is determined based on market prices under comparable servicing sales contracts or the present value of estimated future cash flows. Dominion assesses the impairment of mortgage servicing rights based on the fair value of those rights, and any impairment is recognized through a valuation allowance. Mortgage loans serviced require regular monthly payments from borrowers. Income on loan servicing is generally recorded as payments are collected and is based on a percentage of the principal balance of loans serviced. Loan servicing expenses are charged to operations when incurred. Mortgage Investments Mortgage investments consist of subordinated bonds and interest-only residual assets retained at securitization of mortgage loans. Mortgage investments are classified as trading securities. Interest-only strip residual assets are amortized in proportion to the estimated income received but are analyzed quarterly to determine whether prepayment experience, losses and changes in the interest rate environment have had an impact on the valuation. Expected cash flows of the underlying loans sold are reviewed based upon current economic conditions and the type of loans originated and are revised as necessary. Derivatives -- Other Than Trading Dominion utilizes futures and forward contracts and derivative financial instruments, including swaps, caps and collars, to manage exposure to fluctuations in interest rates, lease payments, and natural gas and electricity prices. These futures, forwards and derivative financial instruments are deemed effective hedges when the item being hedged and the underlying financial or commodity instrument show strong historical correlation. Dominion uses deferral accounting to account for futures, forwards and derivative instruments which are designated as hedges. Under this method, gains and losses (including the payment of any premium) related to effective hedges of existing assets and liabilities are recognized in earnings in conjunction with earnings of the designated asset or liability. Gains and losses related to effective hedges of firm commitments and anticipated transactions are included in the measurement of the subsequent transaction. Cash flow from derivatives designed as hedges are reported in net cash flow from operating activities. Derivatives -- Trading The fair value method, which is used for those derivative transactions which do not qualify for settlement or deferral accounting, requires that derivatives are carried on the balance sheet at fair value, with changes in that value recognized in earnings or common shareholders' equity. As part of Dominion's strategy to market energy from its generation capacity and to manage the risks related thereto, it enters into contracts for the purchase and sale of energy commodities. Dominion uses the fair value method for its trading activities. Options, swaps and future contracts are marked to market with resulting gains and losses reported in earnings. Forward contracts, initiated for trading purposes, are also marked to market with resulting gains and losses reported in earnings. For swaps, forward contracts, and options, market value reflects management's 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 exchange closing prices. 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 revenues, 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 Operating revenue. Cash flow from trading activities is reported in net cash flow from operating activities. Other Derivatives Dominion uses total return swaps to accumulate loans and securities for future sale as collateralized debt obligation securities. Gains and losses from the settlements and sale of total return swaps are recorded as Operating revenue and income -- Other. Total return swaps are marked to market with the corresponding unrealized gains and losses also recorded in Operating revenue and income -- Other. Cash flow from total return swaps are reported in net cash flow from operating activities. As of December 31, 2000, all total return swaps relating to the above have been terminated. Dominion has used total return equity swaps to reacquire shares of its outstanding common stock. Dominion has recorded all amounts received or paid in 2000 under such arrangements as either increases or decreases to equity. The net of amounts paid and amounts received under interest rate swaps is reported as interest expense in the Consolidated Statement of Income. See Note 4 for discussion of recently issued accounting standards and their impact on the Company's accounting for derivatives in 2001. 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, accounts payable included the net effect of checks outstanding but not yet presented for payment of $171 million and $61 million, respectively. For purposes of the Consolidated Statements of Cash Flows, Dominion considers cash and cash equivalents to include cash on hand and temporary investments purchased with a maturity of three months or less. 44 Reclassification Certain amounts in the 1999 and 1998 Consolidated Financial Statements have been reclassified to conform to the 2000 presentation. Note 3 | Accounting Changes Accounting for Net Periodic Pension Cost Effective January 1, 2000, Dominion adopted a company-wide method of calculating the market related value of pension plan assets used to determine the expected return on pension plan assets, a component of net periodic pension cost. Under the new method, the market related value of pension plan assets reflects the difference between actual investment returns and expected investment returns evenly over a four-year period. Prior to Dominion's acquisition of CNG, each company used different methods to determine the "calculated value" of the market related value of pension plan assets. The previous Dominion method recognized interest, dividends and realized gains immediately and deferred unrealized gains and losses evenly over a five-year period. The former CNG method calculated the market related value of pension plan assets as the average of market values at the end of each of the preceding four years, with appropriate adjustments for receipts, disbursements, and investment income during the period. Dominion believes that the new method is preferable to continuing to use either or both of the former methods as the new method enhances the predictability of expected return on pension plan assets, provides consistent treatment of all investment gains and losses, and results in calculated market related pension plan asset values that are closer to market value as compared to values calculated under the previous methods. The $21 million cumulative effect of the change on prior years (net of income taxes of $11 million) is included in income for the year ended December 31, 2000. The effect of the change on 2000 was to increase income before extraordinary item and cumulative effect of a change in accounting principle by $11 million ($0.05 per share-basic and diluted) and net income by $32 million ($0.14 per share-basic and diluted). Retroactive application of the new method, on a pro forma basis, would not have materially changed Dominion's net income for 1999 or 1998. Accounting for Oil and Gas Activities Effective upon the acquisition of CNG on January 28, 2000, Dominion changed its method of accounting for oil and gas exploration and production activities to the full cost method of accounting. Previously, Dominion accounted for these activities, which were primarily directed toward development and extraction rather than exploration, using the successful efforts method of accounting. While the Company's previous method of accounting was in accordance with generally accepted accounting principles, the Company believes that the full cost method of accounting is preferable for its merged exploration and production operations. CNG's exploration and production business is historically larger than Dominion's and consists of substantial investments in exploration activities. CNG uses the full cost method of accounting for its exploration and production activities which management believes better reflects the economics associated with the discovery and development of oil and gas reserves. It is anticipated that the strategic direction of the combined exploration and production operations will be consistent with CNG's past operations, thus supporting the adoption of the full cost method of accounting. Prior year financial statements have been restated to reflect this change on a retroactive basis. The effect of the accounting change on income in 2000, and on income as previously reported for 1999 and 1998 is not significant. The balances of retained earnings for 1999 and 1998 have been restated for the effect (net of income taxes) of applying retroactively the new method of accounting. Note 4 | 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 Company's balance sheet at their fair value effective January 1, 2001. The Company holds certain commodity contracts for trading purposes that are currently subject to fair value accounting under Emerging Issues Task Force Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The Company determined that certain additional contracts will be subject to fair value accounting under SFAS No. 133. A substantial portion of these contracts is used by Dominion in its production and delivery of energy to its customers and involves various hedging strategies. In addition to these commodity contracts, Dominion 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 Dominion is hedging the changes in the 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 Dominion 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 recorded 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 (e.g., anticipated sales). As amounts 45 Notes to Consolidated Financial Statements (continued) 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 $180 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 the FASB, continues to develop interpretive guidance. The DIG has not yet concluded on certain issues that could ultimately impact the application of the standard. Note 5 | Acquisitions and Divestitures Consolidated Natural Gas Company On January 28, 2000, Dominion acquired all of the outstanding shares of CNG common stock for a purchase price of $6.4 billion, consisting of approximately 87 million shares of Dominion common stock valued at $3.5 billion and approximately $2.9 billion in cash . Dominion has accounted for the acquisition of CNG's operations that are not subject to cost-based rate regulation, primarily its oil and gas exploration and production operations, using the purchase method of accounting. For CNG's interstate pipeline and local gas distribution businesses that are subject to cost-based rate regulation, Dominion has accounted for the acquisition in accordance with SFAS No. 71. The purchase price has been allocated to assets acquired and liabilities assumed based on the estimated fair value of those assets and liabilities as of the date of the acquisition. Such allocation was based on the Company's evaluations. The excess of the purchase price over the fair value of CNG's operations not subject to cost-based rate regulation and the historical carrying value of CNG's operations subject to cost of service rate regulation resulted in goodwill of $3.5 billion. The goodwill is being amortized on a straight-line basis over the weighted average useful lives of CNG's gas utility plant and equipment, a period approximating 40 years. As of December 31, 2000, $77 million of amortization associated with the goodwill had been recognized. The results of operations of CNG for the period January 28, 2000 through December 31, 2000 are included in the accompanying consolidated financial statements . Initially, the allocation of the purchase price included estimated values for amounts expected to be realized from the sale of Virginia Natural Gas (VNG) and CNG International, which were classified as Net assets held for sale. In addition, the allocation of the purchase price provided for recognition of liabilities associated with change of control payments triggered by the acquisition of CNG under certain employment contracts ($31 million) and seismic licensing agreements ($26 million). The Company has made adjustments during 2000 to the allocation of the purchase price for changes in preliminary assumptions and analyses based on receipt of additional information, to reflect the following: . actuarial valuations of CNG's pension and other postretirement benefit plan obligations and related plan assets; and . actual proceeds realized from the disposition of VNG and CNG International's Argentine investments. Net assets held for sale at December 31, 2000 included the unsold portion of CNG International, which is primarily its equity investment in Australian energy activities. The December 31, 2000 consolidated balance sheet includes $ 73 million representing the carrying amount of CNG International, which includes the effects of $12 million of interest and $4 million of operating losses capitalized during the post-acquisition period. The following unaudited pro forma combined results of operations for the years ended December 31, 2000 and 1999 have been prepared assuming the acquisition of CNG had occurred at the beginning of each period. The pro forma results are provided for information only. The results are not necessarily indicative of the actual results that would have been realized had the acquisition occurred on the indicated date, nor are they necessarily indicative of future results of operations of the combined companies.
Year ended December 31, 2000 1999 - ---------------------------------------------------------------------------------------------------------------------- (millions, except per share amounts) As Reported Pro Forma As Reported Pro Forma - --------------------------------------------------------------------------------------------------------------- Consolidated Results Revenue $9,260 $9,627 $5,520 $8,390 Income before extraordinary item and cumulative effect of a change in accounting principle $ 415 $ 475 $ 552 $ 546 Net income $ 436 $ 496 $ 297 $ 291 Earnings per share--basic: Income before extraordinary item and cumulative effect of a change in accounting principle $ 1.76 $ 1.99 $ 2.88 $ 2.29 Net income $ 1.85 $ 2.08 $ 1.55 $ 1.22 Average shares--basic 235.2 238.9 191.4 238.4 Earnings per share--diluted: Income before extraordinary item and cumulative effect of a change in accounting principle $ 1.76 $ 1.98 $ 2.81 $ 2.22 Net income $ 1.85 $ 2.07 $ 1.48 $ 1.15 Average shares--diluted 235.9 240.0 191.4 238.4 ==============================================================================================================
46 Millstone Nuclear Power Station Dominion has reached an agreement to acquire the Millstone Nuclear Power Station located in Waterford, Connecticut. Dominion is acquiring the three-unit station from subsidiaries of Northeast Utilities and other owners for a total purchase price of approximately $1.3 billion, including approximately $1.19 billion for plant assets and $105 million for fuel. The acquisition will include 100% ownership interest in Unit 1 and Unit 2, and a 93.47% ownership interest in Unit 3, for a total of 1,954 Mw of generating capacity. Unit 1 is being decommissioned and is no longer in service. Dominion will assume the decommissioning trusts for the three units and expects the trusts to be fully funded to the regulatory minimum at the time of the closing. Divestitures In October 2000, Dominion completed the sale of VNG to AGL Resources Inc. Cash proceeds from the sale were $533 million. After Dominion acquired CNG in the first quarter of 2000, CNG committed to a plan to sell CNG International as part of its desire to focus on the United States oil and gas markets. In October 2000, CNG International completed the sale of its Argentine assets to Sempra Energy International for $145 million. In September 2000, Dominion completed the sale of its 80 percent interest in Corby Power Limited (Corby) to PowerGen plc. for 52.5 million pounds sterling ($78 million at December 31, 2000). Corby is the owner of a 350-megawatt natural gas-fired facility about 90 miles north of London, England. The sale of Corby resulted in an after-tax gain of $13 million ($0.05 per share). In 1999, Dominion reached an agreement to sell its interests in approximately 1,200 megawatts of gross generation capacity located in Latin America. Duke Energy International purchased the interests for approximately $405 million. The Company completed the sale of its interests in Belize and Peru in November 1999. In 2000, Dominion completed the sale of its interests in the generation capacity located in Argentina and Bolivia. Note 6 | Restructuring and Acquisition-Related Activities General As a result of the CNG acquisition and Dominion's desire to focus its businesses in the MAIN to Maine area of the United States, Dominion is divesting certain businesses. The region begins at the Mid-America Interconnected Network (MAIN) and extends north-eastward through Maine. MAIN includes electric service territories of the upper Midwest. In addition, Dominion and its subsidiaries developed and began the implementation of a plan to restructure the operations of the combined companies. The restructuring plan included an involuntary severance program, a voluntary early retirement program (ERP) and a transition plan to consolidate operations after the CNG acquisition. For the year ended December 31, 2000, Dominion recognized $460 million of restructuring and other acquisition-related costs as follows:
(millions) - ---------------------------------------------------------------------------- Severance liability accrued $ 70 Commodity contract losses 55 Information technology related costs 35 Lease termination and restructuring 14 DCI exit strategies 172 ERP benefit costs 114 Curtailment gains (see Note 21) (26) Other, net 26 - ---------------------------------------------------------------------------- Total restructuring costs $460 - ---------------------------------------------------------------------------- Severance paid $ 41 - ---------------------------------------------------------------------------- Ending severance liability $ 29 - ---------------------------------------------------------------------------- Positions eliminated at December 31, 2000 679 Estimated positions yet to be eliminated 89 ERP participants 860 ============================================================================
Employee Severance Programs Dominion established a comprehensive involuntary severance package for salaried employees impacted by workforce reductions. Severance payments are based on the individual's base salary and years-of-service at the time of termination. In addition, severance payments are being provided to employees at DCI (and certain subsidiaries of DCI) who are terminated as part of Dominion's implementation of its strategy to exit certain businesses of DCI. Change in Risk Management Strategy During the first quarter of 2000, Dominion implemented a new hedging strategy for its combined operations. Under its new strategy, Dominion created an enterprise risk management group with responsibility for managing Dominion's aggregate energy portfolio, including the related commodity price risk, across its consolidated operations. Previously, individual business segments managed their respective energy portfolios and related price risk exposure on a stand- alone basis. Dominion management believes this new structure should result in more effective risk management with the objective of maximizing the value of Dominion's diversified energy portfolio and market opportunities. As part of the implementation of the new strategy, management evaluated CNG's hedging strategy associated with its oil and gas operations in relation to Dominion's combined operations. As a result of the evaluation, CNG designated its portfolio of derivative contracts that existed at January 28, 2000 as held for purposes other than hedging for accounting purposes. This action required a change to mark-to-market accounting where derivative contracts are carried at fair value in the balance sheet with any future unrealized gains and losses included in the determination of net income. In addition, CNG entered into offsetting contracts for those contracts in the January 28, 2000 portfolio that would not be 47 Notes to Consolidated Financial Statements (continued) settled during the first quarter of 2000. Due to these offsetting contracts, absent any not yet identified future losses from credit risk exposure, no additional material losses are expected to be realized as these derivative contracts mature through 2003. Early Retirement Program On January 28, 2000, Dominion announced an early retirement program. This program was a voluntary program for all salaried employees of Dominion, excluding officers and employees of DCI, VNG and CNG International. The early retirement option provides up to three additional years of age and three additional years of employee service for benefit formula purposes, subject to age and service maximums under the Company's postretirement medical and pension plans. Qualifying salaried employees and employees covered by several collective bargaining agreements of CNG and its participating subsidiaries who had attained age 52 and completed at least 12 years of service as of July 1, 2000 were eligible under the ERP. For Dominion's other participating subsidiaries, qualifying employees who had attained age 52 and completed at least 5 years of service as of July 1, 2000 were eligible under the ERP. Certain ERP participants will also receive benefits under the involuntary severance package, which are subject to reduction as a result of coordination with additional benefits provided by the ERP. Dominion Capital DCI is a diversified financial services company. Its principal subsidiaries are: . First Source Financial, LLP (First Source), a provider of financial services to middle market companies; . First Dominion Capital LLC, (First Dominion Capital) an integrated merchant banking and asset management business; . Saxon Mortgage, Inc. and its affiliates (Saxon), are involved in the origination, purchase and servicing of single-family residential mortgage loans; and . Dominion Lands, a developer of real estate projects. With the acquisition of CNG, Dominion became a registered public utility holding company subject to the requirements of the 1935 Act. One such requirement restricts investment in non-regulated businesses which are not functionally related to the public utility business. As a result, the SEC order authorizing the CNG acquisition required divestiture of DCI's financial services businesses within three years. As of December 31, 2000, Dominion had implemented exit strategies for certain DCI businesses. During the second quarter of 2000, management adopted a strategy to exit certain businesses of DCI and to de-emphasize the remaining components of the businesses that are expected to be retained or possibly held only as long as necessary to wind up affairs. At this time, the Company does not have a formal plan of disposal for substantive portions of the DCI segment and does not expect to dispose of all such portions of the business within one year. Management has continued to monitor and evaluate its investments in its financial services and real estate businesses. In 2000, Dominion recognized impairment losses of $291 million, of which $172 million was determined to be attributable to Dominion's exit strategy rather than other factors and are included in Restructuring and other acquisition- related costs. The remaining $119 million of impairment charges are related to normal operations of DCI. These charges, net of related income taxes of $105 million, reduced net income by $186 million for 2000. These amounts were recorded and derived from: . a $106 million impairment at Saxon concerning its interest-only residual assets and servicing assets; . additional provisions of $36 million for loan losses applicable to the loans receivable at First Source and First Dominion Capital; . a $46 million loss in value in venture capital equity and other equity investments at First Source and First Dominion Capital; . a $49 million impairment loss related to its investment in First Source; and . a $54 million impairment recorded with respect to certain real estate projects managed and held by Dominion Lands. As the planned exit strategies at DCI are implemented, additional charges may be incurred to reflect updated information. In September 2000, Dominion sold First Dominion Capital's asset management division. Dominion received approximately $10 million in cash after certain fees were paid. Also in October 2000, Dominion sold $823 million in principal amount of commercial loans held in First Source's loan portfolio. The transaction settled in a series of closings which began in mid-October and was completed in the fourth quarter of 2000. Dominion received proceeds of $600 million. In October 2000, Dominion securitized $716 million in principal amount of commercial loans held by First Source and First Dominion Capital in a collateralized loan obligation (CLO) transaction. In the securitization, the loans were sold to an unconsolidated special purpose loan securitization trust, First Source Loan Obligations Trust, in exchange for cash proceeds of $570 million. In addition, Dominion holds a $76 million investment in the subordinated debt of the CLO. First Source will manage the financial assets of the CLO. Dominion closed on another CLO in the first quarter of 2001. It included $461 million of the remaining First Source and First Dominion Capital commercial loans. Dominion retained a $196 million investment in the subordinated debt of the CLO. Dominion's exit strategy for Dominion Lands, DCI's real estate development and management business, is to minimize resources committed to the winding down and exiting of these projects. In addition, Dominion is seeking offers that would expedite its exit from these projects. In August 2000, Dominion realized $8 million from the sale of its interests in certain real estate. Dominion continues to evaluate exit strategies for Saxon. Other Restructuring and other acquisition-related costs also include amounts paid to employees to retain their services during the post-merger transition period, amounts payable under certain employee contracts and information technology systems and operations integration costs. The information technology costs include excess 48 amortization expense attributable to shortening the useful lives of capitalized software being impacted by systems integration. Note 7 | Extraordinary Item and 1998 Rate Settlement Extraordinary Item--Discontinuance of SFAS No. 71 In 1999, legislation was enacted 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 Dominion's utility generation operations in 1999. Dominion's electric transmission and distribution operations con- tinue 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, Dominion evaluated the estimated recovery of regulatory assets through capped rates during the transition period ending July 2007. Generation-related assets and liabilities that will not be recovered through capped rates were written off in 1999, resulting in an after-tax charge to earnings of $255 million. See Note 12 for discussion of regulatory assets at December 31, 2000. The $255 million charge also included the write-off of approximately $38 million, after-tax, of deferred investment tax credits and 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 for impairment. 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, no plant write-downs were appropriate at that time. Dominion 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 pro- jections of possible future market prices indicated a possible loss of $500 million. In the absence of capped rates as provided by the legislation, the potential loss exposure would have been approximately $3.2 billion at March 31, 1999. 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 Dominion's market area and future market prices for fuel and electricity. Virginia Rate Settlement Dominion's 1998 settlement of its outstanding Virginia jurisdictional electric base rate proceedings defined a new regulatory framework for the Company's transition to electric competition. The impact of the settlement provisions was largely recognized in 1998 and 1999 and included: a $150 million base rate reduction phased-in over 1998 and 1999; a $150 million one-time refund in 1998; and the accrual of a $159 million impairment charge which, when coupled with $65 million previously recorded in earlier years, provided for the write-off of $220 million of regulatory assets. Note 8 | Income Taxes Income before provision for income taxes, classified by source of income, before minority interests, was as follows:
(millions) Year ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------ U.S. $552 $797 $420 Non-U.S 48 32 467 - ------------------------------------------------------------------------ Total $600 $829 $887 ========================================================================
The provision for income taxes, classified by the timing and location of payment, was as follows:
(millions) Year ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------ Current: U.S. $255 $187 $153 State 20 18 25 Non-U.S 4 101 - ------------------------------------------------------------------------ Total current 275 209 279 - ------------------------------------------------------------------------ Deferred: U.S. (111) 66 32 State 16 (3) Non-U.S 22 (1) 21 - ------------------------------------------------------------------------ Total deferred (73) 65 50 - ------------------------------------------------------------------------ Amortization of deferred investment tax credits--net (19) (15) (17) - ------------------------------------------------------------------------ Total provision $183 $259 $312 ========================================================================
49 Notes to Consolidated Financial Statements (continued) The statutory U.S. federal income tax rate reconciles to the effective income tax rates as follows:
Year ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------ U.S. statutory rate 35.0% 35.0% 35.0% Utility plant differences 0.8 0.3 3.0 Preferred dividends 2.1 1.6 1.4 Amortization of investment tax credits (2.3) (1.8) (1.9) Nonconventional fuel credit (7.1) (4.4) (2.8) Other -- benefits and taxes related to foreign operations (2.7) (0.2) (0.1) State taxes, net of federal benefit 4.3 1.5 1.5 Goodwill amortization 4.4 Employee pension and other benefits (1.4) Other, net (2.6) (0.8) (0.9) - ------------------------------------------------------------------------------------------------------ Effective tax rate 30.5% 31.2% 35.2% ======================================================================================================
The tax benefit associated with dispositions of employee stock plans reduced taxes currently payable for 2000. In 1998, the United Kingdom reduced its corporate income tax rate, effective April 1, 1999, by one percent to 30 percent. Accordingly, deferred tax liabilities and 1998 income tax expense were reduced by $8.3 million. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Dominion's net deferred tax liability is attributable to:
(millions) At December 31, 2000 1999 - ----------------------------------------------------------------------- Assets: Deferred investment tax credits $ 55 $ 52 Other 4 - ----------------------------------------------------------------------- Total deferred income tax asset 59 52 - ----------------------------------------------------------------------- Liabilities: Depreciation method and plant basis differences 1,994 1,493 Income taxes recoverable through future rates 20 20 Partnership basis differences 141 159 Postretirement and pension benefits 481 (6) Intangible drilling costs 269 44 Other (26) 52 - ----------------------------------------------------------------------- Total deferred income tax liability 2,879 1,762 - ----------------------------------------------------------------------- Net deferred income tax liability $ 2,820 $ 1,710 =======================================================================
Note 9 Transfers and Servicing of Financial Assets During 2000 Dominion sold commercial loans in a securitization transaction. In that securitization, Dominion retained servicing responsibilities and subordinated interests. Dominion receives annual servicing fees approximating 38 basis points of the outstanding balance and rights to future cash flows arising after the investors in the securitization trust have received the return for which they contracted. The investors and the securitization trusts have no recourse to Dominion's other assets for failure of debtors to pay when due. Dominion's retained interests are subordinate to investors' interests. Their value is subject to credit and general economic risks on the transferred financial assets. All of the loans in the securitization are variable rate loans, consequentially changes in interest rates will not cause a material change in the performance of the portfolio of loans. Dominion also securitizes receivables of residential mortgage loans. When Dominion sells receivables in securitizations of residential mortgage loans, it retains interest-only strips, one or more subordinated tranches, servicing rights and future rights to prepayment penalties, all of which are retained interests in the securitized receivables. Gain on sale of the receivables depends in part on the previous carrying amount of the financial assets involved in the transfer. Dominion generally estimates fair value based on the present value of future expected cash flows using management's best estimates of the key assumptions--credit losses, prepayment speeds, forward yield curves and discount rates commensurate with the risks involved. During 2000 and 1999, Dominion sold residential mortgage loans through securitization transactions. In each of those securitizations, Dominion retained servicing responsibilities and subordinated interests. Dominion receives annual servicing fees approximating 50 basis points of the outstanding balance and rights to future cash flows arising after the investors in the securitization trust have received the return for which they contracted . In addition, Dominion receives future cash flows from prepayment penalties on mortgage loans that prepay during the contractual penalty period. The investors and the securitization trusts have no recourse to Dominion's other assets for failure of debtors to pay when due. Dominion's retained interests are sub-ordinate to the investors' interests. The retained interests' value is subject to credit, prepayment and interest rate risks on the transferred financial assets. In 2000 and 1999, Dominion recognized pretax gains of $85 million and $107 million, respectively, on the securitization of residential mortgage loans. 50 The weighted-average rates (per annum) for key economic assumptions used in measuring the retained interests from securitizations completed during 2000 were as follows:
Residential Mortgage Loans Servicing Rights - -------------------------------------------------------------------------------------------------------- Prepayment speed * * Weighted-average life (in years) 6.05/2.44 3.63 Expected credit losses 2.26% 2.26% Residual cash flows discounted at 15.07% 14.09% =======================================================================================================
* Fixed rate loans ramp up to 24 Constant Prepayment Rate (CPR) over 13 months and thereafter. Adjustable rate loans ramp up to 40 CPR over 13 months; ramping down to 24 CPR over 32 months and thereafter. Two-year hybrid loans ramp up to 29 CPR over 13 months; ramping up to 57 CPR in month 21 ramping down to 29 CPR over 18 months and thereafter. Three-year hybrid loans ramp up to 29 CPR over 13 months; ramping up to 57 CPR in month 34 ramping down to 29 CPR over 18 months and thereafter. As a result of changes in the market conditions during the first half of 2000, the discount rate used to value interest-only residual assets was increased from 12% to 17%, and a loss of $106 million was recognized. In addition, due to the events described in Note 6, these assets were transferred from available-for-sale to trading. Accordingly, these assets are recorded at fair value. Activity for the interest-only residual assets and servicing rights is summarized as follows:
(millions) Residual Assets* Servicing Rights Total - ------------------------------------------------------------------------------------------- Balance at January 1, 1998 $ 213 $ 18 $ 231 Retained from securitization 157 24 181 Amortization (3) (7) (10) Cash received (57) (57) Fair value adjustment (28) (28) - ------------------------------------------------------------------------------------------- Balance at December 31, 1998 282 35 317 Retained from securitization 169 16 185 Amortization (7) (12) (19) Cash received (79) (79) Fair value adjustment (18) (18) - ------------------------------------------------------------------------------------------- Balance at December 31, 1999 347 39 386 Retained from securitization 99 18 117 Amortization (16) (7) (23) Cash received (51) (51) Gain on trading securities 25 25 Fair value adjustment (102) (5) (107) - ------------------------------------------------------------------------------------------- Balance at December 31, 2000 $ 302 $ 45 $ 347 ===========================================================================================
*Includes prepayment penalties At December 31, 2000, key economic assumptions and the sensitivity of the current fair value of residual cash flows to immediate 10 percent and 20 percent adverse changes in those assumptions are as follows:
Residential (millions, except percentages) Mortgage Loans Servicing Rights - --------------------------------------------------------------------------------------------- Carrying amount/fair value of retained interests $ 301 $ 46 Weighted-average life (in years) 5.23/1.74 3.64 - --------------------------------------------------------------------------------------------- Prepayment speed assumption (annual rate) /(1)/ /(1)/ Impact on fair value of 10% adverse change $ (20) $ (4) Impact on fair value of 20% adverse change $ (37) $ (6) - --------------------------------------------------------------------------------------------- Expected credit losses (annual rate) 2.28% 2.28% Impact on fair value of 10% adverse change $ (10) N/A Impact on fair value of 20% adverse change $ (20) N/A - --------------------------------------------------------------------------------------------- Residual cash flows discount rate (annual) 17% 15% Impact on fair value of 10% adverse change $ (9) $ (1) Impact on fair value of 20% adverse change $ (20) $ (3) - --------------------------------------------------------------------------------------------- Interest rates on variable and adjustable contracts /(2)/ /(2)/ Impact on fair value of 10% adverse change $ (7) N/A Impact on fair value of 20% adverse change $ (18) N/A =============================================================================================
(1) Fixed rate loans ramp up to 24 CPR over 13 months and thereafter for series 96-1, 96-2, 97-1, 99-3, 99-4, 99-5 and 00-1; ramp up to 22 CPR over 13 months and thereafter for series 98-1 and 99-2; ramp up to 27 CPR over 13 months and thereafter for series 97-2 and 97-3. Adjustable rate loans ramp up to 40 CPR over 13 months; ramping down to 24 CPR over 32 months and thereafter. Two-year hybrid loans ramp up to 30 CPR over 13 months; ramping up to 60 CPR in month 21 ramping down to 30 CPR over 18 months and thereafter. Three-year hybrid loans ramp up to 30 CPR over 13 months; ramping up to 60 CPR in month 33 ramping down to 30 CPR over 18 months and thereafter. (2) Based on the full forward 1-month LIBOR, 6-month LIBOR or 1 year CMT through 1/1/2004 based on the variable component of the variable rate contracts. These sensitivities are hypothetical and should be used with caution. As the figures indicate, changes in fair value based on a 10 percent variation in assumptions generally cannot be extrapolated because the relationship of the change in assumption to the change in fair value may not be linear. Also, in this table, the effect of a variation in a particular assumption on the fair value of the retained interest is calculated without changing any other assumption; in reality, changes in one factor may result in changes in another (for example, increases in market interest rates may result in lower prepayments and increased credit losses), which might magnify or counteract the sensitivities. __ 51 Notes to Consolidated Financial Statements (continued) Note 10 | Collateralized Debt Obligation Investments Until September 20, 2000, Dominion managed financial assets held in three collateralized debt obligations (CDO). That business was sold as part of Dominion's strategy to divest its non-core operations. Dominion continues to hold an investment in the subordinated debt of each CDO. The total investment in the CDOs was $ 159 million and $58 million at December 31, 2000 and 1999, respectively. Note 11 | Investment Securities Securities classified as available-for-sale as of December 31 follow:
Gross Gross Unrealized Unrealized Aggregate (millions) Security Type Cost Gains Losses Fair Value - --------------------------------------------------------------------------------------------------- 2000 Equity $ 132 $ 1 $ 15 $ 118 Debt 175 1 174 - --------------------------------------------------------------------------------------------------- Total $ 307 $ 1 $ 16 $ 292 - --------------------------------------------------------------------------------------------------- 1999 Equity $ 134 $ 2 $ 10 $ 126 Debt 396 10 386 - --------------------------------------------------------------------------------------------------- Total $ 530 $ 2 $ 20 $ 512 ===================================================================================================
Debt securities held at December 31, 2000 do not have stated contractual maturities because borrowers have the right to call or repay obligations with or without call or prepayment penalties. For the years ended December 31, 2000 and 1999, the proceeds from the sales of available-for-sale securities were $3 million and $35 million, respectively. The gross realized gains were $1 million and $5 million for 2000 and 1999, respectively. The gross realized loss for 1998 was $1 million. The basis on which the cost of these securities was determined is specific identification. The changes in net unrealized holding gains and losses on available-for-sale securities have resulted in an increase of $7 million, net of tax, in accumulated other comprehensive income during the year ended December 31, 2000. During the twelve months ended December 31, 1999, the changes in net unrealized holding gains and losses resulted in a decrease of $ 17 million, net of tax, in accumulated other comprehensive income. The changes in net unrealized holding gains and losses on trading securities increased earnings during the year 2000 by $6 million. Included in the $6 million increase was a $14 million loss relating to the reclassification of certain available-for-sale securities to the trading category. In 1999, the change in net unrealized holding gains and losses on trading securities increased earnings by $1 million. For a discussion of investment securities held in nuclear decommissioning trusts, see Note 14. Note 12 | Regulatory Assets and Liabilities Regulatory assets and liabilities included the following:
(millions) At December 31, 2000 1999 - ----------------------------------------------------------------------- Regulatory assets: Other postretirement benefit costs $ 126 Income taxes recoverable through future rates 182 $ 57 Deferred fuel costs 98 63 Cost of decommissioning DOE uranium enrichment facilities 49 55 Other 61 46 - ----------------------------------------------------------------------- 516 221 - ----------------------------------------------------------------------- Unrecovered gas costs (See Note 2) 263 - ----------------------------------------------------------------------- Total $ 779 $ 221 - ----------------------------------------------------------------------- Regulatory liabilities: Estimated rate contingencies and refunds $ 41 Income taxes refundable through future rates 18 - ----------------------------------------------------------------------- Total $ 59 =======================================================================
The incurred costs underlying these regulatory assets and regulatory liabilities may represent expenditures by Dominion's rate regulated electric and gas operations or may represent the recognition of liabilities that ultimately will be settled at some time in the future. See Note 7 for information about the write-off of regulatory assets that resulted from 1999 deregulation legislation and the settlement of Dominion's 1998 Virginia rate proceeding. Other postretirement benefit costs consist of the difference between recognized costs and the amounts included in rates charged by Dominion's local gas distribution subsidiaries, pending the expected recovery through future rates. Unrecovered gas costs and deferred fuel costs represent the difference between the actual cost of purchased gas or fuel used in electric generation and amounts recovered for such costs through current rates. Income taxes recoverable or refundable through future rates resulted from the recognition of additional deferred income taxes, not previously recorded because of past rate-making practices, as part of the implementation of SFAS No. 109. The costs of decommissioning the Department of Energy's (DOE) uranium enrichment facilities represents the unamortized portion of Dominion's required contributions to a fund for decommissioning and decontaminating DOE's uranium enrichment facilities. Dominion began making contributions in 1992 and will continue over a 15-year period with escalation for inflation. These costs are currently being recovered in fuel rates. 52 Estimated rate contingencies and refunds are associated with certain increases in prices by Dominion's rate regulated utilities and other rate-making issues that are subject to final modification in regulatory proceedings. Note 13 Gas Stored At December 31, 2000, stored gas inventory used in local gas distribution operations was valued at $41 million under the LIFO method. Based upon the average price of gas purchased during 2000, the current cost of replacing the inventory of "Gas stored-current portion" exceeded the amount stated on a LIFO basis by approximately $283 million. At December 31, 2000, the stored gas inventory of certain non-regulated gas operations of Dominion was valued at $34 million using the weighted average cost method. A portion of gas in underground storage used as a pressure base and for operational balancing is included in Property, plant and equipment in the amount of $126 million at December 31, 2000. Note 14 Property, Plant and Equipment Major classes of property, plant and equipment and their respective balances are: (millions) At December 31, 2000 1999 - ------------------------------------------------------------------ Utility: Production $ 8,103 $ 7,758 Transmission 3,085 1,517 Distribution 6,764 4,835 Storage 573 Plant under construction 562 677 Nuclear fuel 755 801 Other electric and gas 1,574 901 - ------------------------------------------------------------------ Total utility 21,416 16,489 - ------------------------------------------------------------------ Nonutility: Exploration and production properties: Proved 5,210 1,116 Unproved 550 69 Independent power properties 358 811 Other 477 218 - ------------------------------------------------------------------ Total nonutility 6,595 2,214 - ------------------------------------------------------------------ Total property, plant and equipment $28,011 $18,703 ================================================================== Costs of unproved properties capitalized under the full cost method of accounting that are excluded from amortization at December 31, 2000, and the years in which such excluded costs were incurred, follow: (millions) Incurred in Year Ended December 31, - ----------------------------------------------------------------------------- Total 2000 1999 1998 - ----------------------------------------------------------------------------- Property acquisition costs $ 112 $ 69 $ 25 $ 18 Exploration costs 46 46 Capitalized interest 2 2 - ----------------------------------------------------------------------------- Total $ 160 $ 117 $ 25 $ 18 ============================================================================= Amortization of capitalized costs under the full cost method of accounting for Dominion's United States and Canadian cost centers were as follows: (Per Mcf Equivalent) Year ended December 31, 2000 1999 1998 - ---------------------------------------------------------------------------- United States cost center $1.13 $0.75 $0.82 Canadian cost center 0.92 0.80 0.97 ============================================================================ When Dominion's nuclear units cease operations, it 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 total estimated cost to decommission the four nuclear units is currently estimated at $1.6 billion based on 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 unit licenses will begin in 2012, 2013, 2018 and 2020. The balance in the external trusts available for decommissioning was $851 million at December 31, 2000. The Company intends to file relicensing applications in 2001 to extend the life of each unit by 20 years. 53 Notes to Consolidated Financial Statements (continued) The amount being accrued for decommissioning is equal to the amount being collected from ratepayers and is included in depreciation, depletion and amortization expense. The decommissioning collections were $36 million per year for the period 1998 through 2000. The expense provisions were $36 million, $36 million and $26 million in 2000, 1999 and 1998, respectively. Net earnings of the trusts' investments are included in Other 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, depletion and amortization in the Consolidated Balance Sheets, includes the accrued expense and accretion described above and any a gains and losses on the trusts' investments. At December 31, 2000, the net unrealized gains were $268 million, which is a decrease of $ 23 million over the December 31, 1999 amount of $ 291 million. The accumulated provision for decommissioning at December 31, 2000 was $851 million. It was $818 million at December 31, 1999. The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of the nuclear facilities. Dominion's 2000 NRC minimum financial assurance amount, aggregated for the four nuclear units, was $1.0 billion. Financial assurance is provided by a combination of surety bonds and the funds being collected and funded 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. Dominion's proportionate share of jointly-owned utility plants at December 31, 2000 follows: Bath County North Pumped Anna Clover Storage Power Power (millions, except percentages) Station Station Station - ---------------------------------------------------------------------------- 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 proportions as their respective ownership interest. Such operating costs are classified in the appropriate expense category in the Consolidated Statements of Income. Note 15 | Short-Term Debt and Credit Agreements Dominion and its subsidiaries have credit agreements with various expiration dates and pay fees in lieu of compensating balances in connection with these agreements. These agreements provided for maximum borrowings of $4.4 billion and $5.1 billion at December 31, 2000 and 1999, respectively. At December 31, 2000 and 1999, $295 million and $2.3 billion, respectively, was borrowed under such agreements. Dominion and its subsidiaries' credit agreements also supported $2.7 billion and $1.2 billion of commercial paper at December 31, 2000 and 1999, respectively. A significant portion of the commercial paper is supported by credit agreements that have expiration dates extending beyond one year. Therefore, a total of $250 million and $364 million of the commercial paper was classified as long-term in 2000 and 1999, respectively. These borrowings were used primarily to fund the interim financing of the CNG acquisition and operational needs at Dominion and its subsidiaries. In June 2000, Dominion established a $1.75 billion credit facility that supports its combined commercial paper programs. Subject to the maximum aggregate limit of $1.75 billion, Virginia Power and CNG may borrow up to the full commitment and Dominion may borrow up to $750 million. A summary of the amounts that are classified as short-term debt at December 31 follows:
(millions, except percentages) 2000 1999 - ------------------------------------------------------------------------------------------------------ Weighted Weighted Amount Average Amount Average Outstanding Interest Rate Outstanding Interest Rate - ------------------------------------------------------------------------------------------------------ Commercial paper $ 2,414 6.5% $ 813 5.3% Term-notes 823 7.0% 57 9.7% Total $ 3,237 $ 870 ======================================================================================================
54 Note 16 | Long-Term Debt
(millions) At December 31, 2000 1999 - ------------------------------------------------------------------------------------------------------------------------------- Balance Interest Rate/(6)/ Balance Interest Rate/(6)/ - ------------------------------------------------------------------------------------------------------------------------------- First and Refunding Mortgage Bonds/(1/): 1992 Series E, due 2002 $ 155 7.4% $ 155 7.4% 1993 Various Series, 2001-2003 400 6.0-6.6 535 5.9-6.6 Various Series, 2004-2007 665 6.8-8.0 665 7.6-8.0 Various series, due 2021-2025 1,101 6.8-8.8 1,101 5.4-8.8 - ------------------------------------------------------------------------------------------------------------------------------- Total First and Refunding Mortgage Bonds 2,321 2,456 - ------------------------------------------------------------------------------------------------------------------------------- Other Long-Term Debt: Notes: Due 2004 400 7.3 Debentures: Due 2003-2027 1,334 5.8-8.8 Senior notes: 2000 Series C, due 2003 400 7.6 2000 Series B, due 2005 700 7.6 2000 Various series, due 2010-2014 1,400 7.2-8.1 Mandatory Convertibles, convert 2004 413 8.1 Commercial paper/(2)/ 250 300 Term notes, fixed interest rate, due 2000-2008 581 5.7-10.0 422 5.7-10.0 Various series, due 2004-2038 375 6.7-7.2 375 6.7-7.1 Tax exempt financings/(3)/: Money market municipals, due 2007-2027 489 3.3 489 3.3 Other, due 2022-2030 59 4.9-5.5 29 5.4 Variable rate debt, 2000-2007 54 5.8 Secured revolving lines of credit, variable rates, due 2002-2005 237 6.3-7.0 303 5.6-6.0 - ------------------------------------------------------------------------------------------------------------------------------- Total other long-term debt 6,638 1,972 - ------------------------------------------------------------------------------------------------------------------------------- Nonrecourse debt: Bank loans, due 2004-2008/(4)/ 18 7.3 18 5.8 Revolving credit agreements, due 2001 129 6.3-7.0 363 5.7-6.7 Bank loans, due 2000-2024 39 4.5-6.6 Senior secured bonds, fixed rate, due 2020 259 7.3 265 7.3 Other 19 6.9 3 5.4 Senior notes/(5)/: Fixed rate, due 2003 46 7.6 96 6.1-7.6 Term notes, fixed rate, due 2000-2012 959 6.5-9.0 159 6.5-12.1 Line of credit, variable rate, due 2000 76 6.9 48 6.2 Line of credit, fixed rate, due 2000-2001 3 6.3 44 6.2 Notes payable, due 2006 23 6.9 298 6.5 Commercial paper 64 5.6 Revolving credit agreements 1,492 5.9 - ------------------------------------------------------------------------------------------------------------------------------- Total nonrecourse debt 1,532 2,889 - ------------------------------------------------------------------------------------------------------------------------------- Total debt 10,491 7,317 - ------------------------------------------------------------------------------------------------------------------------------- Less amounts due within one year: First and refunding mortgage bonds 100 135 Other long-term debt 141 60 Nonrecourse debt 95 161 - ------------------------------------------------------------------------------------------------------------------------------- Total amount due within one year 336 356 - ------------------------------------------------------------------------------------------------------------------------------- Less unamortized discount, net of premium 54 25 - ------------------------------------------------------------------------------------------------------------------------------- Total long-term debt $10,101 $6,936 ===============================================================================================================================
Notes: /(1)/ Substantially all of Virginia Power's property is subject to the lien of the mortgage, securing its First and Refunding Mortgage Bonds. /(2)/ See Note 15. /(3)/ Certain pollution control equipment at Virginia Power's generating facilities has been pledged or conveyed to secure these financings. /(4)/ Real estate at Dominion is pledged as collateral. /(5)/ Certain common stock owned by DCI is pledged as collateral to secure the loan. /(6)/ Interest rates are rounded to the nearest one-tenth of one-percent and consist of weighted average interest rates for variable rate debt. 55 Notes to Consolidated Financial Statements (continued) At December 31, 2000 and 1999, the Company had aggregate notional principal amounts of interest rate swaps on outstanding debt of $1.5 billion and $600 million, respectively, maturing between March 2002 and October 2023. The impact of the interest rate swaps on interest expense and on the Company's effective borrowing rates in 2000, 1999 and 1998 was not significant. Maturities (including sinking fund obligations) through 2005 are as follows (in millions): 2001-$336; 2002-$1,658; 2003-$843; 2004-$1,314 and 2005-$858. In January 2001, Dominion issued $1.0 billion of 2-year fixed rate 6% notes. In addition, in February 2001, Dominion issued $50 million in aggregate principal amount of Tax-Exempt Pollution Control Revenue Bonds due 2031. Note 17 | Obligated Mandatorily Redeemable Preferred Securities of | Subsidiary Trusts In December 1997, Dominion established Dominion Resources Capital Trust I (DR Capital Trust). DR Capital Trust sold 250,000 Capital Securities for $250 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by DR Capital Trust. Dominion issued $258 million of 7.83% Junior Subordinated Debentures (Debentures) in exchange for the $250 million realized from the sale of the Capital Securities and $8 million of common securities of DR Capital Trust. The common securities represent the remaining 3% beneficial ownership interest in the assets held by DR Capital Trust. The Debentures constitute 100% of DR Capital Trust's assets. In 1995, Virginia Power established Virginia Power Capital Trust I (VP Capital Trust). VP Capital Trust sold 5 million preferred securities for $135 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by VP Capital Trust. Virginia Power 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 common securities represent the remaining 3% beneficial ownership interest in the assets held by VP Capital Trust. The Notes constitute 100% of VP Capital Trust's assets. In January 2001, Dominion established Dominion Resources Capital Trust II (DR Capital Trust II) and Dominion Resources Capital Trust III (DR Capital Trust III). DR Capital Trust II sold 12 million Trust Preferred Securities for $300 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by DR Capital Trust II. Dominion issued approximately $309 million of 8.4% Junior Subordinated Debentures due 2041 in exchange for the $300 million realized from the sale of the preferred securities and approximately $9 million of common securities of DR Capital Trust II. The Debentures constitute 100% of DR Capital Trust II's assets. DR Capital Trust III sold 250,000 Capital Securities for approximately $247 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by DR Capital Trust III. Dominion issued approximately $258 million of 8.4% Junior Subordinated Debentures due 2031 in exchange for the $247 million realized from the sale of the capital securities and approximately $8 million of common securities of DR Capital Trust III. The common securities represent the remaining 3% beneficial ownership in the assets held by DR Capital Trust III. The Debentures constitute 100% of DR Capital Trust III's assets. Note 18 | Preferred Stock Dominion is authorized to issue up to 20 million shares of preferred stock; however, no such shares are issued and outstanding. Virginia Power is authorized to issue 10 million shares of preferred stock, $100 liquidation preference. Upon involuntary liquidation, dissolution or winding-up of Virginia Power, each share is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative. During 2000, the following series of preferred stock subject to mandatory redemption matured: . 400,000 shares of the $5.58 Series of Preferred Stock matured on March 1, 2000; and . 1,400,000 shares of the $6.35 Series of Preferred Stock matured on September 1, 2000. There were no redemptions of preferred stock in 1999. At December 31, 2000, preferred stock not subject to mandatory redemption, $100 liquidation preference, included: Issued and Entitled Per Outstanding Share Upon Dividend Shares Redemption - ----------------------------------------------------------------------- $5.00 106,677 $ 112.50 4.04 12,926 102.27 4.20 14,797 102.50 4.12 32,534 103.73 4.80 73,206 101.00 7.05 500,000 105.00/(1)/ 6.98 600,000 105.00/(2)/ MMP 1/87/(3)/ 500,000 100.00 MMP 6/87/(3)/ 750,000 100.00 MMP 10/88/(3)/ 750,000 100.00 MMP 6/89/(3)/ 750,000 100.00 MMP 9/92 Series A/(3)/ 500,000 100.00 MMP 9/92 Series B/(3)/ 500,000 100.00 - ----------------------------------------------------------------------- Total 5,090,140 ======================================================================= Notes: /(1)/ Through 7/31/03 and thereafter to amounts declining in steps to $100.00 after 7/31/13. /(2)/ Through 8/31/03 and thereafter to amounts declining in steps to $100.00 after 8/31/13. /(3)/ Money Market Preferred (MMP) dividend rates are variable and are set every 49 days via an auction. The weighted average rates for these series in 2000, 1999, and 1998, including fees for broker/dealer agreements, were 5.71%, 4.82%, and 4.49%, respectively. Note 19 | Common Stock On July 20, 1998, Dominion's Board of Directors authorized the repurchase of up to $650 million of Dominion common stock outstanding. As of December 31, 1999, Dominion had repurchased approximately 11 million shares valued at approximately $471 million. In addition, Dominion repurchased approximately 3.2 million shares of stock in 2000 through the implementation of a total return 56 swap facility. These shares were repurchased at a cost of approximately $145 million. For additional information on the total return swap, see Note 24. Immediately before the CNG acquisition, Dominion concluded a first step transaction in which 33 million shares of Dominion common stock were exchanged for approximately $1.4 billion. Basic earnings per common share are calculated by dividing net income by the average number of common shares outstanding during the year. Diluted earnings per share are computed similar to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised and that the proceeds from such exercises were used to acquire shares of common stock at the average market price during the reporting period. In 1999, diluted earnings per share includes an adjustment to reflect the cost incurred under a total return equity swap associated with Dominion's repurchase of common stock. A reconciliation of income before extraordinary item and cumulative effect of a change in accounting principle and basic to diluted share amounts follows:
2000 EPS 1999 EPS 1998 EPS - --------------------------------------------------------------------------------------------------------------------------------- Numerator: Income before extraordinary item and cumulative effect of a change in accounting principle-- basic $ 415 $ 552 $ 548 Income effect of total return equity swap, net of taxes (12) - --------------------------------------------------------------------------------------------------------------------------------- Income before extraordinary item and cumulative effect of a change in accounting principle-- dilutive $ 415 $ 540 $ 548 - --------------------------------------------------------------------------------------------------------------------------------- Denominator: Weighted average shares-- basic 235.2 $ 1.76 191.4 $ 2.88 194.9 $ 2.81 Effect of dilutive securities-- stock options .7 (0.07) - --------------------------------------------------------------------------------------------------------------------------------- Weighted average shares-- dilutive 235.9 $ 1.76 191.4 $ 2.81 194.9 $ 2.81 =================================================================================================================================
Note 20 | Stock Compensation Plans The Dominion Resources Incentive Compensation Plan (Incentive Plan) provides for the granting of stock options, restricted stock and performance shares to employees of Dominion and its affiliates. The aggregate number of shares of common stock that may be issued under the Incentive Plan is 30 million. The Dominion Resources Leadership Stock Option Plan (Leadership Stock Option Plan), adopted by the Board of Directors in 2000, provides for the granting of non- statutory stock options to salaried employees of Dominion. The aggregate number of common shares that may be issued under the Leadership Stock Option Plan is 10 million. The changes in restricted share incentives and option awards under the combined plans were as follows:
Restricted Weighted Stock Weighted Options Shares Average Price Options Average Price Exercisable - ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1997 105,264 $ 38.88 4,826 $ 29.38 4,826 - ------------------------------------------------------------------------------------------------------------------------------- Awards granted-- 1998 75,866 $ 39.78 Exercised/distributed/forfeited (83,162) $ 38.37 (2,700) $ 29.29 - ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1998 97,968 $ 40.02 2,126 $ 29.49 2,126 - ------------------------------------------------------------------------------------------------------------------------------- Awards granted-- 1999 24,758 $ 43.51 7,146,383 $ 41.38 Exercised/distributed/forfeited (94,113) $ 40.71 (1,113) $ 29.37 - ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 28,613 $ 42.29 7,147,396 $ 41.37 7,147,396 - ------------------------------------------------------------------------------------------------------------------------------- Awards granted-- 2000 169,886 $ 41.88 5,388,822 $ 43.87 Exercised/distributed/forfeited (108,077) $ 42.25 (2,204,765) $ 40.07 - ------------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 90,422 $ 41.56 10,331,453 $ 41.77 6,966,695 ===============================================================================================================================
Under SFAS No. 123, Accounting for Stock Based Compensation, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the service (or vesting) period. However, as permitted under SFAS No. 123, the Company instead measures compensation cost in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under this standard, compensation cost is measured as the difference between the market price of the Company's common stock and the exercise price of the option at the grant date. Accordingly, no compensation expense has been recognized for the stock option grants. Had compensation cost associated with the stock options been determined under SFAS No. 123 based on the fair market value of the options at the grant date, such cost, net of related income taxes, would have been approximately $6 million for the year ended December 31, 2000. Basic and diluted earnings per share for the 57 Notes to Consolidated Financial Statements (continued) year would have decreased by $0.03, due to the issuance of the stock options. In 1999, had compensation costs associated with the stock options been determined under SFAS No. 123, compensation cost, net of tax, would have been approximately $20 million for the year ended December 31, 1999. Both basic and diluted earnings per share for the year would have decreased by $0.10. The fair value of the options was estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used: expected dividend yield of 5.22 percent; expected volatility of 21.54 percent; contractual life of 10 years; riskfree interest rate of 5.18 percent; and expected lives of six years. The weighted-average fair value of options granted during 2000 and 1999 was $6.86 and $ 4.35, respectively. In 2000, Dominion instituted a third-party loan program whereby Dominion officers may borrow funds to increase their investment in the common stock of Dominion. Under certain phases of this program, approximately 1.7 million options were issued under the Incentive Plan, which were then immediately exercised. Certain of the officers who met their target ownership level under the loan program received bonus restricted shares equal to five percent of the number of shares they purchased under the program. The number of bonus shares totaled 101,666 in the aggregate. Dominion officers are responsible for the payment of such loans. Note 21 | Employee Benefit Plans In 2000 and 1999, Dominion and its subsidiaries maintained qualified noncontributory defined benefit retirement plans covering virtually all employees of Dominion. The benefits of the retirement plans are based on years of service, age, and the employee's compensation. Dominion's funding policy is to contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. For the year 1998, non- U.S. activity refers to the pension plan of East Midlands, which was sold in July 1998. The pension program also includes the payment of benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. Certain of these nonqualified plans are funded through contributions to a grantor trust. Dominion and its subsidiaries provide retiree health care and life insurance benefits with annual premiums based on several factors such as age, retirement date, and years of service. From time to time in the past, Dominion and its subsidiaries have changed benefits. Some of these changes have reduced benefits. Under the terms of their benefit plans, the companies reserve the right to change, modify or terminate the plans. On January 28, 2000, Dominion offered an early retirement program (ERP). The ERP provided up to three additional years of age and three additional years of employee service for benefit formula purposes, subject to age and service maximums under the companies' postretirement medical and pension plans. Certain employees who satisfied certain minimum age and years of service requirements were eligible under the ERP. The effect of the ERP on the Company's pension plan and post retirement benefit expenses was $81 million and $33 million, respectively. These expenses were offset, in part, by curtailment gains of approximately $20 million and $6 million from pension plans and other postretirement benefit plans, respectively, attributable to reductions in expected future years of service as a result of ERP participation and involuntary employee terminations. In addition, effective January 1, 2000, Dominion adopted a change in the method of calculating the market-related value of pension plan assets. The change is reported as a change in accounting principle. See Note 3. The components of the provision for net periodic benefit cost were as follows:
(millions) Pension Benefits Other Benefits - ------------------------------------------------------------------------------------------------------------------------------- Year ended December 31, 2000 1999 1998 1998 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------- U.S. U.S. U.S. Non-U.S. - ------------------------------------------------------------------------------------------------------------------------------- Service cost $ 65 $ 40 $ 32 $ 10 $ 30 $ 17 $ 12 Interest cost 161 76 71 44 52 28 24 Expected return on plan assets (298) (93) (80) (49) (31) (20) (16) Recognized gain 6 Amortization of prior service cost 3 Amortization of transition obligation (4) 13 12 12 Curtailment gains (20) (6) ERP benefit costs 81 33 Net amortization and deferral (1) (2) (1) - ------------------------------------------------------------------------------------------------------------------------------- Net periodic benefit cost $ (6) $ 23 $ 22 $ 5 $ 89 $ 37 $ 31 ===============================================================================================================================
58
(millions) Pension Benefits Other Benefits - ----------------------------------------------------------------------------------------------------------------------------------- Year ended December 31, 2000 1999 2000 1999 - ----------------------------------------------------------------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at beginning of year $1,305 $1,094 $ 272 $ 212 Acquisition of CNG 2,332 128 Actual return on plan assets 64 232 3 45 Contributions 34 22 45 16 Benefits paid from plan assets (141) (43) (20) (1) Sale of VNG (37) (11) - ----------------------------------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of year 3,557 1,305 417 272 - ----------------------------------------------------------------------------------------------------------------------------------- Expected benefit obligation at beginning of year 1,097 1,126 401 377 Acquisition of CNG 1,002 297 Actuarial (gain) loss during prior period (13) 26 - ----------------------------------------------------------------------------------------------------------------------------------- Actual benefit obligation at beginning of year 2,099 1,113 698 403 Extraordinary accounting charge 10 Service cost 65 40 30 17 Interest cost 161 76 52 28 Benefits paid (141) (43) (43) (18) Actuarial (gain) loss during the year 112 (89) 82 (29) ERP benefit costs 81 33 Sale of VNG (45) (20) Change in APBO due to curtailment (20) (6) Plan amendments (18) (27) - ----------------------------------------------------------------------------------------------------------------------------------- Expected benefit obligation at end of year 2,304 1,097 799 401 - ----------------------------------------------------------------------------------------------------------------------------------- Funded status 1,253 208 (382) (129) Unrecognized net actuarial (gain) loss 177 (177) 13 (45) Unamortized prior service cost (1) 3 (7) Unrecognized net transition (asset) obligation (9) (12) 125 158 - ----------------------------------------------------------------------------------------------------------------------------------- Prepaid (accrued) benefit costs $1,420 $ 22 $(251) $ (16) - ----------------------------------------------------------------------------------------------------------------------------------- Amounts recognized in the Consolidated Balance Sheets at December 31 consist of the following: Prepaid benefit costs $1,455 $ 22 Accrued benefit costs (77) $(251) $ (16) Intangible asset 14 Accumulated other comprehensive income 28 - ----------------------------------------------------------------------------------------------------------------------------------- Net amount recognized $1,420 $ 22 $(251) $ (16) ===================================================================================================================================
The Company has nonqualified pension plans which are reflected in the table above. The projected benefit obligation for these plans was $93 million at December 31, 2000. In addition, Dominion had recognized a minimum liability associated with these plans of $42 million at December 31, 2000. Significant assumptions used in determining net periodic pension cost, the projected benefit obligation, and postretirement benefit obligations were: Pension Benefits Other 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 5.00% 5.00% 5.00% 5.00% Medical cost trend rate 9.00% 4.75% Decreasing to 4.75% in 2005 and years thereafter ================================================================================ 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: Other Postretirement Benefits 1-Percentage 1-Percentage (millions) Point Increase Point Decrease - ------------------------------------------------------------------------------ Effect on total of service and interest cost components for 2000 $10 $ (8) Effect on postretirement benefit obligation at 12/31/00 $86 $(71) ============================================================================== 59 Notes to Consolidated Financial Statements (continued) In addition, Dominion sponsors defined contribution thrift-type savings plans. During 2000, 1999 and 1998, Dominion's recognized $30 million, $29 million and $28 million, respectively, as contributions to these plans. The funds collected for other postretirement benefits in regulated utility rates, in excess of other postretirement benefits actually paid during the year, are contributed to external benefit trusts. Note 22 | Commitments and Contingencies As the result of issues generated in the course of daily business, Dominion and its subsidiaries are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. Management believes that the final disposition of these proceedings will not have an adverse material effect on its operations or the financial position, liquidity or results of operations. Utility Rate Regulation The acquisition of CNG has expanded the Company's exposure to utility rate regulation. Dominion's retail gas distribution companies are subject to price regulation in the states of Ohio, Pennsylvania and West Virginia. In addition, Dominion's gas transmission business is subject to rate regulation. Dominion currently faces competition as a result of utility industry deregulation. Under Virginia's electric utility industry deregulation legislation, the Company's base rates will remain unchanged until July 2007 and recovery of certain generation-related costs will be provided through these 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, Dominion's exposure to potentially stranded costs was comprised of the following: . long-term purchased power contracts that could ultimately be determined to be above market--See Purchased Power Contracts below; . 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 14 and 21. Purchased Power Contracts Dominion has contracts for the long-term purchase of capacity and energy from other utilities, qualifying facilities and independent power producers. Dominion has 54 power purchase contracts with a combined dependable summer capacity of 3,973 megawatts. The following table reflects the Company's minimum commitments as of December 31, 2000, for power purchases from utility and nonutility suppliers. (millions) Commitment - -------------------------------------------------------------------------------- Year Capacity Other - -------------------------------------------------------------------------------- 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 Dominion 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 7 for an evaluation of Dominion's potential exposure under its long-term purchased power commitments. Fuel Purchase Commitments 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. Leases 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 as of December 31, 2000 are: 2001-$115 million; 2002-$58 million; 2003-$51 million; 2004-$40 million; 2005-$29 million; and years after 2005-$92 million. Rental expense included in other operation and maintenance expense was $107 million, $31 million and $27 million for 2000, 1999 and 1998, respectively. Sales of Power Subsidiaries of Dominion enter into agreements with other utilities and with other parties to purchase and sell electric 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, Dominion's current and anticipated load, and other factors. The combined amounts of sales and purchases range from 3,000 megawatts to 15,000 megawatts at various times during a given year. These operations are closely monitored from a risk- management perspective. Environmental Matters Dominion 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, 60 operating and other costs as a result of compliance, remediation, containment and monitoring obligations of Dominion. Dominion currently recovers environmental-related costs from electric service customers through regulated 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, Dominion's results of operations will decrease. After that date, Dominion may seek recovery from customers through utility rates of only those environmental costs related to transmission and distribution operations. In 1987, the U.S. Environmental Protection Agency (EPA) identified Dominion and several 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. Dominion'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. Dominion has accrued a reserve of $2 million to meet its obligations at these two sites. Based on a financial assessment of PRPs involved at these sites, Dominion has determined that it is probable that the PRPs will fully pay the costs apportioned to them. Dominion generally seeks to recover its costs associated with environmental remediaton from third-party insurers. Any pending or possible claims were not recognized as an asset or offset against such obligations. In 1999, Dominion was notified by the Department of Justice of alleged noncompliance with EPA's oil spill prevention, control and counter-measures (SPCC) plans and facility response plan (FRP) requirements at one of Dominion's power stations. If, in a legal proceeding, such instances of noncompliance are deemed to have occurred, Dominion 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 Dominion's financial condition or results of operations. Dominion identified matters at certain other power stations that EPA might view as not in compliance with the SPCC and FRP requirements. Dominion reported these matters to the EPA and in December 1999 submitted revised FRP and SPCC plans. Presently, the EPA has not assessed any penalties against Dominion, pending its review of Dominion's disclosure information. Future resolution of these matters is not expected to have a material impact on Dominion's financial condition or results of operations. During 2000, the Company received a Notice of Violation (NOV) from the EPA alleging that Dominion is operating its Mt. Storm Power Station in West Virginia in violation of the Clean Air Act. The NOV alleges that Dominion 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 civil penalties and injunctive relief. Also in 2000, the Attorney General of New York filed a suit against Dominion alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. Dominion has also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit against Dominion for similar violations. Currently, Dominion has reached an agreement in principle with the federal government and the state of New York about 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 Dominion's coal-fired generating stations in Virginia and West Virginia. Dominion has already committed to a substantial portion of the $1.2 billion expeditures for SO2 and NOX emissions controls in response to other Clean Air Act requirements. Although Dominion and EPA have reached an agreement in principle, the terms of a final binding settlement are still being negotiated. As of December 31, 2000, Dominion has recorded, on a discounted basis, $17 million for the civil penalty and environmental projects. In 1990, Dominion Transmission entered into a Consent Order and Agreement with the Commonwealth of Pennsylvania Department of Environmental Protection (DEP) in which Dominion Transmission has agreed with the DEP's determination of certain violations of the Pennsylvania Solid Waste Management Act, the Pennsylvania Clean Streams Law and the rules and regulations promulgated thereunder. No civil penalties have been assessed. Pursuant to the Order and Agreement, Dominion Transmission continues to perform sampling, testing and analysis, and conducts remediation at some of its affected Pennsylvania facilities. Total remediation costs in connection with these sites and the Order and Agreement are not expected to be material with respect to the Company's financial position, results of operations or cash flows. The Company has recognized an estimated liability amounting to $6 million at December 31, 2000, for future costs expected to be incurred to remediate or mitigate hazardous substances at these sites and at facilities covered by the Order and Agreement. Nuclear 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. Dominion 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, Dominion 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. Dominion'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 be used first to return the reactor to 61 Notes to Consolidated Financial Statements (continued) and maintain it in a safe and stable condition, then to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Dominion'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 Dominion'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, Dominion has the financial responsibility for these losses. Dominion 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, Dominion 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 $7 million. As part owner of the North Anna Power Station, Old Dominion Electric Cooperative 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. Guarantees Dominion has issued guarantees to various third parties in relation to the payment obligations by certain of its subsidiaries and officers. At December 31, 2000, Dominion had issued $1.8 billion of guarantees, and the subsidiaries' debt subject to such guarantees totaled $1.2 billion. DEI Subsidiaries of DEI have general partnership interests in certain of its energy ventures. These subsidiaries may be required to fund future operations of these investments, if operating cash flow is insufficient. DCI At December 31, 2000, DCI had commitments to fund loans of approximately $230 million. Note 23 | Fair Value of Financial Instruments The fair value amounts of Dominion's financial instruments have been determined using available market information and valuation methodologies deemed appropriate in the opinion of management. However, considerable judgment is required to interpret market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that could be realized in a current market exchange. The use of different market estimation assumptions may have a material effect on the estimated fair value amounts. (millions) At December 31, Carrying Amount Estimated Fair Value - ------------------------------------------------------------------------------- 2000 1999 2000 1999 - ------------------------------------------------------------------------------- Assets: Cash and cash equivalents/(1)/ $ 360 $ 280 $ 360 $ 280 Investment securities, trading/(2)/ 275 2 275 2 Mortgage loans held for sale/(3)/ 104 119 104 119 Commodity-based swaps, trading/(4)/ 281 25 281 25 Commodity-based options, trading/(4)/ 29 6 29 6 Available-for-sale securities/(2)/ 292 512 292 512 Loans and notes receivable and finance receivables held for sale/(5)/ 676 2,131 676 2,131 Nuclear decommissioning trust funds/(2)/ 851 818 851 818 - ------------------------------------------------------------------------------- Liabilities: Short-term debt/(6)/ 3,237 870 3,237 870 Commodity-based swaps, trading/(4)/ 325 24 325 24 Commodity-based options, trading/(4)/ 56 6 56 6 Long-term debt/(6)/ 10,491 7,317 10,555 7,185 Preferred securities of subsidiary trusts/(7)/ 385 385 383 359 Preferred stock/(8)/ 180 181 Loan commitments/(9)/ 230 937 - ------------------------------------------------------------------------------- Unrecognized financial instruments: Interest rate-swaps/(10)/ 17 (15) Total return equity swap/(11)/ (19) Swaps, collars and options, hedging/(4)/ (277) 5 =============================================================================== Notes: (1) The carrying amount of these items is a reasonable estimate of their fair value. (2) The estimated fair value is based on quoted market prices, dealer quotes, and prices obtained from independent pricing sources. (3) The fair value is based on outstanding commitments from investors. (4) Fair value reflects the Company's best estimates considering over-the- counter quotations, time value and volatility factors of the underlying commitments. (5) The carrying value approximates fair value due to the variable rate or term structure. (6) Market values are used to determine the fair value for debt securities for which a market exists. For debt issues that are not quoted on an exchange, interest rates currently available to the Company for issuance of debt with similar terms and remaining maturities are used to estimate fair value. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value. (7) The fair value is based on market quotations. (8) Preferred stock matured in 2000. See Note 18. (9) The fair value of commitments is estimated using the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements and the present credit-worthiness of the counterparties. (10) The fair value is based upon the present value of all estimated net future cash flows, taking into account current interest rates and the creditworthiness of the swap counterparties. (11) The fair value of the total return equity swap is estimated by obtaining quotes from brokers. 62 Note 24 | Derivative Transactions Dominion uses derivative financial instruments for the purposes of managing commodity price and interest rate risks. Commodity-Based Instruments -- Non-Trading Dominion manages the price risk associated with purchases and sales of natural gas and oil by selecting derivative commodity instruments whose historical price fluctuations correlate strongly with those of the transactions being hedged. These commodity-based financial derivatives include swaps, options, and collars which require settlement in cash. As these instruments qualify and have been designated as hedges, any gains or losses resulting from market price changes are expected to be generally offset by the related physical transaction. At December 31, 2000, Dominion held swaps with notional quantities of approximately 267 Bcf of natural gas maturing through 2001-2005 with an aggregate unrealized gain of $158 million. Net notional quantities do not represent the quantities exchanged by the parties and are not a measure of Dominion's exposure through the use of swaps but are used in the determination of cash settlements under the swap agreements. At December 31, 2000, Dominion held options and collars covering approximately 202 Bcf of natural gas and 11 million barrels of crude oil maturing through 2001 with an aggregate unrealized loss of $435 million. At December 31, 1999, Dominion held swaps, options and collars covering approximately 42 Bcf of natural gas maturing through 2002 with an aggregate unrealized gain of $5 million. Commodity-based Instruments -- Trading As part of Dominion'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 (including long-term) totaled $1.1 billion and $367 million at December 31, 2000 and 1999, respectively. Commodity contract liabilities (including long-term) totaled $1.1 billion and $354 million at December 31, 2000 and 1999, respectively. As disclosed in Note 23, included in these amounts was a net commodity-based derivative liability consisting of swaps and options totaling $71 million and a net commodity-based derivative asset of $1 million at December 31, 2000 and 1999, respectively. Net gains and losses associated with Dominion's commodity trading activities are reported net of related cost of sales in Operating revenue and income -- other and totaled $95 million and $65 million for 2000 and 1999, respectively. Interest Rate Contracts Dominion enters into interest rate sensitive financial derivative instruments, including swaps and futures, in order to manage exposure to the effects of interest rate changes on outstanding debt and mortgage loans that the Company has funded or has committed to fund, as well as residual interests retained. Net notional quantities or amounts do not represent the quantities or amounts exchanged by the parties, and are not a measure of Dominion's exposure through the use of swaps and futures but are used in the determination of cash settlements under the agreements. At December 31, 2000, Dominion held swaps used to synthetically convert approximately $450 million of variable-rate debt to fixed rates, and approximately $1.0 billion of fixed-rate debt to variable-rate debt. Also, at December 31, 2000, Dominion recorded its interest rate swaps and futures held for trading purposes at fair value, a net liability of $13 million. These contracts had notional quantities of $5.0 billion and resulted in net trading losses of $14 million for 2000. At December 31, 1999, all interest rate swaps and futures were held for purposes other than trading with notional quantities of $3.7 billion. The net deferred hedging losses were not material. Risk Management Policies Dominion has operating procedures in place that are administered by experienced management to help ensure that proper internal controls regarding the use of derivatives are maintained. In addition, Dominion has established an independent function to monitor compliance with the price risk management policies of all subsidiaries. In addition, Dominion 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. Dominion 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, management 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. In addition to the financial derivatives disclosed above, Dominion held futures and forwards that may be settled through the purchase or delivery of commodities. As of December 31, 2000, these instruments were not considered financial derivatives. However, effective January 1, 2001, Dominion adopted SFAS No. 133 which changed the scope and method of accounting for derivatives. See Note 4 for a discussion of impact of adoption of this standard. Other Derivatives In 1998, Dominion entered into total return swap agreements with swap counterparties. The notional amount of the swaps is based on the purchase price of the securities to be acquired by the swap counterparties. As a result of the winding down of the financial services business, the total return swap agreement was terminated in 2000. At December 31, 1999, the notional amount was $249 million. The gains or losses from the sale, settlement or mark to market of the total return swaps are recorded in Other revenue. Earnings due to swap transactions were $2 million and $18 million in 2000 and 63 Notes to Consolidated Financial Statements (continued) 1999, respectively. Total return swap transactions require additional funding of or return of cash collateral resulting from decreases or increases in the fair market value of the swap position. Total return swap cash collateral is included in cash and cash equivalents. Such cash collateral was $59 million at December 31, 1999. During the fourth quarter of 1999, Dominion entered into a total return equity swap facility agreement (Agreement). The Agreement gave Dominion the right to direct the counterparty to purchase shares of Dominion common stock during the term of the Agreement. In addition, Dominion paid the counterparty a carrying cost equal to a LIBOR-based rate on the counterparty's cost of acquiring the shares from the date of such acquisitions until the date of settlement. Due to Dominion's ability to issue shares to settle periodic price fluctuations and fees under the Agreement, Dominion recorded all amounts received and paid as equity. As of December 31, 1999, the counterparty had acquired 3.2 million shares of Dominion common stock under this Agreement at an aggregate cost that was approximately $19 million more than the fair market value of the shares at December 31, 1999. On February 3, 2000, Dominion settled all transactions under the Agreement and received the 3.2 million shares at a cost of $145 million. Note 25 | Gas and Oil Producing Activities (unaudited) Capitalized Costs The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of accumulated depreciation and amortization, follow:
(millions) At December 31, - ------------------------------------------------------------------------------------------ 2000 1999 - ------------------------------------------------------------------------------------------ Capitalized costs of: Proved properties $5,210 $1,116 Unproved properties 550 69 - ------------------------------------------------------------------------------------------ 5,760 1,185 - ------------------------------------------------------------------------------------------ Accumulated depreciation of: Proved properties 2,959 245 Unproved properties 233 6 - ------------------------------------------------------------------------------------------ 3,192 251 - ------------------------------------------------------------------------------------------ Net capitalized costs $2,568 $ 934 ==========================================================================================
Total Costs Incurred The following costs were incurred in gas and oil producing activities during the years 1998 through 2000:
(millions) - ------------------------------------------------------------------------------------------------------------------------------------ Year ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------------ Total United States Canada Total United States Canada Total United States Canada - ------------------------------------------------------------------------------------------------------------------------------------ Property acquisition costs: Proved properties $1,475 $1,459 $ 16 $ 280 $ 121 $ 159 $ 165 $ 165 Unproved properties 125 125 33 3 30 - ------------------------------------------------------------------------------------------------------------------------------------ 1,600 1,584 16 313 124 189 165 165 Exploration costs 159 115 44 4 2 2 20 $ 16 4 Development costs 261 236 25 85 34 51 28 25 3 - ------------------------------------------------------------------------------------------------------------------------------------ Total $2,020 $1,935 $ 85 $ 402 $ 160 $ 242 $ 213 $ 41 $ 172 - ------------------------------------------------------------------------------------------------------------------------------------
Results of Operations The Company cautions that the following standardized disclosures required by the FASB do not represent the results of operations based on its historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overheads.
(millions) Year ended December 31, 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------------------ Total United States Canada Total United States Canada Total United States Canada - ------------------------------------------------------------------------------------------------------------------------------------ Revenues (net of royalties) from: Sales to nonaffiliated companies $ 861 $ 691 $ 170 $ 229 $ 142 $ 87 $ 141 $ 119 $ 22 Transfers to other operations 93 93 - ------------------------------------------------------------------------------------------------------------------------------------ Total 954 784 170 229 142 87 141 119 22 - ------------------------------------------------------------------------------------------------------------------------------------ Less: Production (lifting) costs 158 133 25 77 47 30 43 37 6 Depreciation and amortization 345 294 51 84 47 37 59 45 14 Income tax expense 134 93 41 (10) (19) 9 (10) (11) 1 - ------------------------------------------------------------------------------------------------------------------------------------ Results of operations $ 317 $ 264 $ 53 $ 78 $ 67 $ 11 $ 49 $ 48 $ 1 ====================================================================================================================================
64 Company-Owned Reserves
Estimated net quantities of proved gas and oil (including condensate) reserves in the United States and Canada at December 31, 1998 through 2000, and changes in the reserves during those years, are shown in the two schedules which follow. 2000 1999 1998 - ----------------------------------------------------------------------------------------------------------------------------------- (billion cubic feet) Total United States Canada Total United States Canada Total United States Canada - ----------------------------------------------------------------------------------------------------------------------------------- Proved developed and undeveloped reserves--Gas At January 1 1,114 600 514 591 473 118 447 447 Changes in reserves: Extensions, discoveries and other additions 274 232 42 156 94 62 66 57 9 Revisions of previous estimates (89) (59) (30) (18) 25 (43) 17 17 Production (269) (222) (47) (97) (60) (37) (63) (50) (13) Purchases of gas in place 1,322 1,322 512 98 414 129 6 123 Sales of gas in place (15) (15) (30) (30) (5) (4) (1) - ----------------------------------------------------------------------------------------------------------------------------------- At December 31 2,337 1,858 479 1,114 600 514 591 473 118 =================================================================================================================================== Proved developed reserves -- Gas At January 1 1,005 600 405 591 473 118 447 447 At December 31 1,954 1,593 361 1,005 600 405 591 473 118 =================================================================================================================================== 2000 1999 1998 - ----------------------------------------------------------------------------------------------------------------------------------- (thousands of barrels) Total United States Canada Total United States Canada Total United States Canada - ----------------------------------------------------------------------------------------------------------------------------------- Proved developed and undeveloped reserves -- Oil At January 1 Changes in reserves: 20,808 659 20,149 4,204 2,661 1,543 2,349 2,349 Extensions, discoveries and other additions 14,213 12,813 1,400 2,051 118 1,933 966 925 41 Revisions of previous estimates (5,082) (2,443) (2,639) 8,339 (552) 8,891 140 140 Production (7,694) (6,436) (1,258) (2,057) (595) (1,462) (1,025) (751) (274) Purchases of oil in place 54,977 48,359 6,618 9,244 9,244 1,897 1,897 Sales of oil in place (1,880) (1,880) (973) (973) (123) (2) (121) - ----------------------------------------------------------------------------------------------------------------------------------- At December 31 75,342 51,072 24,270 20,808 659 20,149 4,204 2,661 1,543 =================================================================================================================================== Proved developed reserves -- Oil At January 1 6,102 659 5,443 4,204 2,661 1,543 2,349 2,349 At December 31 36,236 21,709 14,527 6,102 659 5,443 4,204 2,661 1,543 ===================================================================================================================================
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein The following tabulation has been prepared in accordance with the FASB's rules for disclosure of a standardized measure of discounted future net cash flows relating to Company-owned proved gas and oil reserve quantities.
(millions) Year ended December 31, 2000 1999 1998 - ----------------------------------------------------------------------------------------------------------------------------------- Total United States Canada Total United States Canada Total United States Canada - ----------------------------------------------------------------------------------------------------------------------------------- Future cash inflows $22,762 $18,277 $ 4,485 $ 2,401 $1,282 $ 1,119 $ 1,311 $1,102 $ 209 Less: Future development and production costs 2,558 1,945 613 1,097 497 600 485 381 104 Future income tax expense 7,145 5,591 1,554 209 125 84 120 137 (17) - ----------------------------------------------------------------------------------------------------------------------------------- Future cash flows 13,059 10,741 2,318 1,095 660 435 706 584 122 Less annual discount (10% a year) 5,721 4,620 1,101 546 310 236 324 280 44 - ----------------------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $ 7,338 $ 6,121 $ 1,217 $ 549 $ 350 $ 199 $ 382 $ 304 $ 78 ===================================================================================================================================
65 Notes to Consolidated Financial Statements (continued) In the foregoing determination of future cash inflows, sales prices for gas were based on contractual arrangements or market prices at each year-end. Prices for oil were based on average prices received from sales in the month of December each year. Future cash inflows also reflect the effects of hedging activities. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, or permanent differences and tax credits. It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary . In addition, present costs and prices are used in the determinations and no value may be assigned to probable or possible reserves. The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year.
(millions) Year ended December 31, 2000 1999 1998 - ----------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows at January 1 $ 549 $ 382 $ 329 Changes in the year resulting from: Sales and transfers of gas and oil produced during the year, less production costs (796) (152) (98) Prices and production and development costs related to future production 8,706 (110) (114) Extensions, discoveries and other additions, less production and development costs 1,602 103 61 Previously estimated development costs incurred during the year 82 57 71 Revisions of previous quantity estimates (778) 34 8 Accretion of discount 259 44 40 Income taxes (3,309) (44) 8 Acquisition of CNG 1,322 Other purchases and sales of proved reserves in place 994 245 83 Other (principally timing of production) (1,293) (10) (6) - ----------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows at December 31 $ 7,338 $ 549 $ 382 ===============================================================================================
Note 26 | Quarterly Financial and Common Stock Data (unaudited) The following amounts reflect all adjustments, consisting of only normal recurring accruals (except as disclosed below), necessary in the opinion of Dominion's management for a fair statement of the results for the interim periods. (millions, except per share amounts) 2000 1999 - -------------------------------------------------------------------------- Operating revenue and income First Quarter $ 2,072 $ 1,293 Second Quarter 2,056 1,315 Third Quarter 2,351 1,663 Fourth Quarter 2,781 1,249 - -------------------------------------------------------------------------- Year $ 9,260 $ 5,520 ========================================================================== Income from operations First Quarter $ 415 $ 322 Second Quarter 71 300 Third Quarter 658 492 Fourth Quarter 385 214 - -------------------------------------------------------------------------- Year $ 1,529 $ 1,328 ========================================================================== Income (loss) before extraordinary item and cumulative effect of a change in accounting principle First Quarter $ 143 $ 138 Second Quarter (103) 120 Third Quarter 255 235 Fourth Quarter 120 59 - -------------------------------------------------------------------------- Year $ 415 $ 552 ========================================================================== Net income (loss) First Quarter $ 143 $ (117) Second Quarter (103) 120 Third Quarter 255 235 Fourth Quarter 141 59 - -------------------------------------------------------------------------- Year $ 436 $ 297 ========================================================================== Earnings (loss) per share before extraordinary item and cumulative effect of a change in accounting principle Basic Diluted - -------------------------------------------------------------------------- 2000 1999 2000 1999 - -------------------------------------------------------------------------- First Quarter $ 0.64 $ 0.71 $ 0.64 $ 0.71 Second Quarter (0.44) 0.63 (0.44) 0.63 Third Quarter 1.07 1.23 1.07 1.23 Fourth Quarter 0.49 0.31 0.49 0.24 - -------------------------------------------------------------------------- Year $ 1.76 $ 2.88 $ 1.76 $ 2.81 ========================================================================== Earnings (loss) per share Basic Diluted - -------------------------------------------------------------------------- 2000 1999 2000 1999 - -------------------------------------------------------------------------- First Quarter $ 0.64 $ (0.61) $ 0.64 $ (0.61) Second Quarter (0.44) 0.63 (0.44) 0.63 Third Quarter 1.07 1.23 1.07 1.23 Fourth Quarter 0.58 0.30 0.58 0.23 - -------------------------------------------------------------------------- Year $ 1.85 $ 1.55 $ 1.85 $ 1.48 ========================================================================== 66 Quarterly Financial and Common Stock Data--Unaudited, (continued) - ----------------------------------------------------------------------- 2000 1999 - ----------------------------------------------------------------------- Dividends per share First Quarter $ 0.645 $ 0.645 Second Quarter 0.645 0.645 Third Quarter 0.645 0.645 Fourth Quarter 0.645 0.645 - ----------------------------------------------------------------------- Year $ 2.58 $ 2.58 ======================================================================= Stock price range First Quarter 43 1/8 - 34 13/16 47 1/16 - 36 7/8 Second Quarter 47 1/2 - 38 1/16 44 13/16 - 36 9/16 Third Quarter 59 13/16 - 42 13/16 47 3/16 - 43 Fourth Quarter 67 15/16 - 50 3/4 49 3/8 - 39 1/4 - ----------------------------------------------------------------------- Year 67 15/16 - 34 13/16 49 3/8 - 36 9/16 ======================================================================= Certain amounts recorded in 2000 and 1999 were not ordinary, recurring adjustments. For the year ended December 31, 2000, Dominion recognized $460 million of restructuring and other acquisition-related costs. See Note 6. During the second quarter of 2000, management adopted a strategy to exit certain businesses of DCI and to de-emphasize the remaining components of the businesses that are expected to be retained or possibly held only as long as necessary to wind up affairs. Under this strategy, DCI reevaluated certain assets and businesses and impairment losses were recognized. During 2000, Dominion has recognized impairment losses of $291 million, of which $172 million was determined to be attributable to Dominion's exit strategy rather than other factors and are included in Restructuring and other acquisition- related costs. During the quarter ended September 30, 2000, Dominion adopted a company- wide method of calculating the market related value of plan assets used to determine the expected return on pension plan assets, a component of net periodic pension cost. Dominion recorded $21 million, net of income taxes of $11 million, as a cumulative effect of the change on prior years' income. The effect of the change for the year 2000 was to increase income before extraordinary item and cumulative effect of a change in accounting principle by $11 million, or $0.05 per share, and net income by $32 million, or $0.14 per share. Extraordinary Item In the first quarter of 1999, Dominion recorded an after-tax charge of $255 million, or $1.33 per share, to reflect the write-off of assets and liabilities that will not be recovered through base rates capped by Virginia legislation enacted into law on March 25, 1999. This legislation establishes a detailed plan to restructure the electric utility industry in Virginia. The after-tax charge was recorded as an extraordinary item on Dominion's Consolidated Statements of Income. 67 Notes to Consolidated Financial Statements (continued) Note 27 Business Segments Business segment financial information follows for each of the three years in the period ended December 31, 2000. Corporate includes intersegment eliminations.
Dominion Dominion Dominion Dominion Dominion Corporate Total (millions, except total assets) Delivery Capital Energy UK E&P Operations Consolidated - -------------------------------------------------------------------------------------------------------------------------------- 2000 Revenue $2,824 $ 433 $ 4,764 $ 1,369 $ (130) $ 9,260 Interest income 8 8 Interest expense 198 192 207 83 278 958 Operating income 707 215 934 438 (765) 1,529 Depreciation and amortization 318 34 340 352 132 1,176 Unusual items 351 351 Equity income 6 23 12 6 47 Income tax expense (benefit) 187 12 262 97 (375) 183 Net income 339 11 478 270 (662) 436 Equity investments 111 223 71 68 473 Capital expenditures 457 5 330 751 22 1,565 Total assets (billions) 7.9 2.0 10.6 3.6 5.2 29.3 1999 Revenue 1,166 473 3,593 256 32 5,520 Interest income 12 4 7 23 Interest expense 141 152 173 39 2 507 Operating income 431 265 623 44 (35) 1,328 Depreciation and amortization 246 32 313 84 32 707 Extraordinary item (255) (255) Equity income 4 14 5 10 33 Income tax expense (benefit) 109 35 161 (29) (17) 259 Net income 175 78 271 44 (271) 297 Equity investments 166 186 23 31 406 Capital expenditures 317 9 461 86 21 894 Total assets (billions) 4.6 3.6 7.5 1.2 0.9 17.8 1998 Revenue 1,111 409 3,510 $1,009 164 (122) 6,081 Interest income 12 2 15 29 Interest expense 145 121 179 102 19 17 583 Operating income 424 210 615 142 29 (316) 1,104 Depreciation and amortization 237 25 337 75 59 733 Unusual items 332 332 Equity income 21 14 4 2 41 Income tax expense (benefit) 104 31 157 133 (20) (93) 312 Net income 168 59 262 227 34 (202) 548 Equity investments 203 122 18 39 382 Capital expenditures 282 6 260 92 50 65 755 Total assets (billions) 4.6 3.1 7.5 0.8 1.5 17.5 ================================================================================================================================
Geographic Areas Revenue International --------------------------------------------------- (millions) United Latin Total Year Domestic Kingdom America Canada International Consolidated - -------------------------------------------------------------------------------------------------------------------------------- 2000 $ 9,068 $ 13 $ 179 $ 192 $ 9,260 1999 5,392 106 22 128 5,520 1998 4,913 $ 1,009 133 26 1,168 6,081 Long-Lived Assets International --------------------------------------------------- (billions) United Latin Total Year Domestic Kingdom America Canada International Consolidated - -------------------------------------------------------------------------------------------------------------------------------- 2000 $ 21.5 $ 0.5 $ 0.5 $ 22.0 1999 10.7 $ 0.1 $ 0.4 0.5 1.0 11.7 ================================================================================================================================
68 Notes to Consolidated Financial Statements (concluded) Under SFAS No. 131, Disclosures About Segments of an Enterprise and Related Informations, Dominion has defined segments based on product, geographic location and regulatory environment. On March 3, 2000, Dominion announced a new business structure that integrates CNG's businesses, streamlines operations, and positions Dominion for long-term growth in the competitive marketplace. Under the structure, Dominion operates three principal business units: . Dominion Energy manages Dominion's 19,000-megawatt generation portfolio, consisting of generating units and power purchase agreements. It also manages the Company's generation growth strategy; energy trading, marketing, hedging and arbitrage activities; and gas pipeline and storage operations. . Dominion Delivery manages Dominion's electric and gas distribution systems, as well as customer service and electric transmission. The Company's telecommunications business is also included in the Dominion Delivery segment. . Dominion Exploration & Production manages Dominion's onshore and offshore oil and gas exploration, development and production operations. Operations are located on the outer continental shelf and deep water areas of the Gulf of Mexico and in selected regions in the lower 48 states and Canada. In addition, Dominion also reviews the following as business segments: . the financial services businesses of DCI; and . Corporate Operations. The Corporate Operations category includes: . corporate costs of Dominion's and CNG's holding companies; . Corby Power (UK) operations, prior to its sale on September 29, 2000; . intercompany eliminations; . restructuring and acquisition related costs (see Note 6); . cumulative effect of a change in the method of accounting for pensions (see Note 3); . impairment and re-valuation of DCI's assets (see Note 6); . the write-off of generation-related assets and liabilities at Dominion in 1999 (see Note 7); and . the impairment of regulatory assets and one-time base rate refund resulting from the settlement of Virginia Power's 1998 Virginia jurisdictional rate proceedings (see Note 7). While Dominion manages its daily operations as described above, assets remain wholly owned by its legal subsidiaries. Selected Consolidated Financial Data
(millions, except per share amounts) 2000 1999 1998 1997 1996 - ----------------------------------------------------------------------------------------------------------- Operating revenue and income $ 9,260 $ 5,520 $ 6,081 $ 7,263 $ 4,815 Income before extraordinary item and cumulative effect of a change in accounting principle $ 415 $ 552 $ 548 $ 412 $ 482 Extraordinary item (net of income taxes of $197) $ (255) Cumulative effect of change in accounting principle (net of income taxes of $11) $ 21 Net income $ 436 $ 297 $ 548 $ 412 $ 482 Total assets $ 29,348 $ 17,782 $ 17,549 $ 20,184 $ 14,911 Long-term debt, preferred stock subject to mandatory redemption and preferred securities of a subsidiary trust/(1)/ $ 10,486 $ 7,321 $ 6,817 $ 7,761 $ 5,362 Common stock data: Earnings per share--basic $ 1.85 $ 1.55 $ 2.81 $ 2.22 $ 2.70 Dividends paid per share $ 2.58 $ 2.58 $ 2.58 $ 2.58 $ 2.58 ===========================================================================================================
Note: /(1)/ In 1999, preferred stock subject to mandatory redemption is included in Securities due within one year and is excluded from this amount. 69 Report of Management's Responsibilities The management of Dominion Resources, Inc. is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the annual report. 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 annual report 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 Dominion's and its subsidiaries' 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 objectives. The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who were designated by the Board. Their audits were conducted in accordance with auditing standards generally accepted in the United States of America and include a review of Dominion's and its subsidiaries' 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 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 corporate conduct. This responsibility is characterized and reflected in Dominion's Code of Ethics, which addresses potential conflicts of interest, compliance with all domestic and foreign laws, the confidentiality of proprietary information, and full disclosure of public information. Dominion Resources, Inc. /s/ Thos. E. Capps /s/ Steven A. Rogers Chairman, President and Vice President, Controller and Chief Executive Officer Principal Accounting Officer Independent Auditors' Report To the Shareholders and Board of Directors of Dominion Resources, Inc. Richmond, Virginia We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, comprehensive income, common shareholders' equity, 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 Dominion Resources, Inc. and subsidiaries 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. Also, as discussed in Note 3 to the consolidated financial statements, in 2000 the Company changed its method of accounting for its oil and gas exploration and production activities to the full cost method of accounting and, retroactively, restated the 1999 and 1998 consolidated financial statements for the change to the full cost method. Deloitte & Touche LLP Richmond, Virginia January 25, 2001 70 Directors and Officers Dominion Resources, Inc. Directors Thos. E. Capps, 65 Chairman, President and Chief Executive Officer William S. Barrack, Jr., 71 Former Senior Vice President, Texaco, Inc. New Canaan, Connecticut George A. Davidson, Jr., 62 Former Chairman, Dominion Resources, Inc. Pittsburgh, Pennsylvannia Raymond E. Galvin, 69 Former President, Chevron USA Production Company Houston, Texas John W. Harris, 53 President, Lincoln Harris, LLC, Charlotte, North Carolina Benjamin J. Lambert, III, 64 Optometrist, Richmond, Virginia Richard L. Leatherwood, 61 Former President and Chief Executive Officer, CSX Equipment, Baltimore, Maryland Paul E. Lego, 70 Former Chairman and Chief Executive Officer, Westinghouse Electric Corporation Pittsburgh, Pennsylvania Margaret A. McKenna, 55 President, Lesley University, Cambridge, Massachusetts Steven A. Minter, 62 President and Executive Director, The Cleveland Foundation, Cleveland, Ohio Kenneth A. Randall, 73 Corporate director of various companies, Williamsburg, Virginia Frank S. Royal, M.D., 61 Physician, Richmond, Virginia S. Dallas Simmons, 61 Chairman, President and Chief Executive Officer, Dallas Simmons & Associates, Inc., Richmond, Virginia Robert H. Spilman, 73 President, Spilman Properties, Bassett, Virginia David A. Wollard, 63 Chairman of the Board, Exempla Healthcare, Denver, Colorado Officers Thomas F. Farrell, II, 46 Executive Vice President (Chief Executive Officer of Dominion Energy) H. Patrick Riley, 63 Executive Vice President (Chief Executive Officer and President of Dominion Exploration & Production) Edgar M. Roach, Jr., 52 Executive Vice President (Chief Executive Officer of Dominion Delivery) Thomas N. Chewning, 55 Executive Vice President and Chief Financial Officer James P. O'Hanlon, 57 Executive Vice President (President and Chief Operating Officer of Dominion Energy) Robert E. Rigsby, 51 Executive Vice President (President and Chief Operating Officer of Dominion Delivery) James L. Trueheart, 49 Group Vice President and Chief Administrative Officer Eva Tieg Hardy, 56 Senior Vice President -- External Affairs & Corporate Communications G. Scott Hetzer, 44 Senior Vice President and Treasurer James L. Sanderlin, 59 Senior Vice President -- Law William C. Hall, Jr., 47 Vice President -- External Affairs & Corporate Communications Simon C. Hodges, 39 Vice President -- Financial Planning Karen E. Hunter, 46 Vice President -- Tax Steven A. Rogers, 39 Vice President, Controller and Principal Accounting Officer James F. Stutts, 56 Vice President and General Counsel Patricia A. Wilkerson, 45 Vice President and Corporate Secretary 71 EX-21 6 0006.txt SUBSIDIARIES OF THE REGISTRANT Exhibit 21 DOMINION RESOURCES, INC. SUBSIDIARIES OF THE REGISTRANT
JURISDICTION OF NAME UNDER WHICH NAME INCORPORATION BUSINESS IS CONDUCTED Consolidated Natural Gas Company Delaware Consolidated Natural Gas Company Dominion Capital, Inc. Virginia Dominion Capital, Inc. Dominion Energy, Inc. Virginia Dominion Energy, Inc. Dominion Exploration & Production, Inc. Delaware Dominion Exploration & Production, Inc. Dominion Transmission, Inc. Delaware Dominion Transmission, Inc. The East Ohio Gas Company Ohio Dominion East Ohio The Peoples Natural Gas Company Pennsylvania Dominion Peoples Dominion Virginia Power in Virginia and Dominion North Carolina Power Virginia Electric and Power Company Virginia in North Carolina
EX-23 7 0007.txt CONSENT OF DELOITTE AND TOUCHE Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 333-55904, 333-36082, 333-93187, 333-46043, and 333-35501 of Dominion Resources, Inc. on Form S-3 and Registration Statement Nos. 333-38398, 333-38398, 333-95795, 333-95567, 333-87529, 333-78173, 333-69305, 333-49725, 333-25587, 333-18391, 333-02733, and 33-62705 of Dominion Resources, Inc. on form S-8 of our reports dated January 25, 2001, appearing in and incorporated by reference in this Annual Report on Form 10-K of Dominion Resources, Inc. for the year ended December 31, 2000. DELLOITTE & TOUCHE LLP Richmond, Virginia March 16, 2001 -----END PRIVACY-ENHANCED MESSAGE-----